FLOATING DRILLING VESSELS

1
Section

1.0 FLOATING DRILLING VESSELS

OBJECTIVES

On completion of this lesson, you will be able to:

List the advantages and disadvantages of operating with a semisubmersible or drill

ship.

Describe how environmental loading effects floating rigs.

Describe the two most commonly used methods to designate the severity of a design
environment.

Describe how wind, waves and current are measured/reported and how the direction
impacts floating drilling rigs.

Describe the six degrees of rotation (motion) of a floating vessel.

List the equipment and methods used to compensate for rig motions.

Describe the equipment used on floating rigs to handle the BOPs, bulk material,
tubulars and deck material.

List the requirements for rig selection and inspection.

Describe the requirements for a typical Marine Support Vessel.

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CONTENTS Page

1.0 FLOATING DRILLING VESSELS .................................................................................................... 1

OBJECTIVES ................................................................................................................................... 1
CONTENTS ...................................................................................................................................... 2
1.1 OVERVIEW ...................................................................................................................................... 3
1.2 COMPARISON BETWEEN SEMISUBMERSIBLES AND DRILLSHIPS ......................................... 8
1.2.1 DRILLSHIPS ...................................................................................................................... 8
1.2.2 SEMISUBMERSIBLES .................................................................................................... 10
1.2.3 RIG MOVES ..................................................................................................................... 11
1.2.4 DYNAMIC POSITIONING ................................................................................................ 13
1.2.5 COST AND PERFORMANCE.......................................................................................... 14
1.3 ENVIRONMENT ............................................................................................................................. 15
1.3.1 WINDS ............................................................................................................................. 18
1.3.2 WAVES ............................................................................................................................ 20
1.3.3 CURRENT ........................................................................................................................ 22
1.3.4 DIRECTIONALITY ........................................................................................................... 24
1.3.5 OTHER ENVIRONMENTAL CONSIDERATIONS ........................................................... 26
1.4 RIG MOTIONS ............................................................................................................................... 28
1.4.1 MOTION COMPENSATION ............................................................................................. 31
1.4.2 RISER SLIP JOINTS ....................................................................................................... 36
1.4.3 DRILLING RISERS .......................................................................................................... 38
1.4.4 DRILLSTRING MOTION COMPENSATORS .................................................................. 39
1.4.5 FLEX JOINTS .................................................................................................................. 46
1.5 STORAGE AND EQUIPMENT HANDLING ................................................................................... 47
1.5.1 BULK HANDLING SYSTEMS ......................................................................................... 48
1.5.2 PIPE HANDLING ............................................................................................................. 49
1.5.3 CRANES .......................................................................................................................... 52
1.5.4 BLOWOUT PREVENTER HANDLING SYSTEMS .......................................................... 54
1.6 IG CAPABILITY OVERVIEW ......................................................................................................... 55
1.7 OIMS REQUIREMENTS, RIG SELECTION, INSPECTION ........................................................... 56
1.8 MARINE SUPPORT VESSELS...................................................................................................... 58
1.9 REFERENCES: .............................................................................................................................. 62
1.10 APPENDICIES..................................................................................................................................... 63
APPENDIX I - SEMISUBMERSIBLE RIGS ................................................................................... 63

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1.1 OVERVIEW
In the late 1950s and early 1960s, the search for petroleum began to extend to
unprotected offshore waters with depths deeper than could be drilled with bottom-
founded drilling rigs. The first floating rig operations were small, shipshape vessels
converted for seafloor coring and very shallow drilling in water depths of 300 to 1000 ft.
Promising exploration potential, Offshore California was one of the early drivers for
floating drilling rig development. Figure 1.1 shows progression of industry well water
depths vs. time.

World Water Depth Record

Year
60

63

66

69

72

75

78

81

84

87

90

93

96

99
19

19

19

19

19

19

19

19

19

19

19

19

19

19
0
1000
2000
Wa ter Depth ft

3000
4000
5000
6000
7000
8000
9000
10000

Figure 1.1 World Water Depth Drilling Record

Technology for bottom-founded drilling rigs could not be easily adapted to floating rigs
due to the motion of the rig (as compared to the seafloor). This characteristic generated
completely new methods for drilling which included subsea blowout preventers, drilling
risers and drillstring motion compensation. The earliest floating rigs used essentially long
bell nipples fabricated into joints with conventional bolted flanges. Riser tensioning
systems were a series of wirerope, sheaves and weights. There was no drillstring
compensation other than the use of bumper subs installed in the drillstring.

In the late 1960s most floating rigs were older vessels that were converted for drilling.
Several early drillships had shipshape hulls (Figure 1.2) and a few drillships had a barge
type hull. By the early 1970s many new vessels with shipshape hulls were being
constructed for drilling. About this time, a new type floating rig, the semisubmersible,
was being designed (Figure 1.3).

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Figure 1.2 - Early Shipshape Floating Drilling Rig

Figure 1.3 - Early Semisubmersible Floating Rig, Bluewater II, 1975 Vintage

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The new semisubmersible designs were basically upgrades on submersible barge rig
designs with larger pontoons. These rig designs were typically moored vessels.
Examples include the Sedco 135, early Odeco designs (Ocean Prospector, etc) and
Pentagone 80 series rigs. With the oil embargo and the crude price increases of the
early 1970s, the number and the different design types of floating rigs exploded.
Floating rigs which include both drillships and semisubmersibles are generally classified
into generations based on their design and characteristics. A description of the general
characteristics of the several generations of semisubmersible rigs can be found in
Appendix 1.1.
With new, large semisubmersible rig designs, the number of drillships declined after the
early 1980s. The much better motion characteristics of the semisubmersible made it the
favorite of the industry. Due to the shift in market demand, drilling contractors built no
drillships for the industry between 1983 and 1997. However, during this time frame, the
government of India did build two drillships for their own use. All the drillships with barge
type hulls were removed from the fleet by the mid 1980s.
Most of the early floating rigs were moored but dynamically positioning technology was
being developed in the 1960s for seafloor coring operations. By the early 1970s the first
dynamically positioned (DP) floating drilling rigs (shipshape) were being used in water
depths as deep as 6000 ft. Early DP vessels included the Sedco 445 (built in 1971) and
the Discoverer Seven Seas (built in1975).
By the mid 1980s the worldwide floating rig fleet was composed of about 170
semisubmersibles and 60 drillships (Figure 1.4). The number of floating rigs in the
world held fairly constant between 1985 and the early 1990s at about 160 to 225 units.
During this same time period, many of the first generation floating rigs were retired from
service as the result of the downturn in the industry. The number of floating rigs
declined to about 140 by the 1990s. By 1993 about 23 drillships existed.

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World Floating Rig Fleet

250 Semisubmersibles
200 Drill ships
Number of rigs

150

100

50

0
1980 1985 1990 1995 2000
Year

Figure 1.4 - Number of Industry Floating Rigs

In the late 1990s the price of oil increased, and many deepwater and ultra-deepwater
leases were purchased in the Gulf of Mexico and around the world. Deepwater is
generally considered in excess of 2000 ft and ultra-deepwater in excess of 5000 ft. To
drill the new leases there was an immediate need for deepwater and ultra-deepwater
floating rigs. However, engineering designs for large ultra-deepwater semisubmersibles
had languished during the industry downturn in the late 1980s and early 1990s. To fill
the need for ultra-deepwater, drillships became the optimum choice, due to existing hull
designs and the large variable load needed for the long and heavy drilling riser. About 15
ultra-deepwater shipshape drillships were built in the late 1990s and early 2000s. Many
of these rigs were capable of drilling in water depths as deep as 10,000 ft. In the early
2000s, semisubmersible designs for ultra-deepwater, i.e., high variable load capability,
became available and several very large semisubmersibles were built (i.e., Deepwater
Horizon, Bingo 9000, etc.). These new semisubmersibles had variable loads required for
drilling in up to 10,000 ft water depth, however these rigs do not have variable loads as
high as deepwater drillships.
Beginning in the late 1980s dynamically positioned and/or dynamically positioned
mooring assist semisubmersibles began to be designed and built. Today several
semisubmersible rigs are available that have the capability to be completely dynamically
positioned without a mooring system.
In 2000, forty drillships were in the world floating rig fleet. Thirty of these rigs were
equipped to operate in a fully dynamically positioned mode, and ten rigs had only
m o o rin g ca p a b ility. B y 2 0 0 0 , 2 3 o f th e w o rld s fle e t o f 1 7 0 se m isu b m e rsib le rig s h a d fu ll
DP capability, and the balance were moored.

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With this world fleet available, the industry steadily increased the water depth and
number of wells drilled worldwide. Figure 1.5 illustrates that prior to 1980, only about
500 wells had been drilled worldwide in greater than 600 ft water depth. By 1990, more
than two thousand wells had been drilled in over 600 ft water depth and by the year
2000, the well count had increased to over 4400 wells. By the year 2000, only 140 wells
had been drilled worldwide in over 5000 ft water depth.

World Water Depth Drilling History

5000
Wells In Greater Water Depth

Before 1980
4000
Before 1990
3000 Before 2000

2000

1000

0
0 2000 4000 6000 8000 10000
Water Depth ft

Figure 1.5 - Worldwide Floating Rig Water Depth History

Rig rates for floating rigs have always been very sensitive to demand and industry
activity. It has not been uncommon to see the rate for a deepwater rig to be as low as
$35-40k/day during industry slow downs, then during times of high industry demand, the
rate for these rigs can double or triple. Historically, offshore platform rig rates have had
very stable daywork rates that are reflective of capital employed to build the rig and rig
labor costs. Jack up rig rates have been a bit more sensitive to industry demand. A
general rule-of-thumb is that rig rates will be about $600 to $1000/day per million dollars
of new construction cost. For example, a new ultra-deepwater semisubmersible with a
cost near $300 M and would have a dayrate near $225k/day.
Prior to the fifth generation rigs built or converted in the late 1990s and early 2000s,
floating rigs were typically outfitted to drill to only about 20,000 to 25,000 ft. These rigs
typically had 2000 or 3000 Hp drawworks and one million-pound rated derricks. Most of
the fifth generation rigs have much higher rated depth capacity (25,000 to 35,000 ft) with
4000 Hp or larger drawworks and derricks rated to as much as two million pounds.

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1.2 COMPARISON BETWEEN SEMISUBMERSIBLES

AND DRILLSHIPS
Floating rigs come in many sizes, capabilities, shapes, designs and configurations. Each
has its own advantages and disadvantages. For the two general types of floating rigs,
drillships and semisubmersibles each have several general operating characteristics.
Table 1.1 is a general summary of these characteristics.

General Floating Rig Operating Characteristics

Drilling Requirement Drillship Semisubmersible
High Variable Deck Load Very Good Moderate
Extreme Weather Conditions Poor Good
High Current
Collinear with wind & waves Good Good
Not Collinear with wind & waves Poor Good
Rig Motions Poor to Good Good
Completion Operations Good Good
Mobility Very Good Moderate
Structural integrity Very Good Good

Table 1.1 - General Characteristics of Drillships and Semisubmersibles

1.2.1 DRILLSHIPS
Drillships have the primary advantage of very high variable load capability, and they can
move long distances in a short time. Many early drillships had variable load capacity for
well supplies that could allow drilling an entire well without re-stocking. Variable loads of
10,000 to 20,000 tons would permit transit to a remote location with all the casing,
cement, mud products and other supplies needed to drill an entire well. This was an
important factor in early offshore drilling operations as many areas of the world lacked
the necessary infrastructure to obtain well supplies. Today most areas of the world have
a developed infrastructure and the importance of a high variable load is not as important.
An old industry rule-of-thumb for floating rigs is the variable load required for well
operations is 1000 tons per 1000 ft of water depth.

A high variable deckload is still important in deepwater since the riser system can have
an air weight approaching four to five million pounds (2000 to 2500 tons) rather than
the one to two million pounds air weight of riser systems for 1500 to 2000 ft water depth.
The large riser system air weight made shipshape vessels a logical choice for early
ultra-deepwater rigs.

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All drillships today have shipshape hulls and are self-propelled with open water transit
speed of about 10-12 knots. For example, the Jack Ryan drillship traveled almost 2100
nautical miles from Trinidad to the Gulf of Mexico at an average speed of just over 10
knots in the spring of 2001 (8.7 transit days).
A disadvantage of drillships is that they are very sensitive to weather (wind, waves and
current) impacting the rig anywhere other than the bow. If environmental loads are
placed on the side of a rig rather than on the bow, very high rig motion results and
stationkeeping problems are increased. A moored shipshape vessel cannot change
the rig heading more than about five degrees (by adjusting mooring line tension) after
it is moored and is thus very sensitive to environmental loads impacting the rig on the
beam (side).
In the late 1970s very few turret moored shipshape vessels were built. These rigs had
mooring systems and limited dynamic positioning capability. The mooring was located
a ro u n d th e rig s m o o n p o o l circu m fe re n ce a n d a llo w e d th e rig to ch a n g e rig h e a d in g
(turn). Turret moored rigs typically had relatively small mooring systems and were not
capable of full dynamic positioning. This would keep the prevailing environment on the
bow and reduce vessel motions when the environment impacted the rig from a
quartering or beam environment. Only two turret moored shipshape vessels exist in
2001 (Discoverer 511 and Discoverer I).
Dynamically positioned rigs change bow heading (sometimes slowly) to keep the bow
into the environment. This minimizes vessel motion and environmental loads on the rig.
If the environment is not collinear (wind, wave and current not from the same direction)
shipshape vessels can have significant rig motions which may slow or prevent rig
operations. In many areas of the world such as the North Sea, winter environment
conditions are so severe that a shipshape vessel cannot safely work due to excessive
ship motions.
A disadvantage of shipshape rigs is their increased motion sensitivity to the direction and
intensity of the environment. Early shipshape rigs were used only in low environmental
conditions or areas such as in the summer months in the North Sea and offshore
Norway due to this sensitivity. The fifth generation shipshape rigs have improved motion
responses to the environment because of their large size and displacement.

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1.2.2 SEMISUBMERSIBLES
The primary advantage of semisubmersible rigs is the reduced sensitivity of rig motion
as a result of environmental loading. Wind and wave loads on the columns and the rig
structure are much less than those generated on a shipshape vessel. Generally,
semisubmersible rigs are not as dependent on the direction from which the environment
impacts the rig. Rig heading changes to minimize environmental loads are not required.
This is important for moored operations. Many semisubmersible rigs have the drill floor
located very near the center of the rig to take advantage of the reduced vessel motion at
this location on the rig.
Early shallow water depth rated semisubmersible rigs had very low variable loads.
Common variable loads were 1500 to 2000 tons, which limited well supplies that could
be carried on the rig. Most rigs drill with a low air gap (to improve vessel stability) and
transit at a higher draft (to permit higher transit speeds). At the higher transit draft, the
variable load of a semisubmersible is generally significantly reduced as required to
maintain vessel stability. Most semisubmersible designs would permit transit with only
minimal casing, well supplies or drillstring left standing in the derrick. This characteristic
of a semisubmersible rig requires frequent restocking with necessary well supplies.
The ultra-deepwater semisubmersible designs of the late 1990s have variable loads
as high as 8,000 to 10,000 tons. The riser can be the largest user of variable load on a
ultra-deepwater rig and can consume as much as 25 to 30% of the available variable
load. The ultra-deepwater rigs have drilling risers with larger (heavier) choke and kill
lines, longer joints (reduced weight of connections) and often use long lengths of bare
riser. Today new materials and designs can reduce the top deck riser weight as much as
15 %. New floatation materials offer about 20% more buoyancy per unit volume over
conventional buoyancy materials; however, presently there is a substantial cost
premium. Building risers out of composite materials is an emerging technology that may
reduce on-deck weight of the riser by 40-50 % in the future.

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1.2.3 RIG MOVES

The transit or moving speeds of semisubmersible rigs are highly variable and depend
on vessel design and loading. Typically a deepwater (moored or dynamically positioned)
semisubmersible can average about five to six knots under its own power on long
moves. Higher transit speeds are possible and one large semisubmersible crossed the
Atlantic Ocean in 1974 in a record-breaking 21 days and averaged a speed of 9.7 knots.
Figure 1.6 shows the difference in travel time that can be expected between a
shipshape and a semisubmersible for worldwide locations where active deepwater
drilling is occurring. The difference in transit cost for these two rig types can sometimes
be mitigated by using creative contract terms (during rig moves) arranged between the
contractor and the operator.

General Transit Time for Floating Rigs

100 GOM to Gabon

GOM to N.Sea
GOM to Trinidad

GOM to S.E. Asia

Drillship
90

80 Semi

70
Transit time days

60

50

40

30 Assumptions:
20 1. Drillship speed = 10 kt

10
2.Semi speed = 6 knot
0
1000 3000 5000 7000 9000 11000
Transit Distance Nautical Miles

Figure 1.6 - Travel Time for Floating Rigs

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Many semisubmersible rigs are moved on transport ships when a long rig move is
required. With a semisubmersible on the deck of the ship (dry tow) (Figure 1.7) the rig
transport ship can make in excess of 10-knots transit speed. Only recently have transit
ships been large enough to carry more than second generation size semisubmersibles.
The larger semisubmersibles were simply too large and weighed too much to place on
the transport vessel. In the late 1990s larger transport ships have become available and
some of the larger semisubmersibles can be dry transported.

Figure 1.7 - Dry-Tow of a Large Semisubmersible Rig

Many early drillships and semisubmersible rigs had both thrusters and/or self-propulsion.
For example, most of the Aker H-3 semisubmersible rigs had thrusters and all of the
Odeco Victory class semisubmersible rigs had a propeller in each pontoon for self-
propulsion. As these rigs have been updated and modified over the years, many of the
older semisubmersible rigs have had their thrusters and/or self-propulsion features
removed. This was generally done for economic reasons as a semisubmersible with
self-propulsion is usually required to have a marine crew (captain, able-bodied seamen,
etc.) on the rig all the time. Typically these rigs are towed by tugboats between rig
locations today.

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1.2.4 DYNAMIC POSITIONING

In the past, dynamic positioning has proved less reliable than moored operations in
m a in ta in in g a rig s p o sitio n o ve r a su b se a w e llh e a d . In 1 9 9 3 a n d 1 9 9 4 , a jo in t in d u stry
study (Deepstar) performed a qualitative risk assessment of emergency disconnect
frequency with dynamically positioned rigs(1). The report concluded that on average,
loss of station occurred once every 175 operational rig days. The new more advanced
dynamically positioning systems used on rigs built after the 1990s should have
increased reliability over the dynamically positioning systems included in this study.

Generally moored rig stationkeeping has a very high reliability. North Sea experience
indicates the probability of a total mooring system failure is once every 200 rig years.
The reliability of moored stationkeeping in milder environments such as the Gulf of
Mexico should be better.

Many operators have been reluctant to production test or complete production wells with
dynamically positioned rigs. The reliability of stationkeeping with dynamically positioned
rigs is the primary concern. For many areas of the world, these operations require a
separate barge to capture produced fluids (flaring has regulatory restrictions) which
further increase risk of these dynamically positioned operations.

Many of the large ultra-deepwater rigs built after the late 1990s (for example the
Discoverer Enterprise) have the potential to hold large volumes of produced crude in the
ships hull. This capability has a high cost for inert gas blanket systems in crude storage
tanks, increased regulatory and safety requirements, etc. Many of these rigs were
constructed with this capability; however, the necessary equipment has never been
installed and would have an added cost of several million dollars.

Dynamically positioned rigs typically have large power plants installed and consume
large quantities of fuel. Large dynamically positioned drillships and semisubmersible rigs
can average consuming 300 to 350 bbls of diesel per day. A standard moored rig will
typically have much less installed horsepower and average only 75-100 bbl/day of diesel
consumption. The difference in fuel cost is at least partially offset by the cost of anchor
handling vessels and time required for mooring. Providing for very large anchor
handling vessels needed for deepwater mooring in remote locations can be very
expensive.

In some areas of the world, the quantity of air emissions is tightly regulated and the
increased air emissions of a dynamically positioned rig must be considered. DP systems
will be covered in section 5.0.

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1.2.5 COST AND PERFORMANCE

The very high cost and long contract term required for many ultra-deepwater rigs make
the performance and efficiency of a rig an extremely important consideration in rig
selection. In many cases, a higher cost, high efficiency rig can be a better value than a
lower cost rig with poor operations efficiency. Drilling contractors have recognized this
and have made great improvements in the operability of the ultra-deepwater rigs. One
contractor has a patent for rigs with full dual drilling capability. This feature adds a
second drilling package resulting in two rotary tables, two drawworks, two hoisting
systems, increased derrick size, added rig floor space and increased personnel. Full
dual activity was originally thought to improve efficiency as much as 40% in certain
drilling scenarios such as development drilling. The rig efficiency gain while drilling
exploration wells has proven to be about 20%. The equipment and personnel required
for dual activity operations has a $15-20M capital cost and with added crews, will
increase dayrates $10-15k per day.
Use of concurrent activities above the rig floor can also improve efficiency of drilling
operations. Multiple activities, such as making up bottom hole assemblies or casing into
stands, can improve efficiency by at least 15 to 20%. The use of concurrent activities
requires automated pipe handling equipment, larger derrick, second hoisting system,
added crews, etc. With added crew cost concurrent capability can increase the dayrate
$7 to $10k/day.

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1.3 ENVIRONMENT
This section is intended to provide a general background on the offshore environmental
data needed for the assessment of operating conditions and risks associated with
floating rig operations.
Effective operations with floating type rigs strongly depend on the environment. Unique
to floating drilling is the movement of the rig with the environment as compared to the
well and mudline.
A meteorologist generally gathers environmental data. Generally they develop a
prediction of future meteorological conditions after studying past data on winds, waves
and currents. From these data, models are developed that will permit predicting how
severe the environment may be in the future.
A method used to evaluate past environmental conditions is called a hindcast or the
determination of the magnitude of storms, which occurred at the rig site historically. An
environmental hindcast for a given area is usually available. For example, a joint industry
hindcast known as GUMSHOE is available for the Gulf of Mexico. The hindcast should
cover at least a three-year period. After the hindcast data is gathered and modeled, a
forecast of future environmental conditions can be made. Figure 1.8 shows the results
of a forecast of environmental conditions for use in rig stationkeeping and riser analysis.

Typical GOM Floating Rig Design Environments

(IIlustration Only, Not for Design Purposes)

45
100 Year Return
Significant Wave Height ft.

40
35 Fifty Year Return
30 Twenty Year Return

25
Five Year Return Ten Year Return
20
15 One Year Return
10
95% Non-exceedance
5
20 40 60 80 100
Wind Speed knots

Figure 1.8 - Typical Floating Rig Design Environmental Conditions

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There are two commonly used methods to designate the severity of a design
environment for a floating rig. These methods are:
The cumulative probability method which specifies the percentage of time
during the average time period (year) that the environment (winds, seas and
current) will not exceed a given level.
The return period method which specifies the average recurrence interval
between the occurrence of a given environment.
Extreme meteorological conditions are usually modeled with the return period method.
Fixed platform, floating production facilities and floating rigs operating next to (or above)
offshore facilities often use this design approach. For example wind, waves and current
for a 100-year return period are often specified as the design environment for fixed
platforms, floating production facilities, etc.
For short-term floating rig operations away from other offshore structures or facilities,
the risk of a stationkeeping failure is less severe, and a lower design environment is
warranted. For low to moderate design environments, the cumulative probability method
is often used.
Wind, waves and current for a 100-year design environment are not the most severe
storm, which occurs once every 100 years. It is the environment, which has a 1/100
probability of being exceeded in one random year. The probability that a 100 year
environment will be exceeded in 100 years is 1-(0.99) 100 or 0.63. The probability that a
100 year storm will be exceeded in 20 years is 1-(0.99)20 = 0.18.
Prior to the mid 1990s, most floating rig stationkeeping analysis used the cumulative
probability method to determine the design environment. Today, most stationkeeping
analysis for floaters uses the return period method, and often, both methods are used.
In general, there is no direct correlation between the return period method and the
cumulative probability method.
ExxonMobil typically will use both the cumulative probability and the return period
method when analyzing the stationkeeping capabilities of a floating rig.

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Pride North America Rig

200 95%
180 One yr return
160 M iss. Canyon Blk 509
Force on rig Kips

URC analysis dated 5/15/2001

140 Quartering Environment

120
100
80
60
40
20
0
Wind Wave Current

Figure 1.9 Environmental Loads for Typical Operating Environments.

Figure 1.9 illustrates the loads imparted to a floating rig during a typical operating
environment. A floating rig responds to loads imparted to it by three environmental
conditions: winds, waves and currents. Usually, winds are the most significant
environmental load that impacts a floating rig.

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1.3.1 WINDS

Since wind loads can have a powerful effect on a floating rig, a basic understanding of
the cause and nature of winds is important.
Winds are caused by differences in atmospheric pressure that occur from one
geographic location to another. Winds flow from geographic areas with high pressure to
areas that have low pressure. High and low pressure geographic areas around the world
are generally created by differences in temperature.
The wind speed at any one location is a function of the difference between high and low
pressure across that location. As winds move due to pressure gradient differences from
one location to another, Corollas force affects its motion due to the rotation of the earth
and centripetal force due to the curvature of streamlines. When mapping winds, lines of
constant atmospheric pressure are called isobars. When isobars are closely spaced, the
pressure gradient is very large and winds will have higher velocity than where isobars
are spaced further apart. In the Northern Hemisphere, the Corollas force results in winds
circulating counter-clockwise. In the Southern Hemisphere, this force causes winds to
circulate in a clockwise direction.
Wind is air in horizontal or nearly horizontal motion and is named in accordance with the
direction from which it blows, i.e.; an east wind is from the east. The freedom of air to
move is a function of the proximity and topography of the surface it flows over. As air
flows over land, it behaves in an irregular fashion.
Friction between the ground
and the air produces Typical Wind Speed vs. Elevation Correlation
eddies in the air, which one hour mean w ind speed
produce gusts and lulls. 150
Convection from local
temperature differences 130
Height Above Sealevel - meters

can also influence air

110
motions.
The friction of flowing 90
w in d o ve r th e e a rth s
70
surface also affects the
wind speed. The wind 50
speed typically
increases with height 30
above th e e a rth s
10
surface due to reduced
0 20 40 60 80 100 120 140
friction. Figure 1.10
Wind Speed - knot
illustrates typically how
the height above the
earth surfaces can affect Figure 1.10 Typical Wind Speed vs. Elevation
the wind speed.
Note: At higher wind speeds, the difference increases between the wind speed at the
e a rth s su rfa ce a n d a t a higher elevations.

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FLOATING DRILLING VESSELS

For floating rigs, wind speeds are generally referenced to a height of 32.8 ft or 10 meters
above sealevel. Wind speed is generally expressed in knots; one knot is equivalent to
1.15 miles per hour. Since a knot is a measure of speed, it is incorrect to express wind
speed in knots per hour. Distances in marine operations are usually expressed in
nautical miles, which are equal to 1.15 statute miles. Dividing nautical miles by speed in
knots results in time.
The surface of air is least turbulent over the open sea where friction is reduced to a
minimum. Generally, winds are steadier and have higher velocity over the sea than over
a land surface. Wind speeds constantly fluctuate (i.e., gusts). To account for changing
wind speeds, floating rig stationkeeping design is based on average wind speed over
specified intervals. Typical designs call for one-minute, 10-minute or one-hour average
wind speed. In general, the shorter the average time interval, the higher the average
wind speed. Often, it is possible to develop a relationship between the one-minute, 10-
minute and one-hour wind speed for a given geographic area. A common error is to
confuse or misunderstand the difference between these three wind speed design
averages.
Approximate conversio n s a re o fte n u se fu l, a n d th is ro u g h b a llp a rk ru le -of-thumb can
easily be remembered:
(1-minute average wind speed) x 0.85 = 1 hour average wind speed
(20 meter (65.6 ft) height wind speed) x 0.92 = 10 meter (33ft) wind speed.
For example, a 50-knot wind observed at a 66-ft rig height would be roughly equal to a
45-knot wind at a 10-meter elevation.
Once the design wind speed is determined, a way to calculate the force imparted to the
rig from that wind speed must be determined. Wind forces on a floating rig impact the
projected area exposed to the wind. The load from wind is a square root function of the
wind velocity, and this general equation relates wind speed to load imparted to a floating
rig:
2
Wind Force = (wind speed) x shape coefficient x projected area of all
surfaces exposed to the wind
In addition to using more exact equations than the above general equation, model tests
are usually used to better quantify wind loads on a rig, and a meteorologist develops
wind speeds.
The projected area exposed to the wind should include columns, deck members,
deckhouses, trusses, crane boom, derrick substructure, drilling derrick and the hull
above the waterline. The shape coefficient typically ranges from about 0.5 to 1.5
depending on the exposed area. Since wind speed increases with height above
sealevel, this equation requires the correct wind speed for the elevation of the exposed
area.
The calculated wind forces on a rig can be treated as constant or as a combination of
a steady component and a time varying component. Generally, the second method will
use a longer average wind speed than when wind is treated as a constant. The time
varying component is also known as low-frequency wind force. Low-frequency wind
forces are normally computed with an empirical numerical method. Low-frequency
wind forces typically induce low frequency rig motions.

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FLOATING DRILLING VESSELS

1.3.2 WAVES
For very extreme meteorological conditions, (i.e., winds and waves) waves can be the
largest environmental load imparted to a rig.
Waves are generated by winds acting on the surface of the ocean over a distance. This
distance is called fetch. There is a relationship between wave height, wind speed, fetch
and the length of time that a wind blows. For a fixed fetch distance, increasing wind
forms increasing height waves. As fetch distance increases, a given wind will produce
bigger waves.
Swells are a system of waves that have moved out of the generating area into a region
of weaker opposing winds (or calm). Swells decrease in height with travel and may be
difficult to distinguish from locally wind-generated waves. Swells usually have a well-
rounded profile, a greater wave length, and disturb the water to a greater depth. Swells
indicate that there may have been strong winds or a severe storm recently hundreds of
miles away. The swells come from the same direction as the wind which created them
and may indicate an approaching storm.
A simple or a regular wave is shown in Figure 1.11. The basic measure of wave height
is called significant wave height represented by Hs. Hs is equal to the average of the
highest one third of the waves passing a point. This method is used because it is roughly
equivalent to what a trained observer would estimate as the wave height for a given
series of waves.

Still Water Level

H = Wave Height d = Water Depth

= S u rfa ce E le va tion
AO = Wave Amplitude
L = W a ve L e n g th T = W a ve P e rio d

C = L /T = W a ve C e le rity
Seafloor

Wave Period The time that elapses for a wave to traverse its length.
Wave Height Difference in elevation between the wave crest and the proceeding wave trough.
Amplitude The height of the elevation of the wave crest above the still water level.
Wave Length The horizontal distance between two successive wave crests.
Wave Celerity The propagational speed of the wave.
Frequency The number of wave cycles per second
Figure 1.11 Definition of Simple Wave

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FLOATING DRILLING VESSELS

The significant wave height is not the maximum wave height. The maximum wave height
is larger than the significant wave height. A rule-of-thumb is that the maximum wave
height is estimated to be 1.9 to 2.2 times the significant wave height.
The period of a wave is the time that elapses for a wave to traverse its length. The
motions of a floating rig are very dependent on the period of a wave. In general, the
longer the period of the waves the more the vessel will respond (heave) to the wave.
For a short period wave, vessel motion response will be lower. Typically, waves have a
period of 8 to 14 seconds with swells having the longest period and producing the most
floating rig motion response. Longer period waves travel faster than short period waves.
The period, length, energy level and the depth of swells can be the major factor affecting
the motion of a rig. Local weather can be insignificant but a large swell can have a large
impact on floating rig motions. Areas of the world where swell often impact floating rig
operations are West Africa, Brazil and Australia.
Determining the force imparted to a floating rig by waves is a very complex problem.
Typically, model tests or analytical methods are used to relate wave characteristics to a
force imparted to the rig. The direction a wave impacts the rig must also be considered
for this calculation.

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FLOATING DRILLING VESSELS

1.3.3 CURRENT

Current is important to floating rigs since current can have a large impact on many
drilling operations. Some operations, which can be significantly impacted by current,
include operations prior to running the BOPs and riser (open-water work), Remote
Operated Vehicle (ROV) operations and rig stationkeeping. Generally, problems arise in
currents exceeding two knots because of high drag loads on the riser and drilling vessel.
Currents are caused by local or global winds that drive water around the oceans. Ocean
current can generate a significant load on floating rigs. Unlike wind and waves, currents
will result in loads imposed both on the floating rig, tubulars and other equipment below
the ocean surface such as mooring equipment. A good understanding and knowledge of
the impact of current on floating rigs is essential.
Similar to wind, current loading on a floating rig is a square root function of the current
velocity, and this general equation shows this relationship:
2
Current Force = (current speed) x drag (or current) coefficient x
projected area of all surfaces exposed to the current or the wetted
surface area (shipshape hull).
Drag or current coefficients are generally established from model testing.
There are three general types of currents that are often encountered offshore. The first is
currents associated with major ocean circulatory currents, such as the Gulf Stream
located off the US East Coast. The second is locally induced currents and the third is
periodic currents associated with tidal flow.

Figure
Figure 1.12
1.12 Major
Major Ocean
Ocean Currents
Currents of
of the
the World
World

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FLOATING DRILLING VESSELS

Globally generated ocean currents generally are found worldwide but are usually found
at continent margins. Typically, current along the eastern margin of a continent are
stronger than current along the western margin of a continent. Figure 1.12 shows major
cu rre n ts o f th e e a rth s o ce a n s. S u b su rfa ce cu rre n ts ca n a lso b e d u e to th e rm a l
variations in the water column or bathsymetry changes. These currents can occur for
long sections at any depth in the ocean. The GOM eddy and Loop current are globally
generated currents.
Locally generated currents are driven by the wind and/or swell and are usually limited to
a relatively shallow surface layer of the ocean. Since winds and/or swell cause these
currents, they are usually collinear with the generating wind direction and are confined to
a relatively shallow surface layer.
General correlation of wind speed with locally generated currents can be made. For
example, for water depths greater than 250 ft in the Gulf of Mexico, current speed may
be taken as 2.5% of the wind speed of return periods of 5 to 50 years and as 1.5% of the
wind speed for a one-year return period (current uniformly distributed over the top 250 ft
of the water column). Another correlation sometimes used is that wind induced current
is 1% of the wind velocity at 32.8 ft elevation. Formulas other than these for variation of
current velocity with ocean depth can be considered if shown to be appropriate for the
site condition.
Currents associated with tidal events often affect long lengths of the water column but
are usually not found in deeper water depths. These currents change in direction over a
period of time. As the tide rises, the flow will be in one direction, and as it falls, it will be
another direction.
There are a few special environmental events that can affect environmental loading,
these include Tsunamis and Solitons. Tsunamis are very large waves caused by an
earthquake or volcanic eruption either on the ocean floor or near the shoreline. Both
waves and current can intensify as they move into shallower water.
Solitons are found most often in the Far East and are formed by a combination of
thermal variations, lunar tidal changes and bathymetry. A Soliton is an underwater wave
that is usually periodic in nature.
In many areas of the world historical current data is very minimal. In these cases, it is
common to install current meters on a temporary oceanfloor-anchored mooring to gather
tidal and global current information. This data gathering process may take in excess
of a year.

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FLOATING DRILLING VESSELS

1.3.4 DIRECTIONALITY
It is necessary to understand the direction from which the wind, waves and current
impact a floating drilling rig, since this will have a large effect on total environmental
loading. Figure 1.13 shows the definition of wind and wave directions (relative to a
drilling rig) as is commonly used when performing stationkeeping analysis. For winds
and waves, it is common to assume these two environmental loads impact a rig
collinearly or from the same direction. Likewise, wind generated surface current is
usually assumed to act on a rig collinearly with wind and wave forces.

Figure 1.13 - Wind and Wave direction

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FLOATING DRILLING VESSELS

Currents, especially tidal or global currents, will usually impact a rig at a different
heading than the heading from which wind and waves impact the rig. In cases with high
global or tidal current, the rig heading may be chosen to minimize environmental loading
from current rather than to minimize loading from the wind and waves.
Wind and wave generated (storm generated) currents generally occur in shallow ocean
depths where the structure (hull, pontoons, columns) of floating rigs are located. Wind
and wave generated loads can be added with tidal or global currents if both these
environments impact the rig from the same direction. It is also possible for wind and
wave generated surface current to impact a rig at 90o or 180o from tidal or global current
orientation. Obviously not only the magnitude of wind, wave and current environments
are important, but also the direction of these environmental loading forces.

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FLOATING DRILLING VESSELS

1.3.5 OTHER ENVIRONMENTAL CONSIDERATIONS

Other environmental considerations sometimes encountered when drilling with floating

rigs in clu d e ice b e rg s a n d se a sp ra y icin g o n a rig s stru ctu re in co ld e n viro n m e n ts.
In some areas where petroleum exploration occurs, very low, freezing temperatures
prevail for a major portion of the year. Ice in the form of fields of floating, grinding packs,
moving back and forth on the tidal currents produces formidable design problems. Sea
ice ca n o ccu r in so m e a re a s, a n d n o n e o f to d a ys flo a tin g rig s h a ve b e e n d e sig n e d to
survive stresses associated with sea ice.
Icebergs occur in many areas of the world, and special procedures must be employed to
divert or move a floating rig to avoid a collision. Some floating rigs have special fast
release mooring and riser systems for use when drilling in iceberg-affected areas.
Standby vessels are often used to tow/divert icebergs away from the rig.
Icin g o n a flo a tin g rig s d e rrick a n d to p d e ck a re a ca n b e ca u se d b y w in d b lo w n w a te r
particles. Seaspray can affect the structure of a floating rig to about 50 ft above the
waterline. Ice formed from fog or rain can accumulate on any exposed surface.
Factors affecting superstructure icing are wind speed, air temperature and water
temperature. Conditions for superstructure icing caused by wind-blown spray are
shown in Figure 1.14.
Surfa c e Wind (knots)
60 55 50 45 40 35 30 25 No Ic ing
-2 28

-4 24

Lig ht Ic ing
-7 20

-9 16

-11 12

-13 8
g
Ic i n
e

-16 4
ra t
de
Mo

-18 0 -2 1
-
28 0
-20 -4 1
30

(oC) (oF) 2
32

3
4
34

6
36
38

7
8
40

ng 9
ur
42

i
)

Ic
( oC

t
44

ra

ng vy
pe

i
46

Ic a
He
(o 8

vy
4
Se F)
Te

a
He
a

ry
Ve

Figure 1.14 - Icing Caused by Windblown Spray.

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 FLOATING DRILLING VESSELS

Using this figure for a location with a 14oF air temperature, wind velocity of 30 knots and
a sea temperature of 32oF, it indicates that heavy icing could be expected. Table 1.2 can
be used to estimate the icing accumulation expected for these icing categories:
Category Accumulation
____________ ______________________
Light 0.4 in. to 1.4 in. in 24 hours
Moderate 1.4 in. to 2.6 in. in 24 hours
Heavy 2.6 in. to 5.7 in. in 24 hours
Very Heavy 5.7 in. + in 24 hours
Table 1.2 - Categories of Icing Conditions

Icing can impact the loading and stability conditions of a rig and should be considered in
wind-force calculations.
Steel components, i.e., pontoons, columns, drilling riser, etc., exposed to temperatures
below 4oF should be qualified for cold temperature applications. Such qualification may
require material testing and special steel formulations for cold service. The special steels
used in cold environments are not as susceptible as common steels to becoming brittle
and fracturing in very cold environments. The operating range of elastomeric materials
should also be consistent with cold weather operations.
Many years ago weather mapping used a Beaufort scale to describe wind and sea state.
For reference, Table 1.3 summarizes and defines the Beaufort scale.
Wind Speed U.S. Estimated wind speed WMO Code
Beaufort S eam an s Weather Effects observed at sea Effects observed on land Term and height Code
meters per km per
Number knots mph term Bureau of waves in feet
second hour
Term
0 Under 1 Under 1 0 .0 0 .2 Under 1 Calm Sea like mirror Calm; smoke rises vertically
Ripples with appearance of scales; Smoke drift indicates wind
Calm, glassy, 0 0
1 1-3 1-3 0 .3 1 .5 15 Light air no foam crests direction; vanes do not
Light
move
Small wavelets; crests of glassy Wind felt in face; leaves
2 4-5 4-7 1 .6 3 .3 6 11 Light breeze Rippled, 0-1 1
apperance, not breaking rustle; vanes begin to move
Large wavelets; crests begin to Leaves , small twigs in
Gentle
3 7-10 8-12 3 .4 5 .4 12 19 Gentle break; scattered whitecaps constant motion; light flags Smooth, 102 2
breeze
extended
Small waves, becoming longer; Dust, leaves, and loose
Moderate
4 11-16 13-18 5 .5 7 .9 20 28 Moderate numberous whitecaps paper reaised up; small Slight, 2-4 3
breeze
branches move
Moderate waves, taking longer form; Small trees in leaf begin to
5 17-21 19-24 8 .0 1 0 .7 29 38 Fresh breeze Fresh Moderate, 4-8 4
many whitecaps; some spray sway
Larger waves forming; whitecaps Larger branchges of trees in
Strong
6 22-27 25-31 1 0 .8 1 3 .8 39 49 everywhere; more spray motion; whistling heard in Rough, 8-13 5
breeze
wires
Strong
Sea heaps up;white foam from Whole trees in motion;
Moderate
7 28-33 32-38 1 3 .9 1 7 .1 50 61 breaking waves begins to be blown resistance felt in walking
gale
in streaks against wind
Moderate high waves of greater Twigs and small branches
length; edges of crests begin to broken off trees; progress
8 34-40 39-46 1 7 .2 2 0 .7 62 74 Fresh gale Very rough, 13-20 6
break into spindrift; foam is blown in generally iompeded
Gale well marked streaks
High waves; sea begins to roll; Slight structural damage
9 41-47 47-54 2 0 .8 2 4 .4 75 88 Strong gale denbse streaks of foam; spray may occurs; slate blown from
reduce visibility roofs
Very high waves with overhanging Seldom experienced on
crests; sea takes white apperance as land; trees broken or
10 48-55 55-63 2 4 .5 2 8 .4 89 102 Whole gale High, 20-30 7
foam is blown in very dense streaks; uprotted; considerable
Whole
rolling is heavy and visibility reduced structural damage occurs
gale
Exceptionally high waves; sea Very rarely experienced on
11 56-63 64-72 2 8 .5 3 2 .6 103 117 Storm covered with white foam patches; land; usually accompanied Very high, 30-45 8
visibility still more reduced by widespread damage
12 64-71 73-82 3 2 .7 3 6 .9 118133 Air filled with foam; sea completely
13 72-80 83-92 3 7 .0 4 1 .4 134149 white with driving spray; visibility
14 81-89 93-103 4 1 .5 4 6 .1 150166 greatly reduced Phenomenal, over
Hurricane Hurricane 9
15 90-99 104-114 4 6 .2 5 0 .9 167183 45
16 100-108 115-125 5 1 .0 5 6 .0 184201
17 109-115 126-136 5 6 .1 6 1 .2 202-220

Table 1.3 Beaufort Scale

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FLOATING DRILLING VESSELS

1.4 RIG MOTIONS

Floating drilling operations are unique since there is not a rigid connection between the
rig and the well. The marine riser system accommodates the motion between the rig
and the well. This system includes the riser tensioner system and all equipment between
the lower marine riser connection and the rig floor.
Floating rigs move with the environment and the resulting rig motions are very important
to rig operations. Excessive rig motions can cause a rig to stop normal operations and
go into a standby mode. It is also important to have a near-term forecast of weather and
resulting rig motions to ensure that critical operations, such as running the BOPs and
riser and running long heavy casing strings, are performed safely.
Figure 1.15 illustrates the six motions of either a drillship or a semisubmersible rig.

Figure 1.15 Six Types of Motion

Rotation
Heave, surge and sway are measured in ft (or meters). Roll, pitch, and yaw are
measured in degrees. However, the magnitude of these motions needs further definition.
Rig motions measured in degrees are usually stated as either single amplitude or double
amplitude motions. If a shipshape rig were rolling four degrees to each side (from a
center upright position) the motion would be described as an eight-degree double-
amplitude motion or as a four-degree single-amplitude motion. Sometimes a motion,
w h ich is m e a su re d in d e g re e s, is re fe re n ce d to a s sig n ifica n t. A sig n ifica n t va lu e
would represent the average of the one-third highest motions measured over time.
Similar to wave height, a tra in e d o b se rve r w o u ld b e a b le to e stim a te sig n ifica n t rig
motions after watching a given series of motions.

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After the design environmental conditions of a rig are determined, resulting rig motions
must be determined. Typically, environmental loads impact a rig and produce two types
of motions, mean or steady-state vessel offset and low frequency motions about the
mean vessel offset. Wind and currents are generally considered to produce steady state
vessel motion. Waves can produce both steady state motions and low-frequency
motions
A primary motion of a rig is the vessel offset. This is important, as it will affect riser and
structural casing design and operability. Vessel offset is caused by the combination of
current, wind and wave forces. Typically the steady state and low-frequency rig motions
are combined to calculate a mean or average vessel offset and a maximum vessel offset
which would include low-frequency vessel motions.
Vessel offset is measured as a percent of water depth for floating rigs. Figure 1.16
shows how vessel offset is measured for floating rigs. Vessel offset depends on many
factors including water depth, environment, riser system and rig design. The offset limits
for a rig under the maximum design and operating limits should be determined by a riser
analysis in conjunction with a stationkeeping analysis.

Displacement = 100 ft.

Offset = 100 ft = 5%
2000 ft

W ater D ep th = 2000

Figure 1.16 Vessel Offset Measurement

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FLOATING DRILLING VESSELS

There are some general rules-of-thumb for vessel offset. Generally, the two conditions
are maximum design (and operating) condition and the allowable mean offset. The
allowable mean offset is the offset produced by mean or average environmental forces.
Maximum allowable offset includes the mean offset and low-frequency vessel motions.
Generally, the allowable mean offset falls in a range of two to four percent of water
depth. The lower bound generally applies to deepwater and the larger range applies to
shallow water (less than 300 ft) operations. Maximum allowable offset for deepwater is
typically in the range of 8% to 12% of water depth. The lower bound generally applies to
deepwater and the upper bound applies to shallow water. Generally, when a rig exceeds
its specified maximum operating limit, the riser is disconnected from the BOPs to prevent
rig equipment damage. After the riser disconnect, much larger offsets are possible
before rig motions become a limiting factor.
When a new rig design is first constructed, a model test is generally performed in a wave
tank and/or a wind tunnel. Rig response to a full range of wave frequencies is measured
and a response amplitude operator (RAO) graph results. The RAO curve is often used to
compare the motion response expected for different rig designs.
E ve ry rig h a s a n O p e ra tin g M a n u a l w ith th e rig s o p e ra tin g lim its fo r rig m o tio n s a n d
offsets clearly identified. This manual should be consulted and used when determining
permitable vessel motions in different operating conditions. Table 1.4 is a summary of
typical vessel motion limits for several rig operations.

Typical Floating Rig Motion Limits

Operation Limiting Limiting Limited By
Criteria Value (a)
Mooring Seas 9-12 ft Anchor handling Vessel, safety
Drilling Roll or Pitch 5 degrees Motion on rig floor
Heave 12 ft Motion compensator
Tripping (b) Roll or Pitch 5 degrees Equipment handling
Heave 10 ft Tubular make-up
Tripping BOP Roll or Pitch 3 degrees Equipment handling
Heave 5 ft High loads, riser spider
Open water work Roll or Pitch 6 degrees Material handling, Safety
(running structural, etc.) Heave 10 ft Fatigue of running drillstring
Production Testing Roll or Pitch 6 degrees Production equipment limits
Heave 10 ft Height test tree above rig floor
Material Transfer Roll or Pitch 8 degrees Workboat motions, Safety
Heave 9-12 ft Crane loading

Note: (a) All motions are double amplitude, significant values

(b) May be dependent on type of drillstring handling equipment

Table 1.4 Typical Floating Rig Motion Limits

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1.4.1 MOTION COMPENSATION

Heave for a floating rig can be limiting criteria for operations in some areas, especially in
areas with large swells. Typically the riser slip joint telescoping length will limit maximum
heave. Most older floating rigs have slip joints and riser tensioner systems with
maximum 50 ft stroke. For routine conditions, riser pup joints are used to space-out the
riser slip joint to permit about equal downward travel (25 ft) and upward travel (25 ft). In
deeper water depths it is common to space out the riser to permit a bit more upward
travel since vessel offset in deepwater can be significant. Figure 1.17 illustrates the gain
in riser length (slip joint scope) as a result of offset in various water depths. Newer fifth
generation rigs have longer stroke riser slip joints and riser tensioner systems (as much
as 65 ft stroke).

Figure 1.17 Gain in Riser Length for Vessel Offset for Various Water Depths

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FLOATING DRILLING VESSELS

1.4.2 RISER TENSIONERS

The marine riser system forms an extension of the well bore from the BOPs to the
floating drilling vessel. The primary functions of the marine riser system is to:
Provide for fluid communication between the well and the drilling vessel.
Physically support methods of communication with the well and BOPs (choke line,
kill line, etc).
Guide tools into the well.
Serve as a running and retrieving string for the BOPs.

The riser tensioner system is a vital part of the marine riser system. The riser tensioners
apply vertical force to the top of the marine riser. The marine riser system is designed
a n d to p te n sio n se le cte d b a se d o n th e rise rs re sp o n se to th e e n viro n m e n ta l a n d
hydrostatic loads, as well as the requirement that it properly perform its functions.
Among the marine riser system functional constraints are the angles at both the lower
flex joint and the upper ball joint. Other constraints include ensuring stress levels in the
riser are below the allowable stresses. In addition to stresses resulting from some
functional constraints, stresses in the riser are also caused by dynamic loads, loads from
hydrostatic pressures (burst and collapse) and stress loads required to prevent the riser
from buckling. Since the riser has seawater on. the outside and a heavier mud on the
inside, a minimum riser tension is required to prevent the riser from buckling which can
add bending stresses and lead to a functional failure.
Specialized computer programs are generally used to predict riser behavior under the
design conditions. The analysis includes calculating the required riser top tension,
maximum permissible rig offsets and maximum loads on riser components. Detailed
information on the design of the marine drilling riser system will be covered in Section 9.
The riser tensioner system applies a constant vertical force to the riser while the floating
vessel moves vertically and laterally in response to the environment (wind waves and
current). The riser tensioners generally use high-pressure air (typically to 2000 to 2400
psi) applied to a piston area to generate constant upward force on the riser. Oil is usually
maintained in the piston only for lubrication. By keeping the pressure constant, applied
tension to the riser is held constant as the rig moves with the environment. Figure 1.18
shows the basic components of a typical riser tensioner system.

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Air Pressure Vessel

Low Pressure Seal

Fixed Orifice

Accumulator

Air-Oil Reservoir
25-40 psi

High Pressure Seals

Cylinder

Turn Down Sheave

Low Pressure Air

High Pressure Air
Low Pressure Oil
High Pressure Oil

Figure 1.18 Typical Riser Tensioner System

Multiple (usually six to ten) hydraulic cylinders with wireline sheaves and wirerope are
generally used. The wire rope is reeved around the sheaves and one end of the wire
rope is attached to the outer barrel of the slip joint (the outer barrel is attached to the
riser, BOPs and seafloor). The hydraulic cylinders are powered by air pressure stored in
numerous pressure vessels. The tension on the wire rope and the riser is directly
proportional to the pressure of the stored air which is controlled at a specific value by the
Driller.
Most early floating rigs had limited riser tensioner capacity (generally less than 1000 kip)
which is generally adequate for shallow to moderate water depths and mud weights.
Most fourth and fifth generation floating rigs are designed for deeper water depths and
have higher tensioner capability, typically 2 to 3.5 million pounds. Some fifth-generation
rigs have as much as 4.8 million pounds of riser tensioning capacity.
The most often encountered riser tensioner is the Shaffer 80 kip, 50 ft travel unit. This
u n it is o fte n still re fe re n ce d a s a R u cke r te n sio n e r. T h e se te n sio n e rs a re o fte n m o u n te d
in pairs and riser tensioner capacity of rigs is often a multiple of 80 kip. Other companies
manufacture 80 kip, 50 ft travel tensioners. Larger tensioner units are often encountered
on later generation rigs that have a capacity of 160 kip or 250 kip each. A few rigs have
100 kip, 125 kip and various other rated tensioners with travels of 50 to 55 ft. A few early
generation floating rigs have 60 kip tensioners with a 40 ft stroke. These companies
manufacture riser tensioners: Shaffer, Vetco, Western Gear, Brown Brothers, and
Maritime Hydraulics.

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Most riser tensioner systems include a method to limit the speed and/or distance they
will pull the riser in the event of a structural failure of a riser or a broken wirerope. For
rigs that are dynamically positioned, the riser tensioner system also includes a more
sophisticated method (know as a riser recoil system) to limit and manage riser tension
and travel when a DP system failure occurs resulting in an emergency disconnect of the
riser from the subsea BOPs.
In the late 1990s, a new type of riser tensioner system illustrated in Figure 1.19 was
introduced and is included on several fifth generation rigs. These tensioners are called
In -lin e te n sio n e rs a n d w e re d e ve lo p e d fo r in cre a se d rise r te n sio n s a sso cia te d w ith
ultra-deepwater. The system operates essentially the same as conventional riser
tensioners except the hydraulic cylinders are attached directly to the riser tension rig and
each tensioner is rated to 800 kip.

"Trip Saver" skid-back beam

Rig Floor

Padeye
Diverter
Ball & Socket
Ball Joint To APV &
Oil Accumulators

Six 40-65'
Cylinders
Slip 800 kip each
Joint

Tensioner
Power Line
3000 psi

Load Ring with or

or w/o bearings
Padeye
Split Ring
Ball & Socket

Choke, Kill, Boost

or Hydraulic Power line

Figure 1.19 - Hydralift N-Line Drilling Riser Tensioner

System

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By the end of 2001, six ultradeep rigs have this type of riser tensioner system installed
and at least two more planned rig upgrades will include this new type riser tensioner
syste m . T h e p rim a ry a d va n ta g e o f In -lin e rise r te n sio n e r syste m s o ve r tra d itio n a l
wireline systems include: lower initial cost, lower maintenance cost and lower weight
(located lower on the rig).
An o th e r a d va n ta g e o f th e N -lin e rise r te n sio n syste m is th e T rip S a ve r o p tio n . W ith
this option, the riser tensioner cylinders are mounted under the rig floor on sliding
beams. This makes it possible to slide a deployed riser and BOP from under the well
center to an alternate site in the moonpool. This permits performing work at the well
center (such as running subsea trees) without retrieving the riser and BOPs.
Many riser tensioners often have common piping to an opposite tensioner. When one
tensioner is out of service for maintenance, often an opposite tensioner will also be out
of service. This is one reason riser designs often assume only ~ 80% of the riser
tensioner rated pull be relied on for riser tension. The riser tensioner air system is
usually hard-piped from stainless materials and requires very special welding and
cleaning procedures if the system is modified.
It is important that a rig have adequate air compressors, air pressure vessel (APV)
volume and emergency/standby capacity.
Almost all rigs have some guideline tensioners. Typically these are just smaller versions
of the riser tensioner units with 16 kip tension and 40 ft strokes. Some early generation
floating rigs have 14 kip 30 ft stroke guideline tensioners and several 22 kip 40 ft stroke
guideline tensioners have been manufactured. These units are often used for BOP pod
recovery umbilicals as well.

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1.4.2 RISER SLIP JOINTS

A floating rig moves on the ocean surface as a result of environmental loading and the
well, subsea wellhead and drilling riser are attached to the ocean floor. To compensate
for the vertical motion between the top of the riser and a floating rig, a riser slip joint is
u se d . T h e rise r slip jo in t te le sco p e s to p e rm it th is ve rtica l m o tio n . A d d itio n a lly th e slip
joint has a low-pressure seal to permit mud in the riser to return to the rig and the
surface mud system.
Figure 1.20 is a drawing of a typical riser slip joint. The outer barrel is attached to the
riser, the inner barrel is attached to and moves with the rig. The riser tensioners are
attached to the outer barrel only, and riser tension should not be transmitted to the inner
slip joint barrel. For dynamically positioned rigs, the riser tensioner rig has the capability
to rotate when rig heading changes are made.
Rig Floor

Diverter Packer
Diverter Housing Diverter Insert

Flowline to Riser Tensioner System

and Diverter

Upper Ball Joint

Inner Slip Joint

Barrel Packers

Load Ring

Outer Barrel

Gooseneck

Not To Scale

Flexiable Pipe

Riser Coupling

Marine
Riser Choke, Kill, Boost or
Hydraulic Power Line

Figure 1.20 Typical Riser Slip Joint Configuration

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The seal between the inner and outer slip joint barrel is usually a packing element, which
provides a low-pressure seal. The packing element is a rubber bladder (similar in
principal to a tire inner tube), and internal air pressure activates the seal between the
inner and outer barrel. On some rigs, the air pressure to the packer can be regulated at
th e D rille rs co n so le to p e rm it in cre a sin g th e p a cke r p re ssu re if a le a k o ccu rs d u rin g a
riser flow situation. Many rigs use the rig air supply (80 to 100 psi) to charge the packer
which can limit increasing the packer pressure to match well pressure if it exceeds the
rig air pressure limitation. Some rigs have switched from low-pressure rig air to a high-
pressure air source and use a regulator to adjust the pressure in the packer. This
permits using higher pressure in the slip joint packer. Most slip joints have two packing
elements for redundancy. Often the upper packer is actually two pieces and can be
changed-out with the slip-joint in service. Usually the lower slip joint packer is a single
piece unit and cannot be replaced while the slip joint is in service. Some rigs have one
slip joint packer operated by air and the second packer hydraulically operated for
redundancy. Slip joints on older rigs typically provide for 50 ft of total travel, however,
later generation floating rigs have longer slip joints.
On some early ship-shape rigs, the rig floor is only 40-50 ft above sealevel. On these
rigs, the riser tension ring can be under sealevel, and short p ig ta ils o f w ire ro p e a re
used to place a connection in the riser tensioner wireropes above sealevel (where divers
will not be required to slip and cut the wireropes). If the top of the outer barrel is below
sealevel, it is also possible to reduce the slip joint packer pressure and allow seawater to
flood into the riser very fast. This could be an asset if severe lost returns were
experienced.
Each drilling contractor has their own philosophy on cutting and slipping the wirerope
used with conventional tensioner systems. Some contractors keep up with the ton-miles
service of the wire rope and slip and cut wirerope at specified intervals. Large
semisubmersible rigs in mild environments often have a very limited heave and most
contractors will not have a formal cut-and-slip wire rope policy for riser tensioners.
At the top of the inner barrel and just under the diverter housing and flowline, a flex joint
or ball joint permits the rig to roll and pitch. On some rigs a second riser flex joint is
located just under the slip joint to provide for additional rig roll and pitch.
Located below the riser tensioner ring are the termination connections for the choke, kill,
hydraulic power line and riser boost line. Steel armored flexible lines are typically used
to accommodate the motion of the upper flex joint and the telescoping joint. More
information on flexible lines can be found in Section 10.
More information on slip joints including operational information, inspection guidelines
and associated equipment can be found in Section 9.

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1.4.3 DRILLING RISERS

Drilling risers are rated by the API for different tension limits. These API designations
are shown in Table 1.5.

Marine Risers
Coupling Tensile Load Rating
Class Rated load

A 0.50 million pounds

B 1.00 million pounds
C 1.25 million pounds
D 1.50 million pounds
E 2.00 million pounds
F 2.50 million pounds
G 3.00 million pounds
H 3.50 million pounds

Black: included in API Specification 16R

Blue: Projected
Table 1.5 API Designations for Riser Tension Limits

T h e e a rlie st rise r co n n e ctio n s w e re ju st A P I fla n g e s. L a te r, d o g -typ e rise r co n n e cto rs

(Vetco MR-6C, MR- 4 C , e tc) w e re d e ve lo p e d . T h e d o g typ e rise r co n n e cto rs u se d fo u r
or six dogs in the connection box that engaged profiles cut on the connector pin. These
co n n e cto rs a re g e n e ra lly ra te d to le ss th a n 2 .0 m illio n p o u n d s te n sile ca p a city. T h e d o g -
typ e co n n e ctio n s a re su sce p tib le to h ig h stre ss co n ce n tra tio n s a t th e d o g w in d o w
corners, and this area should receive special inspections.
As riser loading increased due to deepwater and harsh environment, flange type riser
connectors were developed in the 1980s. These special flange type connections are
rated to much higher tensile loads, have good fatigue characteristics, and are
lightweight.
Many rigs have riser spider running tools that permit a limited amount of motion between
a rig and a riser while the riser is being run. The spider generally includes either
pressure operated shock absorbers or rubber elements.

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1.4.4 DRILLSTRING MOTION COMPENSATORS

The earliest floating rigs did not have drillstring motion compensators. These rigs used
bumper subs or shock subs in the drillstring to accommodate for vertical rig motion (as
compared to the well). The first drillstring motion compensators were introduced in the
late 1970s and were generally rated for 400 kips and had strokes of 15, 20 or 25 ft.
The drillstring compensator isolates the drillstring from environmentally induced vertical
rig motions. The first compensators were mounted between the traveling block and the
hook. A major advantage of the drillstring compensator was to minimize wear inside the
BOPs, marine riser and casing when drilling. While drilling with weight on the bit, the
drillstring does not move (in relative position with the well) with rig motions. The
compensator also permitted better control of weight on bit which is important when
directional drilling. A disadvantage is that a drillstring compensator mounted between the
block and the hook requires a substantial height which requires that the derrick be taller.
Also, rails in the derrick are generally installed to control swinging motion of the
compensator as a result of ship motion. The compensator can add over 40 kips weight
to the traveling assembly.

Figure 1.21 shows a 400 kip, 18

ft stroke Shaffer drillstring
compensator used on many
early floating rigs. This type
compensator is referred to as an
in -lin e co m p e n sa to r. T h is is
probably the most often
encountered motion
compensator found today on
floating rigs. Shaffer, Vetco,
Brown Brothers, Houston
Systems, Maritime Hydraulics
and Western Gear all
manufacture drill string
compensators.

The Shaffer drillstring compen-

sator has two hydraulic cylinders
with leaf chains used to provide
the linkage between the hook
and the traveling block. Very
early Shaffer motion
compensators only had one
pressure cylinder.

Figure 1.21 - Shaffer Drillstring

Motion Compensator

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The system operates very similarly to riser motion compensators with air pressure air
(up to 2400 psi) acting on a piston area. Usually oil is kept in the piston for lubrication
purposes. As the rig heaves upward, the compensator cylinders are compressed and the
hook moves downward (relative to the drill floor) and the hook stays at a constant level
with the earth (well). The cylinder pistons compress the air through the hose into the
APVs to maintain the preset tension level. As the rig heaves downward, air from the APV
expands into the compensator cylinders and the hook move upward in relationship to the
rig floor. Operation of a drillstring motion compensator is shown in Figure 1.22. During
operation, the compensator works at approximately midstroke and the only movement
relative to the rig is the drillstring, hook and cylinder rod. The traveling block, hoses and
main frame remain motionless relative to the drilling vessel. The Driller can increase,
decrease or maintain drill bit weight by controlling the pressure applied to the
compensator.

Figure 1.22 - Operation of a Drillstring Motion Compensator

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Adjusting the air pressure sets the compensator tension. The air pressure is increased
by transferring air from the standby APV to the power APV and is decreased by bleeding
air. The weight on the drill bit equals the drill string weight minus the compensator weight
(traveling block and compensator main frame weight). The crown block weight indicator
determines the drillstring weight.
As an example, if a drillstring has a 200 kip weight and the desired WOB is 25 kip, then
the hookload gauge should be set to the force required as 200 minus traveling block
weight minus compensator main frame weight minus weight on bit. For example a 15 kip
traveling block, a 35 kip main frame weight and a 25 kip WOB, the hookload gauge
should read 125 kip (200-15-35-25).
Most motion compensators ca n b e lo cke d to p re ve n t th e co m p e n sa to r fro m o p e ra tin g .
W h e n a n in -lin e co m p e n sa to r is in th e lo cke d p o sitio n , th e te n sile lo a d o f th e
compensator will increase substantially. For example, when locked, the 400 kip Shaffer
motion compensator has a one million pound hookload capacity but there will be no
motion compensation. Typically leaf chains are used instead of wire rope on the
compensator pistons. The adjustment and maintenance of the chains are very important.
Inspection and wear checks of the compensator chains should be made when rigs
receive the initial pre-work inspection and on a monthly schedule.
The compensator shown in Figure 1.22 is a p a ssive co m p e n sa to r in th a t it m a in ta in s a
constant weight on the bit as set by the Driller. When a bit or other suspended string is
off bottom (no weight on the bit), the string moves with the rig. In other words, a passive
compensator will not react to vessel motion if the load is freely suspended from the
floating rig. For later generation rigs, this type motion compensator has been increased
in working loads to 500, 600, 800 and 1000 kips. Most passive drillstring motion
compensators can control WOB to about 8-12 % of total load. For example, for a drill
string with a weight of 450,000 lbs., the hookload may vary as much as 50,000 lbs.
before the compensator will function correctly. Passive compensators are also very
sluggish when in use with light string weights (or mass loads)(2).
In the mid 1980s, significant changes in drillstring motion compensator designs
occurred. Several contractors introduced the top mounted drillstring compensator at this
time. Advantages of a top-mounted compensator are less hookload fluctuation. The
system works essentially like a conventional in-line compensator except the cylinders
are located between the crown block and the traveling block or at the very top of the
derrick (Figure 1.23). This eliminates the need for heavy duty guide rails in the derrick.
These units typically have 25 ft stroke and are rated (compensating) to 600 or 1000 kips.

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Figure 1.23 - Crown Mounted Drillstring Compensator

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Figure 1.24 - Operation of A Crown Mounted Drillstring Compensator

Difficulty landing subsea trees in extreme environments such as the North Sea led to the
development of active h e a ve co m p e n sa to rs in th e m id 1 9 9 0 s. T h e te rm a ctive h e a ve
refers to the addition of sensors to monitor rig heave and compensator position which
are then input to a computer. The computer then controls an active hydraulic cylinder
installed in a passive compensator system. With active heave compensation, the bit will
stay at the same position in reference to the bottom of the well. While landing a subsea
tree, the tree will stay in the same position relative to the seabed (and subsea wellhead)
througho u t a ll o f th e flo a tin g d rillin g rig s h e a ve m o tio n . M o st rig s th a t o p e ra te in e xtre m e
environments have an active heave compensating system.
The heave motion and compensator position sensors provide increased control of
drillstring motions by actively applying force to the passive compensator system.
Active heave compensation can be installed on both conventional in-line and top-
mounted passive heave compensator systems. Many rigs have conventional passive
motion compensators that have been retrofitted with active heave systems. An active
heave compensator retro-fitte d to a rig s e xistin g e q u ip m e n t ca n h a ve a co st o f a b o u t
$1.0M. Most rigs have active heave compensator systems that permit active heave
compensation across the full spectrum of operations. However, a few early rigs and
systems may have limitations (software) that will only be able to operate active heave
compensation in BOP and completion landing.

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In the late 1990s, an active heave compensating drawworks was developed to

counterbalance vessel heave(3) (Figure 1.25). Spooling wire rope off or back onto the
drawworks drum counteracts vertical rig movement. For instance, if the rig heaves
upward, wire rope is reeled off the drawworks drum to compensate.

Figure 1.25 Typical Schematic for a Drawworks Compensator

This system has several advantages over conventional traveling block and crown
mounted compensators:
1. The unit will electronically sense the relative motion of the vessel and eliminate the
need for changes in weight or pressure to compensate for rig vertical movement.
2. The full-rated load of the traveling equipment can be utilized during compensation
because the system is an integral part of the drawworks.
3. The system eliminates a large mass located high in the derrick, and thus rig stability
is increased.
4. A shorter derrick can be utilized.
These advantages are important in deepwater when loads (risers, long casing strings,
etc.) approach the weight limits of the traveling equipment.
This system uses a computer to process input from multiple sensors located on the
travel block, dead-line and on the rig structure. Programmable logic controllers then
activate AC motors that provide power to the drawworks. As much as 7000 continuous
HP is required for the drawworks. Several of these active heave compensating
drawworks are installed on fifth generation floating rigs.

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FLOATING DRILLING VESSELS

Most drillstring compensator manufacturers have developed procedures to permit use of

a drillstring compensator during logging operations. These systems provide for reduced
motion of the logging tools in relationship with the well.

Wireline operations on a floating rig may also be impacted by the rig heave and may
require the use of the motion compensator. Figure 1.26 shows how the motion
compensator can be configured to operate during wireline operations by attaching a
cable from the block (motion compensator) to the outer barrel of the slip joint (outer
barrel is fixed to the riser not compensated). Since the wireline is attached at two
points, the deck of the rig and the wellbore, the motion compensator cable should be
attached to the outer barrel of the slip joint and run through a sheave above the wireline
sheave and back to the deck. This is necessary to maintain a one-to-one travel between
the wireline and the compensator. Therefore the distance between the hook and outer
barrel of the slip joint does not change was the rig heaves up and down.

Figure 1.26 Typical Rig-up for Wireline with Motion Compensator

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1.4.5 FLEX JOINTS

The riser slip joint permits the vertical motions and offset of a floating rig. Flex joints
allow for the rig to roll, pitch and offset and are located at the top and the bottom of the
riser. As noted, almost all floating rigs have a ball joint located between the diverter and
the riser slip joint. This ball joint permits the rig to move in relationship to the top of the
riser. Most upper ball joints have a 10o maximum angle.
Located just above the subsurface BOPs, all floating rigs have a device to permit
misalignment between the BOP stack and the marine riser. This misalignment is caused
when the rig is offset from the well. Most flex joints can accommodate up to 10 o (in each
direction) misalignment.
Early floating rigs used ball joints just above the BOP stack. Almost all of these have
been replaced by flexjoints. The early ball joints were pressure balanced to minimize
frictional resistance to bending. Most used hydraulic oil pressurized from the rig. When
lower ball joints were used, appreciable wear often occurred as the angle change
between the riser and the BOPs occurred very quickly and the drillstring often was in
contact with the ball joint, riser and BOP inside diameter.
There are many different types
of flexjoints (Figure 1.27). Some
flex joints (Vetco Uniflex, Oil
States FlexJoint) permit a less
rapid angle change between the
riser and the BOPs. Some
flexjoints can be ordered
equipped to permit installation of
a wear bushing. As flexjoints
bend, they develop a reactive
bending moment that also helps
create a longer smoother bend
that will help mitigate drillstring
wear in the riser and BOPs.
The manufacturers of flex joints
build units with different
pressure and tensile ratings for
different water depths and
operating conditions.
To accommodate the flexjoint
bending, the choke, kill and
power fluid lines must flex. Early Figure 1.27, Typical Drilling Riser Flexjoint
generation rigs used spiral steel
flex loops (either horizontal or vertical loops) and almost all rigs today use flexible hoses
to accommodate this motion. Information on flexible hoses is found in Section 10.

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1.5 STORAGE AND EQUIPMENT HANDLING

Storage and equipment handling on floating rigs can vary widely. While much of the
material handling equipment used on floating rigs is the same as that used on fixed
structure rigs, (land, jack-up and platform rigs), there are many differences.
Floating rigs are arranged with a wide range of material handling and storage
capabilities. Ideally, the rig and the requirements of the drilling program should be
matched. For example, large storage volumes on a rig would have increased importance
while drilling at a remote location. In the GOM, workboats and the environment permit
rapid and frequent supply of drilling materials, and for a rig with large storage capacity,
material handling and storage would have less importance. The need for and limitations
of material handling equipment is an important consideration when drilling efficiency is
important. The material handling equipment on a rig would typically include cranes, pipe-
racking systems, bulk handling systems, BOP handling equipment and riser handling
equipment.
For floating rigs, storage limitations can be a primary factor. Most floating rig operations
are far offshore, and storage and handling of drillstrings, risers, fuel, casing and bulk
products are usually limited in some areas of the rig.

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1.5.1 BULK HANDLING SYSTEMS

All modern floating rigs have a pneumatic bulk storage system, which is used for
cement, barite and often, benonite. Early floating rigs use about 40 psi air pressure to
move bulk materials through steel lines to the point of delivery, i.e., cement mixing or
mud mixing areas. Later floating rigs use higher air pressure systems (about 60 psi).
Similar to rigs, newer workboats have 60 psi bulk air systems. Most rigs use a dedicated
air supply system rather than rig air system. It is important that the bulk air supply have
adequate air dryers to remove moisture from the air used to move bulk materials.
Storage of bulk materials is in pressurized tanks often called P-tanks. These tanks vary
in size from about 500 cubic ft to over 3000 cubic ft. Workboats have similar P-tanks
and air systems installed for transfer of bulk materials from the supply base (on land)
and the rig. Anytime that any type of solid particle is moved through a line, static charges
will build up. For this reason only steel piping is used, and ground wires around rubber
hose sections should be installed.
Most second-generation rigs have roughly 8,000 to 10,000 cubic ft of cement and bulk
mud material storage capacity. Later generation rigs have more storage capacity, as
much as 20,000 to 25,000 cubic ft. It is generally best if bulk storage tanks are located
near their end use; e.g., cement bulk storage tanks should be near the cementing unit.
Shipping bulk materials over long distances or to much higher elevations has been
troublesome for many floating rig operations in the past.
Some rigs store bulk barite and cement in separate storage systems. With this
arrangement, it is not possible to ship barite to the cement mixing area. As a
contingency, every rig should have the ability to ship barite to the cement unit if well
control operations require mixing and pumping a barite plug.
A primary concern with bulk systems is contamination. For example, visually it is very
difficult to tell the difference between some types of cement and barite. It is very easy to
become confused and mix cement and barite or contaminate barite with bentonite, etc. It
is recommended a dedicated offloading hose be used for each bulk material stored on
the rig.
Periodically, it is necessary to clean P-tanks, which requires placing personnel in the
tank. This procedure should be very closely supervised to ensure adequate breathing air
is available in the tank, and that all applicable safety precautions are taken, i.e., limited
working time due to heat, breathing apparatus, etc.

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1.5.2 PIPE HANDLING

Most second generation semisubmersible rigs and some drillships handle drillpipe very
much like jackup, platform and land rigs. Some of these rigs have Iron Roughnecks and
spinning tongs. Drillpipe is racked into finger boards in the derrick by a derrickman.
The derricks on these floating rigs are designed to accommodate dynamic loads
resulting from a drillstring stood-back (since the derrick moves with rig motions).
Since floating rigs can have substantial rig motions, manual pipe handling is often
replaced with more sophisticated racking systems. Safety and reduction in drillstring
handling time have driven the industry to the more advanced drillstring handling
systems.
Some second-generation semisubmersibles and drillships have automated pipe-racking
systems. Examples of early automated vertical pipe racking systems are the BJ type V,
Maritime Hydraulics 3-arm systems, and the Varco PHM systems. A derrickman
operates an automated racking system, which lifts and moves a stand of drillpipe into a
fin g e rb o a rd . O n so m e rig s a sta b b in g a rm is u se d to h e lp limit motions of the drillpipe
while it is being moved around in the derrick.
Most early drillships used horizontal pipe racker systems. Since early drillships had
substantial rig motions, dynamic loading of a drillstring standing back in the derrick is
a concern. The horizontal pipe racker eliminated the need to stand a drillstring in
the derrick.
Horizontal pipe rackers store drillpipe in stands horizontally (Figure 1.28). The drillstring
storage racks are located just outside the derrick. A stand of drill pipe is moved to the rig
flo o r o n a ska te . W h e n th e to o l jo in t is n e a r th e ro ta ry, th e to p o f th e sta n d is p icke d u p
to the vertical position inside the derrick. The stand is then made-up and added to the
d rill p ip e in th e h o le . U su a lly a sta b b in g a rm is u se d to h o ld th e b o tto m o f th e sta n d
when it is stabbed into the drillstring in the rotary. When pulling out of the hole, the
process is reversed and the drill pipe is stored in stands (horizontally) in the pipe racker
on trips. Usually only very limited amounts of special tools are stood-back in the derrick
on the early drillships. Horizontal drillstring handling systems are susceptible to
mechanical or hydraulic failures and manual handling of a drillstring cannot be used
if the racker is broken.

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Figure 1.28 - Horizontal Drillpipe Racking System used on Drillship

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In the 1980s, Varco

introduced a second
generation of drillstring
handling systems. Designated
the PRS system, several
types of vertical pipe rackers
were introduced that all
basically include a rotating
column, two racking arms and
AC electric motors (Figure
1.29). The AC motors move
the drillpipe toward and away
from the rotary to the stand-
back area. The rackers are
semi-automatic and remote
controlled.

The more advanced Varco

pipe handling systems can
build stands of drillpipe offline
and then rack the stand into a
fingerboard. A winch hoist
assembly can lift stands of the
drillstring. Many units can
handle triples or fourable of
drillpipe and drill collars and
can also handle doubles or
triples of casing. Varco
manufactures other types of
racking systems including the
S ta r ra cke r, w h ich is u se d
on many land rigs. This unit
uses a radial design for the
fingerboard. Many fifth
generation floating rigs use
two drillstring pipe racking
systems. And many fifth
Figure 1.29 - Vertical Drillpipe Racking Systems generation shipshape rigs
have both a horizontal and a
vertical pipe racking system. For example the Jack Ryan drillship has both a horizontal
and a vertical pipe racking system.
Several companies manufacture automated mousehole make-up systems. With these
systems a hydraulic make-up/break-up drillstring and a hoist system can change the
length of the mousehole. With these systems, it is possible to make-up or break-out
drillstrings concurrent with routine drilling operations.
Varco manufactures several automated drillstring pipe handling systems used for
drillstring lay-down and pick-up of their storage racks.

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1.5.3 CRANES

There are two basic types of cranes used on floating rigs, mechanical and hydraulic
cranes. Mechanical cranes can have very fast lift times but require substantial operator
skill and training. Hydraulic cranes typically have slower lift speeds but are simpler to
operate. Most cranes are powered by a dedicated diesel engine, but electrically powered
cranes are sometimes found on floating rigs.
Since floating rigs move with the environment, cranes on these rigs must be designed to
accommodate dynamic loading. The dynamic loads exerted on a crane may be 2-3
times the static loads of the material being lifted.
Most second-generation floating rigs have cranes rated for a maximum of about 40 to 60
to n s w ith 1 0 0 to 1 2 0 ft b o o m s. T h e cra n e s ra te d ca p a city is b a se d o n th e sm a lle st liftin g
ra d iu s. T h e cra n e s ca p a city a t th e m a xim u m b o o m ra d iu s is a s lo w a s 5 -10 tons.
Typically, the heaviest loads a floating rig will handle are the wireline logging unit or a
double BOP ram body. The long riser joints on many fifth generation floating rigs can
approach 50,000-lbs air weight.
S e ve ra l fifth g e n e ra tio n rig s (D isco ve re r E n te rp rise ) h a ve cra n e s w ith kn u ckle b o o m s
(Figure 1.30). The boom on these cranes are segmented and this permits more control
on the crane and its load when high rig motions are being experienced.

Figure 1.30 - Knuckle Boom Crane

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Most drilling contractors will limit crane operations to certain environmental operating
conditions. The sea state is the primary concern for cranes, but crane operations are
also limited by wind speed. It is a common requirement that cranes cannot be operated
when wind speed exceeds about 40 to 45 knots. This can be an important consideration
when developing plans for rig operations prior to tropical storms.
Every crane must be equipped with a load-rating chart that defines the maximum load
carrying capacity. For floating rigs, capacity in dynamic loading conditions are also
specified. Limits on wind velocity, rig motions, sea states, etc., are included on each
crane load carrying capacity.
Personnel bypassing safety systems cause most problems with rig cranes. It is common
for one rig crew to disable a safety system and then fail to reinstate it. The next crew will
assume the safety system is functional and rely on the safety system to prevent an
overload. If all safety systems are not operational, serious accidents can occur.
Crane booms are designed for vertical lifts only. Marginal side loads on a crane boom
will cause a failure.

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1.5.4 BLOWOUT PREVENTER HANDLING SYSTEMS

Almost all floating rigs are equipped with a 18-3/4 in. BOP 15 ksi systems today. A BOP
stack can have an air weight of as much as 500 kip. Generally, the lower marine riser
package will weigh 125-150 kip with the balance of the stack weight included in the ram
preventer package.
Most second-generation rigs stored the BOPs at the surface in two pieces. The LMRP
is stored in one location and the BOP rams in a second location. This permits handling
the BOP with a short rig floor substructure. Typically, overhead trolley cranes were used
to move the BOP sections from their storage stumps to the moonpool. Since the BOP
sections are transported with an overhead crane, it is free to swing with vessel motions.
Rig motions often limit BOP running operations when overhead cranes are used to
transport BOP stacks. Once the two BOP sections are mated in the moonpool, they
must be pressure tested to ensure pressure integrity of the system.
Some second and many most third generation rigs have taller substructures and can
move the entire BOP stack as a unit with overhead cranes. This eliminates the need to
test the BOP in the moonpool during critical path rig operations.
Many third and later generation rigs have BOP transporter systems. The BOP
transporter is a hydraulically operated carrier, which also serves as the BOP stump
when the BOPs are not being used. A transporter typically handles the entire BOP stack
as a unit. Since the transporter holds the BOPs, vessel motions do not affect the ability
of the stack to be run and retrieved. Many BOP transporter assemblies have guide rails
to permit control of the BOP while it passes through the splash zone. A disadvantage of
transporter systems is that they are heavy and typically require a large moonpool. Since
the BOP stack is handled in the moonpool (or even partially below the moonpool), a
relatively short derrick substructure can offset the added weight of the transporter
system.
BOP equipment will be covered in detail in Section 9.

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1.6 RIG CAPABILITY OVERVIEW

T o d a ys flo a tin g rig fle e t h a s a la rg e m ix o f ca p a b ilitie s. W h ile m a n y w e lls ca n b e d rille d
with about any floating rig, some wells require special characteristics such as a large
hookload, high current capability or a high riser tension. Efficiency of a rig is important
but a low rig rate can make a low efficiency rig competitive with a high efficiency rig
(assuming time is not an issue).
P ro p e r p la n n in g a n d a sse ssm e n t o f a flo a tin g rig s ca p a b ility are important to an efficient
operation. Using a rig for a well just because of availability or a low mobilization cost
may result in very inefficient or even unsafe operations. Once a rig is on location and
drilling, it can be very costly if the rig capabilities are not correct for the job.
A fte r e n su rin g th a t a rig s sta tio n ke e p in g , B O P a n d rise r, w e ll co n tro l, p u m p in g a n d
hoisting systems will meet all of the requirements required to drill a well, other factors
should be considered. In many countries, special regulatory restrictions exist. Typically,
o n ly a fe w rig s in th e w o rld s flo a tin g rig fle e t w ill m e e t th e se re strictio n s. T h e co st to
upgrade a rig to meet the restrictions may be prohibitive. Countries with special
regulatory requirements are Norway, the United Kingdom and Canada. The special
restrictions often include special living quarter restrictions, mooring system emergency
disconnect systems, special back-up BOP control systems, etc.
B e fo re a rig is co n tra cte d , th e co n d itio n o f th e rig s equipment and its seaworthiness
must be established. The history of the rig design and ensuring the rig is seaworthy must
be considered. A rig is seldom as it is advertised or represented on a rig equipment
inventory list. The capability and condition of a rig are usually highly contractor
dependent. Some contractors do an excellent job of maintaining their rig and keeping
equipment at safe and efficient operation. Other contractors have very poor
maintenance, have not documented inspections and condition of equipment, and have
poor marine safety records. Some rig designs have a history of structural problems,
which require very careful inspection, analysis and maintenance by the contractor.

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1.7 OIMS REQUIREMENTS, RIG SELECTION,

INSPECTION
The ExxonMobil O IM S m a n u a l re q u ire s a re vie w a n d co n sid e ra tio n o f a co n tra cto rs
capability and past performance in equipment, personnel, safety, health, and
environmental areas before critical service contracts are awarded. Certain specifications
and requirements are included in bid proposals.
This requirement impacts many rig systems, including personnel and inspections during
rig acceptance. Rig acceptance testing and inspection usually occur before a rig is
contracted and prior to a rig going on payroll. The Field Drilling Manager has approval
authority for most rig selection, rig acceptance testing and checklist contents. The Field
Drilling Manager can approve exceptions to most rig acceptance OIMS requirements.
Since every rig and well program is unique, rig inspection and acceptance must be
custom tailored to the situation. Generic rig acceptance lists or procedures are
seldom used.
Floating rigs are a MODU (mobile offshore drilling unit) and have several OIMS special
requirements. For example, when each new rig is contracted, the drill pipe, drill collars
and other drillstring components must be inspected. OIMS also specifies the rotating
hours between inspections for drill string components. A pre-contract inspection and
acceptance testing plan or checklist is an OIMS requirement.
Other requirements of the final rig selection process for floating rigs are a stationkeeping
analysis and a structural assessment. Major structural failures have occurred on floating
rigs, and a failure can have a very high consequence. The structural assessment is
performed to assess adequacy of structural inspections performed for a classification
society and to determine if any additional structural inspection is needed. Typically a
structural assessment consists of visual inspections, and some critical structural
members receive non-destructive inspection. This requires paint removal. If problems
are found, the scope of the inspection is increased to other critical structural members.
After non-destructive inspection, areas where paint was removed must be re-painted.
Another OIMS initial acceptance testing practice is a Marine Safety Survey. The purpose
of this survey is to verify presence and operability of critical marine equipment and that
critical operations procedures are in place. Some of the items reviewed during a Marine
Safety Survey include fire systems tests, drills and station bills, and completeness and
testing of lifesaving equipment. Mooring equipment also requires special acceptance
and inspections procedures as a part of rig acceptance.
The ExxonMobil Drilling OIMS manual should be consulted for complete detail of floating
rig acceptance and selection criteria.
A ll d rillin g ve sse ls a re cla ssifie d b y a cla ssifica tio n so cie ty. T h e so cie ty p ro vid e s a
commercial service to the vessel owner in setting minimum design, equipment and
inspection standards. Each vessel must continue to satisfy these standards throughout
its life. The intent of classification is to assure the vessel owner and insurance agent that
the vessel is safe and seaworthy. Classification societies are commercial concerns that
are hired by the vessel owner.

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Classification societies generally require that a drilling vessel undergo a limited structural
inspection at a given time interval, i.e., every two years, and every four years. The
inspection society records will usually serve at least as a partial basis for determining the
structural integrity and history of the rig.
Floating rig owners use one of these classification societies (listed in order of commonly
encountered floating rigs): American Bureau of Shipping (ABS), Det Norske Veritas
(D n V ), L lo yd s R e g istry o f S h ip p in g , a n d B u re a u V e rita s.
Maritime regulatory bodies are affiliated with a national government. They require that a
floating vessel registered in that country or drilling offshore of that country meets certain
minimum standards with regard to safety equipment, marine equipment and crew.
Maritime regulatory bodies include the United States Coast Guard, the Norwegian
Maritime Directorate, and the United Kingdom Department of Transport. Floating rigs
and offshore support vessels generally receive periodic inspections by the regulatory in
order to keep their agency certificates current.
Some governments also have a regulatory agency, which sets standards and
procedures for rigs, drilling operations, personnel training and safety. Examples include
the United States Minerals Management Service, the Norwegian Petroleum Directorate
(NPD), and the Canada Oil, Gas and Lands Administration (COGLA). These agencies
often set rules covering drilling equipment, pressure testing of equipment, crew training,
safety systems (including life saving equipment), drills and many other areas.

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1.8 MARINE SUPPORT VESSELS

Offshore drilling and operations began in the late 1940s and early 1950s. Many of the
early ships used for supplying offshore drilling rigs were modified WW II PT boats and
fishing vessels. As drilling moved further offshore, more sophisticated and specially built
ships were used to support those operations.
The primary function required for marine support vessels is to transport equipment,
supplies, people, and food. Another requirement is to run and retrieve mooring systems
and to tow floating rigs from location to location.
Several different types of offshore marine operation support vessels are used by the
industry. In areas of the world with moderate environments and developed infrastructure,
specific purpose rig support vessels are often used. General-purpose vessels are used
to transport equipment and supplies. Other vessels are used primarily to transport
personnel or small equipment when rapid delivery is needed. Other ships are used to
handle mooring equipment and/or tow rigs between well locations.
In areas with more extreme environments and/or less developed infrastructure, many of
these ship functions are combined into a single ship. That ship is usually fairly large, can
transport some personnel, and is equipped to handle mooring systems and can even
tow a floating rig.
These ships are commonly known as workboats (Figure 1.31). Workboats typically are
of steel construction and are 180-240 ft in length. With a displacement of roughly 2000-
ton, these ships routinely carry fuel, water, bulk products, deck cargo and other supplies
to offshore rigs. Typically general service workboats have 3000 to 4000 Hp installed and
can average about 6-8 knots when loaded. These workboats are well suited to work in
moderate environmental conditions. For areas like the Gulf of Mexico, environmental
conditions permit rig supply on a frequent basis (every 2-5 days). Most general-
purpose workboats have a fairly small capacity for transporting personnel.

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Figure 1.31 - General Purpose GOM Workboat

In moderate environment areas, another type of support vessel is often used to transport
personnel and limited amounts of deck cargo. Sometimes called crewboats or
speedboats, these ships are typically constructed of aluminum and can travel at over 10
knots. While they can carry a substantial number of people, they are generally limited to
a fairly small deck cargo weight and do not carry bulk materials. Speedboats used in the
Gulf of Mexico typically are 120-160 ft in length and have roughly 6000 Hp installed and
three or four propellers. In recent years, larger aluminum speedboats have been
constructed which are very fast and can also carry more deck cargo.
In areas of the world with more extreme environmental conditions, such frequent supply
of a rig cannot be made. In these areas larger ships are used for rig supply. Some rig
operations drilled in remote areas also use larger workboats due to the cost to provide
multi-function workboats. Since the ship is larger, many of these ships also have the
capability to handle anchors and mooring operations.
Many later offshore support vessels have a thruster installed into the bow to assist
stationkeeping next to a rig while it is offloading. The more advanced support vessels
have azimuthing main screws, large bow thrusters and a dynamically positioning system.

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Anchor handling vessels and tugs are used to tow but only anchor-handling vessels are
used to install and retrieve mooring systems and equipment. An important characteristic
o f th e se tw o typ e s o f sh ip s a re th e ir b o lla rd p u ll. B o lla rd p u ll is th e m a xim u m
continuous pulling force that the workboat can exert when pulling against a stationary
object at zero forward speed. The bollard pull of a particular ship is a function of the
horsepower available to the propellers, the hull design and the environment, etc (Figure
1.32). The rated bollard of a ship is determined experimentally by the ship pulling against
a stationary object (anchor on the seafloor, pile, etc) in a calm wind and seastate and
measuring the line tension. Factors, which can reduce bollard pull, are vessel heading
re la tive to th e p u ll, re d u ce d e fficie n cy o f th e p o w e r p la n t w ith u se a n d e n viro n m e n ta l
condition. Heavy seastate and winds can have a large impact on the bollard pull of an
anchor handling vessel or a tug. A general rule-of-thumb is that a bollard pull of 25
pounds per horsepower can be expected of newer ships with well-maintained and
efficient power and propeller systems.

Bollard Pull of Anchor Handling Vessels

19000
Advertis ed AHV Bollard
Total Installed Horsepower

17000
25 lbs per ins talled Hp
15000

13000

11000

9000

7000

5000
50 75 100 125 150 175 200
Bollard pull - Long Ton

Figure 1.32 - Typical Bollard Pull vs. Installed Horsepower

Ships used for towing have on the stern deck two hydraulically o p e ra te d p in s. T h e p in s
provide directional control of a tow wire between the tow winch and the stern of the ship.
They, in effect, move the pivot point of the towline from the winch location (usually
forward of midship) to a point near the stern of the ship. This prevents the towline from
moving over either the port or starboard side of the ship, which can cause a stability
problem.

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The motion of an offshore support vessel can have important impacts on the efficiency
and safety of floating rig operations. Support vessel motions vary with boat size and the
hull design. Some hull shapes result in reduced ship motions. Generally, the larger the
ship, the better the motion response. Also, the deeper the draft of the hull, the better the
sh ip s m o tio n re sp o nse. The water depth at land-based dock facilities can often be a
limiting factor on the maximum draft of a support vessel, which can be used at the dock.
Similar to floating rigs, offshore support vessels have many regulatory bodies to ensure
vessel seaworthiness. The same classification societies, government regulatory bodies
that have regulations for floating drilling rigs generally also regulate offshore support
vessels. In addition, the International Maritime Organization (IMO) has developed certain
recommendations regarding international standards of maritime vessels. The IMO is an
international organization with members from participating countries and offers only
recommendations and has no enforcement authority.
Stability of an offshore support vessel is an important concern. Stability is a measure of
a sh ip s a b ility to re m a in a flo a t a n d u p rig h t w h e n a cte d u p o n b y e n viro n m e n ta l fo rce s (o r
when damaged and flooded). Generally a regulatory body such as the US Coast guard
will supervise stability tests and issue a stability letter. It is the responsibility of the ship's
ca p ta in to e n su re th a t th e sh ip s lo a d in g is in co m p lia n ce w ith th e a p p ro ve d sta b ility
letter.
Anchor Handling boats have many requirements on their winch, bollard pull and mooring
equipment-handling systems. These requirements are covered in Section 6.

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1.9 REFERENCES
1. S w o rn , A .W .: Q u a n tita tive R isk A n a lysis o f D isco n n e ct F a ilu re D u rin g D yn a m ica lly
P o sitio n e d D rillin g , R e p o rt 1 9 9 3 -221593, DeepStar Ia Project, Feb. 2, 1995.
2. Bennett, P.: A ctive H e a ve T h e B e n e fits to O p e ra tio n s a s S e e n in th e N o rth S e a ,
SPE 37956.
3. G a d d y, D .E .: U ltra d e e p D rillsh ip W ill R e a ct T o H e a ve W ith E le ctric -Compensating
D ra w w o rks, O il a n d G a s Jo u rn a l, Ju ly 2 1 , 1 9 9 7 .

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1.10 APPENDICIES
APPENDIX I - SEMISUBMERSIBLE RIGS

General
There are about 165 worldwide semisubmersible units available today (2000). From
about 1990 to 2000, the semisubmersible fleet has averaged about 160-165 units.
Generally, semis can be divided into five generations determined by rig design and year
of delivery. These groups can be sorted as follows (Table 1.6):

% World
Originally Built Fleet
1st Generation Before 1973 2
2nd Generation 1973 - 1981 46
3rd Generation 1982 - 1985 31
4th Generation 1986 1993 10
5th Generation 1993 - 2001 11

Table 1.6 - Available Semisubmersible Units

FIRST GENERATION RIGS (Before 1973)

These rigs were designed for water depths of 600 - 1000 ft. in calm waters such as the
GOM. Examples include the Sedco 135 rigs, early Odeco designs such as the Ocean
Prospector and the Pentagone 80 Series rigs. These rigs typically have variable loads
between 1500 and 2000 tons, have all chain mooring (2 3/4-in. chain) and 20 to 30 kip
anchors. These rigs were generally equipped with a two-stack system; however, many
have been updated to one-stack 18 3/4-in. systems. Most of these rigs have 1500 Hp
drawworks, two 1600 Hp mud pumps and no or limited automated pipe handling
systems. Riser tensioning capacity is typically less than 350 kips. By 2000, less than
five of these rigs were still in the offshore fleet.

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SECOND GENERATION RIGS (1973 - 1981)

Generally more seaworthy than their predecessors, the second generation rigs were a
result of the new building boom triggered by rising energy prices in the early 1970s.
These rigs were typically designed for water depths of 1000 to 1200 ft. and have variable
deck loads of approximately 2000 tons and 40-60 ft drilling draft. Examples of these rigs
are the Aker H-3, Sedco 700 Series and F&G pacesetter series. Most of these rigs were
originally equipped with 18 -in. 10 KSI BOP systems, and most handled the BOP in
two pieces. BOP systems typically included about 30-35 pilot lines and use power-open
(WD sensitive) only choke and kill valves. Most of these rigs have two C&K outlets and
pressure balanced ball joints. Larger rigs have 3000 Hp drawworks, and two 1600 Hp
mud pumps. Typically installed total horsepower is approximately 9,000 to10,000 Hp,
and most of these rigs have SCR power systems, with limited emergency (150-250 KW)
backup/automatic switchgear. These rigs are usually all chain (2 -in.) with 30 kip
anchors and combination chain/wire systems were introduced on some rigs. Most rigs
had automated pipe handling systems and iron roughneck. Riser tensioner systems
were typically about 300-500 kip capacity, and 400 kip motion compensators are
standard.

THIRD GENERATION RIGS (1982-1985)

These rigs were typically designed for deeper water depths and higher environmental
loads. These units were designed for water depths of 1500-3000 ft and have variable
loads of 2500 - 4000 tons. Examples of these rigs include the GVA-4000, Aker H3.2,
Bingo and Enhanced Pacesetter designs. Some of these rigs are self-propelled and
some have thrusters to assist mooring. Many of these rigs have 18-3/4 in. 10 KSI BOP
systems, while later units incorporated the newly introduced 15 KSI systems. Most BOP
systems included about 50 pilot line hose bundles and three choke and kill (C&K) valve
outlets, and the C&K valves are pilot opened and closed. Most of these rigs handle the
BOPs as a unit with a hydraulic lifting/moving system. Pressure balanced ball joints
were generally not used and were being replaced by flex joints. Flexible C&K lines were
used on some rigs (opposite the flex joint) replacing steel flex loops. Risers were still
"dog" type and riser tensioning capacity typically are about1000 kips. Motion
compensators are typically 400 kip units. Mooring systems were usually combination
chain/wire with 3 -in. wire and 3-in. chain and use permanent chain chasers (PCC)
rather than pendant and buoy systems. Some units were all chain systems with chain
size to 3 -in. High holding capacity anchors (Bruce, Stevpris) were common with
30-40 kip weight. Power distribution system are SCR with 250 -300 KW emergency
generators and automatic switch gear. Most rigs have two ballast pump rooms and
adequate ballast pumping systems. Drawworks were generally 3000 Hp with two 1600
Hp mud pumps. Using a dedicated three-riser line (boost line) to circulate the riser was
gaining popularity and being included on some rigs.

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FOURTH GENERATION (1986-1993)

These units compose about 10% of the current rig fleet consisting of about 165 rigs and
are designed to accommodate the demands of working under arctic, harsh environment,
or in deepwater. Water depth ratings to 5000 ft are common, and several full DP semis
were built. Typical designs include the GVA 4500, Aker H-4.2 and F&G trendsetter
designs. Variable loads typically range from 4000 to 6000 tons, and water draft typically
is about 80-90 ft. These units are primarily combination chain-wire rigs with about 40 kip
high holding capacity anchors, 3 to 3-in. K-4 chain; 3-in. wire rope. Some rigs have
thruster assist and or self-propelled and/or full DP. BOP systems are all 18-in. 15 KSI
with up to 65 pilot line hose bundles with some rigs using guidelineless systems and
MUX BOP controls. Flexible hose lines jumping the riser flex joint are standard and
flange-type riser connectors have replaced dog-type riser connectors on most rigs. Riser
tension capacity is typically 1.2 to 2.0M lbs, and 600 kip motion compensators are
common. These rigs generally have four ballast pump rooms and improved ballast
pumping capability. Most rigs have three mud pumps, riser boost lines, top drive
systems and larger derricks rated to about 1.2M lbs. Most rigs have about 3000 bbl mud
storage, dedicated completion fluid/oil mud diesel storage tankage. Generally, at least
three high-speed shakers are available with first-cut shakers removing gumbo/large
solids (cascade shaker systems). Some rigs have two gas buster systems, one for the
well and one for the riser since they can be circulated simultaneously.
Moonpools are typically larger with BOP transport/handling systems standard. Power
systems are SCR with about 20,000 total installed horsepower and emergency
generators 900 KW or larger.

FOURTH GENERATION CONFIGURATION/UPGRADE (late 1990s)

In the late 1990s, several second and some third generation rigs underwent significant
conversions for service to about 3500 to 5000 ft water depth and well depths of 20,000
to 25,000 ft. Typically, variable load of the rig was increased to near 4000 tons by the
addition of columns or sponsons, and the pontoons were enlarged with blisters. New
mooring systems were installed (typically with traction winches) and riser tension
capability increased to near or just over 1.0M lbs. Most of the upgrades also added mud
storage and a third 1600 Hp mud pump. Some rigs received larger powerplants and
SCR systems. Examples of the moderate water depth conversions are the Victory class
rigs, i.e. Ocean Victory and Ocean Star, the Atwood Hunter, the Celtic Sea, the
Amirante and the M.G. Hulme.

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FLOATING DRILLING VESSELS

FIFTH GENERATION (1997-2001)

No semisubmersible rigs were built in the mid 1990s due to the crash in energy prices.
As energy prices recovered in the mid to late 1990s, the demand for deepwater rigs
increased, and many semisubmersible rigs had major upgrades/conversion for deeper
water depth service. Most of these rigs are rated to 5000 to 8000 ft water depth and
have mooring systems, which included traction winches or are fully dynamically
positioned. Ultra-deepwater semisubmersible designs had languished in the late 1980s
and early 1990s and as a result, many ultra-deepwater shipshape rigs were built when
the ultra-deepwater rig demand increased in the late 1990s. Only toward the end of the
1990s were large variable load semisubmersible designs available. Typically, fifth
generation semisubmersible designs have 6000 to 9000 ton variable loads and are rated
to 25,000 to 35,000 ft drilling depth.). Typical new designs are the Sedco Express
and the Reading and Bates RBS. Typical upgrades/conversions include the EVA
4000 design and upgrades of former accommodation vessels (O. Confidence,
Marianias and Stena Tay). Several moderate size semisubmersibles rigs were also
built (Amethyst, etc).
These rigs typically have large mud systems and most have at least three 2200 Hp mud
pumps (some rigs have four mud pumps). Higher 7500 psi standpipe systems are
common as well as 5 -in. and larger drill pipe. The quarters on these rigs were
designed for 110-150 persons. Most of the new design semisubmersibles have 60-in.
rotary tables, TDS-4 or TDS-6 top drive systems with automated pipe handling systems
(PRS-4). Most of the rigs have multiplexed BOP control systems installed on 15 ksi
BOPs with 4-in. ID choke and kill lines and over 2.0M lbs of riser tension capability.

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WELL DESIGN ISSUES

2
Section

2.0 WELL DESIGN ISSUES

OBJECTIVES
On completion of this lesson, you will be able to:

Explain how water depth and RKB elevation impact fracture gradient and pore
pressure.

Be able to adjust mud weights, LOTs, etc. of an offset well to a different water depth
and RKB elevation.

Calculate fracture gradients for wells drilled with floating drilling rigs.

Describe the factors which control planned casing depths.

List the factors which impact equivalent circulating density and know which factors
are manageable.

Describe the factors which must be considered when selecting a mud type for a well
drilled with a floating rig.

Describe how natural gas hydrates affect the mud selection process.

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WELL DESIGN ISSUES

CONTENTS Page

2.0 WELL DESIGN ISSUES................................................................................................................. 1

OBJECTIVES ........................................................................................................................... 1
CONTENTS ........................................................................................................................... 2
2.1 OVERVIEW .................................................................................................................................... 3
2.2 FRACTURE GRADIENT AND PORE PRESSURE........................................................................ 4
2.2.1 OVERBURDEN ................................................................................................................ 5
2.2.2 PORE PRESSURE .......................................................................................................... 7
2.2.3 EFFECTIVE STRESS RATIO .......................................................................................... 8
2.2.4 OFFSET WELL DATA ................................................................................................... 13
2.3 EQUIVALENT CIRCULATION DENSITY .................................................................................... 17
2.4 CASING DEPTH SELECTION ..................................................................................................... 21
2.4.1 STRUCTURAL CASING ................................................................................................ 22
2.4.2 SECOND CONDUCTOR CASING ................................................................................. 23
2.4.3 CONDUCTOR CASING ................................................................................................. 24
2.4.4 SUBSEQUENT CASING STRINGS............................................................................... 25
2.5 CASING DESIGN ......................................................................................................................... 28
2.5.1 STRUCTURAL CASING ................................................................................................ 29
2.5.2 CONDUCTOR CASING ................................................................................................. 30
2.5.3 SURFACE, PROTECTIVE, AND PRODUCTION STRINGS ......................................... 31
2.6 MUD SELECTION ........................................................................................................................ 35
2.7 GAS HYDRATES ......................................................................................................................... 37
REFERENCES ....................................................................................................................................... 46
APPENDICIES ....................................................................................................................................... 48
APPENDIX 1 FRACTURE GRADIENT CALCULATION ....................................................... 48
APPENDIX 2 EXAMPLE CALCULATIONS, BACKUP PRESSURE FOR
BURST DESIGN, FLOATING RIGS ................................................................ 52

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WELL DESIGN ISSUES

2.1 OVERVIEW
As water depth increases beyond the point where bottom founded rigs can drill, floating
rigs and techniques are used while drilling exploration and most appraisal and
development wells. The special equipment used when floating rigs drill has an impact on
well designs. As water depth increases many floating rig drilling techniques become
critical to well planning and efficient operations. It is important that the issues associated
with floating rig operations be included in well planning.
Pore pressure and fracture gradient predictions are the most important factors that affect
well planning in deeper water depths (Figure 2.1). As water depth increases, the margin
between pore pressure and fracture gradient typically reduces as well. The well design
and cost are therefore heavily impacted by these predictions.
Every drilling engineer should be familiar with methods and procedures to develop pore
pressure and fracture gradient predictions. While ExxonMobil has specialists who
develop pore pressure and fracture gradients, it is necessary for the drilling engineer to
understand the basis and the uncertainties in their estimates as well as to compare their
estimates with offset wells.

GOM SHELF GOM DEEPWATER

Figure 2.1 - Example of Reduced PP/FG Margin

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WELL DESIGN ISSUES

2.2 FRACTURE GRADIENT AND PORE PRESSURE

Formation fracture pressure is broadly defined as the pressure at which the formation
starts to take fluid due to induced fractures. Fracture gradient reflects the rate at which
fracture initiation pressure varies with depth. Formation pressure is the pressure
existing in the pore spaces (void areas) in the rock. Overburden is the cumulative
weight of everything above it, e.g. water and formations.
In the 1950s almost all oil wells were normal pressured, i.e. formation pressure was
equal to the hydrostatic pressure exerted by water (either freshwater, seawater or
saltwater). Beginning at this time, more abnormal pressured wells were beginning to be
drilled. Hydraulic fracturing of oil wells was also being developed in the early 1950s, and
the science and theory of fracturing formations was evolving. A classic paper published
in 1957 pioneered the understanding of fracturing(1). This technology was then applied to
predict formation fracture gradients for both normal and abnormal pressure wells.
The first methods to estimate fracture pressures were developed in the late 1960s.
These methods were developed for land wells and were used for shallow water depth
wells. By the mid-1960s the search for hydrocarbons was beginning to extend to water
depth beyond the point where jack-up and fixed platforms could drill. Floating drilling
abilities and procedures were being developed. By the early 1970s, floating rigs were
beginning to be used in water depths near 1500 ft, and the first paper on offshore
fracture gradient prediction methods was published (2). This method identified that long
water columns impacted the formation fracture gradient and presented a way to
calculate fracture gradients in deeper water depths.
Most fracture gradient prediction techniques are generally based on a model developed
by Hubbert and Willis and refined by later authors(1,3). The general equation is:
Fracture pressure = K x (overburden pressure formation pore pressure ) + formation pore pressure

This equation defines the fracture pressure as a variable dependent on the overburden
pressure, the formation pore pressure and the horizontal to vertical effective stress ratio
(K). This general method is used in many methods to predict fracture pressures. The
difference in most predictive methods is how to estimate pore pressure, overburden
pressure and the vertical effective stress ratio K.

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2.2.1 OVERBURDEN
The overburden pressure at a given depth is the weight of everything above it. e.g.,
seawater, density of soil from the mud line to the depth of interest. All well depth
references are from the rotary Kelly bushing (RKB). The air gap can have a significant
impact on overburden (especially shallow overburden) and should be included in all
overburden calculations. The air gap on floating rigs can range from about 40 ft to as
much as 125 ft.
The gradient of a seawater column does change slightly with water depth. However, this
change is usually insignificant, and generally a seawater hydrostatic pressure of 8.55
ppg (roughly 3.5 WT% salt) is a good estimate (4).
To estimate overburden below the mud line, the well depth from the mud line to the
depth of interest is usually broken down into numerous intervals. The bulk density of
each interval is then estimated and the overburden pressure of that interval calculated. A
sum of the overburden pressure from the seawater and all intervals below the mud line
will result in the total overburden pressure at the depth of interest.

Bulk Density vs Depth Below the Mud Line

GOM: 390 ft WD
2.5

2.4

2.3

2.2
Bulk Density, gm/cc

2.1

2
Best Curve Fit
1.9

1.8 Soil Boring Data

1.7 Density Log Data

1.6
0 2000 4000 6000 8000 10000
Subsea Depth ft

Figure 2.2 - Bulk Density Well Bore Profile

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 WELL DESIGN ISSUES

For deeper wells, bulk densities from density logs can be integrated to the depth of
interest and will result in a good estimate of overburden pressure. Unfortunately, density
logs are seldom run in shallow hole sections of a well and getting an estimate of shallow
below mud line overburden pressure can be difficult. Soil boring data is available in
almost all areas of the world, and typically, soil borings will penetrate from a few feet to
as much as 2000 ft below the mud line. The submerged unit weight of soil can be
integrated to develop an overburden pressure for shallow formations. Figure 2.2 is an
example of a bulk density vs. depth below sea level plot for a GOM shelf well.
Overburden pressure is expressed in psi. An overburden gradient is measured in psi/ft
and is the normal method used in the industry to express overburden. The overburden
gradient for a well typically increases asymptotically with depth and should near a 1.0
psi/ft (19.2 ppg or a 2.3 SG) with depth. Figure 2.3 shows typical overburden gradient
curves from around the world.

Typical Overburden Gradient

1.0 psi/ft
2000

4000

6000
Depth Below Mudline - ft

8000

10000 North Sea

Offshoe California
12000
Gulf Coast - Fertl &
Timko
14000 MW Shelf, Australia

East Java Sea Shelf

16000
GOM Crazy Horse
18000 Eaton Gulf Coast

20000
13 14 15 16 17 18 19 20 21
Overburden pressure Gradient- lbs/gal

Figure 2.3 - Worldwide Overburden Gradients

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WELL DESIGN ISSUES

2.2.2 PORE PRESSURE

Many methods have been developed to estimate pore pressure from well logs (both
wireline logs and LWD logs). The first methods to estimate pore pressures from logs
were developed in the mid-1960s. While numerous models have been developed, the
model most commonly used by the industry is the Eaton Model. This method to
calculate pore pressure was first published in 1975 (5). The general procedure used by
the Eaton model to develop pore pressure is:
Develop overburden gradient from density logs, sonic logs or seismic data.
Using log data, plot the resistivity of shale sections on semi-log paper.
Establish a normal compaction trend line.
Measure normal and observed resistivities at various depths.
Calculate the ratio of normal compaction resistivity to observed resisitivity.
Use the actual overburden pressure and the resisitivity ratio to calculate the
pore pressure.
In the mid-1990s, several methods were developed to permit estimating formation pore
pressure from seismic data (6). The Bowers model is based on the premise that change
of formation velocity is an exponential function of vertical effective stress. Other
models assume that formation velocity varies with temperature, burial rate and clay
surface area.

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WELL DESIGN ISSUES

2.2.3 EFFECTIVE STRESS RATIO

We know from rock mechanics that a formation will fracture when the pressure applied
to the formation is the minimum horizontal stress (1). We also know that minimum
horizo n ta l stre ss is a fu n ctio n o f th e ve rtica l stre ss a n d P o isso n s ra tio .
Using the ratio between horizontal to vertical stress is a method to determine the least
principal stress, which determines when fracturing occurs. The effective stress ratio is
the most difficult variable to estimate when calculating fracture gradients.
Many methods have been developed to relate stress ratio to well variables, i.e., depth,
formation density, compaction, leak-off tests, etc. Typically, the stress ratio ranges from
about 0.3 to 1.0. For formations, which are competent, the stress ratio will be near the
low end of the range because they transfer less of the vertical load into horizontal stress.
Shale typically has a higher integrity (horizontal stress) than sands because they are
more plastic than sands and transfer more of their overburden load into horizontal
stress. The effective horizontal stress ratio in deepwater formations is particularly high
due to the high water content (plasticity) of the shale. They should have horizontal
stresses very close to overburden and thus the stress ratio would be close to one (7).
Also, when the effective stress ratio approaches unity, fracturing tends to occur
horizontally.
In some areas of the world, tectonics can alter the transmission of overburden into
horizontal stress. There are no current methods to predict the effects of tectonics. When
drilling in the vicinity of competent formations and active geological features such as salt
domes and faulting, well plans should allow for an increased level of uncertainty.

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WELL DESIGN ISSUES

Several authors have developed methods to predict fracture gradients in deepwater

depths (8 to 15). The drilling engineer should be familiar with and be able to calculate
fracture gradients with several of these methods. Comparison of the fracture gradient
prediction method with actual data from offset wells will establish the best predictive
method to use in the area. Figure 2.4 is a comparison of several different fracture
gradient calculation methods for a well planned in 7400 ft. water depth. Appendix 1
includes two procedures for calculating offshore fracture gradients.

Frac Gradient Method Comparison

7000

Overburden Gradient
Pore Pressure
9000 Eaton
Daines
Christman
Brennan & Annis
11000 Simmons & Rau
Barker & Woods

13000
Depth RKB, ft TVD

15000

17000

19000

21000

23000

25000
9 10 11 12 13 14 15 16 17
Stress Gradients, ppge
Figure 2.4 - Comparison of Different Fracture Gradient Prediction Methods

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WELL DESIGN ISSUES

By far the most common method to estimate fracture gradients is the Eaton Technique
(8)
. T h is m e th o d re la te s th e e ffe ctive stre ss ra tio to P o isso n s ra tio . P o isso n s ra tio is
th e n co rre la te d w ith o ve rb u rd e n g ra d ie n t. B o th P o isso n s ra tio a n d o ve rb u rd e n a re
variable with depth. Table 2.1 summarizes many of the fracture gradient prediction
methods. The impact of tectonic effects on formation stress states is not directly
incorporated in these predictive techniques.

Fracture Gradient Calculation Methods

Stress Ratio Pore Overburden Remarks Application

Method K Pressure

Eaton (1968) f(Poisson's, OB) yes yes Gulf Coast, Land, Shelf

Anderson (1972) f(shale %) yes yes f(compressibility) All

Christman (1973) f(bulk density) yes yes Offshore Calf.

Daines (1980 & 1982) f(Poisson's) yes yes f(first PIT) All, international

Beekels & Van Eekelan (1982) f(depth) no mo Offset PIT Land, worldwide

Brennan & Annis (1984) f(effective stress) yes yes GOM shelf

Constant & Bourgoyne (1988) f(curve fit) no f(compaction) Worldwide, emphirical

Simmons & Rau (1988) f(Poisson's) yes yes Deepwater, modified Eaton

Zamora (1989) f(bulk density) ? ? Limited, emphirical

Aadony & Soteland (1989) f(lithology) ? ?

Rocha & Bourgoyne (1984) f(depth, compaction) no yes Need computer & Brazil, deepwater worldwide
offset well info

Barker (1997) f(depth) no no planning tool Deepwater GOM, shallow BML

Eaton (1997) f(Poison's, OB) yes yes new OB curve Deepwater

Aadnoy (1998) f(OB) no yes f(fluid barrier) All WD, worldwide

Table 2.1 Summary of Fracture Gradient Prediction Methods

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WELL DESIGN ISSUES

In shallow water and on land, the pore pressure can have a significant impact on the
calculated fracture gradient. In deeper water, the pore pressure has a lesser impact on
the fracture gradient prediction. Figure 2.5 illustrates the sensitivity of calculated fracture
gradients to pore pressure with a fixed overburden gradient for a well in 7400 ft. water
depth.

Figure 2.5 - Sensitivity of Pore Pressure on Estimated Fracture Gradient

In shallow water, the contribution of seawater to total overburden is modest. Many

simply ignore water depth and its effect when calculating fracture gradients. Typically, an
accuracy of 0.5 ppg and 500 ft is adequate for shelf wells except in special cases such
as draw-down sands, very deep well depths, etc.

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Figure 2.6 illustrates that as water depth increases, the need for accurate predictions of
fracture gradient, overburden gradient and pore pressure increases. Many times
deepwater wells have a very small margin between fracture gradient and pore pressure
gradient. Small errors in either fracture gradient or pore pressure predictions can result
in a well not achieving its geologic objectives, or the achievable well depth being
constrained. In these cases, accurate prediction of casing setting depths is also very
difficult, and the well plan has a high degree of uncertainty. The very high cost of
deepwater operations further heightens the critical need for accurate predictions.

Shelf

Increasing
Water
Depth

Deepwater

Low Importance High Importance

Figure 2.6 - Importance of Accurate Fracture Gradient Prediction

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WELL DESIGN ISSUES

2.2.4 OFFSET WELL DATA

A vital part of the pore pressure gradient, fracture gradient prediction process is the
re vie w o f o ffse t w e ll d a ta . F e w w e lls d rille d a re tru e w ild ca t w e lls (w ith ve ry fe w if a n y
offset wells), and information on nearby wells is usually available. Comparing the
predicted pore pressure and fracture gradients against actual results will give much
support to the predictions made for the planned well.
For both land wells and wells drilled in shallow water, there are typically many offset
wells available. Small variations in water depth and RKB elevation between an offset
and a planned well will not have an appreciable impact on the final planned well. For
these areas there is a reduced need for correction of water depth and RKB elevation
from an offset to the planned well.
As water depth increases, more accurate pore pressure and fracture gradient predictions
are needed. Also, as water depth increases, the number of available offset wells typically
decreases, and the offset well(s) may be in significantly deeper or shallower water than
the planned well.
A method is needed to predict fracture gradients and mud weights from offset wells with
different water depths and RKB elevations. A method to normalize for water depth and
RKB elevation is shown in Figure 2.7 (16). This equation can be applied to all parameters
that depend on overburden stress and the reference height, such as fracturing pressure,
mud weight and pore pressure. Changes in tectonic stress states are not incorporated in
this equation.

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WELL DESIGN ISSUES

Offset Well Proposed Well

RKB-Sealevel = 48 ft RKB-Sealevel = 102 ft
Depth
TVD - ft
0

1000
WD 1 = 2000 ft
2000 WD 2 = 3500 ft

3000
Mudline
4000
3500 ft
5000
RKB 1 = 5548 ft PIT 1 = 13.2 ppg
6000

7000 PIT 2 = ?
RKB 2 = 7102 ft
8000

9000

10000

P IT 2 (p p g ) = P IT 1 x (R K B 1 / R K B 2 ) + 8 .5 5 x (W D 2 W D 1 /R K B 2 )

PIT2 = 12.2 x (5548 / 7102) + 8.55 x (3500 / 7102)

PIT2 = 10.31 + 1.81

PIT2 = 12.1 ppg (Adjusted to proposed well water depth and RKB)

Figure 2.7 - Method to Correct Offset Well for Water Depth and RKB Elevation

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WELL DESIGN ISSUES

Figures 2.8 and 2.9 illustrate how adjusting offset well PITs to a common reference
water depth and RKB elevation will help improve the mud weight prediction for a
new well.

Eastern GOM Deepwater

14.5

14 Adjuste to: 84, 5149'

7400 ft WD & 80 ft RKB Elevation
13.5 300, 5844'

13 305, 7073'

12.5 429-1, 6201'

429-2, 6134'
12
Mud weight (ppg)

476, 6626'
11.5
520, 6738'
11
522, 6929'
10.5
606, 6294'
10
607, 6588'
9.5 657, 7520'

9 348, 7209'

8.5 Block WD

8
0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

13000

14000
Depth below mud line, ft

Figure 2.8 - Mud Weight vs. Depth For Offset Wells

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WELL DESIGN ISSUES

Eastern GOM Deepwater

14.5
14.0 Adjusted to:
7400 ft wd & 80 ft RKB elevation 84
13.5
300
13.0 305
12.5 429-1
Mud weight (ppg)

12.0 429-2
11.5 476
11.0 520
10.5 522

10.0 606
607
9.5
657
9.0
348
8.5
8.0
1000

2000

3000

4000

5000

6000

7000

8000

9000
0

10000

11000

12000

13000

14000
Depth below mud line, ft

Figure 2.9 - Offset Well Mud Weight Adjusted to a Common WD and RKB

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WELL DESIGN ISSUES

2.3 EQUIVALENT CIRCULATION DENSITY

Equivalent circulation density (ECD) is the added pressure from fluid friction caused by
circulation in a well. ECD is an increasing design consideration as water depth increases
and the margin between pore pressure and fracture gradient narrows. Figure 2.10
illustrates how fluid circulation can add significant pressures to a wellbore, which
can lead to lost returns, exceeding fracture gradients, etc

Zero psi 2880 psi

Zero gpm 250 gpm

Zero psi Zero psi

Zero gpm 250 gpm

Pannulus = 198 psi

Pdp = 673 psi
9 5/8-in. @ PIT = 17.5 ppg
12000 ft
Pressure = 16.5 ppg Pressure = 16.82 ppg
Mud weight = 16.5 ppg
Delta P = 0.32 ppg
7-7/8 in. HOLE
P annulus = 88 psi
Pbit = 1920 psi
6-1/4" DC,4-1/2in. DP

Mud PV = 25, YP = 15 ECD

ECD =
= MW
16.5 ++ Delta
0.37 P Annulus

ECD = 16.87 ppg

TD = 15000 ft BHP = 16.5 ppg
PV = 25
YP = 15

Figure 2.10 Equivalent Circulation Density

For most shelf and normal pressured wells, ECD is usually not a design issue. Common
casing sizes and low to moderate mud weights result in ECDs, which are relatively
small, typically 0.5 ppg or less. Also, for most of these wells, there is a large margin
between the pore pressure gradient and the fracture gradient, and a small ECD does not
have a significant effect on initial well design or operational procedures. In cases where
a large margin exists, ECD is less important. However there is an increasing number of
shelf wells and shallow water wells being drilled where ECD is a much higher concern
and constraint.

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WELL DESIGN ISSUES

With increasing water depth and well depth, the number of casing strings required to
reach total depth often increases. These wells usually have a low margin between pore
pressure and fracture gradient, several tight clearance liner strings, small hole sizes,
higher mud weights and much higher ECDs. For example, a recent well drilled with a
floating rig in the GOM required nine casing strings to reach 23,000 ft total depth. Also, a
GOM well in 9687 ft. water depth required six casing strings to reach 20,500 ft rkb with a
final mud weight of only 11.1 ppg.
In many ultra-deep wells, ECDs of as much as 1.5 ppg are often encountered (17). Active
management of several drilling parameters, special well planning issues and special
procedures are required for these wells to ensure they reach their geologic objectives.
When drilling a well with a small margin between pore pressure and fracture gradient,
it is often difficult to maintain enough mud weight to overbalance pore pressure when
not circulating and keep ECD low enough to prevent lost returns when circulating
and drilling.
When the pore pressure to fracture gradient margin is small, determining where to set a
casing string can be very difficult. In some cases, increased formation integrity from
setting a casing string can be more than offset by the increased ECD resulting from
su b se q u e n t sm a lle r ca sin g , d rill p ip e a n d h o le size . T h e w e lls a ch ie va b le d e p th m a y b e
limited, and setting several additional casing strings may not significantly improve the
likelihood of achieving deeper well depths. Drilling with underbalanced mud weight is not
an option with many wells drilled with floating rigs as the formation lacks enough
strength and the wellbore becomes unstable. A large volume kick can result very quickly
when drilling into a high permeability, thick sand (high KH) when mud weight is even
slightly underbalanced. As a result there is a tendency to experience large volume
and/or large intensity formation influxes when drilling with large ECDs.

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Figure 2.11 illustrates that, as well depth increases, ECD typically increases, and the
degree of underbalance can rapidly increase when the ECD is removed.

14000

16000
Min.
18000
Well Depth ft

20000
ECD = 1.5 ppg
Typical Range
22000

24000
ECD = 0.5 ppg Max.

26000

28000
ECD = 1.0 ppg
30000
0 500 1000 1500 2000 2500
BHP Change Due to ECD psi

Figure 2.11 - Depth vs. BHP Change Due To ECD

ECDs can be managed by optimizing mud rheology, well geometry, mud circulation
rates, well angle and rate of penetration while drilling (18). Figure 2.12 illustrates how
ECD can be managed (reduced) by optimizing these factors.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
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Figure 2.12 - ECD Optimization

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2.4 CASING DEPTH SELECTION

The number of casing strings available for floating rigs is limited by the BOP size and the
subsea wellhead. By the end of the 1980s, the industry had standardized on 18 3/4-in.
subsea BOPs and wellhead systems. The high pressure subsea wellhead was typically
installed on 20-in. OD casing, and the wellhead had p ro visio n s to h a n g -o ff th re e ca sin g
strings. These strings typically were 13 3/8-in., 9 5/8-in. and 7-in. casing. Most subsea
wellhead manufacturers also had provisions for adding a sub below their standard
subsea wellhead so a string of 16-in. could be installed. If additional strings were
needed, liners could be used below these strings.
Beginning in the 1980s, more wells in deeper water depth and with deeper total depths
began to be drilled. These wells required more casing strings, and it became popular to
add an 11 -in. liner below the 13 3/8-in. when the pore pressure and fracture gradient
margin required another casing string to reach deep objectives. By the late 1990s, well
water depth and total depth increased even further, and all possible casing strings were
often needed to reach depth objectives.
By the late 1980s, the number of strings that could be used with standard 18 3/4-in.
BOPs began to be problematic. By 2000, a new wellhead system was available that
used very close casing string tolerances and permitted use of one additional shallow
casing string(19). T h e se su b se a w e llh e a d syste m s a re ca lle d B ig B o re o r F u ll B o re
wellhead systems.
Within the casing size constraints permitted in a SSWH, the strings used in a floating
well will now be briefly discussed.

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2.4.1 STRUCTURAL CASING

The first string of casing used on floating rigs is called structural casing. This string
serves as a foundation for the well. Typically this string is either 30-in. or 36-in. OD. A
primary function of the structural casing is to resist bending stresses resulting from
floating rig operations while a BOP stack is in place. Also, this string must support its
o w n w e ig h t a n d th e w e ig h t o f su b se q u e n t strin g s a n d p re ve n t th e m fro m sin kin g b e lo w
the mud line.
In almost all cases, a low pressure wellhead housing is installed on the top of this string
with a re-entry structure (permanent guidebase). Many times a mud mat is also used
with structural casing. When used, a mud mat will typically be placed about 14 ft below
the low pressure wellhead housing.
Prior to the 1980s, almost all structural casing strings were installed into a drilled hole
and then cemented. Typically, the string was set in a hole about 300 ft below the mud
line. When water depth at the well exceeded the length of the structural casing, a
temporary guidebase was often used to help guide and stab the structural casing in the
drilled hole.
Beginning in the mid-1 9 8 0 s, m o st o p e ra to rs b e g a n je ttin g -in stru ctu ra l ca sin g . W ith th is
method, a bit and inner string are run with the structural casing. As the structural casing
penetrate below the mud line, pump pressure and circulation remove the soil from just
below the structural casing, and the casing moves into the earth as weight is slacked-off.
Typica lly je tte d -in stru ctu ra l ca sin g is se t fro m 2 0 0 to 3 2 0 ft b e lo w th e m u d lin e . A
large, high flow rate mud motor is often used to turn the bit as the structural casing is
jetted to depth. Placement of the bit in relationship with the bottom of the casing is
critical to the success of the operation. Problems have occurred when the bottom of the
bit is not located about one ft below the bottom of the structural casing. Due to its large
OD, structural casing is usually built from line pipe rather than casing. Machined
connectors are generally welded onto the line pipe. A more detailed section on design
and operation procedures used to install the structural casing are included in Section 7.

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2.4.2 SECOND CONDUCTOR CASING

In the late 1990s, many operators began using a string set 800-1000 ft below the mud
line when drilling in deepwater with a floating rig. This string is often called the second
conductor casing. The purpose of this string is to case shallow high permeability sands
that sometimes are slightly abnormally pressured. Since the BOPs are not installed on
the structural casing, shallow flows can lead to failure of the structural casing if the
abnormally pressured water sands are allowed to flow uncontrolled to the mud line.
Typically when used, this string is either 26-in. or 28-in. OD line pipe and is suspended
inside the low-pressure housing. Some operators drill below this string with a subsea
annular and a drilling riser. This method is generally done for batch-setting development
wells. Most exploration wells drill below this string without a BOP or riser, and well
circulation returns are taken to the mud line.

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2.4.3 CONDUCTOR CASING

The next string of casing typically set in floating drilling operations is the conductor
casing. Typically, this string is set above abnormally pressured sands or sands which
could possibly contain hydrocarbons. This string is normally set about 1500 to 2000 ft
below the mud line, and a string as long as 4000 ft long has been used. This string is
usually 20-in. line pipe, however, smaller sizes and even 22-in. line pipe have been used
for conductor casing. The subsea BOP stack is normally installed on this string.
The setting depth selection for this string is highly dependent on shallow hazards. A
shallow hazard survey will identify possible zones, which could contain shallow gas or
abnormally pressured high permeability sands. The survey will also identify other
hazards such as shallow faults, disturbed sediments (from fluids moving up from deeper
intervals). It is desirable to place the well to miss these hazards if at all possible. In most
cases, a site can be chosen that will miss these hazards or place hazards at chosen
depths in the wellbore.
In the last few years, the industry has begun to set the conductor casing string in
deepwater at deeper well depths, as deep as 4000 ft BML. A review of a typical fracture
gradient curve shows that at shallow BML depths, the expected PIT increases much
faster than the PIT at deeper well depths. Setting the conductor deeper takes advantage
of this characteristic. Many operators are setting the conductor casing at deeper depths
by drilling the conductor casing interval with heavy mud riserless. Weighted mud is
pumped down the drillpipe, and returns are taken to the ocean at the mud line. The
density of the weighted mud in the hole is sufficient to overbalance shallow sands
encountered in this hole section which can be slightly overpressured.

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2.4.4 SUBSEQUENT CASING STRINGS

Floating rigs use protective and production strings and liners like any other well.
Generally these strings are required to isolate lower pressure well intervals which
increase hole integrity as needed to drill deeper higher-pressured formations.
The setting depth for subsequent casing strings is usually governed by the formation
strength at the last casing shoe. It is common to limit mud density in the hole to a value
less than the formation strength as determined by an integrity test (LOT) at the last
casing shoe. A margin between the maximum mud weight and the LOT will provide for
ECD. The margin between the LOT and the maximum mud weight for a hole section is
a regulatory issue in some areas. For example, the U.S. Minerals Management Service
requires that a margin be specified on the Application for Permit to Drill. The margin
between the maximum mud weight and the LOT in a hole section is normally 0.3 to 0.5
ppg. While the margin between the LOT and the maximum mud weight should require a
very detailed engineering analysis, Figures 2.11, 2.12, and 2.13 illustrate the typical
ranges for the margin that can be used in preliminary well planning.

1.2
Actual Wells
1 Minimum
Margin PIT-MW, ppg

Average
0.8

0.6

0.4

0.2

0
25 20 15 10 5
Hole Size in.

Figure 2.13 - Typical LOT to MW Margin for Well Planning

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After the optimum setting depth of the conductor casing is planned, selection of
subsequent casing string setting depths is straightforward. With the expected fracture
gradient and mud weight schedule known, the margin between ECD and the mud
weight below that string will determine the string setting depth. This process is shown
in Figure 2.14 for a generic deepwater well in 7400 ft. water depth.

Mud Weight and Fracture Gradient Comparison

7000

0.3 ppg Barker FG

9000 Predicted Mud Weight

20" conductor @ 10,000'
PIT = 10.2 ppg
11000
Depth-TVD, rkb-ft

13000
Setting Depth 16" @ 12000'

15000

17000

19000
8 9 10 11 12 13 14 15 16
Mud Weight, PPG

Figure 2.14 - First Protective Casing Depth Selection

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This process is continued downhole until reaching the desired well depth or until there
are no longer any casing strings available. The final casing setting depths for the generic
well are shown in Figure 2.15.

Mud Wieght and Fracture Gradient Comparison

7000

Barker FG
0.3 ppg Predicted Mud Weight.
9000
20" conductor @ 10,000'
PIT = 10.2 ppg
11000
16" @ 12000'
TVD Depth, rkb-ft

PIT = 11.5 ppg

13000 0.4 ppg

13-3/8" @ 14500'
PIT = 12.8 ppg
15000
0.4 ppg

9-5/8" @ 17200'
17000
PIT = 12.2 ppg

19000
8 9 10 11 12 13 14 15 16
Mud Weight, PPG

Figure 2.15 - Final Generic Well Casing Strings Setting Depth Design

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2.5 CASING DESIGN

Floating rig operations are unique in that the wellhead is located at the seafloor and is
not readily accessible for manipulation or inspection. Since the rig moves with the
environment and the well is fixed at the mud line, unique operations are required to
install casing strings which will affect casing designs.
With floating rigs, casing strings are usually run and landed in the subsea wellhead with
a string of drill pipe. The drillpipe casing running string is called a landing string. Section
8 discusses design issues and considerations for landing strings. Since casing strings
terminate at the mud line and physical access is not possible, a slip-type casing hanger
typically used with most surface wellhead systems cannot be used. A mandrel type
casing hanger must therefore be used. A disadvantage of a mandrel type hanger is the
hanger must land in the subsea wellhead. If a casing string with a mandrel type casing
hanger becomes stuck off bottom and does not land in a subsea wellhead, repair and
recovery operations can be very expensive and difficult with increased mechanical risks.
A common practice with floating rig operations is to set all casing strings at a depth to
leave roughly 50 ft of rathole below the casing shoe. The rathole and not reciprocating
the casing while cementing will ensure the mandrel hanger is in and stays in the proper
position in the subsea wellhead.
One casing design issue unique to floating rigs is that vessel motions may preclude use
of some connections. Often vessel motions will make stabbing and make-up of some
connections on casing strings (run through the BOPs and riser) difficult. High bending
loads on a casing string can be imparted to strings run prior to the BOP and riser being
installed.
Generally, the first strings installed on wells drilled with floating rigs are large and API
line pipe rather than API casing. Line pipe and casing are manufactured to different
specifications, grades, etc. Also, generally large weld-on connections are used rather
than API threads since these strings can have severe design considerations as
discussed below. An elastomeric seal is used on almost all weld-on connectors. Since
there is no metal-to-metal seal with these connectors, their use when drilling
hydrocarbon intervals should be carefully considered and evaluated. Weld-on
connections for large OD strings will be discussed in more detail in another section.

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2.5.1 STRUCTURAL CASING

Structural casing used in floating rig operations is designed as the foundation of the well.
Its design is highly dependent on several rig systems including the stationkeeping
system, the riser system and the BOP system. Section 7 gives specific information on
design of structural strings. Since structural casing strings are usually 30-in. OD or
larger, API line pipe is used. Also, weld-on connections are used due to their rugged
construction and increased bending ratings.

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2.5.2 CONDUCTOR CASING

After the structural casing is installed, the next casing string normally set is the
conductor casing. Since with floating rig operations the BOP stack is installed on this
string, it is designed for burst using the same design procedures as for surface casing.
BURST LOADING
Burst design for conductor string assumes seawater on the outside of the string and a
full column of gas internal to the string. Also, the burst design assumes a pressure is
applied at the mud line such that when an internal gas gradient is included, the pressure
at the conductor shoe exceeds the LOT (plus a safety margin).
COLLAPSE LOADING
The design standard for conductor casing is to withstand cementing loads. Several
conductor strings have collapsed when running because the rig crews forgot to fill the
string. When running this string, it must be kept full since the large conductor strings
generally have low collapse ratings. Collapse design should consider external loads that
may occur as a result of heavy muds, weighted pills and cementing density when this
string is run.
BENDING STRENGTH
Bending strength is a concern for conductor casing as it is generally run in open water
without the BOPs and riser installed. Environmental loads due to waves or current and
rig roll and pitch can generate significant bending loads. Unfortunately, these loads are
difficult to quantify and model, and experience typically leads to a conductor connector
selection due to bending.
As conductor casing is run, tight hole or bridges in the open hole often require some set-
down weight or jetting before the casing can be run to bottom. Note: When set-down
weight is applied to a conductor casing, it is very important to limit the set-down weight
of the string to a value less than the buoyed weight below the SSWH. This will keep the
conductor string above the SSWH in tension. When a compression load is permitted in
the string above the SSWH, high bending loads can be generated. On several
occasions, compression in this string above the SSWH has led to buckling and high
bending loads which have led to failure (either in the pipe tube or connection). As a
result of these operating conditions, many floating rig well designs include a short higher
strength section of conductor casing just below the high pressure subsea wellhead.
After a conductor is in place and cemented, bending loads are not normally a problem
due to the resistance to bending offered by the structural casing. It is assumed all
bending loads are applied to the structural string, and these loads are not applied to the
conductor string.
TENSION LOADING
Typically this string has a very high tensile rating as is more than adequate to support
itself and compression loads from subsequent strings. Typically, a design check for
compression and tension of this string is made, however burst and collapse loading
usually result in a design that is more than adequate for tension.

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2.5.3 SURFACE, PROTECTIVE, AND PRODUCTION STRINGS

These strings are set in wells drilled with floating rigs for the same reasons and serve
essentially the same functions as in wells drilled on land and with bottom founded
offshore rigs. The design burst, collapse and tension loads assumed for design are the
same as used on other wells except for the effect of water depth on casing back-up
pressure used for burst and collapse design.
With floating rig operations, casing strings are landed in a subsea wellhead and a seal is
installed to isolate the external casing annulus from the wellbore. After the seal is set,
the pressure in the annulus is typically never monitored again. While it is possible to
unset and/or remove a casing annulus seal assembly (prior to subsequent string being
set) this is generally not done. After a subsequent casing string is hung in the SSWH,
even this option is no longer available.
When a casing annulus is sealed creating a trapped volume, pressure testing the casing
hanger seal assembly will be a critical operation. The pressure test volume must be
carefully monitored to ensure the seal is set and test pressure is not being applied to the
entire trapped annulus. On several occasions, test pressure has leaked past a leaking
seal assembly and, since the test pressure exceeded the casing collapse rating, the
casing string was inadvertently collapsed. Prior to the 1980s, casing hanger seal
assemblies used elastomeric seals, and leaks were common. Most of the casing hanger
seal assemblies today use metal-to-metal seals, and leaks in these seal assemblies are
less common.
When cold mud in a trapped annulus is heated by bottom hole temperature, the pressure
in the annulus can reach several thousand psi due to thermal expansion of the fluid. This
problem is thought to have led to at least one complete wellbore failure (20). Generally
the worst design case occurs (highest increase in temperatures) after a well is placed on
production.
To prevent annulus pressure build-up in wells drilled with floating rigs, mitigation options
used include ensuring annuli are not sealed with cement (optimize casing setting depths,
etc), installing pressure rupture disks, use of insulated tubing strings and use of
crushable foam in the annulus. The risk and operating considerations for providing a
method to access casing annuli with an ROV have also been considered.
Trapped casing annuli can also cause problems with connections on the casing. Most
casing strings have connections designed to contain internal pressure only. An external
pressure higher than the internal pressure is not a design criteria for most casing strings.
Special connections which seal both external and internal pressure are often used on
critical wells drilled with floating drilling rigs.
There are two commonly encountered situations with casing annuli that will affect burst
casing design for wells drilled with a floating rig. In most cases, the top of primary
cement is left below the shoe of the last casing string set. This permits any pressure
in cre a se in th e ca sin g a n n u li to b le e d -o ff to fo rm a tio n s e xp o se d b e lo w th e la st ca sin g
shoe. In some cases and for a variety of reasons, the top of primary cement will seal the
casing annuli at the last casing shoe. This creates a fixed trapped volume in the casing
annuli. These two cases are shown in Figure 2.16.

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WELL DESIGN ISSUES

Annulus Cementing Options

Riser Riser Seal

Assembly

36-in. 36-in.

Top of Cement
20-in. 20-in.

Top of Cement

Void

Mud

Cement

13 3/8-in. 13 3/8-in.

Annulus Not Sealed With Cement Annulus Sealed With Cement

Figure 2.16 - Casing Annulus Options, Wells Drilled With a Floating Rig

BURST LOADING
The following guidelines are recommended for calculating annulus pressures for burst
design of casing strings when the strings are landed in a SSWH. The guidelines depend
on whether the casing annuli is sealed with cement at the last casing shoe.
The typical case found with casing strings set in wells with floating rigs is not to seal the
annulus with cement. This is also the preferred method of preventing excessive pressure
buildup in casing annuli. Figure 2.17 illustrates this design condition. Typically it is
possible to place casing strings so that primary cement will not seal the casing annulus
at the previous casing shoe.

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With this case, fluids and pressures in the casing annulus change with time. Pressure at
the casing annulus seal assembly is assumed to balance the local formation pore
pressure below the last casing shoe. Depending on water depth, casing setting depth,
mud weight and exposed formation pore pressure, the mud left in the casing annulus
may or may not drop as shown in Figure 2.17.

Annulus Not Sealed With Cement

Riser Riser Seal

Assembly

36-in. 36-in.

Mud Drop

20-in. 20-in.

Top of Cement Top of Cement

Void

Mud

Cement

13 3/8-in. 13 3/8-in.

No annulus mud drop Annulus mud drop

Figure 2.17 - Casing Burst Design, Annulus Not Sealed With Cement

The recommended pressures to use in burst design when designing casing for floating
operations when the annulus is not sealed with cement are:
1. Assume that the mud in the casing annulus will drop below the seal assembly to
a depth that the setting mud weight will balance the local pore pressure at the
shoe, then use zero backup from the seal assembly to the top of the mud
column.
2. Next use setting mud weight gradient from the top of the mud to the previous
casing shoe.
3. Then use the local pore pressure gradient from the last casing shoe to the design
string setting depth.
Appendix 2 includes an example showing how this recommended method can be used
when designing for burst conditions.

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The presence of shallow hydrocarbons can complicate the goal of leaving casing annuli
non-sealed. It is common practice to cover all hydrocarbon intervals with primary
cement, and this is a regulatory requirement in many areas such as the GOM.
When a hydrocarbon zone is near a previous casing shoe, it can be difficult to cover the
hydrocarbon interval with cement and still leave the shoe at the previous annulus open,
not sealed with cement. It may be necessary to use less than optimum casing setting
depths to leave casing annuli open after hydrocarbon zones are properly cemented.
In a few cases, it may be necessary to seal a casing annulus with cement creating a
trapped volume. When this condition exists, the hydrostatic pressure trapped below the
seal assembly cannot bleed-off to the formation. For this case, the recommended
pressures for use in burst design are:
1. Use zero psi burst backup pressure at the seal assembly.
2. Use setting mud weight from the seal assembly to the top of cement.
3. Use a 9.0 ppg gradient for the cement column (from top of cement to the outer
casing shoe depth).
4. Use local formation pressure gradient from the outer casing shoe depth to the
casing setting depth.
COLLAPSE DESIGN
For collapse design of strings landed in a subsea wellhead, it is recommended that the
external pressure be assumed to be the casing setting mud weight. Credit is not taken
for possible pressure reduction due to fluid loss to exposed formations below the outer
casing string (even if the annulus is not sealed with cement). The worst case assumption
is that permeable formations do not exist below the outer casing shoe.

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2.6 MUD SELECTION

All drilling operations have many basic functions and requirements for the drilling mud
which include, balancing formation pressure, hole cleaning, stabilizing the borehole, etc.
Floating rig operations have all the basic requirements for drilling muds and a few
additional requirements for offshore and deepwater locations. This section will discuss
several of the functions unique to floating drilling.
Typically the marine drilling riser on floating rigs has roughly a 20-in. inside diameter with
a 0.35 to 0.4 bbls/ft capacity. In 5000 ft water depth, the riser can contain as much as
2000 bbls of mud. The volume of the mud system on many deepwater floating rigs can
be 5000 to 6000 bbls. The large mud system volume makes the mud costs for
deepwater very high.
In most offshore areas of the world, there are restrictions on discharge of drilling fluids to
the environment. Many regulatory agencies have requirements on the toxicity, volume
and type of cuttings and mud which can be discharged at the rig. This may limit the type,
rate or components used in the drilling mud for wells drilled with floating rigs. Diesel and
mineral oil mud were used by some operators with floating rig operations in shallow and
moderate water depths in the past. For deepwater floating drilling operations, it is
important that the viscosity of the mud does not increase significantly with cold
temperature and possibly aggravate drilling problems such as lost returns, ECD or
surge and swab pressures.
In most areas of the world, the temperature of the seawater drops with increasing water
depth. Figure 2.18 illustrates that for the GOM, the seawater temperature approaches
roughly 38o F with depth. This is the minimum temperature at the BOPs during long term
periods without wellbore circulation. In floating rig operations, the drilling mud can
experience a wide range of temperatures from static bottom hole temperature to the
temperature at the mud line. Some of the early synthetic based muds (SBMs) were very
viscous at cold temperatures, which slowed the use of early SBM in deepwater. Today
SBMs are used with many floating rigs (especially in the GOM) however, cuttings
discharge to the ocean is very closely regulated in many areas. Synthetic muds are often
used on floaters since they are very inhibitive when drilling reactive shale zones.

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Recorded at Miss. Canyon Block 211

TEMP. DEG. F
35 40 45 50 55 60 65 70 75 80
0
DEPTH BELOW SEALEVEL feet

500
1000
1500
2000
2500
3000
3500
4000
4500
5000

Figure 2.18 - Seawater Temperature vs. Water Depth, GOM

Most wells drilled with floating rigs will drill at least some very geologically young
formations. Typically, very young formations are very sensitive to water. When drilling
these intervals with non-inhibitive muds it is co m m o n to e xp e rie n ce so ca lle d g u m b o
problems. Gumbo can be a significant drilling problem and can limit drilling rates, plug
flowlines and result in oversize hole and formation evaluation problems. As a result,
many operators use inhibitive muds to drill shallow reactive formations. It is common to
drill with high sodium chloride muds, calcium chloride muds and even SBM to prevent
gumbo problems when drilling shallow formations.

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2.7 GAS HYDRATES

When drilling beyond about 1000 ft water depth, well pressure and temperature at the
BOPs are usually favorable for the formation of natural gas hydrates. Natural gas
hydrates are a solid mixture of natural gas and water resembling dirty ice in appearance.
Unlike ice, they can form at temperatures well above 32oF when sufficient pressure is
present. The higher seafloor hydrostatic pressures and lower temperatures encountered
beyond about 1000 ft water depth increase the likelihood of hydrate formation in choke
lines, drilling risers, BOPs and subsea wellheads. When natural gas hydrates occur in
floating rig systems, they can form a blockage in the choke and kill lines and
mechanically prevent closure of valves and BOPs.
As a hydrate forms, it consumes water and natural gas. Water based drilling muds have
a high percentage of water and if a hydrate did occur, water in the mud would be
removed as the hydrate forms. This will leave the mud with reduced water content. If a
significant amount of natural gas hydrates are formed, the reduction in water in the
drilling mud can produce thick, high viscosity mud or even remove enough water from
the mud to leave only solids. It is common to see thick muds and even solids blockage of
subsea equipment after hydrates have formed. Unfortunately, if the pressure/
temperature (P-T) condition in the well returns to conditions where hydrates disassociate
back into water and natural gas, the solids have already formed and potentially plugged
subsea equipment. For this reason, it is common to find only solids when a subsea stack
is retrieved as hydrates will have disassociated and dispersed before the subsea stack
reaches the rig floor.
To form a natural gas hydrate, it is necessary to have natural gas and water interact at
the proper temperature and pressure. The combination of pressure and temperature
where natural gas hydrates and water combine to form stable hydrates are accurately
known. Early research identified the pressure and temperature conditions where
hydrates formed in natural gases. Figure 2.19 is an example of this early research and
illustrates several factors that affect hydrate formation. While this figure is now outdated,
it illustrates that gas composition has an appreciable impact on hydrate forming
conditions.

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Figure 2.19 - Conditions Favorable for Gas Hydrate Formation

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The hydrate formation conditions can be altered by the addition of inhibitors and
promoters. Hydrate inhibitors include salts, alcohols and glycols that lower the threshold
temperature at which hydrates form. Alcohols such as methanol are the most effective
hydrate inhibitors, however addition of alcohols to the mud system has many detrimental
effects, and are generally not used by the industry. Salts including sodium chloride and
calcium chloride are the most often used hydrate inhibitor in drilling mud systems.
Glycols are essentially low-grade alcohols and include ethylene glycol and glycerol, and
they are commonly used in mud systems as hydrate inhibitors.
Other inhibitors function by slowing down rather than preventing the formation of gas
h yd ra te crysta ls. T h e d e ve lo p m e n t o f kin e tic in h ib ito rs has occurred recently, but they
have not been used in drilling fluid systems to date. A primary advantage of kinetic
inhibitors is they apparently function at very low concentrations. However, they are quite
expensive. Hydrate promoters include nitrogen, hydrogen sulfide, oxygen, carbon
dioxide and some other compounds such as lecithin (glyceryl esters).
The pressure at the BOPs is due to the hydrostatic head of the fluid in the well or choke
line plus any surface pressure. Figure 2.20 illustrates an example of subsea conditions
that could be expected with mud weights from 9 to 16 ppg mud with 1000 psi casing
pressure and temperatures at the mud line for the GOM.

Assumes ave. GOM seaw ater temp. 8000' WD

Assumes Press. @ BOP = hydrostatic + 1000 psi 4000' WD
10000
2000' WD
Press ure @ BOP's. psi

16 ppg
1000' WD
9 ppg
500' WD

1000
30 35 40 45 50 55 60 65 70 75
Seafloor Temperature Deg. F

Figure 2.20 - Wellbore Pressure and Temperature Conditions

Experience has shown natural gas hydrates can form when water in the drilling mud
interfaces with natural gas in a wellbore (21). Natural gas in a wellbore can occur due to
formation influxes (kicks) and the process of circulating out a kick. Water in the wellbore
can also be a result of formation water that entered the wellbore during the kick.

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The pressure and temperature conditions where hydrates begin to form is called the
equilibrium condition. The equilibrium hydrate formation conditions for several common
drilling muds are shown in Figure 2.21. The addition of inhibitors (salts or alcohols) to
the liquid phase of a water based mud will depress the P-T conditions where hydrates
can occur.

Assumes ave. GOM seawater temp.

8000' WD
Assumes Press. @ BOP = hydrostatic + 1000 psi
10000 4000' WD
16 ppg Gas Composition
2000' WD
87.1 %C1
6.1%C2
1000' WD
Pres sure @ BOP's. psi

9 ppg 500' WD
Hydrates

Seawater M ud
23 wt%NaCl + 10%Glycol

24-wt% NaCl M ud Freshwater M ud No Risk of

1000 Hydrates
30 35 40 45 50 55 60 65 70 75
Seafloor Temperature Deg. F

Figure 2.21 - Hydrate Equilibrium Conditions For Several Mud Types

Equilibrium charts such as Figure 2.21 do not take into account the kinetics of hydrate
formation. Laboratory testing has shown that the speed a hydrate requires to form
depends on many factors including the magnitude the actual P-T conditions are below
equilibrium condition (supercooling). Figure 2.22 illustrates a typical P-T curve as
hydrate forms and the equilibrium condition.

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WELL DESIGN ISSUES

4000

Hydrates Forming

Cooling
3500

Hydrate
Pressure, psi

Formed
Equilibrium
3000 Condition

Hydrates Decomposing

2500 Heating

65 70 75 80 85 90 95

Temperature, Degrees F

Figure 2.22 - Hydrate Pressure and Temperature Forming Conditions

Figure 2.23 is based on laboratory testing with 24-WT% sodium chloride mud and
illustrates that the risk of forming a hydrate increases with time when the P-T conditions
are less than the hydrate forming equilibrium conditions.

Assumes ave. GOM seawater temp.

8000' WD
Assumes Press. @ BOP = hydrostatic + 1000 psi
10000 4000' WD
16 ppg 2000' WD
Gas Composition
87.1 %C1
1000' WD
Pressure @ BOP's. psi

6.1%C2

9 ppg 500' WD
High Risk

No Hydrates in 24 hrs
No Risk of Hydrates
Low Risk

24-wt% NaCl M ud
Equilibrium

1000
30 35 40 45 50 55 60 65 70 75
Seafloor Temperature Deg. F

Figure 2.23 - Operating Guidelines For 24-WT% NaCl Mud

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WELL DESIGN ISSUES

U se o f a m u d in th e H ig h R isk a re a o f th e e q u ilib riu m ch a rt is a riske d d e cisio n .

Figure 2.24 is an example illustrating a risk analysis of a hydrate inhibitive mud.

(22)
Figure 2.14 - Example Risk Analysis of a Hydrate Inhibitive Mud

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WELL DESIGN ISSUES

Beginning in the mid-1980s, synthetic based drilling muds began to be used with floating
rig operations by some operators. These muds use refined base oil rather than diesel or
mineral oil to reduce the toxicity of the mud and permit cuttings discharges in some
areas. Hydrates can form in a synthetic base mud system. The hydrate inhibition
characteristic of an SBM is primarily a function of the inhibitor concentration in the
dispersed water. The base oil in an SBM can be thought of as an inert ingredient as far
as hydrate formation is concerned. Water in an SBM is generally dispersed in the oil
phase, and it typically has a very high inhibitor concentration (calcium chloride). Testing
of an SBM found that an SBM with 30% CaCl2 in the internal phase did not form
hydrates under extreme subcooling. However, hydrates did form when the concentration
of CaCl2 was reduced to 15-WT% (22). Unlike water based muds, gas is soluble in a
synthetic oil based mud system which can permit gas and the water (which is dispersed
in the oil phase) to come in contact. Research has found that an SBM without salt in the
water phase formed more hydrates faster than are formed in a partially hydrate inhibitive
water based mud system (22). Also, any formation water that occurs with a gas influx can
provide the free water required to form a hydrate in an SBM system.
It is possible to depress the hydrate formation conditions to about 30oF if water based
mud is nearly saturated with sodium chloride. Unfortunately, the minimum density of a
near saturation sodium chloride water based mud is near 10.4 ppg. In many cases, the
formation integrity at the conductor casing will not permit use of a mud with a density
over about 10 ppg. This could be a problem if a shallow gas sand were expected when
the maximum mud weight cannot allow adding sodium chloride to a high saturation in
the mud.
In this situation, either higher risk of hydrate formation must be accepted, or additional
alternate inhibitors must be used. For water based muds, it is typical to run the sodium
chloride concentration at 20 to 24-WT%. As the sodium chloride concentration
approaches saturation, the hydrate inhibition ability of a mud increases faster. As a
result a mud with 20-WT% sodium chloride will have much less hydrate inhibitive
capability than a mud with 24-WT% sodium chloride. Over about 26-WT% sodium
chloride, additional sodium chloride actually is detrimental to hydrate inhibition efforts.
Mixing salts, i.e., NaCl and CaCl2 in a mud system can have solubility problems and salt
precipitation can result. Table 2.2 can be used to convert the chloride ion concentration
of a mud to the WT%.

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Filtrate Chloride-Ion Filtrate Chloride-Ion Salt Weight

PPM Mg/liter %
30300 31599 5
60600 64900 10
90900 100900 15
97000 108200 16
103000 115800 17
109100 123500 18
115200 131200 19
121500 139200 20
127500 147300 21
133500 155200 22
139500 163600 23
145500 169400 24
151500 171700 25
188700 26 (fully saturated)
Table 2.2 - Conversion Table of Chloride-ion to Salt WT%

Additional hydrate depression with a water based mud (below what can be achieved with
salts) must be achieved with the addition of different inhibitors, usually low-grade
alcohols. Low-grade alcohols include glycerol and glycols. With the addition of these
inhibitors, a water based mud can be formulated to achieve a maximum of about 40oF
hydrate depression. Some operators use significantly under saturated water based
muds and rely on using pills with inhibitors such as ethylene glycol as a mitigator when a
potential hydrate condition exists.
Sodium Chloride is the most effective hydrate inhibitor (on a weight basis). Calcium
chloride is a very effective hydrate inhibitor, however calcium chloride muds can be toxic
to marine life and difficult to handle. The use of calcium chloride muds should be
carefully considered. Potassium chloride water based muds are fairly poor hydrate
inhibited systems.
In the late 1980s and early 1990s, the industry performed a great deal of testing on
various hydrate inhibitive mud systems (23). A consulting engineering company, Westport
Technology developed a computer program to calculate the hydrate equilibrium
conditions for many mud systems used by floating rigs. The computer program called
Whyp is used by many in the industry. The computer program only calculates equilibrium
conditions (pressure and temperature) and does not give any qualitative information on
the kinetics of hydrate formation in drilling muds.

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WELL DESIGN ISSUES

Hydrates can also be encountered with floating rigs outside the wellbore. It is common to
observe gas bubbles outside the structural casing and even between the structural and
conductor casing strings. The gas bubbles often accumulate and form a hydrate on the
outside of the BOP stack, wellhead connector and the subsea wellhead. The wellhead
manufacturers have designed into their equipment precautions to prevent hydrates from
forming in critical locations.
For example most wellhead connectors have a seal to keep gas and hydrates out of the
gap between the wellhead connector and the subsea wellhead. Also newer wellhead
connectors usually have the ability for an ROV to inject chemicals into areas of the
connector that could become plugged with hydrates. It is also common to install a seal
between the subsea wellhead housing and the mud mat to help prevent gas migration.
The formation of natural gas hydrates has occurred many times during deepwater
operations, sometimes when not expected. For example, one operator was using a
water based mud system during P&A operations and allowed the sodium chloride
concentration of the mud to drop significantly (to lower mud density). The mud hydrate
equilibrium conditions were significantly under the conditions where hydrates are
calculated to occur. Unfortunately, natural gas was in a casing annulus below a wellhead
seal assembly. When the seal assembly was unset, the gas quickly formed a hydrate
plug with the drilling mud and plugged both choke and kill lines and the BOPs. Several
days were required to resolve this problem and complete abandonment operations on
the well.

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REFERENCES:
1. H u b b e rt, M . K ., a n d W illis, C .G .: M e ch a n ics o f H yd ra u lic F ra ctu rin g , T ra n s. A IM E
(1957) 210.
2. C h ristm a n , S .A .: O ffsh o re F ra ctu re G ra d ie n ts, S P E 4 1 3 3 , JPT (Aug. 1973).
3. M a tth e w s, W .R . a n d K e lly, Jo h n ,: H o w to P re d ict F o rm a tion Pressure and Fracture
G ra d ie n t fro m E le ctric L o g s, Oil and Gas Journal ( Feb. 20, 1967) 92-116.
4. S m ith , R .C . a n d C a lve rt, D .G .: T h e u se o f S e a W a te r in W e ll C e m e n tin g , JPT,
(June 1975) 759-764.
5. E a to n , B .A .: T h e E q u a tio n fo r G e o p re ssu re P re d ictio n fro m W e ll L o g s, S o cie ty o f
Petroleum Engineers of AIME, SPE 5544.
6. B o w e rs, G .L .: P o re P re ssu re E stim a tio n F ro m V e lo city D a ta : A cco u n tin g fo r
O ve rp re ssu re M e ch a n ism s B e sid e s U n d e rco m p a ctio n , S P E 2 7 4 8 9 p re se n te d to th e
1984 IADC/SPE Drilling Conference in Dallas, Texas.
7. W a rp in ski, N .R . a n d S m ith , M ich a e l B e rry: R o ck m e ch a n ics a n d F ra ctu re
G e o m e try, R e ce n t A d va n ce s in H yd ra u lic F ra ctu rin g , S P E M o n o g ra p h (1 9 8 9 ), vo l.
12, pp57-80.
8. E a to n , B .A .: F ra ctu re G ra d ie n t P re d ictio n a n d its A p p lica tio n in O ilfie ld O p e ra tio n s,
JPT (Oct. 1969) 1353-1360.
9. B re n n a n , R .M . a n d A n n is, M .R .: A N e w F ra ctu re G ra d ie n t P re d ictio n T e ch n iq u e
th a t S h o w s G o o d R e su lts in th e G u lf o f M e xico , S P E 1 3 2 1 0 , 1 9 8 4 .
10. D a in e s, S .R .: P re d ictio n o f F ra ctu re P re ssu re s fo r W ild ca t W e lls, S P E 9 2 5 4 , 1980.
11. C o n sta n t, D .W . a n d B o u rg o yn e , A .T .: F ra ctu re -Gradient Prediction for Offshore
W e lls, SPE Drilling Engineering (June 1988) 136-140.
12. S im m o n s, E .L . a n d R a u , W .E .: P re d ictin g D e e p w a te r F ra ctu re P re ssu re s: A
P ro p o sa l, S P E 1 8 0 2 5 , p re se n te d a t th e 1 9 8 8 SPE Annual Technical Conference
and Exhibition, Houston, Oct. 2-5, 1988.
13. R o ch a , L .A . a n d B o u rg o yn e , A .T .: A N e w S im p le M e th o d o f E stim a te F ra ctu re
P re ssu re G ra d ie n t, S P E 2 8 7 1 0 , 1 9 9 4 .
14. B a rke r, J.W .: E stim a tin g S h a llo w B e lo w M u d lin e D e e p w a te r G O M F ra ctu re
G ra d ie n ts, p re se n te d a t th e 1 9 9 7 H o u sto n A A D E C h a p te r A n n u a l T e ch n ica l F o ru m .
15. E a to n , B .A . a n d E a to n , T .L .: F ra ctu re G ra d ie n t P re d ictio n fo r th e N e w G e n e ra tio n ,
World Oil (Oct. 1997), 93-100.
16. A a d n o y, B e rn t S .: G e o m e ch a n ica l A n a lysis fo r D e e p w a te r D rillin g , IA D C /S P E
39339, 1998.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL DESIGN ISSUES

17. F u rlo w , W .: Is E E X s L la n o th e N e xt D e e p w a te r G ia n t? Offshore, November 1998,

pp. 36-37.
18. B a rke r, J.W .: E q u iva le n t C ircu la tio n D e n sity M a n a g e m e n t in U ltra -deep Deepwater
G O M W e lls, D e e p w a te r T e ch n o lo g y, A u g u st 1 9 9 9 , p g 2 9 -33.
19. B a rke r, J.W .: W e llb o re D e sig n W ith R e d u ce d C le a ra n ce B e tw e e n C a sin g S trin g s,
SPE 37615, 1997.
20. B ra d fo rd , D .W ., e t. a l, M a rlin F a ilu re A n a lysis a n d R e d e sig n -Part 1, Description of
F a ilu re , S P E /IA D C 7 4 5 2 8 , 2 0 0 2 .
21. B a rke r, J.W . a n d G o m e z, R .K .: F o rm a tio n of Hydrates During Deepwater Drilling
O p e ra tio n s, S P E /IA D C 1 6 1 3 0 , 1 9 8 7 .
22. Davalath, J. and Elward-B e rry, J.: H yd ra te P re ve n tio n in S u b se a W e ll C o n tro l,
EPR.27PR.91, June 1991.
23. E b e lto ft, H e g e , Y o u sif, M ., a n d S o e rg a a rd , E .: H yd ra te C o n tro l D u rin g D e e p w a ter
D rillin g : O ve rvie w a n d N e w D rillin g F o rm u la tio n s, p a p e r S P E 3 8 5 6 7 p re se n te d a t
the 1997 Annual Technical Conference and Exhibition in San Antonio (5-8 October,
1997).

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APPENDICIES

APPENDIX 1 FRACTURE GRADIENT CALCULATION

The following is an example problem for calculating the fracture gradient for an offshore
deepwater well using the Eaton technique (15) and the method developed by Barker(14).
Three fracture gradients will be calculated for a well in 3250 ft water depth with pore
pressures given. The calculation conditions are:
Water Depth = 3250 ft
RKB elevation = 50 ft
Calculation Depths/ Pore Pressure:

Depth, TVD-rkb-ft Pore Pressure- psi/psi/ft

5100 2372/0.465
6700 3169/0.473
9050 5222/0.577

SOLUTION
Eaton Technique for Deepwater (15):

Step 1: Using Figure 2.15, the overburden at the three desired well depths is:

Overburden Overburden
Depth, TVD-rkb-ft Gradient, psi/ft Pressure, psi/ppg
5100 0.58 2958/11.15
6700 0.68 4556/13.07
9050 0.75 6788/14.42

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Step 2: Calculate P o isso n s ra tio fo r th e th re e w e ll d e p th s:

EATON EQUATIONS:
P o isso n s R a tio (v) for 0 to 4999.9 ft below the mud line:

v = -6.089286 x 10-9 * (Depth)2 + 5.7875 x 10-5 *(D e p th ) + 0 .2 0 0 7 1 4 2 8 5 7 e q . 1

And for 5000 ft and greater below the mud line:

v = -1.882 x 10-10 * (Depth)2 + 7.2947129 x 10-6 x (Depth) + 0.4260341387..eq.2

Eaton Equation for Fracture Gradient F/D:

PIT= v /(1-v) *(Overburden P o re P re ssu re ) + P o re p re ssu re e q . 3

CALCULATION RESULTS
Calc. Fracture Actual Fracture
Depth, TVD ft P o isso n s R a tio - v Gradient, psi/ft/ppg Pressure, psi/ft/ppg
5100 0.390 0.5380/10.35 0.5356/10.3
6700 0.440 0.6356/12.22 0.6344/12.2
9050 0.470 0.7393/14.21 0.7384/14.2

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WELL DESIGN ISSUES

Figure 2.15 - E atons A verage O verburden D ensity Data For Various Water Depths

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WELL DESIGN ISSUES

BARKER TECHNIQUE (14):

Calculate the fracture gradient at 5100 ft rkb:

Soil, psi = (5.3 x (TVD-bml, ft)0.1356 ) x D e p th M L *0 .0 5 2 ..e q . 1

= (5.3 x (1800ft)0.1356) x1800 ft x 0.052
= 1371 psi

Seawater hydrostatic, psi = 8.55 ppg x 0.052 x water depth,ft

= 8.55 ppg x 0.052 x 3250ft
=1445 psi

Fracture pressure, psi = 1371 + 1445

= 2816 psi

LOT,ppg = 2816/0.052/5100 ft
= 10.6 ppg

CALCULATION RESULTS

Calc. Fracture Actual Fracture

Depth, TVD, rkb-ft Gradient, psi/ft /ppg Gradient, psi/ft/ppg
5100 0.552/10.6 0.5356/10.3
6700 0.637/12.3 0.6344/12.2
9050 0.728/14.0 0.7384/14.2

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WELL DESIGN ISSUES

APPENDIX 2 EXAMPLE CALCULATIONS, BACKUP PRESSURE

FOR BURST DESIGN, FLOATING RIGS
EXAMPLE 1
Annular mud drop occurs below the subsea wellhead seal assembly
Given: Water depth = 500 ft, Protection casing will be set at 8000 ft below mud line,
8500 ft subsea, Pore pressure is 9.0 ppg to 7500 ft subsea and then increasing to 12.0
ppg at 8500 ft subsea. Cement will be brought above the top of abnormal pressure but
well below the outer casing shoe. Final mud weight the casing will be set in is 12.5 ppg.
Surface casing is set at 3500 ft subsea. The wellbore sketch is shown in Figure 2.16.

SOLUTION
Step 1, Calculate Annular Mud Drop
In this case there is no seal trapping a fixed volume outside the casing string. The mud
in the annulus can leak-off to the formation. Based on the surface casing setting depth of
3500 ft subsea, calculate the annular mud drop below the casing seal assembly to
balance the 12.5 ppg annular fluid with 9.0 ppg pore pressure (below the surface
casing).

Formation pressure at the surface casing shoe = 3500 ft x 9.0ppg x 0.052

= 1638 psi

Maximum annular mud drop = 3500 ft - 1638 psi/(12.5 ppg x 0.052)

= 980 ft subsea

This is the subsea depth to which the fluid level will drop. Therefore, plot zero backup
pressure from the seal assembly down to the top of the annular fluid at 980 ft. subsea.
Draw a straight line between this pressure and the zero pressure point at the top of the
annular fluid at 980 ft. subsea.

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Step 2, Calculate the Formation Backup Pressure at the Protection Casing Shoe
While there is a transition from 9.0 to 12.5 ppg over the last 1000 ft of this hole section,
use 9.0 ppg for the hole section backup calculation.

Formation pressure at the protection casing shoe = 9.0 ppg x 0.052 x 8500 ft
= 3978 psi

Plot this pressure at the protective casing shoe at 8500 ft subsea and draw the 9.0 ppg
gradient line between this point and the pressure at the surface casing shoe.

234 psi
Pressure psi

0 1000 2000 3000 4000

0
500 ft water depth
1000 Annular Mud Drop 1000
to 980 ft subsea, 480 ft BML 9.0 ppg gradient
2000 2000

3000 3000
Surface 1638 psi
4000 3500 ft subsea 4000
3000 ft BML
Depth 5000 12.5 ppg 5000 Depth
ft Subsea 12.5 ppg setting MW gradient ft Subsea
6000 6000
Top of Cement
7000 7000

8000 Void 8000

Intermediate
9000 8500 ft subsea Mud 3978 psi 9000
8000 ft BML
Cement

Figure 2.16 - Example Problem #1, Casing Design Burst Backup

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WELL DESIGN ISSUES

EXAMPLE 2
Annular mud drop does not fall below the subsea wellhead seal assembly
Given: Water depth = 4000 ft, protection casing will be set at 12,000 ft subsea (8000 ft
bml), Surface casing is set at 7000 ft subsea (3000 ft bml) in normal 9.0 ppg pore
pressure. Pore pressure of 9.0 ppf exists from the mud line to 11,000 ft subsea and then
a transition to 12.0 ppg pore pressure at 12,000 ft subsea. Cement will be brought above
the top of abnormal pressure but below the surface casing shoe. The final mud weight
the protective casing is set in is 12.5 ppg. See Figure 2.17 for the wellbore sketch.

SOLUTION
Step 1: Calculate Annular Mud Drop
In this case there is no cement seal at the surface casing shoe in the casing annulus.
Based on the surface casing setting depth of 7000 ft subsea, calculate the annular drop
required to balance the 12.5 ppg annular fluid with 9.0 ppg pore pressure.

Formation pressure at the surface casing shoe = 7000 ft x 9.0 ppg x 0.052
= 3276 psi

Maximum annular mud drop = 7000 ft 3276/( 12.5 ppg x 0.052)

= 1960 ft subsea

Because this depth is still above the mud line, the fluid level will not fall below the seal
assembly in the casing annulus. Plot the formation pressure at the surface casing shoe
at 7000 ft subsea.

Step 2: Determine the net pressure at the Wellhead

Since the hydrostatic pressure at the wellhead resulting from the 12.5 ppg annular mud
column (from the SSWH to the surface casing shoe), a net [positive pressure results at
the SSWH.
Hydrostatic press. at the surface casing shoe = 12.5 ppg x 0.052 x (7000-4000 ft)
= 1950 psi

Net pressure at the SSWH = 3276 psi 1950 psi = 1326 psi

Plot this pressure at the SSWH at 4000 ft. subsea and draw the 12.5 ppg gradient line
between this point and the pressure at the surface casing shoe.

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Step 3: Calculate Formation Backup pressure at the Protection Casing Shoe

While there is a transition to abnormal pressure over the last 1000 ft of this hole section,
the minimum pressure for the interval (9.0 ppg pore pressure) will be used for the casing
backup pressure calculation.

Formation Pressure at Protection Casing Shoe = 9.0 ppg x 0.052 x 12,000 ft

= 5616 psi

Plot this pressure at the protective casing shoe and draw the 9.0 ppg gradient line
between this point and the pressure at the surface casing shoe.

Pressure psi

0 1000 2000 3000 4000 5000

0

1000 1000

2000 2000

3000 4000 ft water depth 546 psi 3000

4000 1326 psi 1872 psi 4000

No Annular Mud Drop 9.0 ppg gradient
Depth 5000 5000 Depth
ft Subsea ft Subsea
6000 12.5 ppg 6000
gradient
7000 Surface 7000
7000 ft subsea 3276 psi
8000 3000 ft BML 8000

9000 12.5 ppg setting MW 9000

10000 Top of Cement Void 10000

11000 Intermediate Mud 11000

12000 ft subsea
12000 8000 ft BML Cement 5616 psi 12000

Figure 2.17 - Example Problem #2, Casing Burst Back-up Pressure Example

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VESSEL STABILITY

3
Section

3.0 STABILITY

OBJECTIVES

On completion of this lesson, you will be able to:

Define the symbols, definitions and theoretical relationships of the Small Angle (Initial)
Stability Theory.

Perform basic stability calculations for:

Moments
Center of Gravity (Vertical, Transverse and Longitudinal)
Free Surface
Corrected Center of Gravity
Metacentric Height
Mean Draft
List and Trim
Incline Experiment.

Define Stability at Large Angles of Inclination.

Define the characteristics of a Positive, Neutral or Negative Metacentric Height.

Define the data collected and procedures used in a daily ballast control Variable Load
Form.

3-1
EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
VESSEL STABILITY

CONTENTS Page

3.0 STABILITY ...................................................................................................................................................... 1

OBJECTIVES .................................................................................................................................................. 1
CONTENTS .................................................................................................................................................... 2
3.1 INITIAL STABILITY THEORY......................................................................................................................... 3
3.1.1 WHAT IS STABILITY? ..................................................................................................................... 3
3.1.2 ENVIRONMENTAL LOADS ............................................................................................................. 4
3.1.3 DISPLACEMENT ( ) & BUOYANCY FORCE ............................................................................... 5
3.1.4 CENTER OF GRAVITY (G) .............................................................................................................. 5
3.1.5 CENTER OF BUOYANCY .............................................................................................................. 10
3.1.6 INCLINATION ................................................................................................................................. 12
3.1.7 METACENTER ............................................................................................................................... 15
3.1.8 METACENTRIC HEIGHT ................................................................................................................ 17
3.1.9 RIGHTING ARM (GZ) AND RIGHTING MOMENT (RM) ................................................................ 19
3.1.10 FREE SURFACE (FS) .................................................................................................................... 23
3.2 STABILITY CALCULATIONS ....................................................................................................................... 24
3.2.1 KG CALCULATIONS ...................................................................................................................... 24
3.2.2 FREE SURFACE CALCULATIONS ............................................................................................... 26
3.2.3 METACENTRIC HEIGHT (GM) CALCULATIONS ......................................................................... 29
3.2.4 TCG AND LCG CALCULATIONS .................................................................................................. 29
3.2.5 MEAN DRAFT CALCULATIONS ................................................................................................... 30
3.2.6 TRIM AND LIST CALCULATIONS ................................................................................................. 30
3.2.7 MOMENT TO HEEL ONE INCH (MH1) AND MOMENT TO TRIM ONE INCH (MT1) .................... 31
3.2.8 THE INCLINING EXPERIMENT...................................................................................................... 32
3.3 STABILITY AT LARGE ANGLES OF INCLINATION ........................................................................................ 34
3.3.1 LARGE ANGLES OF INCLINATION .............................................................................................. 34
3.3.2 STABILITY CRITERIA .................................................................................................................... 36
3.3.3 INTACT STABILITY........................................................................................................................ 37
3.3.4 IMO INTACT STABILITY CRITERIA .............................................................................................. 39
3.3.5 MAXIMUM ALLOWABLE KG......................................................................................................... 40
3.3.6 DAMAGE STABILITY ..................................................................................................................... 42
3.3.7 DAMAGE CONTROL BULKHEADS .............................................................................................. 43
3.3.8 IMO DAMAGE STABILITY REQUIREMENTS ............................................................................... 44
3.3.9 IMO REQUIREMENTS FOR AFTER FLOODING .......................................................................... 44
3.4 BALLAST CONTROL ................................................................................................................................... 46
3.4.1 STABILITY SURVEY ...................................................................................................................... 47
3.4.2 CHECKING STABILITY CALCULATIONS .................................................................................... 49
3.5 DAMAGE FLOODING COUNTERMEASURES ............................................................................................ 51
3.5.1 GENERAL DAMAGE FLOODING COUNTERMEASURES ........................................................... 51
3.5.2 COLLISION DAMAGE .................................................................................................................... 51
3.5.3 COLLISION DAMAGE FLOODING COUNTERMEASURES ......................................................... 51
3.5.4 PROCEDURES FOR UNEXPECTED LIST AND TRIM .................................................................. 53
3.5.5 CONSTANT UNEXPECTED LIST OR TRIM .................................................................................. 53
3.5.6 TRANSIT CONDITION .................................................................................................................... 54
3.5.7 WATERTIGHT INTEGRITY ............................................................................................................ 54
3.5.8 DAMAGE CONTROL COUNTERMEASURES ............................................................................... 54
3.6 GLOSSARY .................................................................................................................................................. 55
3.7 REFERENCES .............................................................................................................................................. 57
APPENDIX I ........................................................................................................................................................ 58

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VESSEL STABILITY

3.1 INITIAL STABILITY THEORY

3.1.1 WHAT IS STABILITY?

When a vessel is floating, it must be able to resist the forces of the environment and
remain upright (Figure 3.1). Stability is a way of describing the ability of a rig to resist
th e se fo rce s. In ta ct sta b ility is th e rig s a b ility to re m a in u p rig h t w h e n th e re is n o d amage
or flooding, while damage stability is the stability of a rig after flooding has occurred.
Adequate stability is a requirement for safe operation. The design and operating goal is
to maintain the vessel in a condition where accidents do not lead to catastrophes.
Stability is achieved via the interaction of buoyancy and gravity acting on the vessel. The
buoyancy force is exactly equal and opposite to the gravity force. Buoyancy is provided by
the displacement of water. Archimedes determined that the weight of displaced water is
equal to the weight of the floating object. When a vessel is floating, the buoyancy force is
exactly equal and opposite to the gravity force. The buoyancy force acts through the center
of buoyancy. This point is generally referred to as B or CB. The location of B is a function of
the hull shape. Since we can't change the hull without taking the vessel into a yard, the
position of the CB is fixed for a given draft, trim and list. The distance from the keel to the
center of buoyancy is called KB (keel, K, to center of buoyancy, B).

Figure 3.1 Floating Vessel Resisting Forces

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VESSEL STABILITY

3.1.2 ENVIRONMENTAL LOADS

Figure 3.2 shows that the

external forces that act to
overturn a vessel may be due
to one or more of the
following:
Wind
Waves
Current
Mooring tension
Crane loads
Thruster reaction
Riser tension
The wind load is typically the
largest of these external
forces, and is the only force
explicitly calculated by the
vessel designer for the
purpose of analyzing
vessel stability.

Figure 3.2 External forces acting on vessel.

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VESSEL STABILITY

3.1.3 DISPLACEMENT () & BUOYANCY FORCE

1. Displacement is the weight of water displaced by the submerged portion of a floating

object.
2. The displacement of a floating object is equal to the weight of the object.
3. "Archimedes Principle" states that when an object is immersed in a fluid, it experiences
an up-thrust (buoyancy force) equal to the weight of the fluid displaced. Thus, a vessel
floats because it displaces its own weight of water before being completely submerged.

3.1.4 CENTER OF GRAVITY (G)

The center of gravity (G) is the geometric center of mass of the vessel (Figure 3.3). G can
also be defined as the center of the concentration of the weight of the vessel and all
weights on board, and is the point at which all the downward forces of weight can be
considered to act.

Figure 3.3 - Center of Gravity

Keel (K) is the baseline or reference plane from which vertical measurements are taken.

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VESSEL STABILITY

K G is the ve rtical dista nce o f th e vessels gross center of gravity above the keel. KG is
measured in feet to the nearest hundredth. In general, a lower KG produces better stability.
Vertical center of gravity (VCG) is the distance the center of a weight is located above
the keel. VCG is measured in feet to the nearest hundredth.
The gravitational force acts through the center of gravity and is equal to the total weight
of the vessel, i.e., the sum of the lightship and the deadweight. By varying the
deadweight's location, we can manipulate the position of the center of gravity.

T h e b a re ve sse l lig h tsh ip w e ig h t a n d K G (o r V C G ) a re m a in ta in e d a s a p e rm a n e n t

re co rd in th e ve sse ls o p e ra tio n o r sta b ility m a n u a l. B y m e a n s o f a procedure called the
inclining experiment, the lightship weight and VCG are determined just after a vessel is
newly constructed. Throughout its life, a drilling vessel will undergo structural and
equipment changes that will alter its lightship weight and VCG. These changes must be
recorded as they occur so that a lightship weight reflecting the present condition of the
vessel can be stated for the stability calculations.
Deadweight is the weight of supplies and variable items such as fuel, drill water, mud,
drill pipe, casing, riser, etc.

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VESSEL STABILITY

EFFECTS OF ADDING WEIGHT TO G

Weight Added High

The Center of Gravity (G) will move toward a weight that is added (Figure 3.4). If the VCG
o f th e a d d e d w e ig h t is h ig h e r th a n th e ve sse ls K G , G w ill m o ve u p to w a rd s th e weight
that is added, creating a new KG, which is higher. In general, a higher KG produces less
stability. When adding weight, there will be an increase in displacement or mean draft.
This is representative of adding casing on a casing rack.

150.0L.T. 150.0L.T.

VCG
140.0 ft WL1
WL1 G1 WL1
WL1

WL
G WL WL G WL
new
KG G1
KG
new KG VCG
54.00 ft KG 12.00
53.50 ft

KG
100.0 L.T. K 100.0 L.T.

Figure 3.4 - Weight Added High Figure 3.5 - Weight Added Low

Weight Added Low

The center of gravity (G) will move toward a weight that is added (Figure 3.5). IF the VCG
of th e add ed w eig ht is lo w e r th an th e vessels K G , G w ill m o ve do w n to w a rds the w eigh t
added, creating a new KG, which is lower. In general, a lower KG produces better stability.
When adding a weight there will be an increase in displacement or mean draft. This
represents taking on mud low in a column or adding ballast water.

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VESSEL STABILITY

EFFECTS OF SHIFTING WEIGHT TO G

Shifting Weight Down

The center of gravity (G) will move parallel to, and in the same direction as a weight shifted.
If a weight is shifted down (Figure 3.6) from a higher VCG to a lower VCG, G will move
down, and in the same direction as the weight that was shifted. This creates a new KG,
which is lower. In general, a lower KG produces better stability. When shifting a weight,
there is no change in displacement or mean draft.

Figure 3.6 - Shifting Weight Down Figure 3.7 - Shifting Weight Up

Shifting Weight Up
The center of gravity (G) will move parallel to, and in the same direction as a weight shifted.
If the weight is shifted up (Figure 3.7) from a lower VCG to a higher VCG, G will move up,
and in the same direction as the weight that was shifted creating a new KG, which is higher.
In general, a higher KG produces less stability. When shifting a weight, there is no change
in displacement or mean draft.

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 VESSEL STABILITY

EFFECTS OF REMOVING WEIGHT TO G

Upper Weight Removed

The center of gravity (G) will move away from a weight that is removed. If the VCG of the
removed weight is high er tha n th e vessels K G , G w ill m o ve d o w n a w a y fro m the w eig ht
removed. This creates a new KG, which is lower. In general, a lower KG produces better
stability. When removing a weight there will be a decrease in displacement or mean draft.

WL1 WL1 WL1 WL1

Figure 3.8 Removing Upper Weight Figure 3.9 Removing Lower Weight

Lower Weight Removed

The center of gravity (G) moves away from a weight that is removed. If the VCG of the
re m o ve d w eight is lo w er than the vessels K G , G w ill m o ve u p, and a w a y fro m the w eig ht
removed. This creates a new KG, which is higher. In general, a higher KG produces less
stability. When removing a weight there will be a decrease in displacement or mean draft.

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VESSEL STABILITY

3.1.5 CENTER OF BUOYANCY

The center of buoyancy (B) is located at the geometric center of the underwater portion of
the vessel. KB is the vertical distance in feet from the keel to the center of buoyancy. KB
cha nge s as the vessels m ea n d ra ft chan ges.

Figure 3.10 Forces of Buoyancy Figure 3.11 Changes in Buoyancy

When Weight is Added

Effect of Adding Weight to B

An increase in displacement causes an increase in draft. With an increase in draft (Figure
3.11), the underwater portion of the hull increases causing B to move up to the new
geometric center. The new KB therefore increases in height. As draft increases, KB
increases.

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VESSEL STABILITY

Effect of Removing Weight to B

A decrease in displacement causes a decrease in mean draft. With a decrease in mean
draft, the underwater portion of the hull decreases causing B to move down to the new
geometric center (Figure 3.12). The new KB therefore decreases in height. As draft
decreases, KB decreases.

Figure 3.12 Changes in Buoyancy When Weight is Removed.

R em o ving W eight D ecrease D raft

Figure 3.12 Changes in Buoyancy When Weight is Removed

The center of gravity section discussed how the adding, removing or shifting of weights
would affect location of G. The center of buoyancy section discussed how lowering or
raising the draft would affect the location of B. However, during actual drilling operations,
the Ballast Control Operator (BCO) will maintain a constant draft for the drilling vessel.
Thus if a weight is added removed or shifted, the BCO will remove, add or shift ballast
water to compensate for the change in the weights to maintain the constant draft.

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VESSEL STABILITY

3.1.6 INCLINATION

In initial stability theory, when the vessel is inclined to a small angle of about 10o, the center
of buoyancy (B) moves to the inclined (low) side/end. This movement is in the arc of a
circle until it reaches the new geometric center of the underwater portion of the rig. Since
the rig is three-dimensional, the location of G or B must be described in the vertical,
transverse and longitudinal planes.

WL WL

Figure 3.13 - Movement of B During Inclination Figure 3.14 First Dimension - Vertical

FIRST DIMENSION - VERTICAL

There are three things that can be said about the relationship between the forces acting
upon G and B, causing the rig to float:
1. They are equal.
2. They are opposite.
3. They line up vertically with one another when the rig comes to rest.

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VESSEL STABILITY

SECOND DIMENSION - TRANSVERSE

When looking at the rig transversely (port to starboard) in Figure 3.15, the rig will have a
transverse center of gravity (TCG) and a transverse center of buoyancy (TCB).
When the rig is sitting level with zero degrees of list and is in a static position (not affected
by the environment), TCG will align with the TCB upon the centerline of the rig.
TCG and TCB are reported in feet from the centerline of the rig. Thus when the rig is level,
TCG = TCB = 0 feet.

Figure 3.15 No Inclination Figure 3.16 Second Dimension - Transverse

Weight Shift in the Transverse Plane

With the rig level, a 300-ton load is shifted in Figure 3.16 from the starboard side amidships
to the port side amidships. The TCG would move in the same direction as the load that was
shifted and cause the rig to list to the port side. In theory the TCB will move to the low side
in the arc of a circle until it reaches the center of the underwater portion of the rig and is
vertically under the TCG.

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VESSEL STABILITY

Third Dimension - Longitudinal

When looking at a rig longitudinally (bow to stern) in Figure 3.17, you will notice that the
lower hull is not designed equally on both sides of the amidships. This causes the
longitudinal center of buoyancy (LCB) to be aft of the amidships line. The LCB is aligned
with the geometric center of the underwater portion of the rig.
The longitudinal center of gravity (LCG) and LCB are reported in feet from the amidships
line of the rig.
When the rig is sitting level with zero degrees of trim and is in a static position (not affected
by the environment), the LCG distance from amidships equals the LCB distance from
amidships, and they are aligned vertically.

Figure 3.17 - Longitudinal Center of Gravity Figure 3.18 Third Dimension - Longitudinal

Weight Shift in the Longitudinal Plane

With the rig level, a 30-ton load in Figure 3.18 is shifted from the bow centerline to the stern
centerline. The LCG would follow the load that was shifted and cause the rig to trim to the
stern side. In theory, the LCB will move to the low side in the arc of a circle until it reaches
the center of the underwater portion of the rig and is vertically under the LCG.

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VESSEL STABILITY

3.1.7 METACENTER

When a rig lists, the center of buoyancy swings in an arc. The origin point for the arc is
called the metacenter (M) (Figure 3.19). The M is located by the intersection of a vertical
line above the original center of buoyancy (B) when the vessel is level, and a vertical line
above the new center of buoyancy (B1) when the vessel is inclined to a small angle of about
10 degrees. The metacentric radius, BM, is the radius length of the arc that the center of
buoyancy swings along.

Figure 3.19 - Metacenter Figure 3.20 BM and KM

The height of the metacenter in Figure 3.20 above the keel (KM) is measured in feet and is
determined by the KB and the metacentric radius, BM. KM changes as mean draft
changes.
KM = KB + BM
KM = Height of the Metacenter, feet
KB = Height of the center of buoyancy, feet
BM = Metacentric Radius, feet

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VESSEL STABILITY

As displacement and mean draft increase in Figure 3.21, the volume of displacement
increases, which increases KB. If the waterplane area does not change, the net result is
that BM is reduced causing the metacenter to lower, creating a smaller KM.

Figure 3.21 - Increase in Volume of Displacement Figure 3.22 Decrease in Volume of Displacement

As displacement and mean draft decrease in Figure 3.22, the volume of displacement
decreases. If the waterplane area does not change, the net result is that BM increases,
causing the metacenter (M) to rise, creating a higher/larger KM.

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 VESSEL STABILITY

3.1.8 METACENTRIC HEIGHT

As shown in Figure 3.23, metacentric height (GM) is the vertical distance in feet from
the center of gravity (G) to the metacenter (M). G must be lower than M (KG less than
KM) for the vessel to have positive stability.
G M is th e m easure o f a vesse ls initialsta bility. A s G M incre a ses, the vessels in itial stability
increases. As GM decreases, the vessels in itial stability d ecre ases.
For any particular mean draft, M will remain constant, and as such, only the movement of G
will affect GM. As displacement and mean draft change, GM will be affected both by the
movement of G and M.

GM
G

KM
KG
WL
B

Figure 3.24 Increase in KG

Figure 3.23 Metacentric Height

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VESSEL STABILITY

KG must always be subtracted from KM (Height of Metacenter) to find the GM (Metacentric

Height). GM = KM KG, in feet. There are three ways KG can be lowered for an increase
in GM.
1. A d din g w eig ht at a V C G low er tha n th e vesse ls K G . G w illb e lo w e re d; in a dditio n,
displacement and mean draft will increase which may cause M to lower slightly.
2. Shifting weight vertically downward. G will be lowered and the metacenter (M) will not
change as there is no change in displacement or mean draft.
3. Removing weight at a VCG highe r th an th e vesse ls K G . G w illb e lo w e re d and since
displacement and mean draft will decrease, the metacenter may increase slightly
providing a larger GM than either of the above methods.
GM increases as KG decreases (initial stability increases). Conversely, KG can be
increase which will cause a reduction in GM. KG can be increased by adding weight higher
tha n th e vessels K G , re m o ving w eig ht lo w e r th an th e vessels K G , or shifting w eig ht
vertically upward. GM decreases as KG increases (initial stability decreases).

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VESSEL STABILITY

3.1.9 RIGHTING ARM (GZ) AND RIGHTING MOMENT (RM)

Righting arm (GZ) is the horizontal distance between the vertically downward force of
gravity (G) and the vertically upward force of buoyancy (B) after the vessel has been
inclined by an external force. GZ is a distance in feet measured along a line from the
center of gravity to a point (Z) perpendicular to a line representing the buoyancy force.
Righting moment (RM) is the amount of force available to right the vessel. R M is the
product of the displacement () and the righting arm (GZ). RM= x GZ.
As KG decreases in Figure 3.25, GM increases creating a longer righting arm (GZ) and
therefore a larger righting moment (RM).

Environmental Forces
Environmental Forces

Figure 3.25 Righting Arm (GZ) Increases Figure 3.26 Righting Arm (GZ) Decreases

As KG increases in Figure 3.26, GM decreases, creating a shorter righting arm (GZ) and
therefore a smaller righting moment (RM).
A rig s sta bility can be d e scribed a s p ositive , n eu tral or ne ga tive.

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VESSEL STABILITY

POSITIVE STABILITY (STABLE EQUILIBRIUM)

When the center of gravity is below the metacenter, a positive righting arm exists. If the
vessel is inclined to a small angle by an external force, the vessel will return to an upright
position after the external force is removed.
In positive stability as shown in Figure 3.27, the KG is less than the KM, and a positive
righting arm exists.

Figure 3.27 Positive Stability Figure 3.28 Neutral Stability

NEUTRAL STABILITY (NEUTRAL EQUILIBRIUM)

When the center of gravity is at the same vertical height as the metacenter, no righting arm
exists. If the vessel is inclined to a small angle by an external force, the vessel will remain
in the inclined position after the external force is removed. In neutral stability (Figure 3.28),
the KG equals the KM. The angle at which the vessel comes to rest with neutral stability is
called the angle of loll. This is its new initial position, and if further heeled by an external
force, will return to this position when that force is removed.

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VESSEL STABILITY

NEGATIVE STABILITY (UNSTABLE EQUILIBRIUM)

When the center of gravity is above the metacenter as shown in Figure 3.29, a negative
upsetting arm exists. If the vessel is inclined to a small angle by an external force, the
vessel does not have any initial stability, which means it will continue to incline until there is
no longer an upsetting arm. In negative stability, the KG is greater than the KM. Negative
stability is an extremely dangerous condition and must be avoided. A negative GM will
never be encountered if proper loading procedures are followed. Daily stability calculations
must include checking for negative stability if the rig must be raised to survival draft or if the
BOP and riser must be pulled.

Figure 3.29 Negative Stability

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VESSEL STABILITY

The list below describes several characteristics of a negative GM situation.

A negative GM (metacentric height) results when KG increases and becomes larger
than KM. In other words, the center of gravity is higher than the metacenter. A
semisubmersible drilling rig is designed to safely operate when at its operational draft.
Weights are concentrated mainly at two levels; the main deck, containing the
variable/live deck loads and the lower hulls, containing ballast, drill water and fuel oil.
At operational draft, a semisubmersible drilling rig has a larger concentration of weight
in the lower hulls. This provides a relatively low KG while maintaining a satisfactory KM
and as a result, an adequate GM.
Perhaps the greatest risk of negative GM occurring is when deballasting to the smaller
drafts. Potentially at several drafts while deballasting the KM decreases and the KG
increases due to loss in lower hull ballast. Possibly at the same time, if the deck load
does not decrease, a negative GM can occur.
A negative GM (metacentric height) does not necessarily mean that a vessel will
capsize. When the vessel starts to heel over, her breadth at the waterplane increases.
This causes an increase in BM, which may eventually bring the metacenter above the
center of gravity.
It is imperative that the cause of any unexplained list or trim be determined before
corrective action is taken. Attempting to correct a list/trim caused by negative GM using
normal ballasting procedures may cause the vessel to flop to the opposite side with an
increased angle of loll, or fail to correct the situation.
The figure below shows an example of the righting moment that is generated by a vessel
as a function of inclination or heel angle. This curve is called the righting moment curve.
At zero inclination the righting moment is zero. However, any small inclination generates
a moment that tends to push the vessel back to the zero inclination point. The righting
moment increases with inclination up to a point (label ). This is the maximum righting
moment. If the inclination continues to increase, the righting moment decreases until an
inclination is reached where the righting moment becomes negative and the vessel
capsizes (label ). We want to operate with inclinations betwe e n ze ro a n d .
8000

7000

6000
Righting Moment

5000

4000

3000

2000

1000

0

0 5 10 15 20 25 30 35 40 45 50
Inclination (degrees)

Figure 3.30 Righting Moment

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VESSEL STABILITY

FREE SURFACE (FS)

Our study of the effect of loading on stability has thus far considered only secured loads
those whose center of gravity do not move as the vessel inclines. What happens when a
load, such as liquid in a partially full tank, is free to move? This condition is known as free
surface (FS).
A liquid free to move as the vessel inclines will do so to maintain its surface horizontal. As
the liquid moves, its center of mass (centroid) shifts toward the low side. This causes G of
the vessel to shift to the low side parallel to the shift of weight in the tank, thereby reducing
the righting arm (GZ).
Consider a tank partially full of liquids as shown in Figure 3.31. Assume that inclination is
such that pocketing does not take place. Pocketing means the liquid touches the top or
uncovers the bottom surface as
the tank inclines. Pocketing
reduces the effect of free surface.
With inclination, the center of
gravity of the liquid in the tanks
shifts to the low side of the tank.
The center of gravity of the entire
vessel will also shift parallel to the v
transfer of weight within the tank.
This shift is shown as the
movement from G to G1. The
weight of the vessel then acts
through G1, which means that it
also acts through G1V, which is on
the intersection of the line of
action and the centerline. GM is
reduced by the distance G G1V
(free surface correction).
The effects of free surface
depend upon the dimensions of
the surface of the liquid and the Figure 3.31 Free Surface Effect
volume of displacement of the
vessel. The wider a tank (in the
transverse direction or the direction of heel), the more free surface it has. Thus, partially
filled tanks with a large transverse dimension will have a much larger free surface effect
than tanks with a narrow transverse dimension.
A ship or semisubmersible incorporates several large tanks for carrying ballast, fuel oil,
drill water, potable water, sewage and liquid mud. The cumulative free surface effect for
all partially filled tanks can be significant and must be accounted for when evaluating the
ve sse ls sta b ility.
Where practical, the number of partially filled tanks should be minimized to reduce their
effects on stability.

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VESSEL STABILITY

3.2 STABILITY CALCULATIONS

3.2.1 KG CALCULATIONS

Displacement (Weight) KG (VCG) = Vertical Moments in ft-tons

KG (VCG) = Total Vertical Moments
Total Weights (Displacement)

ADDING WEIGHT
Your present displacement is 14,000 long tons. KG at this displacement is 62.00 feet. 200
long tons of casing is loaded on your deck at a VCG of 130.00 feet. How will KG be
affected with the addition of the weight? To find the answer, follow these steps:
1. Multiply original displacement by
original KG. The result will be a vertical
moment of force in ft/tons. 14,000 LT 62.00 FT = 868,000 ft-tons
2. Multiply the loaded weight by its VCG. 200 LT 130.00 feet = 26,000 ft-tons
3. Add the load to original displacement 14,000 + 200 = 14,200 LT
and add the moments of force to get 868,000 + 26,000 = 894,000 ft-tons
4. Divide the total moments by the total
displacement. The result, expressed in
feet, is the new KG. 894,000 14,200 = New KG at 62.96 feet.

Because the weight was added above the original center of gravity, G moved up a total of
0.96 ft.

REMOVING WEIGHT
In order to determine the shift of KG when weights are removed, the only difference in the
process is that the weight and moments are subtracted from the original displacement and
moments. Suppose your original displacement was 18,500 long tons and your KG was
68.00 feet. If 210 long tons at a VCG of 115.00 feet were discharged, the computation
would be:
ORIGINAL DISPLACEMENT: 18,500 LT 68.00 FEET = 1,258,000 ft tons
Load removed: - 210 LT 115.00 feet = - 24,150 ft tons
New displacement: 18,290 long tons 1,233,850 ft tons
1,233,850 18,290 = New KG at 67.46 feet.

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SHIFTING WEIGHT
Calculating the new KG when weights are shifted is actually a process of removing
(subtracting) a weight from its old VCG and then adding the same weight to its new VCG.
Example: The rig has a displacement of 21,000 long tons and a KG of 58.00 feet. A
weight of 180 long tons with a VCG of 110.00 feet is moved to a VCG of 167.00 feet.
WEIGHT KG\VCG VERTICAL MOMENTS
21,000 58.00 feet 1,218,000 ft-tons
-180 110.00 feet - 19,800 ft-tons
+180 167.00 feet + 30,060 ft-tons
21,000 1,228,260 ft-tons
1,228,260 21,000 = New KG at 58.49 feet.
The original displacement is multiplied by the original KG to obtain the vertical moments
before the weight is shifted. The shifted weight is assigned a minus (-) sign, placed in
the weight column and multiplied by its original VCG to determine a negative moment.
The shifted weight is then added back (assigned a plus (+) sign), placed in the weight
co lu m n a n d m u ltip lie d b y its n e w K G w h ich is p la ce d in th e m o m e n ts co lu m n . T h e
moments are then totaled and divided by the displacement (which will be the original
displacement as the weight was not added or removed from the rig).

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3.2.2 FREE SURFACE CALCULATIONS

As discussed earlier, free surface occurs in a liquid tank that is partially full. The effects of
free surface depend upon the dimensions of the surface of the liquid and the volume of
displacement of the vessel. Free surface causes a virtual rise in the center of gravity.
Three formulas are used:
1. The first formula is used to find free surface moments when the dimensions of a
rectangular tank, the specific gravity (SG) of the liquid in the tank, and the specific
gravity of the liquid in which the vessel is floating are known.
2. The second formula is used to find the free surface correction.
3. T he third fo rm ula is used to a dd the free su rfa ce correctio n to the vessels K G to o btain
the corrected KG.
Equation 1A - Free Surface Moment Transverse (FSMT)
FSMT = rlb3
420
Equation 1B - Free Surface Moment Longitudinal (FSML)
FSML = r l3 b
420
r = S. G. of liquid in the tank divided by the S. G. of liquid the vessel is floating in.
l = Length of tank measured along its longitudinal side, feet.
b = Breadth of tank measured along its transverse side, feet.
420 = Constant for a vessel using long tons as its unit of measurement.

Equation 2 - Free Surface Correction (FSC)

2A - Free Surface Correction Transverse (FSCT), ft
FSCT = FSMT
DISPLACEMENT

2B - Free Surface Correction Longitudinal (FSCL), ft

FSCL = FSML
DISPLACEMENT
Where displacement is given in long tons.
Equation 3 - KG Corrected For Free Surface
3A - Transverse direction
KGT = KG + FSCT
3B - Longitudinal direction
KGL = KG + FSCL
Note: that correction for free surface increases KG, which will reduce GM or decrease
stability.

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Sample Problem
A vessels displace m en t is 1 3,0 00 lo n g tons, flo ating in salt w a ter. T he vessels K G is
64.38 feet. A salt-water tank 50-ft in length and 30 ft in breadth has been added to the
vessel. If the tank were half full of seawater what would be the transverse and longitudinal
free surface corrections to KG?

FSMT = rlb3 = 1 x 50 x 30 x 30 x 30 = 3,214 FSMT

420 420

FSCT = FSMT = 3,214 FSMT = 0.25 FSCT

Displacement 13,000 long tons

KGT = KG + FSCT = 64.38 + 0.25 = 64.63 KGT

This example only shows the transverse calculation. The longitudinal calculation will also
need to be performed. For normal free surface correction problems aboard a rig, the free
surface moments are already calculated for each tank sounding located in tank sounding
tables. Figure 3.32 depicts how the free surface effect depends on the shape of the tank.

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Figure 3.32 Free Surface Effects

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3.2.3 METACENTRIC HEIGHT (GM) CALCULATIONS

Metacentric height (GM) is a distance in feet measured from the center of gravity (G) to the
height of the metacenter (KM). As long as KG is numerically less than KM, the vessel
possesses positive initial stability, and GM is positive. Should KG be numerically greater
than KM, the vessel possesses negative initial stability (the vessel is in an unstable
con dition ), a nd G M w ou ld b e n eg ative. S ince m e tacentric he ight is a m e a sure o f a vessels
initial stability, GM must be calculated for any loaded condition.
The basic formula is: GM = KM - KG
Where:
GM = metacentric height, feet.
KM = heigh t o f th e m e tacen te r, fe et. F ou nd in the vesse ls h ydrostatic
tables/curves for a particular mean draft or displacement.
KG = height of the center of gravity, feet (based upon the known location
of all weights, and determined by calculation).

O nce the vessels K G has b ee n d ete rm ine d, the fre e su rface (F S ) co rrection m ust be
calculated. Since FS causes a virtual rise in th e vessels center of g ra vity and is d iffere nt in
both longitudinal and transverse directions there will be two corrected KGs; KGT and KGL.
Since there are two KGs, there are correspondingly two KMs, KMT and KML. Therefore
two GMs must be calculated, GMT and GML. KMT and KML are tabulated separately in the
vesse ls h yd rosta tic ta ble s fo r an y p articu la r m ea n dra ft o r displace m en t.

The GM formulas are: GMT = KMT KGT

GML = KML - KGL

3.2.4 TCG AND LCG CALCULATIONS

The Transverse Center of Gravity (TCG) and the Longitudinal Center of Gravity (LCG) are
determined in exactly the same manner as the vertical center of gravity.
The TCG of any particular load (logging skid, casing load, container, etc.) is its distance in
feet to port (-) or to starboard (+) o f th e vessels fore a nd a ft ce nte rline . A b oard a
semisubmersible drilling rig the LCG of a weight is its distance forward (-) or aft (+) of
amidships. For a drill-ship, LCG is measured in feet either aft of the forward perpendicular
or forward of the aft perpendicular.
The TCG and LCG for each item are first determined. The weight of the load is multiplied
by the respective TCG and LCG to determine the transverse moments (TM) and
longitudinal moments (LM).
The transverse and longitudinal moments for all loads are added and then divided by the
vesse ls disp lace m en t to determ in e th e rig 's T C G and L C G .

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3.2.5 MEAN DRAFT CALCULATIONS

Mean draft calculations are used to determine the following:

chain calculations maximum allowable KG
transit operational drafts
survival large angle stability tables
often used as the entering figure when using the hydrostatic tables.
A drillships m ea n d ra ft is a n a ve ra g e o f th e forw ard a nd a ft d rafts. A se m isub m e rsib le
drillin g rigs dra ft is the a verag e o f all four (4) draft marks located on the columns.
Mean draft can also be calculated using the formula; change in mean draft = weight loaded
or discharged TPI (tons per inch of immersion). TPI is located in the hydrostatic tables for
a specific range of mean drafts or displacements.

3.2.6 TRIM AND LIST CALCULATIONS

Trim is the difference between the drafts forward and aft. If the draft aft is greater than the
draft forward, the vessel is said to be trimmed (or down) by the stern. If the forward draft is
greater than the draft aft, the vessel is said to be trimmed (or down) by the bow.
List or heel is the difference in feet and inches between the port and starboard drafts. If the
port drafts are greater, the vessel is listed/heeled to port. If the starboard drafts are greater,
the vessel is listed/heeled to starboard.
Trim and list are calculated from the draft readings.
The most common means of referring to trim and list is in degrees. The control room
operator compensates for added, discharged and shifted weights by pumping ballast from
or into lower hull ballast tanks and from column tanks. The control room operator uses
transverse and longitudinal inclinometers measuring list and trim (respectively) in degrees
to accomplish this.

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3.2.7 MOMENT TO HEEL ONE INCH (MH1) AND MOMENT TO

TRIM ONE INCH (MT1)

A vessels list/h eel a nd trim ca n be calcula te d usin g the T he ory of M o m e nts. A w eight
moved through a distance equals a moment. The total heel or trim moments are
calculated, and when divided by the MH1 or MT1, heel or trim is determined. MH1 or MT1
may be available on the hydrostatic curves or determined from formulae.

MOMENT TO HEEL ONE INCH (MH1) FORMULA:

MH1 = GMT
12B

= Displacement, Long Tons

B = Distance between transverse (Port & Stbd.) draft marks, feet.

HEEL OR LIST IN FEET FORMULA USING (MH1):

Heel/List, (ft) = TCG
MH1

MOMENT TO TRIM ONE INCH (MT1) FORMULA:

MT1 = GML
12L
L = Distance Between Longitudinal (Fore & Aft.) Draft Marks, feet.

TRIM IN FEET FORMULA USING (MT1):

Trim, (ft) = (LCG - LCB)
MT1

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3.2.8 THE INCLINING EXPERIMENT

The inclining experiment is performed on a vessel after construction and at periodic

intervals th ereafte r; to verify a vessels calculate d K G , u su ally fo r the ligh tship condition. In
carrying out the test, a plumb line is suspended down to a graduated batten that is set
horizontally (Figure 3.33). A known weight is then shifted transversely a known distance
(Figure 3.34), causing the vessel to list and the plumb line to move across the batten. The
deflection is measured. Combining displacement, known weight, the distance the weight is
moved, length of plumb line and deflection the GM can be calculated. KG is determined by
subtracting GM from the KM based upon the vessels m e an d raft a t the tim e o f th e
experiment.
Formula: GM = WT. x Distance ______
Displacement x TAN of Heel
To find TAN of Heel:
Take deflection in inches (A) (L) plumb line length in feet x 12 in.

Figure 3.33
Figure 3.34

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Sample Problem:
A semisubmersible drilling rig with a displacement of 14,566 long tons and KMT of 81.52
ft is preparing for an incline test. A weight of 40 long tons is moved a distance of 68 ft to
port. The plumb line length is 50 ft and deflection is 24 in.
1. W h a t is th e ve sse ls K G T ?
(A) in. 24 in.
TAN = (L) ft x 12 in. TAN = 50 ft x 12 in. TAN = 0.04
40 L. T. x 68 ft 2720
GM = 14566 L.T. x 0.04 GM = 582.64 GM (GMT) = 4.67 ft
KGT = KMT (-) GMT
KGT = 81.52 (-) 4.67
KGT = 76.85 ft
KG = KGT (-) FSCT

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3.3 STABILITY AT LARGE ANGLES OF INCLINATION

3.3.1 LARGE ANGLES OF INCLINATION

When a vessel heels beyond a small angle of about 10 degrees (Figure 3.35), the center of
buoyancy (B) continues to move to the inclined side and the metacenter (M) increases in
height due to an increase in waterplane area at the new waterline. The result is an
increase in stability as metacentric height and righting arm increase, providing that the
center of gravity does not increase in height, or shift to the inclined side.

WL

WL1
WL1

WL

Figure 3.35 Stability at Large Angles Figure 3.36 Downflooding Angle

The angle of inclination at which maximum righting arm is developed is the angle at which
the deck edge becomes immersed. This is called the downflooding angle (Figure 3.36). At
this angle the maximum wedge of buoyancy has been gained on the immersed side. The
maximum angle in degrees at deck edge immersion is governed by the amount of
freeboard. The larger the freeboard, the larger the maximum angle.
At deck edge immersion, maximum waterplane area will have been achieved; thus KM will
have reached its highest point. After deck edge immersion, the waterplane area will
decrease rapidly, causing a lowering of the metacenter and a rapid decrease in GM.

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After the deck edge is immersed, no additional buoyancy can be gained. Any further
inclination, (heel) past deck edge immersion, causes the line of force through the center
of gravity to move closer to the line of force through the center of buoyancy creating a
decrease in righting arm. After deck edge immersion, seawater may be downflooded
into chain lockers, vents, hatches, and doors causing a further reduction in righting arm
due to a lateral shift in the center of gravity.
There are limits as to how much inclination a vessel can survive. The most common
limitation is the angle where compartments begin to flood (Figure 3.37). This angle is
the downflood inclination (downflooding through portholes, etc. may occur before deck
edge immersion). On an open boat, the downflood inclination is where the deck edge
goes under water. On MODUs, downflooding generally occurs through vent lines,
hawse pipes, or weathertight doors. In all cases, stability criteria focus on preventing
downflooding.

Figure 3.37 Downflooding Occurs

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3.3.2 STABILITY CRITERIA

Our vessel needs to be stable in every operating condition. The International Maritime
Organization (IMO) publishes rules that detail required stability criteria for MODUs. The
IMO MODU Code addresses three types of criteria for the vessel:
Intact Stability -- Normal Operating Condition; limiting design wind speed is 70 knots.
Intact Stability -- Severe Storm (or Survival) Condition; limiting design wind speed is 100
knots.
Damage Stability limiting design wind speed is 50 knots.
These rules (or criteria) have been developed over time, taking into account research in
stability and lessons learned from stability-related accidents.
Often, individual nations (like Norway and the United States) will have their own stability
criteria, but they are generally similar to or based on the IMO Code.
It is important to understand that the criteria are not arbitrary restrictions. Their purpose
is to ensure that MODUs and other vessels are designed and operated safely. Failure to
satisfactorily meet the loading condition limits in the Trim and Stability book can lead to
capsize, loss of a vessel and loss of life.

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3.3.3 INTACT STABILITY

To determine how much stability is required, we compare a vessel's righting moment

against a design overturning or heeling moment. Drilling units have large, high topsides.
Winds acting against the topsides will try to overturn the rig. These lateral forces are
reacted by the anchor lines, thrusters, or simply the water drag. The vertical separation
between the lateral forces creates a couple that tries to incline the vessel. Like the
righting moment, the overturning or heeling moment due to the wind can be plotted as a
function of inclination angle as shown in Figure 3.38. Intact stability criteria usually
compare the heeling moment generated by the wind against the righting moment curve
of the vessel.

8000

7000

6000

5000
Righting Moment

4000
g M om ent B
3000 A W in d H eelin
Downflood

2000

1000

0

0 5 10 15 20 25 30 35 40 45 50
Inclination (degrees)
Figure 3.38 - Righting Moment Curve with Wind Heeling Curve and
Downflooding Angle

We gauge the amount of stability by comparing the heeling moment curve against the
righting moment curve. At zero inclination, the wind heeling moment is greater than the
righting moment. The two curves cross at point A. This point is the static inclination
where the wind moment and righting moment are in equilibrium. The vessel would have
this amount of inclination in a steady wind. At some greater inclination, point B, the
righting moment curve crosses the wind-heeling curve a second time. This is called the
second intercept. If the inclination exceeds this angle, the righting moment becomes
less than the heeling moment and the wind will capsize the vessel.
Stability criteria considers the righting moment curve and the heeling moment curve from
the upright condition with zero degrees inclination to the downflooding inclination or the
second intercept inclination, whichever is less.

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The area under the righting moment curve between two angles of inclination represents
the energy required to right the rig. Similarly, the area under the inclining moment curve
between two angles of inclination represents the energy provided by the wind to incline
the rig. In Figure 3.39, areas 1 and 2 correspond to the energy associated with the wind
overturning the vessel up to the downflood angle and areas 2 and 3 represent the
required energy to incline the vessel to this same angle. In all cases, we want areas 2
plus 3 to be greater than 1 plus 2. In other words, that the energy required to list the rig
to the downflooding angle is more than the energy provided by the wind.

8000

7000

6000

5000 3
Righting Moment

4000

3000

2000
1 2
1000

0
0 5 10 15 20 25 30 35 40 45 50
Inclination (degrees)
Figure 3.39 - Righting Moment and Wind Heeling Moment
Illustrating Areas Considered in Stability Criteria

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3.3.4 IMO INTACT STABILITY CRITERIA

The IMO intact stability criteria for MODUs require the righting energy to exceed the
overturning energy by a factor of 1.3 for semisubmersibles (area 2+3 >= 1.3 * {area
1+2}) or 1.4 for ships and barges (2+3 >= 1.4 * {1+2}). The factors of 1.3 or 1.4 provide
some margin for other forces such as waves and currents that act on the vessel and for
uncertainty in weight surveys performed on the rig. Semisubmersibles are not as
susceptible as ships to large roll angles, and thus have a lower factor (1.3 versus 1.4).
In the Normal Operating Condition, the wind heel curve is based on a 70-knot wind
speed, and for the Severe Storm (or Survival) Condition, a 100-knot wind speed must be
used. Since the wind force is proportional to the square of the wind velocity, the
overturning moments in the Severe Storm Condition are approximately double the
moments of the Normal Operating Condition. For the Severe Storm Condition, the
MODU may be deballasted, but removal or relocation of solid consumables or other
variable load is not allowed. Deballasting increases the freeboard, which increases the
reserve buoyancy and the downflooding angle, and usually also increases the righting
moment curve.

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3.3.5 MAXIMUM ALLOWABLE KG

The righting moment curve may be adjusted to obtain the desired area ratio (1.3 or 1.4)
by vertically moving the center of gravity of the rig. Lowering KG increases the height of
the GZ curve, increases the area under the righting moment curve, and for the same
windforce, increases the area ratio. Conversely, increasing KG reduces the area ratio.
The corrected KG which provides the required design area ratio (1.3 for
semisubmersibles and 1.4 for drillships) for intact stability and provides an area ratio of
1.0 for damaged conditions is known at the Maximum Allowable KG (also called KG
Max). Of all the restrictions the marine crew must comply with while operating the rig in
the floating mode, this is the most important. Maintaining KG below the maximum
allowable KG (Figure 3.40) ensures that the stability will be positive.
ALLOWABLE KG (ft)

Figure 3.40 Maximum Allowable KG

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Operating with the rig KG below the maximum allowable KG will allow the rig to
withstand 70-knot winds at operating draft and 100 knot winds at survival draft. In a
damaged condition, the rig will be able to withstand 50-knot winds.
T h e m a xim u m a llo w a b le K G is d isp la ye d in th e rig s o p e ra tio n a l m a n u a l a s a cu rve
similar to figure 3.40. Note that for any draft there is a maximum allowable KG
depending on the wind. For winds greater than 70 knots, the rig must be operated below
the 100-knot wind curve. With winds less than 70 knots, the rig may be operated safely
below the 70-knot curve.
Changing the KG to meet wind limitations from 70 to 100 knots can be difficult. Material
may need to be offloaded from the rig or moved lower in the rig. The BCO must perform
d a ily ch e cks o f th e rig s sta b ility to e n su re th e rig ca n su rvive h ig h e r w in d sp e e d a n d
deballasting to survival draft. Contingency plans should be in place to address deck-
loading moves to meet survival conditions or higher wind speeds if necessary.

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3.3.6 DAMAGE STABILITY

The IMO Code also includes stability criteria and related requirements for cases in which
the vessel is damaged.

Subdivision and IMO Damage Events

Subdivision, which means the number, size and location of watertight compartments,
bulkheads, and decks, is an important design feature required by the IMO Code. The
Code specifies that the vessel must be able to withstand a typical size damage:
Horizontal penetration -- 1.5 meters of horizontal penetration
Vertical extent:
ships and jackups -- from the keel to the top of the hull
semisubmersibles -- 3 meters occurring anywhere between 5 meters above
the highest operating draft and 3 meters below the lowest operating draft
Horizontal length:
ships and jackups -- 3 meters (actually, the Code states that for a
compartment to count as a single compartment, its bulkheads must be at
least 3 meters apart)
semisubmersibles -- up to 1/8th of the column circumference (or 45 around
the outside of the column)

Progressive Flooding:
All piping and ventilation within the damage zone is assumed to be damaged.
Positive means of closing off the damaged compartment and any damaged piping or
ventilation ducts must be provided so that the flooding can be stopped from spreading
to other compartments.

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3.3.7 Damage Control Bulkheads

On semisubmersibles and newer jackups, these damage criteria result in designs that
have damage control bulkheads. Typically, the damage control bulkheads parallel
the shell at a distance inboard somewhat more than 1.5 meters (but only in the waterline
region where IMO allows damage). This results in relatively small compartments
(usually voids or seawater ballast tanks) at the exposed sides of the columns or hull that
limit the flooding should they be damaged. Figure 3.41 shows the typical
compartmentation of a semisubmersible column in the draft range subject to damage.
Drillships normally have adequate compartmentation and reserve stability to withstand
damage without needing damage control bulkheads or double-sides.

> 1.5 meter

Column
Interior
Sea Water Ballast
Tanks

Figure 3.41 Cross Section of a Typical Semisubmersible Column

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3.3.8 IMO DAMAGE STABILITY REQUIREMENTS

The IMO Code prescribes that the vessel must withstand the heel from a wind speed of
50 knots from any direction after damage has occurred. The final waterline must be
below any opening that could result in downflooding. For semisubmersibles, the
following additional requirements apply:
The angle of inclination after damage, and with wind, must be less than 17
All openings within 4 meters above the final waterline are required to be weathertight
The range of positive righting moment must be at least 7 (to the 2nd intercept or the
downflood point)
At some angle within the range of positive righting moment, the righting moment must
reach a value of twice the wind heeling moment.
Some nationalities prescribe an area requirement in the damage condition, similar to the
IMO intact criteria shown in the Figure 3.42. Typically, the area requirement is 1.0.

3.3.9 IMO REQUIREMENTS FOR AFTER FLOODING

1st Intercept 2nd Intercept

Righting
Moment

< 17 > 7
RM

WH
Downflood
At some angle in the
range of positive stability, Angle of
RM >= 2 x WH Inclination

Figure 3.42 - Righting Moment after Damage -- IMO Rules for Semisubmersibles

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The vessel must not sink or capsize if any single compartment is flooded due to the
extent of damage noted previously. For semisubmersibles, in addition to damage within
the damage zones, flooding may include any compartment adjacent to the sea or any
compartment containing a potential source of a sea water leak, such as a pump room.
For semisubmersibles, the following requirements also apply:
The angle of inclination after flooding must be less than 25
The range of positive righting moment must be at least 7 (Figure 3.43).

1st Intercept 2nd Intercept

Righting
Moment
< 25 > 7

Angle of
Inclination

Figure 3.43 - Righting Moment after Compartment Flooding, IMO Rules for Semisubmersibles

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3.4 BALLAST CONTROL

On a semisubmersible, the marine crew responsible for ballast control functions usually
consist of a Barge Engineer or a barge master who is in charge of two or three ballast
control room operators (BCO). Their duties as a crew include arranging and supervising
cargo transfers, operating the mooring system, and insuring that the rig remains a level and
stable drilling platform. The Barge Engineer is also responsible for keeping detailed
stability records that track the quantity and location of on-board weights and the height of
the center of gravity.
T he se re co rds, called stability rep orts or variab le loa d form s, are e xtre m ely im p orta nt
and useful documents. Updated daily, they form the basis for gauging the stability
conditions of the rig and its capability for additional deck loads. Although it is not a
complicated document, supervisory personnel who do not appreciate its relevance to the
operations of the rig are not meeting their responsibilities for monitoring the performance
of the ballast control crew.
Considerable attention has been devoted to insuring that the ballast control crew on
semisubmersibles is highly trained, experienced and competent. Most companies have
established or supported extensive training programs in stability and ballast control for
personnel who lacked formal maritime training. Many companies are now requiring new
hires for ballast control positions to be maritime academy graduates. Many national
regulatory agencies now require that all ballast control personnel meet minimum training
experience and examination standards.
In order to gain a feel for the operations of the rig and its capabilities in the event of a
causality or heavy weather, all sup ervisory p erso n nel sh ould re ad th e units O pe ratio ns
Manual. Required by regulation, the manual contains a description of the rig and its
equipment, instructions for responding to various emergencies, stability information, and
operating limits for various modes (under tow, on stations, etc.). With the margins of safety
that are imposed by the design standards, adherence to the specified limits will virtually
ensure the safety of the rig in the worst weather conditions, even if no counteracting
measures are taken. Anyone who might participate in discussions or decisions in the midst
of an emergency will undoubtedly feel better prepared having done this bit of homework.
The ballast control and seakeeping functions usually consist of shifting ballast, modifying
tension in the mooring lines, and locating loads on the deck to keep the rig at the optimum
drilling attitude.
The importance of their job should not be overlooked simply because it is matter of routine.
Especially important is the maintenance of KG below the maximum allowable limit and the
deck load restrictions. By understanding ballast control functions, monitoring the KG by
re vie w in g ea ch da ys variable loa d fo rm , and o be ying th e op era tin g restrictio ns as outlin e d
in the Operations Manual, supervisory personnel can help ensure the safety of the rig.

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3.4.1 STABILITY SURVEY

A de tailed surve y of th e vesse ls lo ad ed con ditio n is p erfo rm e d b y th e B C O in orde r to

obtain weight and VCG information for the stability calculation. The following outline
describes how this information is obtained.
Vessel Lightship
T h e b a re ve sse l lig h tsh ip w e ig h t a n d V C G a re m a in ta in e d a s a p e rm a n e n t re co rd in th e
ve sse ls o p e ra tio n s o r sta b ility m a n u a l. T h ro u g h o u t its life , a d rillin g ve sse l w ill u n d e rg o
structural and equipment changes, which will alter its lightship weight and VCG.
Therefore, these changes must be noted and recorded as they occur so that a lightship
weight and VCG reflecting the present condition of the vessel can be stated for the
stability calculation.
Liquid Weights
Liquid volumes in tanks are determined by one of two means. The most direct means is
by measuring the height of the fluid in a tank and using a calibration table to determine
the liquid weight and VCG from the liquid height. This direct measurement is called a
so u n d in g . T a n k so u n d in g ca n b e ta ke n d ire ctly th ro u g h m a n h o le s o r o th e r ta n k a cce ss
hatches. However, most tanks are equipped with a sounding tube through which a
measuring tape can be lowered to the bottom of the tank.
Liquid weights are also determined by using remote pneumatic or electromechanical
gauges. The gauges translate the hydrostatic pressure or height of the tank liquid into a
volume or weight, which is displayed on the gauge.
The tank gauge reading should be compared to manual tank sounding on a regular
basis to ensure that the gauges read correctly. Tank sounding should also be taken
whenever a main ballasting operation is performed on a semisubmersible, or when new
fuel or drill water is taken aboard. Proper tank sounding will always provide more
accurate liquid weight estimates than gauge readings.
Bulk Weights
Weights of bulk cement, mud and gel are determined by directly measuring the empty
portion in the tank. This is performed through a hatch located near the top of the tank.
Conversion tables are provided to translate these measurements into bulk weights and
VCGs. Some bulk tanks are equipped with remote sensing gauges that measure the
weight of the bulk material in the tank. As with remote liquid gauges, they should be
regularly checked against manual tank measurements to ensure that accurate
measurements are displayed on the gauges.
Tubulars
The weights and VCGs of drill pipe, drill collars, casing and riser are determined by
surveying the pipe racks and holds in which they are stored.
Drilling Equipment
Drilling subs, fishing tools, slips, casing elevators and other drilling equipment can be
surveyed for the stability calculation. However, the weight of these items is generally
assumed to remain constant throughout a drilling operation.

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Subsea Equipment
The weight and location of subsea equipment carried onboard is determined by survey.
This survey extends to the BOP, BOP hoses, slip joint, flex joint and other subsea
equipment.
Stores
Manifests should be maintained for the various stores on board the vessel. These
stores may include the following:
Drilling stores
Engine room stores
Electrical stores
Paint locker
Subsea stores
G e n e ra l sh ip s sto re s
Food and provisions
The manifests should state the present weight of parts or supplies carried in each
storeroom.
Other Deck Equipment
A general survey should be preformed to identify other weights carried on board.
Mooring Equipment
The weight of deployed chain, wire, anchors, pendant lines and anchor buoys is
accounted for in the stability calculation. Usually these weights are considered to be
part of the vessel light ship, and the mooring equipment deployed is entered as a
d e d u cte d w e ig h t. T a b le s p ro vid e d in th e ve sse ls o p e ra tio n s o r sta b ility m a n u a l a re u se d
to translate deployed lengths of chain and wire into weights and VCGs.
Mooring and Riser Tension
Although not an actual weight, mooring and riser tension may have a significant effect on
the vessel displacement. Mooring and riser tension is typically entered as a weight with
an assigned VCG.
Although the BCO is responsible for the weight survey, other rig personnel including
the toolpusher, chief engineer, chief steward, store clerks and even the ExxonMobil
drilling supervisor may be responsible for providing the necessary weight information
to the BCO.
Ideally, an active record should be maintained by the BCO of all parts, equipment, or
supplies coming aboard or leaving the vessel. This will facilitate the weight survey and
stability calculations and ensure that accurate vessel weight records are maintained.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
VESSEL STABILITY

3.4.2 CHECKING STABILITY CALCULATIONS

The weight estimates performed for the stability calculation can be checked relatively
easily. The check is performed by comparing the calculated vessel displacement with
the actual displacement determined from the vessel drafts.
The major errors in the stability calculations are usually due to one of the following
reasons:
Incorrect Tank Reading
Errors in tank gauge readings are a common source of error. A small error in a liquid
level can lead to a large error in the corresponding liquid weight estimate. This is
particularly true for semisubmersibles, which carry a large percentage of their total
displacement in ballast water and other liquids. Gauges can be checked by comparing
gauge readings against manual tank sounding. If the difference in the two tank
measurements is significant, the gauge should be recalibrated.
Incomplete Weight Survey
An incomplete weight survey of drilling equipment, spare parts, third party equipment
and supplies will often reflect an error in the total weight estimate. Therefore the weight
survey should be as complete and thorough as practical and should use the most
accurate item weight data available.
A major source of error is in estimating the weight of loose equipment and stores
distributed around the vessel. An up-to-date manifest of parts for all compartments will
help maintain a valid weight estimate for the stability calculation.
Old Lightship Estimate
As discussed earlier, the original lightship weight and VCG will change throughout the
life of a drilling vessel. For example a new welding shack may be added on deck, an
Iron Roughneck may be added to the drill floor, or an old emergency generator may be
changed out with a different unit. All these lightship changes should be noted and
recorded in the vessel operations manual so that an up-to-date lightship weight and
VCG can be maintained. If these changes to lightship are not recorded, the true vessel
lightship weight cannot be determined. In such cases, a new inclining experiment may
need to be performed for the vessel in order to obtain valid lightship properties.
Not all marine personnel are diligent in performing a valid stability calculation. A practice
not uncommon on many drilling vessels is to adjust the numbers of the ballast and other
liquid weights on the stability form in order to obtain agreement between the calculated
and actual vessel drafts. Often, liquid tanks on some drilling vessels are never sounded
even though liquid levels in these tanks may be suspect from gauge readings.
Another common practice is to forestall the routine of a daily stability calculation and to
perform these calculations on a weekly or even monthly basis.
These practices are unsafe because the true stability condition of the vessel cannot be
determined from such shortcuts in a detailed daily calculation.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
VESSEL STABILITY

The following is a recommended check for the ExxonMobil Drilling Supervisor to help
ensure the safe operation of the rig:
Review the stability calculation
Do results appear complete and accurate?
Is the correct value of lightship and center of gravity entered?
Does the worksheet contain both the calculated displacement and the
displacement determined from rig draft?
Any unknown weights entries?
Any unknown weights placed at the main deck level?
Is a calculation made to evaluate rig stability if the BOP stack must be
tripped for repair or maintenance?
Is a survival draft calculation made each time a daily stability calculation
is performed?
Check all hydraulic watertight door for proper operations: seals free of paint
Verify that weekly tank soundings are conducted and results are compared
with sensor readings
Are watertight doors and hatches kept closed
Compare daily stability calculations from multiple weeks and different BCOs
to determine trends or input errors
An example daily stability report is provided in Appendix 1.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
VESSEL STABILITY

3.5 DAMAGE FLOODING COUNTERMEASURES

3.5.1 GENERAL DAMAGE FLOODING COUNTERMEASURES

Damage to a floating vessel can occur as a result of collision with another vessel or
obstruction, or due to structural damage/failure. Although damage-flooding
countermeasures are the same for either type of damage, damage due to collision is the
most severe due to the possibility of rapid flooding.

3.5.2 COLLISION DAMAGE

Damage from collision has the capability of being the most severe type. A vessel
displacing several thousand tons moving at a speed of 10-12 knots can inflict a great deal
of damage to an exposed column.

3.5.3 COLLISION DAMAGE FLOODING COUNTERMEASURES

(at operational draft)

Immediate Objectives
A. Reduce list and/or trim.
B. Return vessel to near original mean draft.
C. Reduce mean draft.

Countermeasures
A. Sound the general alarm. Summon damage control team.
B. Identify where the damage is located by using the inclinometer and the King
gauges. (Note: King gauges are not always available to void spaces, chain
lockers etc.)
C. De-ballast adjacent ballast tank. Activate emergency de-ballast system if
available. (De-ballast damaged tank first, only if immediately controllable, such
as may be the case with minor damage.
D. Counter-flood ballast tank on the diametrically opposite side of the vessel if
response from de-ballasting adjacent tank is not quick enough.
E. Plug the vent to damaged tank or void space.
F. Consider other options: Transferring drill-water, using other ballast pumps if
available, dumping drill-water from the day tank, dumping mud from the mud
pits and slacking anchor chains on damaged side.

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VESSEL STABILITY

REMARKS
1. The drill floor should be notified so as to make preparations to disconnect from the
LMRP.
2. Deballasting the damaged tank first should only be attempted if it is known that the
damage is minor.
3. When de-ballasting the adjacent ballast tank, use two (2) ballast pumps. This
action will correct the list/trim faster and perhaps make counter-flooding
unnecessary. In the case of severe damage, de-ballasting with two pumps may be
necessary to keep the list/trim from increasing.
4. Plugging the vent to the damaged tank will assist in reducing list and/or trim by
slowing and perhaps stopping the influx of seawater. When the damage area is
brought above the water line, by decreasing the draft, the plug should be removed
to keep from further damaging the tank.
5. Counter-flooding assists in reducing list/trim by creating a powerful lever of added
weight on the opposite side of the vessel. When counter-flooding, however, mean
draft and, therefore, reserve buoyancy is being reduced., For this reason, counter-
flooding should only be done when necessary, and only as long as necessary.
6. Slacking anchor chains on the damaged side is also an effective means to assist in
reducing list/trim. A fairly large amount of weight can be removed quickly. This may
also be an extremely important countermeasure on a vessel with forward column
damage and aft pump rooms with no emergency de-ballast system. Due to the
various vessel designs, this procedure may not be effective in some situations.
7. Transferring drill water is an additional countermeasure, which may also be initiated
on the ballast panel. This countermeasure provides a righting lever by removing
weight from near the damaged area, and transferring it to the opposite side of the
unit without increasing mean draft. Due to different vessel designs and location of
drill water tanks this countermeasure may not be an option in some cases.

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VESSEL STABILITY

3.5.4 PROCEDURES FOR UNEXPECTED LIST AND TRIM

One of the first actions to take in the case of unexpected inclination is to determine the
cause. The inclination could be the result of open valves, a structural problem in a tank
bulkhead, dumping of mud pits, repositioning of large weights, or possibly, external damage
to the hull. In case of damage, the immediate objective should be to reduce the inclination
and return the vessel to an appropriate draft. If the damage assessment indicates that the
damaged area may be elevated out of the water, then corrective actions should include de-
ballasting.
Unexpected list or trim often falls into one of the following three categories in which vessel
inclination is:
1. increasing rapidly
2. increasing slowly
3. not increasing
The possible causes for unexpected list or trim are:
1. Flooding due to external causes
a. hull damage
b. failure of hull penetration (valve or piping)
2. Flooding due to internal causes
a. broken or corroded piping
b. open valve
c. failed check valve
d. ruptured tank bulkhead
3. Transfer of liquids
a. discharged liquid mud
b. inadvertent (personnel error)
c. equalizing between tanks
d. consumed liquids (fuel and drill water)
4. Shift of non-liquid loads
a. broken mooring line
b. consumed bulk materials
c. repositioning of heavy weights
5. Load form errors
a. mathematics
b. measurements
c. weight estimate
d. center of gravity estimates
6. Heel or trim due to environmental forces

3.5.5 CONSTANT UNEXPECTED LIST OR TRIM

Constant list or trim usually results from a miscalculation in the load form and could result
from a mathematical error, or using the wrong weight or location.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
VESSEL STABILITY

It could also be due to false tank soundings. An obvious solution is to recheck the load
form.
Other causes of constant list or trim could be the inadvertent transfer of a small quantity of
liquid, a load shift, or environmental forces. A corrective action would be to assess the
situation and, if required, level the rig through the transfer of liquids.

3.5.6 TRANSIT CONDITION

If extensive flooding occurs while in transit, due to damage or some other reason, such that
flooding cannot be controlled, the choice of tank from which to pump from will be
limited. Consider using both ballast pumps to pump from the damaged tank in order to
slow the inflow.

3.5.7 WATERTIGHT INTEGRITY

All openings and vents on the main deck, such as hatches, ventilators, tank vents, and
companionways are provided with a means of watertight closure. All watertight openings,
when not in use, should be secured.

3.5.8 DAMAGE CONTROL COUNTERMEASURES

Damage control countermeasures in general, would be the same as for collision damage,
modified to suit the specific damage situation.

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VESSEL STABILITY

3.6 GLOSSARY
SYMBOL TERM DEFINITION
Displacement Weight of the vessel.
WT Weight Cargo/load weight.
K Keel Reference for measuring weight VCG or KG.

)(
Amidship symbol Geometric longitudinal center of vessel.

cL Centerline Geometric transverse center of vessel.

L Length Distance between FWD and AFT draft marks.

B Breadth Distance between port and STBD draft marks.

VCG Vertical center of gravity The center of gravity of a weight measured
vertically above the Keel (Baseline)
KGT Corrected transverse KG Transverse KG corrected for free surface
KGL Corrected longitudinal KG Longitudinal KG corrected for free surface
FSMT Free surface moments Transverse moments of a slack tank from tank
transverse sounding tables or by calculation.
FSCT Transverse free surface Distance in feet determined by dividing FSMT by
correction displacement.
Add KG to get KGT.
FSCL Longitudinal free surface Distance in feet determined by dividing FSML by
correction displacement.
Added to KG to get KGL.
KG max Maximum allowable KG Maximum permitted KG from table in Operations
Manual based upon Mean Draft.

TCG Transverse center of gravity Measured to port or STBD of centerline.

Starboard is positive, port is negative
LCG Longitudinal center of gravity Measured FWD or AFT or athwartship line.
Positive/negative directions may be FWD / AFT
depending on vessel.
M Moment A weight multiplied by a distance.
VM Vertical moment Weight/Displacement x VCG/KG.
TM Transverse moment Weight/Displacement x TCG.
LM Longitudinal moment Weight/Displacement x LCG.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
VESSEL STABILITY

SYMBOL TERM DEFINITION

RM Righting moment Determined by multiplying displacement times
righting arm (GZ).
LCB Longitudinal center of Geometric center of underwater volume
buoyancy measured FWD/AFT of amidships. Located in
hydrostatic tables.

LCF Longitudinal center of Located at the geometric center of the

flotation waterplane area measured FWD/AFT of
amidships. Located in hydrostatic tables.

KMT Height of the transverse Measured in feet above the keel. Located in
metacenter hydrostatic tables.
KML Height of the longitudinal Measured in feet above the keel. Located in
metacenter hydrostatic tables.
GMT Transverse metacentric Measure of initial transverse stability of a vessel.
height Determined by subtracting KGT from KMT.

GML Longitudinal metacentric Measure of initial longitudinal stability of a

Height vessel. Determined by subtracting KGL from
KML.
GZ Righting arm Distance in feet between vertical force of gravity
and vertical force of buoyancy when vessel is
inclined,
KB Height of center of buoyancy Vertical distance the center of buoyancy is
above the keel. Determined from Hydrostatic
Tables.
BM Metacentric radius Vertical distance from center of buoyancy to
metacenter. Determined by formula, may be
used to calculate KM. KM = BM + KB.
TPI Tons per inch of immersion The number of tons required to change mean
draft one inch. Found in Hydrostatic Tables.
TRIM Trim Difference in draft marks FWD and AFT.

LIST List Difference in draft marks PORT and STBD.

Incline due to internal loading.
HEEL Heel PORT and STBD incline due to External forces.

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VESSEL STABILITY

3.7 REFERENCES
1. Diamond Offsh o re : In tro d u ctio n to S ta b ility a n d B a lla st C o n tro l co u rse m a n u a l,
October 1998
2. E xxo n P ro d u ctio n R e se a rch C o m p a n y; M a rin e O p e ra tio n s fo r O ffsh o re D rillin g
Volume I, Stability and Loadout, February 1992
3. M o b il D rillin g ; F lo a tin g D rillin g S ch o o l m a n u a l, Stability and Ballast Control

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VESSEL STABILITY

3.8 APPENDIX

OCEAN WHITTINGTON Condition: 36" casing

STABILITY REPORT Draft = 63.0ft BY Mathews
DATE 12/12/01
ANCHOR CHAIN CORRECTION TABLE protected by STABILITY
DESCRIPTION Chain Actual Long Mom Trans Mom
Out Weight VCG Moment LCG LT-ft TCG LT-ft
ft. LT Ft LT*Ft Ft - FWD Ft - PORT

#1 3460 66 27 1789 -120 -7950 93 6161

#2 3350 79 27 2144 -105 -8339 93 7386
#3 3390 79 27 2145 105 8343 93 7390
#4 3115 76 27 2064 120 9175 93 7111
#5 3260 67 27 1810 120 8046 -93 -6236
#6 3360 78 27 2096 105 8150 -93 -7219
#7 3360 82 27 2201 -105 -8558 -93 -7580
#8 3265 73 27 1967 -120 -8743 -93 -6776

TOTALS 601 27.00 16217 0.21 125 0.40 238

0

MOORING LINE TENSION AND VERTICAL REACTION CORRECTION

Water depth 322 ft. Average tension = 240 kips

Actual Actual Vert Vert

Tens Weight Comp VCG Moment LCG L. Mom. TCG T. Mom.
DESCRIPTION kips LT LT Ft LT*Ft Ft LT*Ft Ft LT*Ft

#1 195 87 43 49.2 2128 -120 -5189 93 4022

#2 185 83 42 49.2 2068 -105 -4414 93 3910
#3 260 116 50 49.2 2478 105 5289 93 4685
#4 450 201 67 49.2 3296 120 8039 93 6231
#5 240 107 48 49.2 2376 120 5795 -93 -4491
#6 260 116 50 49.2 2478 105 5289 -93 -4685
#7 165 74 40 49.2 1944 -105 -4150 -93 -3675
#8 165 74 40 49.2 1944 -120 -4743 -93 -3675
0
TOTAL 1920 857 380 49.20 18714 15.56 5917 6.10 2320
MAX TENSION 350
ANCHOR # 4
ANCHOR CORRECTION TABLE

-444 Line Add. Wt. VCG V. Mom. LCG L. Mom. TCG T. Mom.
DESCRIPTION Out Lt. Ft LT*Ft Ft LT*Ft Ft LT*Ft

#1 1 0.00 27 0 -120 0 93 0
#2 1 0.00 27 0 -105 0 93 0
#3 1 0.00 27 0 105 0 93 0
#4 1 0.00 27 0 120 0 93 0
#5 1 0.00 27 0 120 0 -93 0
#6 1 0.00 27 0 105 0 -93 0
#7 1 0.00 27 0 -105 0 -93 0
#8 1 0.00 27 0 -120 0 -93 0

TOTALS 8 0.00 0 0 0.00 0 0.00 0

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
VESSEL STABILITY

OCEAN WHITTINGTON Condition: 36" casing BY Mathews

DATE 12/12/01
Page
BALLAST TANKS 2
Max Actual Vert Long. Tran. F.S. F.S.
Wt ITEM Sound Wt. VCG Mom. LCG Mom. TCG Mom. LT-ft LT-ft
LT m^3 LT Ft LT*Ft Ft LT*Ft Ft LT*Ft Trans Long
444 PT 1 10 10 0.25 3 -141 -1419 -93 -932 0 0
444 ST 1 10 10 0.25 3 -141 -1419 93 932 0 0
334 PT 2 331 334 10.99 3666 -113 -37569 -101 -33859 0 0
334 ST 2 331 334 10.98 3663 -113 -37702 101 33859 0 0
501 PT 5 497 501 10.99 5506 -75 -37573 -83 -41826 0 0
501 ST 5 497 501 10.99 5506 -75 -37573 83 41826 0 0
334 PT6 195 197 6.47 1271 -38 -7371 -101 -19947 430 1168
334 ST 6 250 252 8.29 2090 -38 -9450 101 25573 430 1168
334 PT7 8 8 0.27 2 -38 -302 -83 -673 0 0
334 ST7 8 8 0.27 2 -38 -302 83 673 0 0
501 PT 9 497 501 10.99 5506 0 0 -83 -41826 0 0
501 ST 9 497 501 10.99 5506 0 0 83 41826 0 0
334 PT 10 331 334 10.98 3663 37 12505 -101 -33859 0 0
334 ST 10 331 334 10.98 3663 37 12505 101 33859 0 0
501 PT 12 497 501 10.99 5506 75 37558 -101 -50839 0 0
501 ST 12 497 501 10.99 5506 75 37558 101 50839 0 0
334 PT 14 331 334 10.98 3663 112 37519 -101 -33859 0 0
334 ST 14 331 334 10.98 3663 112 37519 101 33859 0 0
325 PT15 300 302 10.24 3095 112 34005 -83 -25247 0 0
325 ST 15 301 303 10.27 3116 112 34118 83 25332 0 0
377 PT 17 0 0 22.00 0 -113 0 -93 0 0 0
377 ST 17 0 0 22.00 0 -113 0 93 0 0 0
288 PT 18 0 0 22.00 0 -38 0 -93 0 0 0
288 ST 18 0 0 22.00 0 -38 0 93 0 0 0
367 PT 20 0 0 22.00 0 113 0 -93 0 0 0
367 ST 20 0 0 22.00 0 113 0 93 0 0 0
9953 TOTAL Ballast 6098 10.59 64599 11.91 72605 0.94 5710 860 2336

FUEL & DRILL WATER

Max Actual Vert Long. Tran. F.S. F.S.
Wt ITEM Sound Wt. VCG Mom. LCG Mom. TCG Mom. LT-ft LT-ft
LT m^3 LT Ft LT*Ft Ft LT*Ft Ft LT*Ft Trans Long
279 PT 3 FO 8 6.7 0.26 2 -112.60 -754 -83.49 -559 0 0
279 ST 3 FO 20 16.7 0.66 11 -112.60 -1884 83.49 1397 0 0
489 PT 4 PW 245 241.1 5.42 1308 -74.97 -18078 -101.48 -24471 629 3845
489 ST 4 DW 12 11.8 0.27 3 -74.97 -885 101.48 1199 0 0
419 PT 8 FO 10 8.4 0.22 2 0.00 0 -101.48 -849 0 0
419 ST 8 FO 243 203.3 5.34 1086 0.00 0 101.48 20631 538 3292
326 PT 11 DW 325 319.9 10.79 3453 37.48 11989 -83.49 -26707 0 0
326 ST 11 DW 45 44.3 1.49 66 37.48 1660 83.49 3698 419 1139
419 PT 13 FO 25 20.9 0.55 11 74.97 1568 -83.49 -1746 0 0
419 ST 13 FO 17 14.2 0.37 5 74.97 1066 83.49 1187 0 0
281 PT 19 DW 0 0.0 22.00 0 37.50 0 -92.50 0 0 0
281 ST 19 DW 0 0.0 22.00 0 37.50 0 92.50 0 0 0

4146 TOTAL Fuel & F. 887.4 6.70 5947 -5.99 -5318 -29.55 -26221 1586 8276
water

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VESSEL STABILITY

OCEAN WHITTINGTON Condition: 36" casing BY Mathews

STABILITY REPORT DATE 12/12/01
MAIN DECK LIQUIDS -120' Page
Max Actual Vert Long Mom Trans Mom 3
Wt ITEM Weight VCG Moment LCG LT-ft TCG LT-ft
LT LT Ft LT*Ft Ft - FWD Ft - Port
8 Crane F.O. 7.00 125.00 875 33.60 235 -95.60 -669
13 tank oil tk
Lube 9.50 127.00 1207 -76.70 -729 88.00 836
6 Fuel oil 2.0 106.94 214 -33.55 -67 95.62 191
overflow
8 Waste oil 2.0 104.30 209 -33.50 -67 95.00 190
4 BOP Fluid 4.00 125.00 500 58.50 234 -95.60 -382
tank
19 Settlingtk 19.00 112.00 2128 -33.60 -638 95.60 1816
7.8 F.O. Day 7.8 127.00 991 -58.50 -456 89.00 694
27 Tank
Salt wtr day tk 27.0 113.00 3051 -33.50 -905 88.50 2390
63 DW Day tk 63.0 110.90 6987 -41.00 -2583 -92.50 -5828
53 Pot wtr tk 53.0 110.90 5878 -34.50 -1829 -92.50 -4903
4 Emerggen FOtk 4.0 125.70 503 11.20 45 87.50 350
1 FO Cmt unit 1.0 126.60 127 34.20 34 68.90 69
Holding Tank 12 80.00 960 10.00 120 85.00 1020

Main Dk Seperator 0.0 124.00 0 -35.00 0 68.00 0

TOTAL Tank 211.3 111.82 23627 -31.26 -6605 -20.00 -4225

MUD PIT WORKSHEET

MW Depth Mud Wt Depth
lb/gal Ft. Ft.
Mud pit #1 8.6 6.20 Slug 8.6 6.00
Mud pit #2 8.6 6.80 P belly (2.75' 9.0 0.00
Mud pit #3 10.0 7.00 max)
Sand 9.0 0.00
Mud pit #4 10.0 7.00 trap
Setling Pit 9.0 0.00
Mud pit #5 8.6 5.00 Desander 9.0 0.00
Pit
Desilter Pit 9.0 0.00
Trip tank 8.6 0 <BBLS

MUD PIT SUMMARY

TANK Wt. VCG V. Mom. LCG L. Mom. TCG T. Mom.
Bbls LT Ft LT*Ft Ft LT*Ft LT*Ft LT*Ft

Mud pit #1 326 52.59 123.10 6473 -91.20 -4796 9.00 473
Mud pit #2 358 57.68 123.40 7117 -106.30 -6131 9.00 519
Mud pit #3 221 41.34 123.50 5106 -103.70 -4287 -5.60 -232
Mud pit #4 224 42.00 123.50 5187 -103.70 -4355 -14.80 -622
Mud pit #5 250 40.31 123.50 4979 -76.78 -3095 9.20 371

47 Slug pit 47 7.55 123.00 928 -93.18 -703 -4.60 -35

Possum 0 2.07 138.20 285 -35.88 -74 29.78 62
49 belly
Sand 0 0.00 120.00 0 -87.60 0 -3.30 0
40 trap
Settling Pit 0 0.00 120.00 0 -93.18 0 -14.40 0
41 Desander 0 0.00 120.00 0 -87.60 0 -9.80 0
41 Pit
Desilter Pit 0 0.00 120.00 0 -87.60 0 -15.75 0
Trip tank 0 0.00 120.00 0 -16.00 0 17.70 0
TOTAL MUD PITS 1425.1 243.53 123.50 30076 -96.26 -23442 2.20 537

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VESSEL STABILITY

OCEAN WHITTINGTON Condition: BY Mathews

STABILITY REPORT DATE 12/12/01
Page 4
SACK ROOM

DESCRIPTION Wt. VCG V. Mom. LCG L. Mom. TCG T. Mom.

LT Ft LT* Ft Ft LT* Ft LT* Ft LT* Ft
PLTS CHEMICALS 12 12.00 124.0 1488 -60.0 -720 -20 -240
drums 19 buckets @42 Lbs. 0 3.73 123.0 459 -55.0 -205 15 55.98214
CONTAINERS F/ TRACTION MOTORS & MP CHAINS 3.00 121.0 363 -45.0 -10 -30 -90
BOP VALVES JUG @146 Lbs. 0 1.00 122.0 122 -65.0 -65 -20 -20
FORKLIFT & MISC 12.00 123.0 1476 -55.0 -660 5 60
TOTAL SACK MATERIAL 31.73 123.16 3908 -52.32 -1660 -7.37 -234

BUL K TANK S
1FT=100 Wt. VCG V. Mom. LCG L. Mom. TCG T. Mom.
Type Factor Ft.-In. LT Ft LT* Ft LT* Ft 7 LT* Ft
GEL #1 STBD FWD GEL 1.6675 910 47.23 67.81 3202 -116.75 -5514 88.00 4156
GEL #2 STBD FWD GEL 1.6675 4010 3.53 51.31 181 -109.25 -386 88.00 311
#3 STBD AFT CMT 1.00 3510 16.58 53.93 894 109.25 1811 88.00 1459
#4 STBD AFT CMT 1.00 1604 59.67 64.14 3828 116.75 6967 88.00 5251
#1 PT FWD BARITE 0.7407 4300 0.00 50.00 0 -116.75 0 -88.00 0
#2 PT FWD BARITE 0.7407 3009 39.66 56.55 2243 -109.25 -4333 -88.00 -3490
#3 PT AFT CMT 1.00 2106 47.50 61.26 2910 109.25 5190 -88.00 -4180
#4 PT AFT CMT 1.00 4300 0.00 50.00 0 116.75 0 -88.00 0
Surge Tk. port GEL 6.00 125.00 750 -78.00 -468 -13.00 -78
Surge Tk. stbd BARITE 4.00 124.00 496 -78.00 -312 -5.00 -20

TOTALS 224.17 64.70 14504 13.18 2955 15.21 3409

P-TANKS Type Sx P-TANKS Type Sx

P-TK 1 S/F GEL 1058 P-TK 3 S/A CMT 395
P-TK 2 S/F GEL 79 P-TK 4 S/A CMT 1422
P-TK 1 P/F BARITE 0 P-TK 3 P/A CMT 1132
P-TK 2 P/F BARITE 888 P-TK 4 P/A CMT 0

Total barite = 888 sx Total cement = 2949 sx

Total Gel= 1137 sx

3 - 61
EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
VESSEL STABILITY

OCEAN WHITTINGTON Condition: 36" caising BY Mathews

STABILITY REPORT DATE 12/12/01
M AI N DECK STORES Page 5

Actual Vert Long Mom Trans Mom

DESCRIPTION Weight VCG Moment LCG LT-ft TCG LT-ft
LT Ft LT* Ft Ft - Fwd Ft - Port
Electrical Stores 2.0 125.00 250 18.00 36 90.00 180
Main Stores 25.0 123.00 3075 82.00 2050 -90.00 -2250
Subsea stores 10.0 125.00 1250 65.00 650 90.00 900
Drill tools stores 20.0 125.00 2500 -40.00 -800 -20.00 -400
Pump Stores 20.0 125.00 2500 -40.00 -800 0.00 0
Quarters 18.0 125.00 2250 -80.00 -1440 -65.00 -1170
Dry stores & freezer 12.0 125.00 1500 -77.00 -924 -38.00 -456
Column Stores 15.0 110.00 1650 110.00 1650 90 1350
122.0 122.75 14975 3.46 422 -15.13 -1846

UPPER DECK /BOX BEAM S

BOX GIRDER-130' , BRIDGE DECK- 135' , HELIDECK- 140'
Actual Vert Long Mom Trans Mom
ITEM Weight VCG Moment LCG LT-ft TCG LT-ft
LT Ft LT* Ft Ft - Fwd Ft - Port
DODI DOPE TK FWD DRILL FLOOR 3.25 160.0 520 -20.00 -65 0.00 0
DODI SHAKER SCREENS IN RACKS 1.65 134.0 221 -60.00 -99 -30.00 -50
DODI CASING TOOLS, CABLE REELS 14.00 133.0 1862 55.00 770 79.00 1106
DODI DRUM RACK 12.00 137.0 1644 -55.00 -660 70.00 840
DODI BULK HOSES & D.P. SLINGS 3.00 143.0 429 -75.00 -225 70.00 210
DODI BOARDS, DOPE TANK, USED SCREENS 1.50 138.0 207 -75.00 -113 50.00 75
DODI (4)CABLE REELS, RISER SPIDER w/dolly, TEST15.00
STUMPs 134.0 2010 110.00 1650 100.00 1500
DODI 1- Sub Sea Hot Line Spool By T.V. Dish 1.00 140.0 140 -36.00 -36 20.00 20
DODI (2) T/U ROPES 3.00 133.0 399 115.00 345 -95.00 -285
DODI 3 CABLE REELS ATOP AIR COMP. HOUSE 6.00 137.0 822 112.00 672 68.00 408
DODI CABLE TRAYS, MOORING LINES, PENNANTS5.00 135.0 675 30.00 150 90.00 450
DODI 1-26" H.O.3 STBL,HAZD DRUMS, 1 BIT 6.00 132.0 792 100.00 600 15.00 90
DODI Bundles of pipe + ANGLE iron 6.00 133.0 798 -52.00 -312 92.00 552
DODI FILTER UNIT STBD SIDE OF SHAKERS 3.50 136.0 476 -25.00 -88 47.00 165
DODI 1 CONT. # 29 W/400 SXS. OF SAND 8.90 133.0 1184 -60.00 -534 45.00 401
DODI 2-Waste oil tanks 1.00 133.0 133 -20.00 -20 92.00 92
DODI 1- L/O tk.Mobile Gard 450 #-07 2.6tons 2.60 133.0 346 60.00 156 95.00 247
E/M 4 GUIDE POST FOR WELL HEAD 1.00 131.0 131 60.00 60 95.00 95
133.0 0 90.00 0 95.00 0
133.0 0 0.00 0 95.00 0
132.0 0 -10.00 0 85.00 0
133.0 0 110.00 0 0.00 0
131.0 0 86.00 0 -90.00 0
131.0 0 60.00 0 97.00 0
133.0 0 -15.00 0 95.00 0
131.0 0 60.00 0 96.00 0
132.0 0 70.00 0 -93.00 0
131.0 0 70.00 0 -93.00 0
132.0 0 78.00 0 -93.00 0
126.0 0 100.00 0 -5.00 0
132.0 0 110.00 0 8.00 0
E/M HELO REFULING TANK (HELIPORT) 1.60 140.0 224 -60.00 -96 -35.00 -56
E/M HELO REFULING TANK ( PORT BG) 1.60 133.0 213 35.00 56 -85.00 -136
E/M INTERNATIONAL MUD LOGGING UNIT 8.00 139.0 1112 -35.00 -280 65.00 520
DODI MUD LAB 6.00 145.0 870 -75.00 -450 45.00 270
TOTALS 111.60 136.27 15207 13.28 1482 58.36 6514

RI SER TAL L Y - PORT SI DE

No. Riser w/ float No. Riser w/o float No. Riser w/o float
0 50'X 5/8"@ 8.1 LT/EA. 0 50' X 5/8" @ 5.36 LT/EA. 0 30' X 1/2" @ 3.15 LT/EA.
0 50' X1/2"@ 7.12 LT/EA. 0 50' X 1/2" @ 4.38 LT/EA. 0 20' X 1/2" @ 2.38 LT/EA.
0 45' X 1/2" @ 4.04 LT/EA. 0 15' x 1/2" @ 2.04 LT/EA
0 Slip joint @ 13.77 LT 0 10' X 1/2" @ 1.71 LT/EA.
0 42' X 5/8" @ 3.95 LT/EA. 0 5' X 1/2" @1.37 LT/EA.

RI SER TALLY - STBD SI DE

No. Riser w/float No. Riser w/o float No. Riser w/o float
6 50'X 5/8"@ 8.1 LT/EA. 5 50' X 5/8" @ 5.36 LT/EA. 0 30' X 1/2" @ 3.15 LT/EA.
0 50' X1/2"@7.12 LT/EA. 0 50' X 1/2" @ 4.38 LT/EA. 1 20' X 1/2" @ 2.38 LT/EA.
0 40' X 5/8" @ 3.94 LT/EA. 1 15' x 1/2" @ 2.04 LT/EA
0 Slip Joint 60' @13.77 2 Slip joint @ 13.77 LT 1 10' X 1/2" @ 1.71 LT/EA.
1 42' X 5/8" @ 3.95 LT/EA. 0 5' X 1/2" @ 1.37 LT/EA

3 - 62
EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
VESSEL STABILITY

OCEAN WHITTINGTON Condition: 36" caising BY Mathews

STABILITY REPORT DATE 12/12/01
M AI N DECK L OADS Page 6
PORT VCG- 120'
Actual Vert L. Mom T. Mom
ITEM Weight VCG Moment LCG LT-ft TCG LT-ft
LT Ft LT* Ft Ft - Fwd Ft - Port
DODI OUTSIDE LIVING QUARTERS & TEMPORARY A/C UNIT 10.00 126.00 1260 -20.00 -200 -65.00 -650
DODI TRASH COMPACTOR 2.00 122.00 244 -20.00 -40 -25.00 -50
DODI DRILL LINE SPOOL #S36S BRASDRIL 3826 FT. 1.34 121.00 162 -50.00 -67 -30.00 -40
DODI PARTS ON TOP OF DRILL EQUIP SHED 0.50 123.00 62 35.00 18 -20.00 -10
DODI RISER RUNNING TOOLS 10.00 128.00 1280 -15.00 -150 -25.00 -250
DODI SHACKLE RACK / PUP JOINT RACK 1.00 123.00 123 100.00 100 -55.00 -55
DODI HAZMAT DRUMS & CONTAINERS AIR EQUIP BXS 0.50 123.00 62 100.00 50 -10.00 -5
DODI PERMANANT BOTTLE RACK 2.00 122.00 244 70.00 140 -80.00 -160
DODI 3-OXY & ACET. RACK 0.67 123.00 82 90.00 60 -85.00 -57
DODI JUNK IRON BKT 1.25 122.00 153 65.00 81 -12.00 -15
123.00 0 90.00 0 -85.00 0
122.00 0 70.00 0 -80.00 0
124.00 0 60.00 0 -70.00 0
OCEAN ROV, WORK & CONTROL CABINS, GENERATOR, MISC EQUIP 50.45 126.00 6357 20.00 1009 -55.00 -2775
PORT PI PE RACK No. j ts Wt. Ft. * * *
DODI RISER 0 0.00 125.00 0 60.00 0 -15.00 0
DODI 5" H/W DRILL PIPE 5" 30 55 22.83 122.00 2786 56.00 1279 -44.00 -1005
DODI S-135 RANGE 2 5" 350 19.5 94.45 124.00 11712 56.00 5289 -20.00 -1889
DODI 5" G 105 RANGE 2 5" 0 19.5 0 56.00 0 -44.00 0
DODI 9" DC's 9" 4 165 8.36 127.00 1062 56.00 468 -44.00 -368
DODI 8" DC's 8" 18 151 37.62 123.00 4627 56.00 2106 -44.00 -1655
DODI 6-1/2" DC's 6-1/2" 21 99.1 28.80 123.00 3543 56.00 1613 -10.00 -288
E/M CASING 20" 6 169 20.37 122.00 2485 56.00 1141 -25.00 -509
E/M DP 3 20 13.3 3.68 122.00 449 60.00 221 -30.00 -110
E\M CAING 13 3\8 60 61 66.99 123.00 8240 53.00 3551 -35.00 -2345
DODI PORTABLE WOOD RACK 1.50 122.00 183 90.00 135 -70.00 -105
DODI RECYCLE BIN 1.00 122.00 122 15.00 15 -45.00 -45
DODI TRASH BIN 1.60 122.00 195 8.00 13 -45.00 -72
DODI 0.00 124.00 0 -15.00 0 -45.00 0
DODI 0.00 124.00 0 -10.00 0 -45.00 0
DODI 0.00 124.00 0 50.00 0 -25.00 0
DODI 0.00 122.00 0 65.00 0 -25.00 0
124.00 0 95.00 0 -25.00 0
122.00 0 60.00 0 -10.00 0
122.00 0 58.00 0 -11.00 0
E/M (3) CONTS. OF Dissperants(blue) 36 Drms. Tot. #s 084 , 07C , 024 7.77 125.00 971 90.00 699 -70.00 -544
E/M (2) MUD MOTORS 2.50 125.00 313 70.00 175 -45.00 -113
E/M 4-Drilling Jars 2-6" & 2-8" 5.0 Lts. Tol. 5.00 127.00 635 55.00 275 -45.00 -225
DODI RIG BOX #S 36,32 10.00 124.00 1240 50.00 500 -60.00 -600
DODI JNK IORN SS52 1.00 121.00 121 90.00 90 5.00 5
E\M LONG MONEL BSKT 1101 8.00 121.00 968 70.00 560 5.00 40
E\M LONG MONEL BSKT 1102 8.00 121.00 968 70.00 560 0.00 0
PAER LINKS ,SUBS, ANGLE IORN 2.00 121.00 242 5.00 10 40.00 80
124.00 0 20.00 0 -32.00 0
124.00 0 25.00 0 -25.00 0
121.00 0 30.00 0 -40.00 0
124.00 0 50.00 0 -55.00 0
124.00 0 45.00 0 -75.00 0
124.00 0 20.00 0 -45.00 0
124.00 0 30.00 0 -45.00 0
127.00 0 30.00 0 -65.00 0
123.00 0 30.00 0 -65.00 0
123.00 0 25.00 0 -75.00 0
122.00 0 10.00 0 -50.00 0
122.00 0 25.00 0 -50.00 0
123.00 0 80.00 0 -15.00 0
122.00 0 90.00 0 -80.00 0
124.00 0 60.00 0 -70.00 0
121.00 0 80.00 0 -15.00 0
122.00 0 90.00 0 -20.00 0
123.00 0 90.00 0 -30.00 0
122.00 0 53.00 0 -80.00 0
121.00 0 48.00 0 -87.00 0
AMER 2 GROCERY CONTAINER 6.00 124.00 744 -20.00 -120 -30.00 -180
E\M 5 CONT BL ML 063, 076, 081,065,024 TALL BLUE (WOOD) 15.00 125.00 1875 90.00 1350 -70.00 -1050
NOTE LINKS FROM VARIABLE DECK LOAD SHEET (P/S) 74.85 121.94 9127 64.25 4809 -18 -1379
PORT MAIN DECK TOTALS 507.03 123.53 62634 50.77 25740 -32 -16423

3 - 63
EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
VESSEL STABILITY

OCEAN WHITTINGTON Condition : 36" casing BY Mathews

STABILITY REPORT DATE 12/12/01
Page 7
MAIN DECK LOADS
STB VCG- 120'
Vert L. Mom T. Mom
ITEM Weight VCG Moment LCG Lt*Ft TCG Lt*Ft
Lt Ft Lt*Ft Ft - Fwd Ft - Port
HALLIB HALLIBURTON UNIT W/NEW DECK ABOVE SALT WATER AREA 32.00 125.00 4000 40.00 1280 65.00 2080
HALLIB STORES IN HALLIB UNIT / TOOL BOX 4.00 124.00 496 38.00 152 57.00 228
DODI BAILS ON RACK 4.00 124.00 496 0.00 0 52.00 208
DODI STORAGE ROOMS: SLING/LINKS & BITS 6.00 123.00 738 40.00 240 55.00 330
DODI PRESS WASHER,GRATING,SOAP TK, DRUMS 3.83 122.00 467 -33.00 -126 75.00 287
DODI TOOLS IN TUBES OUTSIDE OIL SEP. HOUSE 4.00 124.00 496 -20.00 -80 40.00 160
DODI DIVERTER 10.74 124.00 1332 0.00 0 40.00 430
DODI SHALE SHAKER FRAME & CABLES IN HALL 1.25 124.00 155 40.00 50 70.00 88
DODI OPEN ROUND CONT. GREY, ABOVE C.P. HOUSE, RISER CONNECTIONS 2.50 132.00 330 25.00 63 30.00 75
DODI PARKER P.D.I. BOTTLE RACK W/CONTROL PANEL IN NEW SUB SEA HOUSE1.60 123.00 197 30.00 48 30.00 48
DODI "DIVING BOARD" 1.00 124.00 124 60.00 60 40.00 40
DODI 15 SHEETS FIBERGLASS GRATING 0.25 136.00 34 40.00 10 49.00 12
DODI JUNK IRON (SAFE WELDING AREA ) 2.00 130.00 260 80.00 160 60.00 120
DODI ANCHOR JEWELRY 18.0st. - STBD DIVE POOL 18.00 120.00 2160 -5.00 -90 52.00 936
DODI MISC PIPE, PLATE AND IRON IN S.W. AREA 15.00 123.00 1845 75.00 1125 75.00 1125
DODI SUBS IN RACK, MISC TOOLS & SLINGS ON RACK 12.00 122.00 1464 105.00 1260 15.00 180
DODI SINGLE RAM W/DOORS 12.72 122.00 1552 25.00 318 35.00 445
DODI RIG BOX #28& 19 4.00 124.00 496 95.00 380 -10.00 -40
DODI 0.00 123.00 0 5.00 0 45.00 0
DODI 2-Cmt. Blks. 0.80 121.00 97 50.00 40 20.00 16
123.00 0 5.00 0 45.00 0
121.00 0 50.00 0 20.00 0
121.00 0 -40.00 0 60.00 0
E/M TOOL BASKET (RED) W/HALLIB TOOLS 3.50 122.00 427 85.00 298 30.00 105
E/M TOOL BASKET (YELLOW) W/MISC TOOLS & SUBS 3.50 122.00 427 85.00 298 30.00 105
OCEAN 2-Air tuggers, yel. & grn. 124.00 0 100.00 0 20.00 0
e\m 1 guide base 3.00 122.00 366 80.00 240 15.00 45
e\m 1 well head base 4.00 122.00 488 90.00 360 -35.00 -140
121.00 0 100.00 0 -35.00 0
121.00 0 0.00 0 25.00 0
123.00 0 32.00 0 25.00 0
122.00 0 55.00 0 10.00 0
DODI RISERS 17 113.02 126.00 14241 70.00 7911 30.00 3391
Size Wt/ft # of Jts 0 0 0
esso CASING 36" 565 5 56.75 122.00 6924 65.00 3689 20.00 1135
DODI HWDP @ 50 ppf 5" 50 0 0.00 122.00 0 56.00 0 25.00 0
DODI DRILL COLLARS 6 3/4" 99.1 0 0.00 122.00 0 56.00 0 22.00 0
DODI DRILL PIPE GRADE( G) 5" 19.5 0 0.00 122.00 0 70.00 0 40.00 0
DODI DRILL PIPE S-135 5" 19.5 0 0.00 122.00 0 65.00 0 75.00 0
DODI DRILL COLLARS 9" 165 0 0.00 122.00 0 65.00 0 75.00 0
0 0.00 123.00 0 53.00 0 -10.00 0
STBD TOTALS 319.46 39611 17684 11408
PORT & STBD MAIN DECK TOTALS 718.22 123.89 88982 52.02 37361 -8.11 -5827
SETBACK & DOWNHOLE
Setback Actual Downhole Actual
No.Jts Item WT/FT WT/JT Wt. No. Jts. Item Wt.
0 TERMINAL HEAD 0 0.00 0 5-1/2" IPC D.P. 0
0 5-1/2" IPC D.P. 17 0.00 0 9"D.C. 0
0 3 1/2" HEAVY WEIGHT 25.3 0.00 0 6-1/2" MONEL/MWD 0
0 5" dp land string 29.5 0.00 0 PROD. RISER 2 10' PUPS 0.00
0 5"DP PL. COATED 19.5 0.00 0 5" DP s-135 0.00
309 5" DP S135 19.5 83.39 0 8" D.C. 0.00
6 8"DC 151 12.54 0 5" HWDP 0.00
0 HVYWT 5" 50 0.00 0 JARS 0.00
9 6-1/2" DC 99.1 12.34 0 4 1/2" TUBING 0.00
0 9"D.C. 185 0.00 0 5'' DP PL. COATED 0.00
0 TUBULAR 5" p/coat 19.5 0.00 0 13-3/8" casing 0.00
0 3 1/2" tubing 9.3 0.00 0 4-3/4DC 0.00
0 JOINTS RISER-5/8"SLICK 5.36 0.00 0 6-1/2" D.C. 0.00
0 3 1/2" D.P. 13.3 0.00 0 3-1/2DP 0.00
0 4-3/4 D.C. 54 0.00 0 5" liner 0.00
0 PROD. RISER 74.87 0.00 0 3 1/2" HVYWT 0.00
0 PR. RIS. STRESS 122.48 0.00 0 PROD. RISER HANGER 0.00
TOTAL SET BACK 108.27 TOTAL DOWN HOLE 0.00

3 - 64
EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
VESSEL STABILITY

OCEAN WHITTINGTON Condition: 36" casing BY Mathews

STABILITY REPORT DATE 12/12/01
Page 8
DRILLING LOADS RIG FLOOR VCG- 152'
Actual Vert L. Mom T. Mom
ITEM Weight VCG Moment LCG LT-ft TCG LT-ft
LT Ft LT*Ft Ft - FWD Ft - Port
Guide line tension 0 0.00 141.00 0 0.00 0 0.00 0
Pod line tension 0 k ea 0.00 141.00 0 0.00 0 0.00 0
Riser tension 0 k ea. 0.00 147.00 0 0.00 0 0.00 0
13.77 Inner slip joint 0 0.00 147.00 0 0.00 0 0.00 0
10.71 Diverter 0 0.00 152.00 0 0.00 0 0.00 0
Hook W/120K T.Drive 0 0.00 176.00 0 0.00 0 0.00 0
Set back load 324 jts. 108.27 200.00 21654 7.50 812 7.50 812
ROTARY 0 jts. 0.00 152.00 0 0.00 0 0.00 0
Misc. Tools 10.00 152.00 1520 7.50 75 8.20 82
TOTALS 118.27 195.94 23174 7.50 887 7.56 894

MOONPOOL LOADS
Actual Vert L. Mom T. Mom
ITEM Weight VCG Moment LCG LT-ft TCG LT-ft
LT Ft LT*Ft Ft - Fwd Ft - Port
51.93 LMRP 51.93 LT. 51.93 127.00 6595 -25.00 -1298 0.00 0
123.00 0 22.00 0 0.00 0
Support frame "DO NOT REMOVE" 6.89 115.00 792 -18.00 -124 0.00 0
Misc tools 4 123.00 492 0.00 0 0.00 0
SSTV 4 123.00 492 0.00 0 0.00 0
Subsea equip 4 123.00 492 0.00 0 0.00 0
82.00 BOP LOWER 82.59 LT. 82.59 128.00 10572 -18.00 -1487 0.00 0
TOTALS 153.41 126.69 19435 -18.96 -2909 0.00 0

116323.2 STABILITY REPORT SUMMARY

Actual Vert Long Tran
47 Weight VCG Moment LCG Moment TCG Moment
LT Ft LT*Ft Ft LT-ft Ft LT-ft
40litewt Lightship NOTE: 9816.94
LIGHTSHIP 78.22
LCG IS 18.30767881.05
FROM LIGHTSHIP
1.02 ADDITIONS
10013 PAGE 2.60
& INCLINING
25524.04
TEST.updated 6/11/01
Corrections to lightship 0.00 0.00 0 0.00 0 0.00 0
Anchor chain 600.62 27.00 16217 0.21 125 0.40 238
Anchors 0.00 0.00 0 0.00 0 0.00 0
Chain vert tens 380.36 49.20 18714 15.56 5917 6.10 2320
0 0
TOTAL Oper. L/W 10797.91 74.35 802811 1.49 16055 2.60 28082

3 - 65
EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
VESSEL STABILITY

OCEAN WHITTINGTON Condition: 36" casing BY Mathews

STABILITY REPORT DATE 12/12/01
Page 9

VARIABLE DECK LOADS

Actual Vert Long Tran
Weight VCG Moment LCG Moment TCG Moment
LT Ft LT*Ft Ft LT-ft Ft LT-ft
SOLID DECK LOADS
Bulk tanks 224.17 64.70 14504 13.18 2955 15.21 3409
Stores 122.00 122.75 14975 3.46 422 -15.13 -1846
Main dk loads 718.22 123.89 88982 52.02 37361 -8.11 -5827
Upper dk/box beams 111.60 136.27 15207 13.28 1482 58.36 6514
Sack matl 31.73 123.16 3908 -52.32 -1660 -7.37 -234
Drilling loads 118.27 195.94 23174 7.50 887 7.56 894
Moonpool loads 153.41 126.69 19435 -18.96 -2909 0.00 0

LIQUID DECK LOADS

Mud pits 243.53 123.50 30076 -96.26 -23442 2.20 537
Main deck liquids 211.30 111.82 23627 -31.26 -6605 -20.00 -4225

TOTAL DECK LOADS 1934.24 120.92 233889 4.39 8491 -0.40 -779

Variable Deck Load = 2166.3 s.t. Deck load margin = 714 s.t.
1934.2 l.t. 638 l.t.
VESSEL SUMMARY
Actual Vert Long Mom Tran Mom F.S. F.S.

Weight VCG Moment LCG LT-ft TCG LT-ft LT-ft LT-ft

LT ft LT*Ft ft - Fwd ft - Port Trans Long.

Operational ltwt 10797.91 802811 16055 28082

Solid deck loads 1479.41 180185 38538 2909
Liquid deck load 454.83 53703 -30047 -3688
Hull diesel fuel 270.23 1117 -3 20061 538 3292
Hull drill water 617.13 4830 -5315 -46282 1048 4984
Ballast 6098.40 64599 72605 5710 860 2336
Marine Growth 46.56 530
Total displacement 19764.46 56.05 1107775 4.65 91833 0.34 6793 2446 10612
VESSEL DRAFT 63.00 ft Theoretical draft = 60.00 ft.
Trim= -0.55 deg NEG. AFT List= 0.32 deg NEG PORT
DISCREPANCY 72 11.00 11 121 -1333.369 -14667 65 715
77165.93
TRANSVERSE STABILITY LONGTITUDINAL STABILITY
KMT 66.34 KML 71.48
VCG 56.05 VCG 56.05
F. SURF + 0.12 F. SURF + 0.54
VCG CORR 56.17 VCG CORR 56.59
GMT ACT 10.17 GML 14.89
GMT REQD 6.49 GML REQD 11.63
Trans. Margin 3.68 Lon'g margin 3.26

CONTINGENCY CHECKS ( TO BE ADDED TO EXISTING DECK LOAD)

WT LT VCG LCG TCG
LMRP 82 135 0 0
RISER 143 130 60 0
RISER TENSION (LOSS) -125 147 7.5 0

-874 10 0 0

LOSS OF #1 ANCHOR -76 27 -120 93

DAMAGE FLOODING

FWD DK 3-5,C/LKR,B/TK 400 69.60 -114.07 92.88

AFT DK3-5,C/LKR,B/TK,TRNK 441.8 66.53 114.88 92.70

PUMPROOM & ACCESS 578.1 13.85 144.39 92.55

3 - 66
EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
MARINE SAFETY

4
Section

4.0 MARINE SAFETY

OBJECTIVES
Upon completion of this section, you will be able to:

Describe key marine safety requirements in the following critical areas:

Stability.
Ballast System.
Abandonment/Survival.
Fire Fighting System.
Emergency Power.
Structural Integrity.
Personnel Qualifications/Experience.
Emergency Response.

List, describe and recognize potential marine related problems in offshore drilling
operations so they can be called to the attention of appropriate personnel and
corrected before they become serious problems.

List and describe the most common marine problems on offshore rigs today.

4-1
EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
MARINE SAFETY

CONTENTS Page

4.0 MARINE SAFETY ............................................................................................................................. 1

OBJECTIVES .................................................................................................................................... 1
CONTENTS ............................................................................................................................... 2
4.1 INTRODUCTION ............................................................................................................................... 4
4.2 STABILITY ........................................................................................................................................ 5
4.2.1 KEY REQUIREMENTS....................................................................................................... 5
4.3 BALLAST SYSTEM .......................................................................................................................... 9
4.3.1 KEY REQUIREMENTS ...................................................................................................... 9
4.3.2 BALLAST SYSTEM OPERATION..................................................................................... 9
4.3.3 BALLAST SYSTEM SCHEMATIC................................................................................... 12
4.3.4 EMERGENCY POWER SOURCE ................................................................................... 13
4.3.5 MOST COMMON PROBLEMS ON RIGS TODAY .......................................................... 13
4.3.6 APPENDIX I ..................................................................................................................... 14
4.4 ABANDONMENT/SURVIVAL ......................................................................................................... 17
4.4.1 KEY REQUIREMENTS .................................................................................................... 17
4.4.2 EVACUATION EQUIPMENT ........................................................................................... 18
4.5 FIRE FIGHTING SYSTEM ............................................................................................................... 24
4.5.1 KEY REQUIREMENTS .................................................................................................... 24
4.5.2 SIMPLIFIED FIRE SYSTEM SCHEMATIC ...................................................................... 25
4.5.3 FIRE FIGHTING/ALARM SYSTEM ................................................................................. 26
4.5.4 FIXED FIRE EXTINGUISHING SYSTEMS ...................................................................... 29
4.5.5 EMERGENCY COMMAND CENTER .............................................................................. 29
4.5.6 STATION BILL................................................................................................................. 30
4.5.7 MOST COMMON PROBLEMS ON RIGS TODAY .......................................................... 30
4.6 EMERGENCY POWER SYSTEM ................................................................................................... 31
4.6.1 KEY REQUIREMENTS .................................................................................................... 31
4.6.2 LOCATION....................................................................................................................... 31
4.6.3 DESIGN OPERATING LIMITS......................................................................................... 31
4.6.4 CRITICAL EQUIPMENT .................................................................................................. 32
4.6.5 EMERGENCY POWER SYSTEM OPERATION .............................................................. 34
4.6.6 MOST COMMON PROBLEMS ON RIGS TODAY .......................................................... 35
4.7 STRUCTURAL INTEGRITY ............................................................................................................ 36
4.7.1 KEY REQUIREMENTS .................................................................................................... 36
4.7.2 CLASSIFICATION SOCIETY ROLE................................................................................ 36
4.7.3 LEAK DETECTION SYSTEM .......................................................................................... 39
4.7.4 MOST COMMON PROBLEMS ON RIGS TODAY .......................................................... 41
4.8 PERSONNEL .................................................................................................................................. 44
4.8.1 KEY REQUIREMENTS .................................................................................................... 44
4.8.2 PERSONNEL QUALIFICATIONS.................................................................................... 44
4.8.3 MOST COMMON PROBLEMS ON RIGS TODAY .......................................................... 55
4.9 EMERGENCY RESPONSE ............................................................................................................. 56
4.9.1 KEY REQUIREMENTS .................................................................................................... 56
4.9.2 EMERGENCY RESPONSE ORGANIZATION ................................................................. 57
4.9.3 EMERGENCY COMMAND CENTER .............................................................................. 62
4.9.4 EMERGENCY DRILLS .................................................................................................... 62
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4.9.5 MOST COMMON PROBLEMS ON RIGS TODAY .......................................................... 63

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4.1 INTRODUCTION
The offshore drilling industry has experienced several major accidents involving high
loss of life. Following each accident, rig contractors and other industry groups took steps
to upgrade safety equipment, maintenance, and training of marine personnel. However,
since the last major accident in 1983, contractors have downsized/merged/ reorganized
to reduce costs and become more competitive. As a result, emphasis on marine safety
has suffered.
Today, there may be a perception throughout industry that compliance with
Classification Society Rules, Governmental Regulations, and Industry Guidelines )such
as the IMO MODU Code, Safety of Life at Sea (SOLAS) and API Recommended
Practices) adequately address marine safety systems and training so that Operators
only need to focus on the drilling equipment requirements for the operation. Although all
industry groups contribute to marine safety, no one group addresses everything.

Even though no major accidents involving high loss of life have occurred recently,
accidents resulting in loss of life still occur - accidents that are primarily due to lack of
equipment maintenance and/or lack of personnel training. Therefore, the risk of a major
accident remains if the right chain of events occurs. This risk can be reduced by
proactive efforts by Operator personnel.
Marine awareness starts with an understanding of the marine safety systems on
an offshore drilling rig. This section of the Floating Drilling School highlights key
requirements in the following critical areas:
Stability.
Ballast Control.
Abandonment/Survival Systems.
Fire Fighting System.
Emergency Power System.
Structural Integrity.
Personnel Qualification/Experience.
Emergency Response Training.

At the end of this section, you should be able to recognize potential problems that
exist on your rig so that they can be called to the attention of the appropriate contractor
and operator personnel before a potential problem becomes a real and serious
problem.
E xxo n M o b ils p rim a ry m a rin e sa fe ty sta n d a rd s a re co n ta in e d in th e Upstream Design
Guidance Manual Mobile Offshore Unit Marine Safety.

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4.2 STABILITY
S ta b ility is th e N a va l A rch ite cts w a y o f d e scrib in g th e a b ility of a rig to resist capsizing or
o ve rtu rn in g . In ta ct sta b ility re fe rs to th e rig s a b ility to re m a in u p rig h t w h e n th e re is n o
damage or flooding while damage stability refers to the stability of the rig after flooding in
one or more compartments has occurred. Loss of stability is one of the most serious
consequences that can happen to a vessel.
Stability theory is covered in another section of the Floating Drilling Manual. This section
addresses the practical application of stability theory in offshore drilling operations.

4.2.1 KEY REQUIREMENTS

The key stability requirements for any rig are:

Compliance with applicable stability criteria

Accurate input (into the stability calculations)

Proper interpretation of results, and

Minimum 3-ft KG margin, (KG is the vertica l d ista n ce o f th e g ro ss ve sse ls ce n te r

of gravity above the keel, see section 3.1.4)

COMPLIANCE WITH APPLICABLE STABILITY CRITERIA

S ta b ility d a ta co n ta in e d in th e rig s O p e ra tin g M a n u a l p ro vid e g u id e lin e s fo r sa fe
operation of the rig. Industry experience has shown that adherence with these guidelines
will ensure that the rig has positive stability under all conditions.

ACCURATE INPUT
Stability calculation results are only as accurate as the input.
Marine safety surveys have shown that errors often creep into the calculations -
sometimes intentionally and sometimes unintentionally. When this happens, the
results are meaningless and everyone on board is placed at risk.
Potential sources of errors found in stability calculation worksheets include:
SENSOR ERRORS
The ballast, fuel, potable water, drill water, and mud pit weights used in the stability
calculation are generally based on sensor input. The sensors measure the liquid level in
each tank, and charts in the Operating Manual are used to correlate the liquid level with
the weight of the liquid in each tank. If these sensors are not reading correctly, errors are
introduced into the calculations. The liquid weights on most rigs represent approximately
35-40% of the total rig displacement (rig weight). Therefore, if these sensors were reading
high by 1%, this would correspond to approximately 100-200 MT.

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All rigs have sounding tubes that permit the liquid level in each tank to be manually
checked in order to verify the accuracy of the sensor input. The tank sounding
readings should be checked against the sensor readings weekly. On many rigs, the
sounding tubes are clogged (corroded) and tank soundings are not regularly conducted.
Operating in this mode introduces uncertainty in fluid levels, in weights, and hence
stability.
ASK: Ask the marine personnel how often they sound the tanks.
Results of rig surveys have shown that tank sensors can be in error by up to 0.5 M. In
most rigs, this would correspond to an error of approximately 5% of the total weight in the
tank. Occasionally, sensors short-out and indicate that a tank is pressed up (completely
full) when the tank is either empty or partially full.
Draft sensors should also be periodically checked against visual observations. Draft marks
are painted on each column for this purpose. Visual readings should correspond to sensor
readings within +/- 0.2 M.

LIGHTSHIP WEIGHT ERRORS

Lightship is the bare vessel weight, see section 3.4.1. Errors in lightship are the most
common weight discrepancies noted on rigs. If the rig is several years old and no changes
to lightship have been recorded, the lightship weight used in the calculations should be
viewed with suspicion. Entered lightship numbers have been found to be low by as much
as 2-3% of the correct lightship value. The best way to check the accuracy of the lightship
value is to conduct a deadweight survey, which is a survey of all equipment and supplies
onboard the rig. This survey usually requires 2-3 days and should be conducted when the
rig is underway or is in port for inspection. After all weights are estimated and added to the
recorded lightship weight, the total weight should equal the displacement corresponding to
the actual draft.

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BCO INPUT ERRORS

A review of one stability worksheet on a rig can provide an idea of how well the Ballast
Control Operator (BCO) is handling his job, but it may not provide any clues on whether
the BCO is altering the input. Several "snap shots" in time are more informative and
useful.
The entries shown in Table 4.1 were taken from stability worksheets prepared on three
different days during one exploration well.
For example, the BCO preparing the worksheet on Day 10 entered 16,918-MT for
lightship, a value that was 342 MT higher than shown in the Operating Manual and
entered on subsequent worksheets. The same BCO entered a weight for all 3rd party
equipment that was 33 MT lower than used in all subsequent calculations, without
evidence that any such equipment had been added to the rig later.
On two occasions (Day 40 and Day 41), the BCO entered the average of the total
mooring line tensions instead of calculating the vertical component and entering that
value into the table. This introduced a 280 MT error.

Day 10 Day 40 Day 41 4.2.1.1

Lightship 169 18 165 76 165 76 16576

3rd Party 158 191 191 191

Mooring Tension 840 1120 1120 840

Chain Out -2012 -1982 -2012 -1754

Dummy Ballast 333

Extra Chain 295

Unknown Weight 237

Table 4.1 - Example - Stability Worksheet Input Variation

Note: All weight entries in Table I are in MT.

Another error made by the BCOs was in accounting for weight of the mooring lines
deployed on location. The BCOs knew that the weight of the chain mooring lines was
included in lightship so they subtracted out the weight of the mooring lines deployed on
location (Note: there was a 30 MT difference in the calculation for weight of chain
outboard; this difference should have been resolved). This particular rig was designed and
equipped for operations in 1500-ft of water. When operations were extended into 1715-ft
of water, additional chain was added to each mooring line to permit operations to be
conducted in deeper water. The BCOs incorrectly deducted the entire mooring line weight
instead of only the mooring line weight included in lightship. This introduced a 250 MT
error.
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On Day 40, the BCO made a 333 MT entry for Dummy Ballast (mystery name), which did
not appear on the other two worksheets. On Day 41, the BCO corrected this error and
entered 295 MT of extra chain that did not appear on the other two worksheets.

PROPER INTERPRETATION OF RESULTS

The results in this example were not being interpreted properly they were being
manipulated to provide a desired answer. When stability calculation results show that
the rig is trimmed/heeled and the inclinometers indicate that the rig is on an even keel, the
BCO should identify the problem and correct it instead of altering input.
ASK:
Ask the BCO if he has any guidelines on how much KG margin should exist.
The results should always indicate a KG margin of at least 3-ft. If you find yourself on a rig
where the KG margin is low (less than 3-ft), you are "at risk." Historically, these are the
same rigs that routinely keep watertight doors and hatches open so that they do not
interfere with normal operations. If the watertight doors/hatches are left open, uncontrolled
flooding can occur during storms, which leads to loss of stability and possibly loss of
the rig.

MOST COMMON PROBLEMS ON RIGS TODAY

The most common problems on rigs today are:

Stability worksheets are not accurantely completed.

Stability margin does not always include contingincy allowances.

Sensors do not work properly (lack of maintenance).

Sounding tubes are plugged.

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4.3 BALLAST SYSTEM

The ballast system is used to maintain the rig on an even keel and to change drafts
(transit, survival, and drilling). Inadvertent ballasting/deballasting of the wrong tank,
particularly during storm or damage conditions, can lead to excessive trim or list of the rig,
which then places all personnel on board "at risk."

4.3.1 KEY REQUIREMENTS

The ballast system should have the capability to:

maintain the rig on an even keel during all normal operations.

return the rig to an even keel and safe draft after flooding.

prevent uncontrolled flooding of ballast tanks after power failure.

deballast from drilling draft to survival draft in less than 3 hours.

ballast/deballast any ballast tank following failure of critical equipment (equipment

redundancy).

4.3.2 BALLAST SYSTEM OPERATION

Operation of the ballast system during normal operations consists of selectively
ballasting and deballasting tanks to maintain the rig on an even keel as supplies are
brought out from shore and consumed in the well. In the event of a collision that results
in flooding of a compartment below the waterline, the BCOs should be capable of
returning the rig to an even keel by selectively ballasting/deballasting ballast tanks.

Ballast Control Room

The ballast control room is generally located on the upper deck although the control
room on a few rigs is located in the upper section of one of the columns.

Ballast Pump Rooms

On semisubmersibles, the pump rooms are usually located in the pontoon or the lower
area of one of the columns; one pump room on either side of the rig. In addition, some rigs
have pump rooms at both the fore and aft ends of each pontoon that provide redundancy
and added capability to take suction on every tank.
Pump rooms do occasionally flood (In fact it is the single most common flooding incident).
In this event, use of all equipment in the room is lost for at least 7-10 days. A report of an
actual pump room flooding incident on an Exxon contracted rig is included in Appendix I to
illu stra te th a t o ve rsig h ts a n d o m issio n s b y rig p e rso n n e l ca n p la ce e ve ryo n e o n b o a rd
at risk.

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Ballast Pumps
The ballast system normally includes two independent pumps in each pontoon to permit
continuous operation of the system if one of the pumps is out of service for routine
maintenance or pump replacement. Newer rigs locate these pumps in separate
compartments so that if one pump room floods, both ballast pumps in that pontoon are not
lost.
Each ballast pump should be capable of taking suction on every ballast tank in the
pontoon. In addition, ballast pumps are typically selected to permit suction to be taken on
every tank with the rig inclined up to about 10 degrees (each rig will have slightly different
limits).
ASK: Ask the BCOs if they know the limiting angle for proper operation of the
ballast pumps. See if they need to go to equipment manuals to answer
your question.
Ballast Control Operators should be aware of the ballast system capabilities and
limitations so that timely and correct action can be taken during an emergency. Otherwise,
all personnel on board are "at risk."
There are no current industry standards for ballast pumps with the exception that the
ballast system should be capable of deballasting the rig from drilling draft to survival draft
in less than three hours. (The objective is to be able to secure operations and
deballast to survival draft in advance of a storm). Consequently, pumps are primarily
selected for suction.
ASK: Ask the BCOs if they know the length of time required to deballast from
drilling to survival draft.
If ballast piping suffers from scaling and/or pump impellers are excessively worn, the
three-hour objective may not be met.
Control Valves
The ballast system includes both manual and remotely operated valves. Manual valves
are generally installed to isolate various sections of the system during routine
maintenance, and remotely operated valves are installed for normal operations.

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In the event of power failure, the ballast system must be secured to prevent
uncontrolled flooding. Some remotely operated valves are designed to fail in the closed
position while others are designed to fail in the current position. The valves may or may
not be designed to change position upon the reactivation of power. The mode of failure
depends upon the valve design and the control system arrangement:

Some valves are opened and closed electrically (worm or screw drive). Upon loss
of electrical power, these valves fail in the position at the time of failure. When
power is restored, the valve resumes its position or operation at the time of failure
(open, closed, or shifting position).

Other valves are fitted with air or hydraulic actuators. An electrical signal from the
control panel activates a solenoid, which opens a valve in the air or hydraulic
pressure line leading from an accumulator to the ballast valve. When pressure (air
or hydraulic) is applied to the ballast valve, the valve opens. When the electrical
signal to the solenoid valve is turned off, the solenoid in the air/hydraulic pressure
line is closed. Some control systems are designed so that pressure is
simultaneously bled off the ballast valve when the solenoid in the control pressure
line is closed. Other designs employ a shuttle valve so that an electrical signal is
required to shift the shuttle valve to bleed pressure off the ballast valve. In either
event, when pressure is bled off, a spring forces the ballast valve to shift to the
closed position.
If all remotely controlled valves fail in the closed position, the ballast system is
secure. If all remotely controlled valves fail in the current position, any tank open to the
sea at the time of power failure will flood unless rig personnel go to the pump room and
manually secure the valve.
ASK: Ask the BCOs if all ballast valves fail in the closed position.
If the valves are not designed to fail in the closed position, the Barge Engineer and Ballast
Control Operator must have contingency plans in place so that rig personnel go
immediately to the pump room and manually close all valves to each ballast tank. Ballast
valves should all be labeled to indicate the direction to close the valve (CW or CCW). Most
rigs are equipped with both CW and CCW close valves.

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4.3.3 BALLAST SYSTEM SCHEMATIC

A simplified ballast system schematic for one pontoon is shown in Figure. 4.1. The two
ballast pumps are located in the center of the schematic. Seawater is drawn into the
system through the sea chest, which contains a strainer (filter). The sea chest can be
isolated by manually closing the valves on either side. These manually operated valves
are normally open. Inboard of the sea chest is a remotely operated valve (a) which isolates
the ballast system from the ocean.

Figure 4.1 - Simplified Ballast System Schematic

A manual and a remotely operated valve are located on the inlet (upstream) side of each
ballast pump. The valves shown on the discharge side (downstream) of the pumps are
manually operated. The discharge valve on pump #2 is shown to be normally open. The
discharge valve on pump #1 is shown to be normally closed. If the primary pump #2 fails,
the discharge valve on pump #1 must be manually opened.
ASK: Ask the BCOs if the ballast pumps have both a manual and a remotely
operated valve upstream and downstream of the pump.
Some rigs have both manual and remotely operated valves on the discharge side of the
ballast pump instead of just a manually operated valve as shown in Figure 4.1.
In order to pump ballast into a tank, remotely operated valves a, b, c and d must be open.
Valves e and f must be closed.
For deballasting operations, remotely operated valves d, f, b, and e should be open.
Valves a and c should be closed.
Upon loss of main power, valves a, b, c, d, e and f should be closed to prevent
uncontrolled flooding or cross flow between tanks.
The system is normally arranged so that only one tank in each pontoon can be handled
at a time.

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4.3.4 EMERGENCY POWER SOURCE

If main power is lost, the capability should exist to supply one ballast pump in each
pontoon from the emergency source of power. Some rigs have one ballast pump in each
pontoon connected directly to the emergency switchboard while others back feed power to
the ballast pumps through the main switchboard (see Emergency Power System).
Separate wiring directly from the ballast pump to the emergency switchboard is necessary
to maintain system capability in the event of a fire in the main engine room.
ASK: Ask the BCOs how emergency power is supplied to the ballast pumps.

4.3.5 MOST COMMON PROBLEMS ON RIGS TODAY

The biggest problems on rigs today are:

Ballast pumps are not isolated in each pontoon

BCOs do not know the limiting conditions for pump operation

Ballast pumps are not connected directly to the emergency switchboard

Manual valves are not all clockwise or counterclockwise close

No chain locker covers

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4.3.6 APPENDIX I
Accident Report - Flooding of Starboard Pump Room
June 30, 1992
Summary:
June 6 Salt-water pump in starboard pump room failed.
June 10 Pump removed for inspection and repair.
Electrical and mechanical isolation permits issued.
Manual upstream valve closed.
Remote upstream valve in closed position; not manually closed (locked
out).
Parts placed on order.
June 30 Starboard pump room floods (completely fills with water).
Bilge alarms ignored.
Electrical equipment problems on starboard side (fans in
accommodation space start/shut down; 440v circuit breaker trips and
will not reset; elevator in starboard center column will not operate).
Flooded pump room confirmed 40 minutes after initial bilge alarms.
Pump room completely flooded and starboard fire pump, sprinkler
pump, fuel oil pump, cooling water pump, and drill water pump under
water.
Cause
The manual valve upstream of the salt-water pump was in fact not closed
on June 10 as thought. Some of the valves in the pump room were left-
hand close and some were right-hand close. The valve in question was a
left-hand close and was properly marked, but it was apparently opened
instead of being closed because left-hand close valves were unusual on
this rig. The pump room then flooded when someone inadvertently opened
the remotely controlled valve upstream of the pump.
Contributing Causes
The Marine Department did not sign off on the isolation permits.
A sign was not posted on the panel in the ballast control room
indicating that the pump was out of service.
Several BCOs were not informed that the pump was out of order.
Several maintenance personnel were not aware of the pump isolation.
Remote valve was not closed (locked out)

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Blind, watertight flanges were not installed on the upstream and

downstream piping when the pump was removed.

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Potential Problems
The rig was designed with one pump room and two thruster pump rooms in
each pontoon. The main pump room in each pontoon houses the fire, fuel
oil, sprinkler, cooling water, drill water, and salt-water pumps. The ballast
pumps, which also serve as emergency bilge pumps, are located in the
thruster pump rooms. In this particular situation, the rig maintained the
capability to deballast to survival draft, if necessary. In addition, the fire,
fuel, drill water pumps in the port pontoon provided the necessary capability
to continue operations without jeopardizing safety.
Many rigs are designed with only one pump room in each pontoon. If the
pump room floods on these rigs, all pumps on that side of the rig are lost.
To compensate, some rigs have cross piping connecting the two pontoons.
Otherwise, in the event of a storm, the rig would not have any capability to
deballast to survival draft.

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4.4 ABANDONMENT/SURVIVAL
Semisubmersibles are equipped with lifeboats or survival craft, life rafts, and life jackets for
use in an emergency. In some instances, exposure suits are also provided.
In most areas of the world, rig evacuation by helicopter is the preferred means for rig
abandonment. If abandonment by helicopter is not possible, rig evacuation by
lifeboat/survival craft offers a greater chance of survival than using life rafts or jumping
directly into the water, provided crews and rig personnel are properly trained and
equipment is maintained.
Marine safety surveys have found that lifeboat/survival craft maintenance and personnel
training are weak on some rigs. Surveys also have found that many rig personnel are
afraid to climb into a lifeboat/survival craft during a drill because they are concerned that
the lifeboat/survival craft may be prematurely released and fall into the water resulting in
in ju ry o r d e a th . In e ffe ct, e ve ryo n e o n b o a rd is p la ce d at-risk during rig abandonment
unless the contractor has handled his maintenance and personnel training properly.
In addition, many personnel are not aware of the serious consequences of entering cold
water without wearing an exposure (survival) suit. They may not have received necessary
training on how to quickly put on an exposure suit and properly seal all openings. They are
"at risk" if they do not properly don a suit and seal all openings before leaving the rig. An
exposure suit that leaks is not much better than no suit at all.

4.4.1 KEY REQUIREMENTS

The key requirements are:

An Escape, Evacuation, and Rescue (EER) analysis that describes a safe and reliable
means to evacuate all personnel

Exposure suits for all personnel on board, if applicable typically if the water
temperature is below 60o to 68o F.

Adequate personnel training

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4.4.2 EVACUATION EQUIPMENT

LIFEBOAT/CAPSULE
Lifeboats/survival craft should be designed and equipped as follows:
1. Totally Enclosed
2. Self-Righting
3. Motor-Propelled
4. On-load/Off-load Release Hooks
T h e se life b o a ts/su rviva l cra ft a re o fte n re fe rre d to a s to ta lly e n closed motor propelled
survival craft (TEMPSC).
The release hooks should be designed to release regardless of whether the falls
are under load. Commonly, the hooks are described as on-load release hooks with
off-load backup release capability or off-load release hooks with on-load backup
release capability.

Off-load Release Hooks - Off-load release hooks are designed to disengage after
the lifeboat/survival craft has been lowered and is floating on the water with no
load on the falls.

On-load Release Hooks - On-load release hooks are designed to release under
any load up to 1.1 times the fully loaded weight of the lifeboat on the falls. These
hooks will not release if the lifeboat/survival craft is floating on the water and
there is no load on the falls.
Note: An industry study conducted several years ago concluded that the design of
release hooks, particularly on-load release hooks, requires that certain
procedures be followed to prevent accidental or premature release. In a
number of accidents, the safety features failed because the release gear
malfunctioned or crew members failed to understand the system and, as a
consequence, did not properly reset the release hooks.
Lifeboats/survival craft should be launched quarterly.
5. Seating Capacity
Lifeboat/survival craft seating capacity requirements shall be established by an EER
analysis. It should provide at least one seat for everyone on board under the
emergency scenarios requiring evacuation. Consideration shall be given to injured
personnel, loss of a TEMPSC, and use of survival suits, where required. Normally, this
requires seating for 200% of personnel onboard 100% on bow and stern (semi) and
100% on port and starboard (drillship).
Lifeboat/survival craft seating capacity varies with manufacturer and model.
Lifeboat/survival craft installed on semisubmersibles usually have seating for about 50-
65 averag e people wearing life jackets. Exposure suits are bulkier than life jackets
a n d m o st o ffsh o re d rillin g p e rso n n e l a re b ig g e r th a n a n a ve ra g e 1 5 0 -lb person, so
the maximum seating capacity may be less than the rated capacity.
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6. Equipment
Lifeboats/survival craft should be equipped with the following:
permanently installed VHF marine radio connected to a battery charger
emergency lighting
radar transponder or EPIRB (Emergency Position Indicating Radar Beacon)
first-aid kit
fire extinguisher
potable water
sprinkler system
signaling equipment
compass
breathing air
running lights
cold start capability, if required
back-up starting system
off load release hooks with on-load backup
external strobe lights
food (may be waived if justified by the EER analysis)
Note: Lifeboat/Survival Craft Inspection. Regular inspection by factory-trained
personnel is necessary to help ensure that the lifeboats and associated release
hooks are properly maintained and that rig personnel are familiar with
lifeboat/survival craft and release hook operation. Each lifeboat manufacturer has a
routine maintenance program for their equipment, and a copy of the program
should be available on the rig. Rig personnel should understand Lifeboat/survival
craft maintenance procedures.
Manufacturers also periodically issue service bulletins or service alerts, which
notify customers of accidents and/or identify recommended modifications. A copy
of all service bulletins should be maintained on the rig. These bulletins are
g e n e ra lly se n t to th e co n tra cto rs h o m e o ffice , a n d th e h o m e o ffice is re sp o n sib le
for forwarding copies to each rig. In some instances, the manufacturer's service
bulletins were lost when rigs were sold or contractors merged. Consequently,
there are still lifeboat/survival craft within industry that have not been modified to
correct problems.
Note: The practice of hanging dual-fall lifeboats by temporary support pendants (for
maintenance) introduces a safety hazard. Consequently, the maintenance
pendants should be inspected by the senior marine operations supervisor prior to
release from the falls.

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LIFE RAFTS
The EER analysis should establish the number of davit-mounted life rafts. Normally, a rig
should be equipped with a sufficient number of float-free life rafts to accommodate 100%
of the rig compliment. The rafts should be located away from the lifeboat/survival craft
launch areas so that they are accessible even when the lifeboats are not.

LIFEJACKETS
Lifejackets should be provided for 150% of the maximum number of people permitted on
board. All lifejackets should be equipped with a light.
A lifejacket should be stored near each bunk (100%) and another 50% should be stored at
locations near the moonpool, spider deck, and abandonment stations.

LIFE RINGS
Life rings should be located in areas around the upper deck and the moonpool area and
other areas where there is a potential for a man to fall overboard. At least one life ring
located near each normally manned space should be equipped with a light and self-
activating smoke generator. In addition, at least one life ring should have a retrieving line.

ESCAPE ROUTES
Two escape routes should be available from every normally manned space.
Routes from the quarters to lifeboats should be clearly marked and free of obstructions.

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EXPOSURE SUITS
The rig should be equipped with exposure suits for everyone onboard when operations are
conducted in areas where the daily mean water temperature is anticipated to be below
20oC (68oF) over 5% of the time during a month and rescue time exceeds survival time
without a suit.
Cold water can kill in a relatively short period of time. During the first few minutes after
entering cold water there is a high probability of death by drowning as a result of
respiratory and circulation shock responses. If the individual survives the initial shock of
entering the water, the body core temperature will gradually drop until it reaches 91o F
when voluntary movement ceases and drowning and/or heart failure occurs (hypothermia).
A person becomes unable to help themselves (i.e. grab a line long before this occurs).

Figure 4.2 - Estimated In-Water Survival Time for an

Unprotected, Average Person

The length of time between entering the water and losing all voluntary movement
(estimated survival time) is related to the weather, physical characteristics of the
individual, and the type of protective clothing. For example, the average survival time for
an individual in 50o F water wearing work clothing (no protective clothing) is
approximately 2 hours as shown in Figure. 4.2. The dotted lines above and below the
solid line indicate the range in survival times for different individuals. In 32oF water, the
average survival time is approximately one hour.

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Survival time can be increased by use of protective clothing as shown in Figure 4.3.
Uninsulated helicopter suits increase the survival time to about 8 hours in 50o F
water. Insulated helicopter suits increase survival time to more than 14 hrs and
exposure suits provide almost unlimited survival time in 50o F water.

Uninsulated
Helicopter Suit
w/Heavy Clothing

Figure 4.3 Estimated In-Water Survival Time for Various Types of Protection

Most suits are one-piece with integral hood, boots and gloves. The suits have a fast and
efficient entry via a waterproof airtight front zipper. Air expulsion valves ensure instant
venting of excessive trapped suit air in water, without water ingress. Buoyancy and
thermal insulation is provided by internal-buoyant cell foam. The suits are designed to limit
the average drop in body temperature to 2o or less with water conditions between 32 and
37o F (0 and 3 deg C) after a 6 hr period in the water. Theoretically, body temperature
should not drop below 92o F in 18 hours if the individual is wearing a properly sealed
exposure suit.
Number: Suits should be provided for 150% of the maximum number of personnel
permitted on board.
Location: Stored in the quarters (one near each bunk) and at lifeboat/survival craft
stations

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4.4.3 MOST COMMON PROBLEMS ON RIGS TODAY

The most common problems on rigs today are:

Personnel are not familiar with operation of the lifeboat release mechanism(s)

Preventative maintenance of abandonment systems is not performed

Lifeboat backup crews have not received sufficient training/re-training

Personnel are not aware of the hazards associated with entering the sea

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4.5 FIRE FIGHTING SYSTEM

Each semisubmersible will have a fire detection and extinguishing system, however
system capabilities will vary from rig to rig. Current industry standards include smoke and
fire-sensing devices, gas detection devices, an automatic alarm system, a seawater fire
main system, a fixed gas-extinguishing system, and a helideck foam system. The major
difference between equipment found on new and older rigs is the requirement for a fire
alarm and detection system and a gas alarm and detection system. On older rigs,
personnel must detect gas or smoke and manually activate an alarm, while newer rigs are
constructed with automatic detection and alarm devices.
Once the alarm is sounded, system capability depends on how well the fire-fighting
equipment has been maintained. Surveys have shown that maintenance of fire-fighting
equipment is often inadequate. Leaking fire hydrants and worn pump impellers are
common occurrences - problems that lead to low water main pressure and corresponding
difficulties in fighting a fire.

4.5.1 KEY REQUIREMENTS

Two independent fire pumps
Pumps should be physically separated
Capability to operate system after loss of main power
50 psi pressure (min. at nozzle) with two hydrants open and nozzles on straight
stream
Helideck foam system, if required for refueling
Fire detection and alarm system
Gas detection and alarm system
Emergency Command Center

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4.5.2 SIMPLIFIED FIRE SYSTEM SCHEMATIC

A one-line schematic for a simplified sea water fire main system is shown in Figure 4.4.
The fire pumps are located in the lower hull and take suction from the sea through the sea
chest. The discharge from the pumps goes directly to a "closed loop" fire main that
circles the rig in the upper hull. Constant pressure is maintained on the fire main at all
times. The "closed loop" is equipped with a pressure sensor that automatically starts the
fire pump when pressure drops below a pre-set level.

Figure 4.4 - Simplified Fire System Schematic

Remotely operated valves in the fire system should fail in the open position.
Only services which are directly associated with fire fighting or washdown should be
connected to the fire main.

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4.5.3 FIRE FIGHTING/ALARM SYSTEM

FIRE PUMPS
The rig should be equipped with at least two independently driven fire pumps installed in
separate locations so that an accident in one area will not disable all of the pumps. One of
the pumps should be dedicated to fire fighting service exclusively. The other pump(s) may
be used for sanitary, ballast, bilge or general service as long as they are manifolded into
the fire main.
Each pump should be capable of maintaining 50-psi pressure at the nozzle tip with any
two hydrants open and 19mm nozzles set on straight stream. In addition, where a foam
system is provided for protection of the helicopter deck, the pump should be capable of
maintaining 100 psi at the foam installation.
The fire pumps should automatically start upon loss of pressure in the fire main.
ASK: Ask fire team leaders if the fire pumps are wired for automatic operation.
If the pumps are not wired for automatic operation, remote start-up switches should be
located at strategic points around the rig. The pumps should also be set for local
operation.
Any pump connected to a fire main should be provided with a manually operated valve to
isolate the pump from the fire main for repairs and maintenance.
At least one pump, if electrically operated, should be connected directly to the
emergency switchboard.

FIRE MAIN
The fire main should be routed clear of hazardous areas. It should also contain isolation
valves so that any section of the main can be closed off and permit the remainder of the
main to be held at rated pressure as shown in Figure 4.5.

Figure 4.5 - Isolation Valve Locations

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ASK: Ask the fire team leaders to show you the isolation valves.

FIRE STATIONS
Fire stations should be located at strategic places around the rig. Each station should
consist of:

a hydrant

a 50-60 ft length of hose (minimum)

a combination fog and straight stream nozzle

a hose wrench, if applicable

All fire stations should be inspected quarterly to determine the condition of
equipment and to check for system leaks.

HYDRANTS
The number and position of hydrants should be sufficient to permit at least two jets of
water from hoses attached to separate hydrants to be brought to bear in any part of the rig
where a fire may occur.

FIRE HOSES
Standard fire hoses are 50 to 60 ft. in length. Most hoses are 2 in. diameter, however
some stations are outfitted with 1 in. diameter hoses. Permanently connected hose reels
found in accommodation spaces usually have smaller diameter non-collapsible hoses.

NOZZLES
Standard nozzle sizes are 12 mm, 16 mm, and 19 mm.
Note: The 16 and 19 mm nozzles are generally used at outdoor fire stations, and the
12 mm nozzle is generally used in accommodation and service spaces.

FIREMAN'S EQUIPMENT
Every rig should have at least 4 sets of fireman's equipment. Each set should consist of
the following:
a protective outfit, including gloves, boots, a face mask or hood and a helmet
a self-contained breathing apparatus with at least 3 spare breathing air bottles
a portable battery-operated safety lamp capable of functioning efficiently for a
period of not less than 3 hrs
a fireman's axe
a safety harness and lifeline.
The equipment should be stored in pairs (2 sets/pair) at different locations.

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FIRE EXTINGUISHERS
Sufficient fire extinguishers should be available so that at least one extinguisher is readily
accessible from any part of the rig. In addition, one portable fire extinguisher should be
located adjacent to every exit in the accommodation space.
Spaces equipped with fixed fire extinguishing systems such as machinery spaces should
also have fire extinguishers positioned at several locations in the space.
Portable extinguishers should be inspected quarterly. Checks should confirm the
proper charge - type (A, B, C) matched to potential class of fire; hoses and extinguishers
should appear to be in good condition; and the extinguishers should contain a current
inspection stamp with date.

HELIDECK
Fire fighting equipment for the helideck should consist of the following:

two dry powder extinguishers with a total capacity of at least 45 kg;

if the rig is equipped with refueling capability, a foam application system consisting
of monitors or foam-making branch pipes capable of delivering foam solution to all
parts of the helicopter deck.

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FIRE DETECTION
Every rig should have a fire detection system.
Machinery Spaces. Two different types of detectors should be provided in machinery
spaces - Thermal, smoke, and fragile bulb type detectors are commonly used.

Thermal (heat) - Thermal sensors detect a sudden rise in temperature. They

should not be installed in spaces with a roof, ceiling or overhead covering higher
than 8 M, and should be spaced so that each sensor does not monitor more than
37 M2 of deck area.

Smoke (optical) - Optical sensors detect loss of visibility due to smoke in a

compartment. These sensors are susceptible to the effects of ventilation on flow
patterns.

Smoke (flame) - Ultra violet flame detectors are generally used in open areas.

Fragile bulb - These sensors are generally set at approximately 30oC above the
normal ambient temperature. Most regulations also specify that the sensors need
not be set at temperatures less than 57oC.
Accommodation Spaces. A smoke detector should be installed in every personnel-
sleeping compartment.

4.5.4 FIXED FIRE EXTINGUISHING SYSTEMS

Machinery Spaces. Internal combustion machinery spaces (with 750 kw or more [1000
hp or more]) and paint lockers should be equipped with an inert gas flooding system.
The extinguishing system should provide sufficient agent to reliably extinguish a fire in the
protected space with the ventilation dampers and hatches closed. Both carbon dioxide and
Halon 1301 systems are acceptable. A conspicuous warning sign should be posted at all
entrances to the protected area.
With all types of inert gas flooding systems, alarms should be located in the
protected space to adequately warn occupants of impending discharge. These
alarms should provide adequate time for the crew to vacate the space. In high noise
areas, visual as well as audible alarms should be installed.

HELIDECK FOAM SYSTEM, IF REQUIRED

The foam system should be capable of rapidly discharging sufficient foam through fixed
discharge outlets to fill the greatest space to be protected at a rate of at least 1 m in depth
per minute. The quantity of foam-forming liquid available should be sufficient to produce a
volume of foam equal to five times the volume of the largest space to be protected. The
expansion ratio of the foam should not exceed 1000 to 1.

4.5.5 EMERGENCY COMMAND CENTER

The rig should have an emergency command center located outside the confines of the
machinery spaces and designated hazardous areas. The command center should have:
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internal communications to all personnel muster points.

external communications to supply boats, standby boats, marine emergency

frequencies, helicopters, aviation emergency frequencies, and the shore base.
a contactor (actuator) for the general alarm.
Command centers should have sufficient detailed plans of the rig to permit choosing
primary and secondary fire boundaries and marking emergency squad locations on the
plans. Fire command centers should have a drawing of the fire main system that clearly
identifies all systems connected to it and the location of isolation valves.

4.5.6 STATION BILL

The rig station bill should assign the Offshore Installation Manager (OIM) and a suitable
number of assistants to the emergency command center during an emergency.

4.5.7 MOST COMMON PROBLEMS ON RIGS TODAY

The most common problems on rigs today are:

low fire main pressure

missing or inoperable fire fighting equipment

personnel are not properly trained in marine fire fighting techniques

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4.6 EMERGENCY POWER SYSTEM

Every floating rig will have an emergency power system. The equipment connected
directly to the emergency switchboard will vary from rig to rig because older rigs are not
required to comply with current industry standards. Consequently, it is necessary to
identify which equipment is connected directly to the emergency switchboard.
In addition, periodic load tests of the emergency power system are essential to ensure that
it will operate properly in an emergency. Loss of emergency power places everyone
onboard "at risk."

4.6.1 KEY REQUIREMENTS

Isolation from the main power system

Automatic start (within 45 seconds) upon loss of main power

All critical equipment connected directly to the emergency switchboard

Capability to simultaneously operate all critical equipment connected to the

emergency switchboard

Capability to operate at a 22.5 degree angle of inclination, and

Periodic load test

4.6.2 LOCATION
The emergency source of power and the emergency switchboard should be located:

in a separate compartment so that a fire or other casualty in the space containing

the main source of electrical power will not interfere with the supply or distribution
of emergency power, and

on/or above the uppermost continuous deck level.

4.6.3 DESIGN OPERATING LIMITS

The emergency generator should operate at full rated power when upright and when
inclined up to the maximum angle of inclination for the rig in the intact and damaged
condition.
In actual practice, generator manufacturer's seldom custom build emergency
generators; instead they construct emergency generators to comply with industry criteria.
For semisubmersibles, the criteria is 22.5 degrees in any direction, which should exceed
the maximum inclination angle for a rig in either the intact or damaged condition.

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4.6.4 CRITICAL EQUIPMENT

The emergency power source should be capable of supplying simultaneously the
following services for 18 hours (if they depend on an electrical source for their
operation). Due consideration should be given to the starting currents and the
transitory nature of certain loads.

Navigation/helideck lights .

Emergency lighting:
at every embarkation station on deck and over the side.
in all service and accommodation alleyways, stairways and exits.
in the machinery spaces and main generating stations.
in all control stations and in all machinery control rooms.
in the tool pusher's office and on the drill floor (all spaces where drilling
activities can be controlled.
at the stowage position(s) for firemen's outfits.
at the sprinkler pump, if any, at the fire pump, at the emergency bilge
pump, if any, and at their starting positions.
on the helicopter landing deck.

General alarm and public address system.

Gas detection system.

Fire detection system:

fire detection and its alarm systems.
intermittent operation of the manual fire alarms and all internal signals that
are required in an emergency.

Fire extinguishing system.

All internal and external communication equipment required in an emergency.

One fire pump, if electric.

Sprinkler pump, if applicable.

BOP controls and riser disconnect systems.

Ballast pump.

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On semisubmersibles, each ballast pump should be capable of being supplied with power
from the emergency switchboard (only one of the pumps should be considered to be in
operation at any one time). The preferred arrangement is to have one of the pumps in
each hull connected directly to the main switchboard and the other pump connected
directly to the emergency switchboard. When sizing the emergency source of power, the
largest ballast pump should be assumed to be operating simultaneously with the other
critical loads noted above.

Ballast control system and ballast valves, if electrically operated.

Bilge Pump for each pontoon.

Personnel transfer cranes and elevators giving access to areas not accessible by
stairways.

Navigation and steering for self-propelled vessels.

Flooding alarms.

Computers necessary for emergency operations.

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4.6.5 EMERGENCY POWER SYSTEM OPERATION

Normal power to the emergency switchboard is provided through a feeder from the
semisubmersible's main switchboard as shown in Figure 4.6.

Figure 4.6 - Simplified One-Line Emergency Power Schematic

Note: The feeder should be protected against overload and short circuit at the main
switchboard. When the system is arranged for feedback operation, the feeder
should also be protected against short circuit at the emergency switchboard.

If the voltage level on the emergency switchboard falls to a pre-set level (normally 60% to
85% of normal), the bus-tie circuit breaker automatically opens and interrupts the supply of
electrical power from the main switchboard. When this occurs, power to the emergency
switchboard is then supplied by the emergency generator or accumulator battery source.
A short time delay is usually built into the system to delay opening of the bus-tie circuit
breaker after loss of main power in order to eliminate start-up of the emergency power
system when the main power system immediately recovers from a transient loss of power.
When main power is restored, the bus-tie circuit breaker is closed (either manually or
automatically), thereby restoring power from the main switchboard to the emergency
switchboard. The circuit breaker to the emergency power source is simultaneously opened
to break that circuit.
The arrangement shown in Figure 4.6 is typical of many rigs in operation today, but it
does not have the ballast pumps connected directly to the emergency switchboard. In
order to operate the ballast pump, the bus-tie circuit breaker must be closed and power
"back-fed" to the main switchboard. This approach is impractical if main power is lost
because of a fire in the main engine room.
The schematic in Figure 4.7 represents the preferred arrangement, which also complies
with current industry standards.
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Figure 4.7 - Preferred Practice Emergency Power One-Line Schematic

As shown, one ballast pump in each pontoon is connected directly to the emergency
switchboard in addition to the fire pump and other emergency equipment. This
arrangement permits all equipment to be operated during normal operations because
the bus-tie circuit breaker is closed and power from the main switchboard is delivered
to the emergency switchboard. When main power is lost, all critical equipment is
already connected to the emergency switchboard, and there is no reliance on the
main switchboard.

LOAD TEST REQUIREMENTS

Emergency power systems should be activated weekly and operated under partial load
(50% of rated capacity, minimum or equivalent full emergency load, whichever is greater)
for approximately one hour. During the load test, the coolant temperature should be
monitored to ensure that the emergency generator does not overheat.
The weekly load test should be documented.
ASK: Ask to see documentation on the weekly load tests.
If rig personnel have not conducted the weekly load test as specified, all critical equipment
may not be directly wired to the emergency switchboard.

4.6.6 MOST COMMON PROBLEMS ON RIGS TODAY

The most common problems on rig today are:
Failure to run the emergency generator under full load weekly

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4.7 STRUCTURAL INTEGRITY

S tru ctu ra l in te g rity is th e ke y to safety offshore. Too many times, however, structural
integrity is taken for granted.

4.7.1 KEY REQUIREMENTS

The key requirements for any rig are:

Design integrity

Fatigue life

Absence of major structural defects

Leak detection and alarm system (optional)

4.7.2 CLASSIFICATION SOCIETY ROLE

Historically, assurance of rig integrity has been handled by the Classification Society.
American Bureau of Shipping (ABS) and Det Norske Veritas (DnV) class most of the
offshore drilling units in operation today, and both societies have Rules that apply
specifically to floating rigs. These Rules address the design, construction standards, and
periodic in-service inspection requirements after the rig is delivered by the shipyard.

DESIGN REVIEW
Prior to construction, Classification Society personnel review drawings and calculations
provided by the owner to confirm that the design is in accordance with the "Rules." Design
approval includes a review of stress analyses, fatigue analyses, and may include an
evaluation of member redundancy. In some instances, the Classification Society may
conduct independent analyses to evaluate new designs.
Stress Analysis: The stress analysis includes an evaluation of the stresses in individual
members and the stress levels at connections.
Fatigue Analysis: Offshore drilling rigs are generally designed for a minimum 20-year
fatigue life under an assumed set of environmental conditions. Since most drilling rigs
operate worldwide in a variety of environments, these fatigue analyses are useful in
identifying highly stressed areas ("hot spots"), but they are not very good at reliably
predicting actual rig service life.
Member Redundancy: Some of the newer rigs were designed with member
redundancy, which means that one of the lower structural members (horizontal or
diagonal) could fail and the remaining members would not be over stressed. This design
feature provides additional confidence that the rig should not experience a structural
problem that would lead to rig collapse and possibly high loss of life.

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Computer analysis techniques used by both rig designers and Classification Society
personnel in their design reviews have improved significantly since the 1970s when the
first semisubmersibles entered the offshore fleet. As a result, the newer fourth and fifth
generation rigs should be better designed and should have fewer structural problems.
On the other hand, these same tools allow designers to design closer to the allowable
stress limits, thus perhaps removing conservatism that used to exist.
After a rig has been placed in service, an in-service inspection of critical joints
provides the best information about the condition of the rig itself and whether the
rig is fit for continued service. These inspections are particularly significant for
older rigs where cracking due to fatigue has occurred.

IN-SERVICE INSPECTION
Classification Societies require an inspection of selected critical connections every five
years. These particular inspections are called "Special Periodical Surveys (SPS). The
inspection program typically includes non-destructive testing of approximately 20-25% of
the major structural connections such as the column to pontoon, horizontal brace to
column, diagonal brace to column, K-joint, column to upper deck, diagonal to upper deck,
transverse girder and longitudinal girders. Loss of integrity in any of these joints could
cause adjacent members to be overstressed, which would ultimately lead to loss of the rig.
The inspection techniques vary from Society to Society and surveyor to surveyor. DnV
Rules specify magnetic particle inspection (MPI) or eddy current (EC) with limited use of
ultrasonics to inspect critical areas while ABS will accept visual inspection for most
connections.
These inspections also include a random sample of external attachments such as
hydrophone brackets, lifting padeyes and walkways. The remaining areas are inspected
visually. If significant defects are found, the Classification Society Surveyor will expand the
scope of the inspection.
DnVs program is much more structured and formalized than the ABS approach. Following
shipyard delivery, DnV issues an inspection plan which includes rig drawings showing
areas that are to be inspected, the inspection frequency, and the type of inspection
technique (visual, magnetic particle, x-ray, ultrasonic). ABSs approach is slightly different -
they ask the rig owner to submit a plan and then ABS will either approve or disapprove it.
Access to the lower structural members for inspection generally requires the rig be at
shallow draft in a protected area. Normally scaffolding must be erected on the pontoons to
permit access to the lower horizontal and diagonal connections to the columns. Access to
some of the upper connections also requires scaffolding. If MPI is used, the surface must
be repainted/recoated.
A typical structural inspection requires five to seven days, depending on weather and the
number of inspection crews.
The Classification Society surveyor is usually not present during the entire
inspection; instead he uses reports of third party inspectors hired by the rig owner to
determine suitability of the rig for continued operations.

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When the inspection is completed and all repairs, if any, have been made, the
Classification Society surveyor will provide a temporary permit until a formal certificate is
issued approximately six months later by the Classification Society home office. A typical
example of the wording used in the formal certificate "...all areas were found or placed
in satisfactory condition" is shown in Appendix II. This certificate is intended to serve as
proof that the Classification Society surveyor witnessed the inspection, and he has
concluded that the rig is fit-for-purpose. This certificate is also needed by the rig owner
to maintain insurance. The Surveyor also issues a Special Periodic Survey report,
which contains the inspection program and results of the inspection. A copy of the
SPS report is required to be on the rig and another copy is provided to the
contractor for his office files.

REPORTING DAMAGE
If a collision occurs while the rig is in service, the Classification Society is to be informed
immediately. A surveyor will be sent to the rig to review the damage and make a
determination on whether temporary repairs will be adequate until the rig comes in for its
next SPS or whether the rig must come into the shipyard for immediate repairs.

REPAIRS
Any welding of structural members or any structural modifications to the rig must have
Classification Society approval. The repair and the welding procedures to be followed
should be approved by the Classification Society.

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4.7.3 LEAK DETECTION SYSTEM

Leak detection is a means used to monitor the integrity of underwater structural members
on semisubmersibles. Laboratory tests have shown that an underwater tubular member
w ill le a k b e fo re it b re a ks. B a se d o n th is co n ce p t, se n so rs a re p la ce d in a ll u n d e rw a te r
tubular members that are designed to be void (dry). If the sensor detects water, a through
member crack exists that can eventually result in failure of the member.
In order for a through member crack to occur, some defect (crack initiator) must have
existed initially. All rigs have construction defects that can lead to through penetration
cracks under the right conditions. The rate of penetration of a surface defect through the
wall of a structural member depends on the stress level in the member as shown in Figure
4.8. This particular curve illustrates the length of time required for a 1-mm surface crack to
propagate through a 25-mm wall tubular member.

Figure 4.8 - Time required for a 1-mm surface crack to penetrate through a 25-mm
tubular member

Note: The curve in Figure 4.8 was based on DNV test results on a horizontal member to
column connection on a specific rig.

As an example, 5-6 M waves would produce a stress level of 5.6 ksi in the member. At this
stress level a 1-mm crack would work its way completely through the wall thickness in a
little more than 300 days. If the wave height was higher, the stress level would be greater
and the length of time to propagate through the member would be shorter. In the Northern
North Sea, waves exceeding 5-6 M occur between 5 - 40 days/year. Therefore, it is
possible to have a minor surface defect work its way completely through the member in
about 8 yrs if the defect was not detected and repaired.

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The curve in Figure. 4.9 illustrates how rapidly the crack length increases after a
penetration occurs. As shown, the rate of propagation speeds up as the length of the crack
increases. Under the same 5-6-M waves, the crack length doubles every 20 days.

Figure 4.9 - Crack Propagation Rate Around a Bracing After Leakage

Note: The crack does not have to propagate all the way around the member before
failure occurs. As the crack propagates, the intact part of the member must carry
all of the load. Eventually, the load will exceed the strength of the remaining tubular
surface and the member will fail in tension.

The SPS surveys are intended to locate and repair such defects before they cause
structural failure.

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4.7.4 MOST COMMON PROBLEMS ON RIGS TODAY

The most common problems on rigs today are:

Rig personnel are not aware of previous inspection results.

Contractor on-shore personnel do not believe that operator personnel need to be

aware of previous inspection report results.

Inspections rely too much on visual methods which miss significant defects.

Poor inspection documentation.

ExxonMobil performs a structural assessment before mobilizing a rig. This assesses if the
S P S in sp e ctio n s m e e t E xxo n M o b ils e xp e cta tions. If not clear, a risk decision is made on
whether to perform an independent ExxonMobil inspection.

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4.7.5 APPENDIX II
American Bureau of Shipping
65 Broadway, New York, N.Y. 10006
Report No. AD2070 Aberdeen, U.K., 24th September 1985
Best Driller
THIS IS TO CERTIFY that the undersigned Surveyor to this Bureau, did, at the request of
the Owner's Representative attend the Column Stabilized Drilling Unit "Best Driller" of
London, U.K., on the 4th day of September, 1985 and subsequent dates as she lay afloat
on drilling location in the North Sea and at Invergordon, Scotland, in order to examine and
report upon Underwater Inspection in Lieu of Drydocking, Continuous Hull Survey and
Continuous Machinery Survey. For particulars see report as follows:
UNDERWATER INSPECTION IN LIEU OF DRYDOCKING
1. Selected areas of the Unit's underwater parts of the lower hulls were cleaned by
divers and the sea was sufficiently clear.
2. Exposed areas of the shell plating of the lower hulls and columns, above the
waterline, were examined and found or placed in satisfactory condition as noted
below:
(a) Shell plating and internals in way of column SC-2 were cropped and partly
renewed at this time. For details, refer to Report No. AD2076 dated 24th
September 1985.
(b) Shell plating and internals in way of columns CSC-1 and SC-1 were cropped
and partly renewed at this time. For details refer to Report No. AD2074 dated
24th September 1985.
3. The center hulls, below the waterline, including the welded butts, sea chest
strainers, external piping, kort nozzles and propellers were examined, as
recommended, by qualified divers using closed T.V. circuit with two-way
communication system and video-tape documentation supplemented by the diver's
report describing and attesting to the conditions found and considered in
satisfactory condition. The condition of the port kort nozzle, as reported in Report
No. AD1711 dated 17th May 1984, found not to have been aggravated and
it is recommended that the pittings in way of the port kort-nozzle be re-examined
at next drydocking survey.
4. The stern tube bearings were examined externally by the divers and no leakages
were noted. Due to configuration of the kort-nozzles, it was not possible for
clearances to be taken.

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5. A magnetic particle examination was carried out in way of the following

locations:
(a) End connections of 5'-0" diameter bracings.
(b) End connections of 12'-0" diameter bracings.
(c) End connections of main bracings.
(d) Column's connections to pontoons.
(e) Lower conical transition connections to columns CPC-2, CPC-3, CSC-2
and CSC-3.
and found or placed in satisfactory condition as noted below:
fractured welding at the connections of the main bracings to columns CS-1,
CP-1 both at 6 o'clock were ground clear, prepared, welded and re-examined
by MPI and UT.
6. A complete set of the divers' reports will be forwarded to the American Bureau of
Shipping, New York Office upon receipt and verification of same.
7. Various tanks below the waterline were examined internally at this time, and no
significant defects were noted.
CONTINUOUS HULL SURVEY
8. The following tanks and spaces were examined
CONTINUOUS MACHINERY SURVEY
9. The following items were opened up, as recommended, examined, maintenance
records sighted, operationally tested as necessary and considered in satisfactory
co n d itio n
For outstanding recommendation, see Item No. 3 of this report.
The undersigned recommends that this Unit be retained as classed with this Bureau.
________________________
A. M. Best
Senior Surveyor

SEMINAR NOTE:
The bold emphasis in the text was added to illustrate the non-descriptive method
used by surveyors to state that the rig is in good condition.
This rig was 10 years old at the time of the inspection. The weld repairs indicated
above were due to either overstressing, poor weld repairs to correct earlier problems,
or poor welds at the time of shipyard delivery that had not been detected until this
inspection. In any case, these areas should be monitored.

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4.8 PERSONNEL
Personnel training and experience levels vary from contractor to contractor and from rig to
rig. At the present time, industry has not adopted any minimum marine requirements
fo r p e rso n n e l in ke y p o sitio n s su ch a s O ffsh o re In sta lla tio n M a nager (OIM), Barge
Engineer, Assistant Barge Engineer, and Ballast Control Operator. Some countries
(Norway, United States) have instituted formal requirements and now require licensing in
these key positions, however, there are still many areas of the world where personnel
performing these jobs have only received "on-the-job" training and little, if any, formal
training. Industry experience has shown that all personnel on board are "at risk" if
personnel assigned to these key positions are not adequately trained.

4.8.1 KEY REQUIREMENTS

T h e ke y re q u ire m e n ts fo r m a rin e p e rso n n e l a re :
Experience.
Training.

4.8.2 PERSONNEL QUALIFICATIONS

The OIM, barge engineer, assistant barge engineer and ballast control operators should
have the qualifications (training and experience) to handle the marine side of the business
properly and safely. The following minimum qualifications are provided as guidelines for
e va lu a tin g p e rso n n e l in ke y m a rin e p o sitio n s.

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4.8.2.1 Offshore Installation Manager/Person in Charge

RESPONSIBILITIES
The Offshore Installation Manager (OIM) or Person in Charge is the senior person on
board and is responsible for:
The overall safety of the drilling rig.
The stability of the drilling rig.
The structural integrity of the drilling rig .
Training emergency crews (fire fighting, lifeboat crews, etc.).
EXPERIENCE
The Offshore Installation Manager (OIM) should have at least four years of employment
assigned to a MODU in a supervisory position (OIM, rig superintendent, toolpusher, driller,
barge engineer, or maintenance supervisor) and six months on board the specific MODU.
TRAINING
In order to properly carry out this responsibility, the OIM should have completed the
following training programs:
Advanced fire fighting.
Basic and advanced stability.
Ballast control (semisubmersibles only).
Survival at sea.
Basic first aid.
LICENSING
In order to be licensed, the rig OIM must successfully complete courses in the above
subjects, meet experience guidelines, and successfully pass an examination which
includes relevant questions on the following topics:
Watchkeeping.
Meteorology and Oceanography.
Stability.
Ballasting.
Damage Control.
Maneuvering and Handling.
Fire Prevention and Fire Fighting Appliances.
Lifesaving and Survival.

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4.8.2.2 Barge Engineer/Assistant Barge Engineer

RESPONSIBILITIES
The Barge Engineer and Assistant Barge Engineer are typically responsible for:
The stability of the rig.
Ballasting operations.
Daily stability calculations.
Watertight integrity.
Inspection and maintenance of mooring and towing equipment.
Loading and placement of consumables such as casing, barite, cement, bentonite,
fuel and water.
Maintenance of emergency and other marine related equipment.
EXPERIENCE
T h e B a rg e E n g in e e r a n d th e A ssista n t B a rg e E n g in e e r sh o u ld h a ve a t le a st o n e ye a rs
experience on the specific semisubmersible as a barge engineer or ballast control
operator.
TRAINING
The Barge Engineer and Assistant. Barge Engineer should have completed the following
training programs:
Basic fire fighting.
Basic and advanced stability.
Ballast control (semisubmersibles only).
Survival at sea.
Marine Operations.
Basic First Aid.

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LICENSING
In countries that license the barge engineer position, personnel must successfully
complete courses in the above subjects, meet experience guidelines, and successfully
pass an examination which includes relevant questions on the following topics:
Watchkeeping.
Meteorology and Oceanography.
Stability.
Ballasting.
Damage Control.
Maneuvering and Handling.
Fire Prevention and Fire Fighting Appliances.
Lifesaving and Survival.

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4.8.2.3 Ballast Control Operator

RESPONSIBILITIES
The Ballast Control Room Operator (BCO) or watchstander is typically responsible for:
The stability of the rig.
The rig draft.
Maintaining the rig on an even keel.
The stability calculations (or assisting the Barge Engineer)..
The daily maintenance and operation of the control room and pump room.
EXPERIENCE
Semisubmersible ballast control operators should have at least six months experience in a
"trainee" position on a similar design semisubmersible constantly supervised by a qualified
BCO.

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MARINE SAFETY

TRAINING
All BCOs should have completed the following training schools or programs:
Basic fire fighting.
Basic stability.
Ballast control.
Survival at sea.
Basic first aid.
LICENSING
Personnel licensed as a Ballast Control Operator must have successfully completed
courses in the above subjects, meet experience guidelines, and successfully pass an
examination that includes relevant questions on the following topics:
Meteorology and Oceanography.
Stability.
Ballasting.
Damage Control.
Fire Prevention and Fire Fighting Appliances.
Lifesaving and Survival..

4.8.2.4 Manning Level

Contractually, the contractor is obligated to provide sufficient competent personnel on
board the drilling unit to perform the contract services in a safe and efficient manner. The
manning list would typically include the following minimum number of marine personnel on
board at all times:
OIM 1
Barge Engineer 1
Assistant Barge Engineer 1
Ballast Control Operator 2
ASK:
Who relieves the BCO at night? Is he qualified?
The Ballast Control Operator (BCO) is responsible for sounding all tanks at least once a
week, checking all sensor inputs required for stability calculations, and verifying all weights
on board. During the time that the BCO is performing these tasks or is out of the control
room for meals, a fully qualified replacement should be at the Ballast Control Console. On
many rigs today, the BCO on the day tour is relieved by the Barge Engineer, but the BCO
on the night tour is relieved by either the crane operator or a roustabout who have no
formal stability training.

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4.8.2.5 Resumes
The resumes of the OIM, Barge Engineer/Assistant Barge Engineer, and the BCOs should
be reviewed prior to awarding the contract, prior to initiation of operations if personnel
have changed, and during operations when new personnel are assigned to the rig. Most
resumes submitted to Operator personnel show the individual's name, current position,
date hired by the contractor and an abbreviated summary of the individual's oilfield
experience and training. Educational background is often not provided.
In order to obtain all of the data required to evaluate personnel in a timely manner, the
request for resumes should include a request for the following information:
Name.
Age.
Position.
Experience summary including dates, positions held, and employers.
Training summary including course name, school name, location, and dates
attended (self study courses should be indicated).
Education summary including college/university, location, dates attended,
degree awarded.
Many resumes do not include the location of the school or the duration of the
school, so it is difficult to assess whether the training was a one-day overview or a
more comprehensive five-day course.

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Several typical examples for personnel in the key marine positions are described below:
Offshore Installation Manager. The resume shown in Table 4.2 describes an OIM on a
semisubmersible operating in the UK sector of the North Sea.

Name:
Position: OIM
Hired: 05/89
Experience School Dates of Training
OIM Survival Combined 04/20/90
Rig Alpha
03/90 - Present

OIM
Rig Beta
05/89 - 03/90

Harbor Pilot
Virgin Island Port
Authority
10/83-01/89

Chief Mate
Point Shipping Inc.
01/80 - 09/83
Table 4.2 - Example Resume - Offshore Installation Manager

As shown, the OIM did not have any prior experience on a semisubmersible or any other
drilling rig before being hired as OIM. Although this individual had been a Chief Mate and
Harbor Pilot, he had not received any formal training on semisubmersible operations
(ballast control and stability). The resume shows that he received survival and fire fighting
training but it does not indicate where the training was received or the duration of the
program. The resume does not provide any information on college/university education.

This individual would not meet the minimum requirements discussed earlier.

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Barge Engineer. The resume shown in Table 4.3 is for a Barge Engineer on a
semisubmersible operating in the UK sector of the North Sea.

Name:
Position: Barge
Engineer
Hired: 12/79

Experience School Dates of Training

Barge Engineer Module VIII (Barge 06/01/81

Rig Delta Engr/BCO)
12/88 - Present RGIT Basic 09/24/82
Offshore Survival 12/02/83
Ballast Control Operator and Fire Fighting 10/03/84
Rig Delta DOT Coxswain 10/29/85
12/86 - 12/88 SCOTA Helicopter
Landing Officer 03/28/86
Ballast Control Operator RGIT First Aid 04/17/86
Rig Echo Stability and
08/82 - 12/86 Damage Control II 10/20/88
PITB Basic fire 05/26/89
Ballast Control Operator RGIT First Aid 10/27/89
Rig Foxtrot RGIT Survival 09/14/90
07/80 - 08/82 Refresher
PITB Helicopter 02/11/92
Roustabout Fire
Rig Foxtrot Coxswain
12/79 - 7/80 Refresher
First Aid Refresher
Table 4.3 - Example Resume - Barge Engineer

This gentleman was hired in December 1979 as a Roustabout. Eight months later, he was
promoted to Ballast Control Operator. He completed a "self study" course for Barge
Engineers/Ballast Control Operators in June 1981, approximately one year after he
became a BCO. Five years later, he received formal training in stability. Although the
training shows a course in stability and damage control, it does not indicate where the
training was given or the duration of the course. The resume does not provide any
information on educational background.
Although this individual meets the experience and training requirements now, he
would not have been acceptable in the 1980-85 period.

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The Barge Engineer described in Table 4.4 was working on a semisubmersible in the Gulf
of Mexico.

Name:
Position: Barge Engineer
Nationality: U.S.
Date of Birth: 12/28/35
Hired: 5/88
Experience Schools Dates of Training
Barge Engineer Master MODU,
Rig Kilo USCG License 1988
06/91 Present Master MODU 1988
Basic Buoyancy 1988
Barge Engineer and Stability
Rig Lima Ballast Control 1990
05/89 06/91 Simulator
Engineering 1989
Ballast Control Technology
Operator Certificate 1990
Rig Oscar OIM MODU, 1990
10/88 05/89 unrestricted, USCG
Marine Fire Fighting
Barge Engineer and Emer.
Rig Oscar Training
05/88 10/88 Combined Offshore
Survival, Fire
Barge Engineer Fighting and First
Rig Tango Aid
1986 1988 Offshore Survival

General Manager
Astilleros Corrientes
1981 1985

Sr. Project Manager

Vemar, Inc.
1980 1981

Manager Hydraulics
Houston Corp.
03/77 - 11/80
Table 4.4 - Example Resume - Barge Engineer

The resume only describes the schools attended since he went to work for the present
Contractor. The resume also indicates that this individual has an Engineering Technology
Certificate, but it does not state the college/university or the dates. This individual
satisfies the minimum requirements for his position.

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Ballast Control Operator. The Ballast Control Operator described in Table 4.5 was also
working on a semisubmersible operating in the UK sector of the North Sea.

Name:
Position: Ballast Control
Oper.
Hired: 12/85
Experience School Dates of Training
Ballast Control RGIT Combined 02/21/86
Operator Survival 05/10/90
Rig Delta RGIT Combined
11/90 - Present survival Refresher 06/11/90
Module VIII (Barge
Roustabout Engr./BCO) 01/17/91
Rig Delta Basic Fire Course 06/03/91
09/89 - 11/90 Helicopter Landing 02/07/92
Officer
Floorman Stability Theory
Rig Zebra
09-88 - 11/88 (Quit)

Roustabout
Rig Zebra
02/86 - 09/88

Table 4.5 - Example Resume - Ballast Control Operator

This gentleman was hired in December 1985 as a roustabout. After holding various
assignments as a roustabout and floorman, he was promoted to Ballast Control Operator
in 1990; however, he did not receive any formal stability training until February 1992. He
did complete a "self study" course for Barge Engineer/Ballast Control Operator in June
1990 before assuming his first job as BCO. His resume indicates that he successfully
completed the Robert Gordon Institute of Technology (RGIT) survival and fire fighting
courses in 1986 and a refresher in 1990. The resume does not indicate if the stability
course was an in-house course or provided by outside sources. The resume does not list
any educational background. This individual would not have met our requirements at the
time he was promoted to the position of Ballast Control Operator.

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The resume for the Ballast Control Operator described in Table 4.6 indicates that he
completed mandatory Survival at Sea training but there is no mention of any stability or
ballast control training. He does not meet the minimum requirements for this position.

Name:
Position: Ballast
Control Oper.
Hired: 10/88
Experience Schools Dates of Training
Ballast Control Survival Combined 03/30/90
Operator
Rig Alpha
05/89 - Present

Ballast Control
Operator
Rig Alpha Beta
10/88 - 04/89
Table 4.6 - Example Resume - Ballast Control Operator

Note: A review of BCO resumes indicates that many men are given a trial period of six to
nine months as a BCO before they receive any formal training in order to ensure that the
man will stay with the job. During this time, they usually receive "on-the-job" training by the
Barge Engineer while they are manning the control console on a full time basis. Very few
contractors have Ballast Control Operator trainee positions.

These resumes indicate that most of the men holding those positions were not
qualified at the time they assumed their jobs, and one is still not qualified. Although
there are many well qualified men holding OIM, Barge Engineer, and Ballast Control
Operator positions, there are also many unqualified men within industry. Personnel
working on rigs where unqualified men are employed are "at risk" every day.

4.8.3 MOST COMMON PROBLEMS ON RIGS TODAY

The most common problems on rigs today are:
BCOs lack formal ballast control training
No qualified BCO relief at night
OIMs lack formal training in stability and ballast control
OIMs lack experience on semisubmersibles

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4.9 EMERGENCY RESPONSE

Assessments of rig mishaps reveal that most marine tragedies can be attributed to three
main factors:
The failure of installed safety equipment to function properly.
The absence of certain emergency equipment or features.
The inability of the crew to properly use safety equipment or otherwise respond to
the emergency.
The rig's emergency equipment and emergency response organization (ERO) are the
first line of defense in dealing with an emergency. However, even if the emergency
equipment meets current day standards, it will not be effective unless it works as designed
and the rig's response organization responds properly and in a timely manner.
Consequently, every rig needs an effective emergency response program to continually
train the crew, test equipment, test the emergency response organization and exercise rig
communications. Otherwise, all personnel on board are " at risk."

4.9.1 KEY REQUIREMENTS

T h e ke y re q u ire m e n ts o f a n e ffe ctive e m e rg e n cy re sp o n se program are:
Station Bill
Chain of Command
Emergency Command Center
Effective Drills Program

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4.9.2 EMERGENCY RESPONSE ORGANIZATION

The rig crew responds to an emergency through the emergency response organization.
Individual responsibilities are shown on the Station Bill (Table 4.7).

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Example Station Bill

"BEST DRILLER"
STATION BILL

SIGNALS
Fire and Emergency: Intermittent ringing of general alarm bells; sounding of whistle
for period of at least ten seconds
Abandon ship: Continuous ringing of general alarm bells
Man Overboard: Hail and pass the word "man overboard" to the bridge
All Clear: Ringing of general alarm bells three times

INSTRUCTIONS
1. All personnel reporting on board will immediately determine the location and duties of
their emergency station.
2. All personnel will be instructed in the performance of their special duties by their
immediate supervisor.
3. Each person participating in an abandon ship drill will be required to wear a properly
donned life preserver.
4. At the sounding of an emergency signal, emergency squads will assemble with
equipment at their designated station to await squad leader's instructions.
5. Any person discovering a fire will immediately notify the bridge and, if safe to do so,
extinguish the fire with available equipment.
6. At the sounding of the fire and emergency signal:
Start fire pumps.
Close all weathertight doors, hatches, and air shafts.
Stop all ventilator fans and blowers.
Lead out fire hose to affected area as directed by fire squad leader.
7. At the sounding of the man overboard signal, toss life ring buoy with smoke signal
overboard, keep man overboard in sight. Rescue boat crew will immediately clear
rescue boat for launching. Crane operator will stand by to launch rescue boat or lower
personnel basket as directed.
8. Helicopter emergencies:
motorman will immediately start foam pump
all personnel stay clear of the helicopter deck and await instructions

Table 4.7.1 Station Bill

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FIRE AND EMERGENCY STATIONS

POSITION ON DUTY CREW OFF DUTY CREW ASSIGN

TOOLPUSHER - OIM COMMANDS ALL COMMANDS ALL ED
NO. 3
OPERATIONS OPERATIONS LIFEBO
TOURPUSHER DRILL FLOOR DRILL FLOOR AT
NO. 2
BARGE SUPERVISOR FIRE SQUAD LEADER BACK-UP FIRE SQUAD NO. 3
LEADER
ASST. BARGE SUPER. FIRE SQUAD LEADER BACK-UP FIRE SQUAD NO. 2
LEADER
DRILLER - ABLE DRILL FLOOR MUSTER LIFEBOATS NO. 2 NO. 2
SEAMAN &3
ASST. DRILLER - FIRE SQUAD BACK-UP FIRE SQUAD NO. 3
SEAMAN
DERRICKMEN DRILL FLOOR/PUMP ROOM REPORT TO LIFEBOAT NO. 2
FLOORMEN DRILL FLOOR REPORT TO LIFEBOAT NO. 2
CRANE OPERATOR FIRE SQUAD BACK-UP FIRE SQUAD NO. 3
ROUSTABOUTS FIRE SQUAD BACK-UP FIRE SQUAD NO. 2
ROUSTABOUTS REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 2
WELDER REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 2
ELECTRICIAN SCR/MOTOR ROOM SCR/MOTOR ROOM NO. 3
MECHANIC GENERATOR ROOM GENERATOR ROOM NO. 2
MOTORMAN GENERATOR ROOM REPORT TO LIFEBOAT NO. 2
OILER GENERATOR ROOM REPORT TO LIFEBOAT NO. 2
BALLAST CONTROL OP. CONTROL ROOM A.B. COXSWAIN LB NO. 1 NO. 3
MATERIALSMAN MUSTER LIFEBOAT NO. 1 MUSTER LIFEBOAT NO. 1 NO. 1
SUBSEA RIG FLOOR/SUBSEA RIG FLOOR/SUBSEA NO. 2
RADIO OPERATOR BRIDGE COMMUNICATIONS LIFEBOAT NO. 1
COMMUNICATIONS
MEDIC BRIDGE EMERGENCY BRIDGE EMERGENCY NO. 3
SQUAD SQUAD
CLIENT SUPERVISOR DRILL FLOOR BRIDGE CONTROL ROOM NO. 3
CLIENT ENGINEER REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 2
CLIENT GEOLOGIST REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 1
CAMP BOSS CHECK ALL CABINS CHECK ALL CABINS NO. 1
COOK CLOSE GALLEY VENTS CLOSE GALLEY VENTS NO. 1
GENERAL SERVICES REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 1
SERVICE REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 1
VISITORS REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 1
Table 4.7.2 (Cont'd)

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ABANDON SHIP STATIONS

POSITION ON DUTY CREW OFF DUTY CREW ASSIG

TOOLPUSHER - OIM COMMANDS ALL COMMANDS ALL NED
NO. 3
OPERATIONS OPERATIONS LIFEBO
AT
TOURPUSHER DRILL FLOOR SECURE DRILL FLOOR - SECURE WELL NO. 2
WELL
BARGE SUPERVISOR B/U COMMANDS ALL B/U COMMANDS ALL NO. 3
OPERAT. Operations.
ASST. BARGE SUPR. B/U COXSWAIN LB # 2 BACK-UP COXSWAIN LB NO. 2 NO. 2
DRILLER - ABLE DRILL FLOOR SECURE A.B. COXSWAIN LIFEBOAT NO. NO. 2
SEAMAN WELL 2
ASST. DRILLER - DRILL FLOOR SECURE ASSIST LOADING LIFEBOAT NO. 3
SEAMAN WELL
DERRICKMEN DRILL FLOOR SECURE REPORT TO LIFEBOAT NO. 2
WELL
FLOORMEN DRILL FLOOR SECURE REPORT TO LIFEBOAT NO. 2
WELL
CRANE OPERATOR ASSIST LOADING LIFEBOAT ASSIST LOADING LIFEBOAT NO. 3
ROUSTABOUTS ASSIST CRANE OPERATOR REPORT TO LIFEBOAT NO. 2
ROUSTABOUTS REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 2
WELDER ASSIST MECHANIC ASSIST MECHANIC NO. 2
ELECTRICIAN SHUT VENTS, ETC. SHUT VENTS, ETC. NO. 3
MECHANIC SHUT DOWN ENGINES SHUT DOWN ENGINES NO. 2
MOTORMAN ASSIST MECHANIC ASSIST MECHANIC NO. 2
OILER ASSIST MECHANIC ASSIST MECHANIC NO. 2
BALLAST CONTROL A.B. COXSWAIN LB # 3 A.B. COXSWAIN LIFEBOAT NO. NO. 3
OPER. 1
MATERIALSMAN B/U COXSWAIN LB # 1 BACK UP COXSWAIN LB NO. 1 NO. 1
SUBSEA DRILL FLOOR SECURE DRILL FLOOR SECURE NO. 2
WELL WELL
RADIO OPERATOR LB # 1 WITH EMER. RADIO NOTIFY STAND-BY VESSEL NO. 1
MEDIC ASSIST INJURED CREW ASSIST INJURED PERSONNEL NO. 3
CLIENT SUPERVISOR RIG FLOOR SECURE WELL BRIDGE CONTROL ROOM NO. 3
CLIENT ENGINEER REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 2
CLIENT GEOLOGIST REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 1
CAMP BOSS CHECK ALL CABINS CHECK ALL CABINS NO. 1
COOK CLOSE GALLEY VENTS CLOSE GALLEY VENTS NO. 1
GENERAL SERVICES REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 1
SERVICE REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 1
VISITORS REPORT TO LIFEBOAT REPORT TO LIFEBOAT NO. 1
Table 4.7.3 (Cont'd)

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STATION BILL
Key requirements of a station bill:
It should be:
Clear and easy to understand
Written in languages understood by all of the crew
It should include:
The Chain of Command - alternatively, the Chain of Command should be
posted nearby (Table 4.8).
Emergency station assignments for everyone on the rig including visitors.
Chain of Command
Offshore Installation Manager
Sr. Tool Pusher
Night Tool Pusher
Barge Engineer
Table 4.8 - Chain of Command

The leader, backup leader, and the individual responsible for taking muster at
each emergency station
The emergency command center staff
Fire squads (two four-man teams minimum; leader, nozzle man and two hose
men)
Lifeboat crews (one crew for each lifeboat; commander, second-in-command,
radioman, mechanic)
The equipment to be brought to each station and the people who are to bring
the equipment.
Note: Every station should have a hand-held radio to communicate with the
command center.
Emergency signals
All emergency stations should be under the command of the Offshore
Installation Manager (OIM).

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MARINE SAFETY

4.9.3 EMERGENCY COMMAND CENTER

The emergency command center should be a location where the OIM can communicate
with all rig personnel and direct the emergency response(s). The command center should
also contain the emergency alarm panel, which identifies fire and gas zones. Typically, the
emergency command center is the ballast control room.
During emergencies, the emergency command center should be manned by the OIM and
two assistants (minimum).
The following steps should be followed by personnel in the emergency command center
after having been notified of an emergency:
- sound the alarm to inform the crew of the problem, and to activate the emergency
response organization identified on the station bill
- muster all personnel to account for the entire crew
- call for assistance to alert service boats and shore personnel of the possible
need for help as soon as possible
All stations should report to the OIM in the emergency command center. If rig
communication is not effective, messengers should be sent to the emergency command
center to report to the OIM. It is essential that the information flows to the emergency
command center so that the OIM can fully assess the situation and issue the orders.

4.9.4 EMERGENCY DRILLS

Effective drills test the equipment, the emergency response organization, and train the
crew to properly respond to an emergency. There is little to be gained by installing millions
of dollars worth of lifesaving equipment if the crew either cannot effectively deploy it or
panics and cannot use it. Effective drills uncover weaknesses and shortcomings in a
controlled setting, and they are relatively simple and inexpensive to implement. The hour
or so spent every week on emergency drills, if spent effectively, could save your life.

4.9.4.1 Classification Society/Governmental/Industry Standards

Most governmental regulations specify weekly fire and abandonment drills, but these
regulations do not contain any specific guidance on how to conduct effective drills. The
International Association of Drilling Contractors and the UK Offshore Operations
Associations have issued guidelines for effective drills, however, most contractors are
either not aware of the guidelines or have elected not to follow them.
The U. S. Coast Guard requires weekly fire and boat drills, with fire pumps started, all
boats "prepared for use", one boat partially lowered (weather permitting) and its engine
started. There are also drill documentation requirements.

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The 1989 International Maritime Organization (IMO) MODU Code specifies detailed and
comprehensive requirements for drills and training. The same requirements are contained
in the MODU Code Consolidated Edition issued in 2001. While many countries in which
you operate require adherence to the IMO Code, the 1989 Code applies only to rigs
constructed beginning in May 1991. The previous 1979 Code hardly addresses drills and
training. This shows, once again, that you cannot necessarily rely on "the regulations" to
ensure an adequate level of marine safety.
E xxo n M o b ils G u id e lin e s o f C re w P ro ficie n cy D rills (w h ich in clu d e fire /a b a n d o n m e n t) a re
included in the Safety Management Program Manual (SMP).

4.9.5 MOST COMMON PROBLEMS ON RIGS TODAY

The most common problems on rigs today are:
Drills are conducted to comply with Governmental Regulations only
Drills do not:
1. Train the crew.
2. Check the operational status of equipment.
3. Test the organization.

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5
Section

1.0 DYNAMIC POSITIONING

OBJECTIVES
On completion of this lesson, you will be able to:

Describe the basic operation of a dynamic positioning system.

List the major components of the dynamic positioning system.

List the advantages and disadvantages of a dynamically positioned rig compared to

a moored rig.

Describe the basic operation of each of the position reference systems used by
deepwater drilling rigs.

List the different types of thrusters used by DP vessels and describe the differences
between each.

Understand the basic layout of a power distribution system onboard a DP vessel and
be familiar with the associated protection systems.

Describe the basic function of the power management system.

Interpret Drive-off/Drift-off results to determine the settings for the red and yellow
watch circles.

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DYNAMIC POSITIONING

CONTENTS PAGE

5.0 DYNAMIC POSITIONING ................................................................................................................ 1

OBJECTIVES ................................................................................................................................... 1
CONTENTS ...................................................................................................................................... 2
5.1 INTRODUCTION .............................................................................................................................. 4
5.1.1 BASIC PRINCIPLE OF OPERATION ................................................................................ 5
5.1.2 ADVANTAGES AND DISADVANTAGES ......................................................................... 6
5.2 DYNAMIC POSITIONING SYSTEM ................................................................................................. 7
5.2.1 PRINCIPLES OF OPERATIONS ....................................................................................... 8
5.2.2 MAJOR ELEMENTS ........................................................................................................ 11
5.2.3 HEADING REFERENCE .................................................................................................. 17
5.2.4 ENVIRONMENTAL REFERENCE ................................................................................... 18
5.2.5 VERTICAL REFERENCE SENSOR ............................................................................... 19
5.2.6 WIND SENSORS ............................................................................................................ 20
5.3 POSITION REFERENCE SYSTEMS ............................................................................................. 22
5.3.1 GLOBAL POSITIONING SYSTEM .................................................................................. 23
5.3.2 DIFFERENTIAL GPS ....................................................................................................... 30
5.3.3 GLONASS SYSTEM ........................................................................................................ 37
5.3.4 HYDROACOUSTIC POSITION REFERENCE SYSTEM ................................................. 37
5.3.5 RISER ANGLE ................................................................................................................. 48
5.3.6 POOLING OF DATA ........................................................................................................ 49
5.4 THRUSTERS .................................................................................................................................. 53
5.4.1 CONSIDERATIONS ......................................................................................................... 64
5.5 POWER SYSTEMS ........................................................................................................................ 64
5.5.1 POWER DISTRIBUTION ................................................................................................. 66
5.5.2 POWER MANAGEMENT SYSTEM ................................................................................. 69
5.5.3 POWER SYSTEM PROTECTION.................................................................................... 73
5.5.4 BLACKOUT ..................................................................................................................... 74
5.6 DP SYSTEM RELIABILITY ............................................................................................................ 75
5.6.1 REDUNDANCY CONCEPTS AND REQUIREMENTS .................................................... 75
5.6.2 FAILURE MODES AND EFFECTS ANALYSIS (FMEA) ................................................. 76
5.6.3 REGULATORY AND CLASS REQUIREMENTS FOR REDUNDANCY LEVELS ........... 76
5.6.4 CONSEQUENCE ANALYSIS .......................................................................................... 77
5.6.5 SPECIFICATION, EVALUATION, AND TESTING OF A DP VESSEL ........................... 78

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5.7 OPERATIONS ................................................................................................................................ 79

5.7.1 GENERAL REQUIREMENTS .......................................................................................... 79
5.7.2 SYSTEM CAPACITY ASSESSMENT.............................................................................. 80
5.7.3 EMERGENCY DISCONNECT ......................................................................................... 81
5.7.4 OPERATOR COMPETENCY AND TRAINING ................................................................ 82
5.7.5 DP OPERATING INCIDENTS .......................................................................................... 83
5.8 DRIVE OFF/DRIFT ANALYSIS ...................................................................................................... 84
5.8.1 OVERVIEW ..................................................................................................................... 84
5.8.2 WATCH CIRCLES .......................................................................................................... 85
5.8.3 ENVIRONMENT ............................................................................................................... 85
5.8.4 CRITERIA ........................................................................................................................ 85
5.8.5 ANALYSIS PROCEDURE ............................................................................................... 86
5.9 REFERENCES ............................................................................................................................... 89

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DYNAMIC POSITIONING

5.1 INTRODUCTION
Dynamic Positioning (DP), like conventional mooring, is a means of maintaining a
floating vessel at a specified location with respect to a reference point and at a specified
heading using propellers and/or thrusters. For drilling, the reference point usually is the
wellhead on the seafloor.
Dynamic Positioning and its associated technology have evolved over the past forty
years. The control of a ve sse ls p o sitio n b y th e u se o f th ru ste rs, ra th e r th a n m o o rin g
lines and anchors, was originally conceived for positioning coring ships in deepwater
where deploying anchors was not possible. The Cuss I was the first ship to maintain its
station by dynamic positioning on 9 March 1961 in 948m water depth offshore La Jolla,
California. The ship was equipped with four 200 HP thrusters. Each individual thruster
was manually controlled to maintain the vessel's position and heading. The system
employed a surface radar receiving echoes from four buoys and a sonar interrogating
subsea beacons to provide a position reference. This arrangement was nowhere near
today's definition of Dynamic Positioning.
As one can imagine, maintaining an acceptable watch circle by simultaneous manual
control of a number of thrusters would be quite tedious. This gave rise to the need for
automatic control. The coring vessel Eureka, working for Shell Oil, also in 1961, was the
first to be fitted with analog controllers of a very basic nature. The system made use of
two steerable thrusters fore and aft along with her main propulsion to automatically
maintain the vessel's position and heading.
F u rth e r ve sse ls fo llo w e d su ch a s th e "C a ld rill", "G lo m a r C h a lle n g e r" a n d "T e re b e l. A ll
pioneers in the development of the dynamic positioning technology. The systems
employed were crude by today's standard, utilizing analog controllers with no
consideration given to system redundancy, but it was a start.
Today's systems are much more sophisticated and complicated but have also become
much more reliable. Modern Dynamic Positioning systems have taken advantage of the
tremendous advances made in computer technology over the past couple of decades.
Redundancy has become integral to the design of modern DP systems. This redundancy
includes every aspect of the DP system; the computers, the position reference inputs,
the vessel's power generation and electrical distribution systems, and the propulsion
systems. A modern DP vessel of the highest classification is capable of maintaining
station following the total loss of a single compartment.

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DYNAMIC POSITIONING

5.1.1 BASIC PRINCIPLE OF OPERATION

A dynamically positioned vessel will have, in addition to a number of thrusters, a power
system to supply power to the thrusters, controllers, one or more systems to track the
vessel position and various external sensors. All of these sub-systems must work
together as one integral system to ensure proper vessel positioning.
The DP operator inputs a desired position for the vessel, e.g. directly over the well
lo ca tio n . T h e p o sitio n re fe re n ce syste m (s) m e a su re th e ve sse ls p o sitio n , a n d if it is
different from the desired position, provide an error signal to the controller. The controller
will use the error signal to command the thrusters in such a fashion as to bring the
vessel back to position. For a moored vessel the mooring system, acting as a large
spring, provides the restoring force to counter the environmental forces that tend to
move the vessel off location. For a DP vessel, the DP system utilizes active control of
the thrusters to provide the restoring force and maintain position.

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5.1.2 ADVANTAGES AND DISADVANTAGES

Conventional mooring is being successfully applied in increasing water depths, with the
present record at 7710 ft (2350m), established by Shell in the GOM in 2000. However,
equipment constraints and economic considerations often limit its use to lesser water
depths. Drilling vessels using dynamic positioning can operate in water depths from
about 500 ft up to the water depth limits of the subsea equipment and the marine riser.
The water depth record for DP exploration drilling is currently at 9687 ft (2952 m) in the
Gulf of Mexico (GOM) in May 2001 by Unocal using the DP drill ship Discovery Spirit.
The corresponding ExxonMobil records are: moored drilling in 4864 ft water depth in
1995 by Ocean America and DP drilling in 6695 ft water depth in 2001 by Glomar Jack
Ryan, both in the Gulf of Mexico.
Table 5.1 lists some of the advantages and disadvantages of DP systems. DP system
applicability and cost are not as water depth dependent as those for a mooring system.
Other DP advantages generally include greater mobility in transiting to new locations,
ability to easily turn the vessel into a more favorable heading relative to the environment,
ability to start operations in sea states or current conditions in which work boats would
not be able to deploy a mooring system, and greatly reduced time required to move off
location in response to rapidly changing situations such as approaching storms or ice
encroachment.

Advantages Disadvantages
Deepwater applications Higher power requirements
Self-propelled, no tugs required to move Higher fuel cost
from one location to another
Higher maintenance cost
No need to hire large expensive anchor
handling boats Need for specially trained personnel to
operate the sophisticated equipment
Rapid setup on location
More vulnerable to failures resulting in
Rapid move-off capability in storm or the need to emergency disconnect
iceberg conditions
Greater risk of riser/wellhead damage in
Ability to head into weather excessive offset/failure to disconnect
scenarios
Ability to start up in higher sea states
Higher day rate compared to moored rigs
Can easily work in areas where damage
to hardware on the seabed, such as
pipelines, is a concern

Table 5.1 - DP System Advantages and Disadvantages

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A significant disadvantage of a DP vessel is that the day rate is normally higher than for
an equivalent moored vessel - due to both greater capital expense and additional
operating cost. Sophisticated DP equipment and higher installed power on board result
in higher capital expenditure. Fuel consumption, equipment maintenance, and the need
for specially trained operating personnel all contribute to the increased operating cost.
Another, somewhat intangible, disadvantage is the higher engineering attention required.
The responsible engineer (i.e. Chief Engineer or Senior Maintenance Supervisor) on the
vessel should have a thorough understanding of the DP system to ensure its efficient
and safe operation. In addition, a fair amount of shakedown time is usually needed if the
DP system is new or has just gone through a major modification.

5.2 DYNAMIC POSITIONING SYSTEM

Dynamic Positioning may be defined as a system that automatically controls a vessel's
position and heading by means of active thrusters.
Individuals concerned with the operation of a DP vessel must be aware of the complete
integration of this system with the rest of the vessel. A DP system is not just a
standalone system installed on the bridge. Dynamically positioned vessels are designed
around this capability. The DP system not only includes the electronics on the bridge but
also includes the power generation plant, the electrical distribution system, and the
thrusters along with their control systems. This is just the tip of the iceberg. If the diesel
generators are to be considered part of the DP system, then the supporting systems
must also be included, such as the cooling system, fuel delivery system and the
lubrication system, etc. A failure in one of these subsystems can cascade into a loss of
DP. Another example is the dependence of the DP computers on the cooling provided
by the air-conditioning system. Therefore the air-conditioning system in this
compartment must also be considered part of the DP system, since the computers would
not be able to operate without it. So as you can see, developing a robust system capable
of withstanding any single-point failure can influence every aspect of the vessel design.
During the design stage and initial sea trials Failure Mode and Effect Criticality Analyses
(FMECA) are conducted on the entire system to identify and correct any potential single-
point failure modes. These are very thorough reviews which assess how a single failure
can potentially cascade into larger system failures. Any single-point failures, which can
prevent the system from maintaining station, are addressed and corrected prior to the rig
being accepted from the shipyard. More often than not these single-point failures are
corrected through redundancy.

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DYNAMIC POSITIONING

5.2.1 PRINCIPLES OF OPERATIONS

All vessels have six degrees of movement (Figure 5.1), three rotational and three
transitional. Each is defined as follows:
ROTATIONAL MOVEMENT
Yaw - This is rotational movement of the bow about a vertical axis. It is this movement
which dictates the vessels heading.
Pitch - This is rotational movement about a transverse axis.
Roll - This is rotational movement about a longitudinal axis or side-to-side.

TRANSLATIONAL MOVEMENT
Surge - This is movement in the horizontal plane in the forward or aft direction.
Sway - This is movement in the horizontal plane in the transverse direction or
side-to-side.
Heave - This is the vertical movement in the up or down direction.

Figures 5.1 Six Degrees of Rotation

The DP system is concerned with controlling only three of these movements, surge,
sway, and yaw. The combination of surge and sway define the vessel's position while

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yaw defines the vessel's heading. Even though the remaining three freedoms of
movement, pitch, roll and heave, are not controlled by the DP system, they are
measured as necessary inputs to correct the vessel position reference signals.
These motions are detected by the Vertical Reference Unit (VRU).
Both vessel position and heading are controlled about desired input values, known as
"se tp o in ts. In e a ch ca se the vessel's actual position and heading must be measured in
order to obtain "feedback" values. The vessel position at a given moment in time is
determined through a range of Position Reference Systems while the vessel heading is
provided by one or more gyro compasses. The difference between the desired
setpoints and the measured feedback is the error. The DP system, in turn, provides
thruster commands in attempt to reduce the error to zero.

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DYNAMIC POSITIONING

WIND

WAVE
FORCES
CURRENT
FORCES

Figure 5.2 Environmental Forces

Once a rig is on location, external forces (Figure 5.2) act on the vessel structure to
move it from its desired position or heading. These forces include wind, wave and
current. To maintain the desired position or heading the DP system must then produce
equal and opposite forces via the thrusters. The difficult part is to be able to measure
these external forces accurately so that the system knows how much thruster force is
needed and which direction to apply it.
Wind can be measured directly using a wind sensor. Wind sensors can provide an
accurate and continuous measurement. This measurement is then fed into the computer
for immediate compensation. Wind compensation is further discussed in section 5.2.6.
An accurate method has not been developed to measure the current and wave forces
using sensors deployed from the vessel. This is because the vessel's structure and/or
thruster wash disturb the waters in the immediate which results in inaccurate
measurements. For this reason, this portion of the external force must be deduced over
a period of time by monitoring the rig's tendency to move off location or change heading.
All forces not attributable to direct measurement (i.e. wind) are combined together and
la b e le d a s "cu rre n t. T h e cu rre n t fo rce is a co m b in a tio n o f cu rre n t, w a ve , a n d sw e lls
along with any errors in the system.

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5.2.2 MAJOR ELEMENTS

The major elements which make up the DP system include: the computer or controller,
the position sensors and associated auxiliary sensors, and the thrusters (as shown in
Figure 5.3). Of course, an indispensable element is a skilled and alert operator.

DGPS
Portable 3-
Computers/ axis Joystick
Display
consoles

Thrusters

Wind Sensors

Operators

Uninterruptible
Power Supply

Tautwire/
Riser Angle
Sensors Motion
Gyrocompass
Reference
Sensors Acoustic Reference
System

Figure 5.3 - DP System Equipment

COMPUTERS
For the most part, modern DP systems utilize off-the-shelf Pentium type computer
processors operating in a Windows environment. The computers may be arranged in a
single, dual or triple configuration, depending on the level of redundancy required. The
system communicates via an Ethernet or Local Area Network (LAN), which incorporates
many other vessel control functions.

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DYNAMIC POSITIONING

DP vessels that meet the highest classification requirements (class 3) are triple
redundant consisting of three operator stations and three independent computers.
Communication between the three systems is via a dual high-speed data network. This
type of arrangement significantly increases the reliability of the system compared to a
single or even a dual system. The system is able to detect an error and isolate the faulty
data or component. The concept of majority voting is used to detect and isolate faults.
If a fault is detected in one of the computers or sensors, that computer or sensor is
isolated. The onus does not befall the DP Operator to determine which data or
component is correct, as is the case with dual redundant systems.
The term MMI or man-machine interface has been adopted for the control consoles.
Basically this is where all the input buttons, indicator lights, display screens and
maneuvering joystick are located. The control consoles are typically installed on the
bridge along with the other essential controls such as position reference control units,
thruster control console (Figure 5.4), communication suite, radar and vessel
management system console. In some semi-submersible vessels the DP consoles may
be located in a space other than the bridge. The location is not all that critical, but there
is definitely an advantage to having the operator located in a space that has a view of
the outside to provide some orientation during heading and position changes.

Figure 5.4 - Simrad ADP 703 System Console

For vessels to satisfy the class 3 requirement, a backup computer and control console
must be provided in a separate location from the main system. This is so DP capability is
not lost in the event of a fire or flooding in the compartment housing the main system.
The DP system is protected against power failure by the inclusion of an Uninterruptible
Power Supply (UPS). This system provides a stabilized power supply not affected by
short-term interruptions or fluctuations of the ship's a.c. power supply. Power is supplied
to the computers, consoles, displays, alarms, position- and environment-reference
systems. In the event of an interruption to the main a.c., a bank of batteries will supply
power to all of these systems for a minimum of 30 minutes. Note: this emergency back
up applies only to the DP system electronics and not to the thrusters.

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DYNAMIC POSITIONING

MATHEMATICAL MODELING
The DP computers carry out their positioning function by using a feedback control loop
as shown in Figure 5.5. The DP operator inputs the desired position for the vessel into
the controller. The actual position of the vessel is determined by the position reference
systems and is input into the computer.
Based on the position error (desired minus actual), the controller calculates the
commands to the thrusters which provide the necessary forces to counter the
environmental forces and maintain the vessel on location.
Critical to the reliability and performance of a DP vessel is the power generation,
distribution and management system as discussed in detail in Section 5.6.

ENVIRONMENTAL
MEASURED WIND FORCES

DESIRED MOTIONS
CONTROLLER THRUSTERS SHIP
POSITION Fc

POSITION
THRUSTER
ERRORS
COMMANDS

APPARENT POSITION
POSITION REFERENCE

Figure 5.5 - Dynamic Positioning Control Loop

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DYNAMIC POSITIONING

There are three independent control loops, one each for the surge, sway and yaw axes
of the vessel. The three control axes are coupled by the thruster allocation logic in the
controller as shown in Figure 5.6.

WIND SPEED, DIRECTION

WIND DRAG
TABLES

Fx T1
SURGE +
+
CONTROLLER
T2
VESSEL INDIVIDUAL
SWAY Fy THRUSTER
POSITION + THRUSTER
CONTROLLER + ALLOCATION
ERRORS T3 COMMANDS
LOGIC

YAW Mz T4
+
CONTROLLER +

Figure 5.6 Three-Axis Controller and Thruster-Allocation Logic

Certain properties of the vessel, such as the displacement, added mass, hydrodynamic
and aerodynamic coefficients must be known in order to design the control system
software.

CONTROLLER
The controller of a DP system must perform the following main functions:
Process all data generated by the dynamic positioning sensors, discarding non-
significant or faulty signals, carry out the necessary filtering and computations, and
optimize stability of the implemented control algorithm.
Determine most probable true position (surge, sway and heading) and command
available thrusters, minimizing power consumption and complying with any other
requirements (e.g. that imposed by power management system).
Present the operator with up-to-date information on vessel location relative to the
reference point, status information about all equipment including alarms,
malfunctioning equipment, and adequate warnings about potential loss of position.

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DYNAMIC POSITIONING

PID CONTROLLER
The earlier generation controllers calculated the thruster commands based on the
position error, the rate of change in position error and time integral of the position error.
This controller is commonly referred to as the PID (proportional-integral-derivative)
controller. The "proportional" control provides the thrust that is analogous to the spring
force generated by a mooring system when the vessel is offset from its equilibrium
position. The "derivative" control provides the controlled damping, and the "integral"
control is required to maintain a zero position error. If the integral term is not included,
a cumulative difference in the measured and reference variables must be tolerated so
that the controller, through the proportional term, can command the necessary steady-
state counterforce.
KALMAN CONTROLLER
Another type of controller, more commonly used now, uses what is known as Kalman
filtering technology. Functionally these Kalman controllers are analogous to the PID
controllers - the manner in which the proportional, integral and derivative terms are
computed is different. Kalman controllers employ mathematical models and the thruster
commands no longer depend on the difference between required and measured values,
but between required values and values derived from models. The measured values
obtained from the position reference systems and other sensors are used to adjust the
models in real time. Use of the modeling method involves calculation of the forces acting
on the vessel and thus requires knowledge of the numerous hydrodynamic parameters
of the vessel. Nevertheless, the Kalman controller can provide a superior performance
relative to the PID controller, as it can include a much better position signal processing
logic, especially in situations where the position signals are constantly contaminated by
ambient noise. Another situation where the Kalman controller is superior is when the DP
system is in a "dead reckoning mode" following complete loss of all online position
sensors. Better dead reckoning performance allows the operating personnel more time
to deal with the situation.
Kalman filtering provides another system improvement. Ocean waves act on a floating
vessel in two ways. First, there is a high frequency component that physically lifts the
ship up and puts it back down in the same place, in an oscillatory and circular motion.
Because the high frequency forces involved are so large, and the thrusters so relatively
small, it would be futile to try and command the thrusters to counter these motions.
Second, there is a low frequency component where the ship drifts slowly off position due
to low frequency forces, called wave drift forces. This effect can be witnessed when
watching a seagull floating in waves; it moves around in a vertical circle in each wave
but only drifts along very slowly.
One of the controller requirements, therefore, is to remove the high frequency
component from the position measurements so as to prevent the control system, and
therefore the thrusters, reacting to it. Applying Kalman filtering and modeling techniques
to the processing of the error signal has achieved improved filtering of the wave
frequency motions without introducing a lag in the system, and thus has improved
controller performance.

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DYNAMIC POSITIONING

SYSTEM RESPONSE AND STABILITY

The basic performance characteristics of a DP closed loop control system are the
system response time, the thruster modulations and the stability of the system. First and
foremost, the control system must be stable, i.e., its time response to a disturbance must
converge with time and not increase without bound. However, stability in itself is not
sufficient, and the gain parameters in the controller are designed to provide acceptable
response time and minimize thruster modulations, in addition to providing a stable
control system. The optimal gain parameters depend on the vessel characteristics,
thruster capacity and response, position sensor noise characteristics and the expected
operating conditions of the vessel. In addition to performing gain margin tests for new or
modified DP vessels to ensure adequate stability and acceptable response, some
"tuning" of the system is required if significantly different operating conditions are
encountered. Usually, the operator can select low, normal or high gain settings for the
system depending on conditions.

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5.2.3 HEADING REFERENCE

Heading reference is provided from the gyrocompass (Figure 5.7), which transmits data
into the DP system in the same way that it transmits data to any other heading-stabilized
equipment (radar, repeater, etc.). The gyrocompass has a proven record in the marine
environment as being reliable and accurate. It basically consists of a two-axis gyro,
which senses the earth's rotation causing the gyro to align its spin axis in a northerly
direction.

Figure 5.7 - Dual Master Gyro Compasses

In vessels where redundancy is necessary, two or three gyros are fitted. If only two
gyros are fitted, the problem still exists with determining which unit has failed. All the DP
system can do is to monitor the difference in heading readout between the two gyros,
and flag up a warning if that difference exceeds a certain value (e.g. 3 degrees, initiating
the warning "Gyro Difference Error"). This puts the ball firmly back into the DPOs court
regarding the selection of the correct gyro; it may be that the backup has failed. This
leaves a less than satisfactory situation for the DPO, as it may be impossible for him to
tell immediately which compass is giving problems. In vessels with two gyros, it is
strongly recommended that the DPO note the magnetic compass heading when the
vessel is set up on DP and settled. Note: it is not normal for the DP system to be
configured to accept input from magnetic compasses.
The gyrocompass is an extremely important input into the DP system. Without the
gyrocompass input, the DP system will not be capable of maintaining heading nor
position. It may be intuitively obvious why the system will not be able to maintain
heading, but perhaps not so much why the positioning capability is lost. This is because
the position setpoint is used to define the position of the moonpool center. The gyro
compass reading is used by the Position Reference Systems (PRS) to account for the
orientation of the sensors (antennas, transducers, & hydrophones) from the moonpool.
Without this orientation the PRS will not know its relation to the setpoint.
If three gyros are fitted, then the DP system may use Voting logic to detect a gyro failure,
and give an appropriate warning to the DPO. Three gyros are typically fitted in vessels
complying with Equipment Class 3, where triple modular redundancy is the norm in the
DP system.

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5.2.4 ENVIRONMENTAL REFERENCE

Three main environmental factors provide forces which will cause the vessel to move
away from her setpoint position and/or heading: wind, waves and current. A description
was given earlier for determining current values. If deemed necessary, a facility exists in
modern DP systems to manually input values for current and wind. This facility must be
treated with care. If manual values for current have been entered, care must be taken to
ensure that they represent the actual current, and it is necessary for the DPO to
regularly update this value as the tide changes. If this is not done, the positionkeeping
quality could degrade as the true current and the manual input value diverge. In general,
it is not recommended that this facility be used unless a significant error is observed in
the current vector displayed by the system compared to observed reality.
If the DPO observes a large discrepancy between the value of current displayed on the
screen, and that obtained for real, then he should realize that the current vector is a total
integration of all factors between the predicted position and the measured position.
These factors will include the real current but will also contain all errors in the system.
The DPO must look carefully at all elements of his system to try to detect the error
causing the current discrepancy. It may be that a wind sensor element has seized,
causing erroneous wind input; the wind error will be put down to current. Once such a
discrepancy has been detected and corrected, the erroneous current vector may persist,
although it should slowly dissipate as the mathematical model updates itself.
There can be no direct active compensation for waves. In practice, the frequency of the
waves is such that it is not feasible to provide compensation for individual waves. A low-
frequency factor exists relating to a continuous wave-induced drift. A vessel drifting in a
steady wave pattern will slowly drift in the direction of the waves; this drift is separate to
any wind-induced drift associated. There can be no direct measurement of this drift
factor, and as such it will be incorporated into the derivation of the current value.

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5.2.5 VERTICAL REFERENCE SENSOR

One result of the environment is the roll, pitch and heave motions of the vessel. These
are three of the six freedoms of movement not controlled by the DP system. For the
purposes of DP we ignore heave
entirely, but it is necessary that the
DP system be provided with accurate
and instantaneous values of Roll and
Pitch. This is to allow compensation
values to be applied to the various
position reference sensor inputs to
the DP relating to angular
measurements. Some Position
Reference Systems rely on angle
measuring sensors, which are
located some distance from the
center of gravity of the vessel. This is
similar to the heading compensation
Figure 5.8 - Vertical Reference Units
described in the previous section.
For example the hydroacoustic PRS make calculation based on sensor inputs assuming
the vessel in vertical. Without this compensation errors would be introduced into this
positioning information. Instrumen-tation to measure these values is provided in the form
of a Vertical Reference Sensor (VRS) or Vertical Reference Unit (VRU). The terms VRS
and VRU are synonymous.
There are many types of vertical reference sensors. The pendulous mass type sensor is
the simplest and least expensive. Its performance, however, is only marginally
acceptable due to the effects of lateral accelerations. The measured angle includes both
the true angle of inclination and the error induced by the lateral acceleration of the
vessel.
Other types of sensors include vertical gyros and the combination of linear and angular
accelerometers which provide significant improvement over the pendulous mass type
sensor.

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5.2.6 WIND SENSORS

All DP systems carry wind sensors (Figure 5.9), providing feedback as to the direction
and strength of the wind. This data is then used to calculate wind-induced forces acting
on the vessels hull and structure, allowing these forces to be included in the positioning
calculation.
Typically, a wind sensor consists of a simple transmitting anemometer, usually of the
rotating-cup type with a separate windhawk indicating direction. Another type consists
of a windvane shaped like a streamlined airplane fuselage, the tail fin containing a
tube aligned longitudinally. Within the tail fin revolves a small impeller, detecting
the wind force.
The wind sensors are coupled into the DP system by
means of a "feed forward" function (also referred to
as active wind compensation), which bypasses the
mathematical model, in addition to being included
into the modeling process. This is vitally important to
the performance of the DP system during conditions
of radical changes in wind direction, strength or both.
This feed forward function is best described as a
"g u st/th ru ste r co m p e n sa tio n .
The mathematical model in general reacts to
changes in the vessel/environment only slowly,
typically a period of twenty minutes being required to
completely update any change. Unfortunately, the
wind can change much faster than this, and large Figure 5.9 - Wind Sensor
changes in wind speed or direction can cause major
disturbances in the quality of position and heading control. Without immediate thruster
compensation, an unexpected and strong gust of wind can cause a significant and
unacceptable excursion. The amount of thruster compensation would be in proportion to
the distance that the vessel is from the setpoint, and the velocity of the vessel. Without a
wind feed-forward function, the compensation thrust would be small until the excursion
was unacceptably large. However, the wind feed-forward allows an immediate
compensation thrust to be applied in direct proportion to the change detected in the
windspeed and/or direction.
The wind force is easily calculated by multiplying the square of the wind velocity by a
drag coefficient. The value of the drag coefficient is based on the above water profile of
the vessel. The vessel's draft and relative aspect to the wind (i.e. relative wind direction)
all factor into determining the drag coefficient to be used. Having the ability to quickly
measure and calculate the wind force allows immediate thruster compensate to be
applied, preventing the vessel from being "blown off" location. Once steady conditions
are obtained, the feed-forward factor decays as the wind values build into the
mathematical model. This function very elegantly solves the problem of gusting wind
conditions.

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The detection of representative wind values is sometimes difficult, and is often a factor of
correct positioning of the wind sensors. In general they must be above and clear of any
structure that would provide windshadow. Windshadow may stem from masts or
structures such as the derrick. It is common to position wind sensors on either end of a
transverse yardarm or on opposite ends of the vessel.
In most DP systems, the DPO selects the in-use wind sensor, and it is up to him to
determine when that wind sensor input is no longer appropriate, and to select an
alternative. If both wind sensors are de-selected, the DP system will use the value of the
wind contained in the model, i.e. a constant value. Under these conditions there will be
no update of wind values, and feed-forward facility, so no direct compensation for
gusting conditions. The DPO must be aware of this. It may be that he has de-selected
both wind sensors for an impending helicopter visit, in order to prevent disruption of the
positioning due to draft from the helicopter's rotors affecting the wind sensors. If this is
the case, the DPO must also be aware of the hazards involved in the re-selection of the
wind sensor. If the value for the wind on re-selection is different to that contained in the
model, then the DP system will treat the apparent change as an instantaneous gust, and
the feed-forward may initiate a drive-off. Unless the change in windspeed during the
period of de-selection has been radical, the drive should not be particularly violent, but
it is something for which the DPO must be prepared.

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5.3 POSITION REFERENCE SYSTEMS

Central to the DP function is the establishment and maintenance of reliable, continuous
and accurate position reference. A seagoing vessel will be outfitted with navigational
positioning equipment such as Deeca Navigator, Loran C and GPS. These systems are
of insufficient accuracy, all ranging from 15 to 100m, while DP operations require better
than 5m and preferably better than 1m accuracy. Therefore Position Reference Systems
(PRS) have been specifically designed for this purpose (Figure 5.10). Five types of PRS
are in common use by DP systems today. These are Artemis, Hydroacoustic Position
Reference (HPR), Taut Wire, Differential GPS, and Fanbeam. For drilling rigs operating
far offshore in deepwater only HPR and DGPS are applicable. These will be discussed
here in detail.

Figure 5.10 Overview of Positioning Systems

Each of these systems operates separately and independently of the DP system, and
feed information to the DP by means of an interface. The DP system can typically handle
multiple PRS input, pooling the information to provide a continuous "best fit" of position
data. This process, which is a function of the mathematical modeling of the system, will
be described.

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5.3.1 GLOBAL POSITIONING SYSTEM

The GPS system (full title: The Navigation Satellite Timing and Ranging Global
Positioning System - NAVSTAR GPS) is a satellite-based passive-ranging navigation
system. It was initially envisioned in the 1960s but not implemented until the 1980s. The
satellites are placed in orbit so that at any given time a minimum of five satellites will be
in view to users anywhere in the world (Figure 5.11). A GPS receiver picks up the
signals from satellites in view of its antennas and uses the coded information to calculate
a range from the satellites and hence a position.

Figure 5.11 GPS Constellation

The Navstar GPS consists of three segments: Space, Control and User.

Figure 5.12 Three Segments of GPS

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SPACE
The space segment consists of 24 satellites in 6 orbital planes, including three in-orbit
spares. These orbit the earth in 12-hour orbits at an altitude of 20,200 kilometers.
CONTROL
The control segment consists of a Master Control station in Colorado Springs, with 5
monitor stations and 3 ground antennas located throughout the world. The monitor
stations track all the GPS satellites in view and collect ranging information from the
satellite broadcasts. These stations in turn relay this information to a Master Control
station where satellite orbital parameters or ephemeris data are computed (Figure 5.13).
This precise orbital data is injected back to the satellites by uplink every six hours via the
three upload stations. This orbital correction information is then incorporated into the
positioning information (L1 & L2 signals) broadcasted by the satellite.

Figure 5.13 GPS Control

Segement
USER
The User segment consists of the shipboard positioning receivers, processor and
antennas that allow land, sea, or airborne operations to receive the GPS satellite and
compute their position, velocity or time. Some basic GPS receivers work with as few as
4 channels, which limits the amount of data available for position computation. At any
given time and location there will be between 5 and 9 satellites in view of the observer,
then for best results an advanced 9-channel receiver is necessary.

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SATELLITE SIGNAL
The GPS system operates at two frequencies; 1575.42 MHz (L1) and 1227.60 MHz (L2).
All satellites transmit both L1 and L2 frequencies. Since the frequency is the same for all
satellites, the modulation must contain characteristics making it possible to separate the
different satellite signals from each other. This is achieved by using codes on the
signals, called pseudo-random noise codes (PRN codes) (Figure5.14). There are two
types of pseudo-random noise codes used; a precise-code (p-code) and a Coarse
Acquisition code (C/A - code). The L1 transmission is modulated by the P-code and the
C/A-code, while the L2 frequency carries the P-code only. The P-code provides the
Precise Positioning Service (PPS) which provides an accuracy of 20 meters. This portion
of the GPS service was originally restricted for military use only. The US DoD injected a
deliberate degradation in the range accuracy of the C/A code known as Selective
Availability (S/A). The degradation is achieved by introducing "jittering" or "dither" to the
transmitted clock data, which gives a rapid rate of change to the pseudoranges. Further,
slow rate-of-change errors are introduced to the ephemeris data (orbital co-ordinates). In
combination these two effects reduce the overall accuracy to around 100 meters. Civilian
users were thus limited to the Standard Positioning Service (SPS) obtained from the
C/A-code signals transmitted on the L1 frequency.
As of May 1, 2000 Selective Availability was removed allowing civilian receivers to yield
the higher accuracy from the C/A code.

Figure 5.14 GPS Positioning Principles

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MEASUREMENT PRINCIPLE
Each satellite continuously broadcasts the time and its orbital position. A GPS receiver
must receive four or more of these signals at once to determine its position. The receiver
makes use of "Pseudo-Ranges" to calculate a position. The measurement is based on
the principle that both the satellite and the receiver are generating the same pseudo-
random codes at the exact time. By comparing how late the satellite's pseudo-random
code appears, compared to the receivers code, the travel time of the signal can be
determined. The travel time is then multiplied by the speed of light to get the distance.
These measurements are referred to as pseudo-ranges as they will be affected by
errors in the receiver clock. Since this error will be the same for all satellites in view,
provided that at least four satellites are in view, the clock offset can be determined by
use of simultaneous equation techniques. To compute the antenna position, the receiver
must resolve four unknowns: Cartesian co-ordinates x, y and z and clock error. The
spatial locations of the satellite are known quantities included in the coded satellite
messages. Three satellites can be used to compute a 2-dimensional fix if the height
above the terrestrial spheroid is known. This technique is known as fixed height and is
also used to enhance position computations with more than three satellites.
This method is known as height aiding.

SOURCES OF ERROR
Even without the deliberate degradation in range accuracy there are other sources of
error that influence the signal accuracy (Figure 5.15).

Figure 5.15 GPS Accuracy Budget Pseudo Range Errors

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Ionosphere
The ionosphere is the layer of the atmosphere ranging in altitude from 50 to 500 km
and consists largely of ionized particles, which causes signal delays and refraction
(Figure 5.16).

Figure 5.16 Sources of GPS Errors

Troposphere
The troposphere is the lower part of the atmosphere. This is where changes in
temperature, pressure and humidity associated with weather changes occur.
These factors cause varying degrees of delay and refraction to the signal.

Multipath Effects
These are caused by reflection signals from the surface near the receiver that can either
interfere with, or be mistaken for, the signal that follows the straight-line path from the
satellite. If the reflected signal is very strong, the GPS receiver might lose lock on the
satellite. Multipath is difficult to detect and sometimes hard to avoid (Figure 5.17).

Figure 5.17 Multipath Effects

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Geometry Effects
Basic geometry can itself magnify other errors with a principle called Geometric Dilution
of Precision - GDOP. When the user is at a position where the lines drawn from the
satellites are nearly perpendicular to each other, the point of intersection is well defined.

Figure 5.18 GPS Good Geometry

Figure 5.18 shows GPS Good Geometry. When the angle either becomes very large or
very small, the point of intersection is blurred and positioning degrades.

Figure 5.19 Poor Geometry

The effects of geometry vary with time of day and number of satellites available. Poor
geometry can magnify small errors (Figure 5.18). The dilution of precision (DOP) is a
dimensionless number indicating how much geometry is magnifying the errors. DOP is
broken into four components (horizontal, vertical, geometric, & time), the most commonly
used value being the horizontal component, HDOP. The lower the HDOP value the
better the accuracy based on satellite geometry. Ideally, HDOP values should remain
below 3, if HDOP creeps above 5, then the position fixing becomes suspect.

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Figure 5.20 HDOP Geometry

GPS RECEIVERS
Dual-frequency receivers are available on the market which have the capability to track
both L1 and L2 signals from a maximum of, typically, nine satellites simultaneously, and
is able to use a cross-correlation tracking mode if the P-code is encrypted. These
receivers are the most sophisticated on the commercial civilian market. Refraction
effects occurring in the ionosphere and the troposphere can be measured and corrected
for if two phase-synchronized radio frequencies are observed. Thus, a dual-frequency
receiver will yield superior results, compared to one working with L1 only, even if the
P-code is encrypted and unavailable.
A standard navigational GPS receiver will typically operate with six channels and track
the L1 signal using the C/A code only. The best type for commercial use is a parallel all-
in-view receiver with eight or more channels. Cheaper receivers are of the sequencing
type, where satellites tracked are observed in a sequence from a lesser number of
channels. Parallel receivers track all channels simultaneously. All GPS receivers utilize
an elevation mask of around 10, blocking out signals liable to suffer distortion due to the
ionosphere and troposphere. The receiver will give an indication of the number of
satellites being tracked together with a Horizontal Dilution of Position (HDOP) value.
Receivers have different methods of implementing the Height Aiding feature. The
operator may elect to switch the height aiding off altogether, in which case the system
will only give fixes if four or more satellites are being tracked. The system may be
selected to auto height aiding, such that height aiding is automatically switched in if the
number of satellites degrades to three. In this case the antenna height used will be the
value determined from the preceding 3D fix.

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5.3.2 DIFFERENTIAL GPS

In order to enhance the accuracy from the GPS and to overcome the effects of SA, a
differential technique is used (Figure 5.21). This is achieved by establishing reference
stations with accurately known positions. The pseudo ranges derived by the receiver are
compared with the computed range between the known satellite positions and the
reference station. This comparison yields a Pseudo-Range Correction (PRC) for each
satellite. These corrections are then included in a telemetry message sent to the ship's
receiver by a data link. The receiver then applies the PRCs to the observed pseudo
ranges at the vessel location to compute a differentially corrected position. The use of
PRCs instead of geographical corrections (latitude/longitude differences) allows the
reference station and ship receivers to observe different satellites, allowing greater
flexibility.

Figure 5.21 Principal of Differential Global Positioning System

The user in the vessel will apply the PRCs in one of two ways. Direct Injection involves
interfacing the PRCs directly to the GPS receiver so that the pseudo ranges can be
corrected, deriving a differentially corrected position. The second method is to supply
both pseudo-ranges from the GPS receiver, and the PRCs to a PC running DGPS
software which combines the two sets of data to derive the corrected position.

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The use of differential techniques may potentially result in system accuracies superior to
those obtained from the p-code. Even when using the p-code, the GPS system will
exhibit inaccuracies associated with errors in satellite position within its orbit. Using the
C/A code with differential corrections, the effects of orbital errors are reduced.
The differential link used to transmit the corrections varies from HF and UHF short-range
radio links to communications satellite links providing longer range or even global
coverage. The type of differential link selected will depend on circumstances and
location but an essential requirement is a high update rate for the corrections. For DP
purposes, update rates of less than 5 seconds are necessary. Longer update intervals
will result in erratic positioning.
DIFFERENTIAL GPS DATA LINKS
There are several different types of PRC data link available from DGPS suppliers.
Typical systems and suppliers are shown in Table 5.2.

SYSTEM TYPE SUPPLIER RANGE

UHF Subsea Survey/Veripos 40 km

HF/MF Difftech 600 km

Kongsberg/Diffstar 400 - 600 km
Racal Survey Deltafix LR 600 km
Subsea Survey/Veripos 600 km

LF Racal Survey Pulselink 700 km

INMARSAT Fugro Starfix Worldwide network

Racal Survey Skyfix Worldwide network

EUTELSAT Wimpol Spotbeam NW Europe

Table 5.2 Typical GPS Systems

There are advantages and disadvantages to every type of link available. The UHF and
VHF links allow the fastest correction update rates and thus tend to provide the highest
accuracy, generally at the two meter level or better. They are however limited in range to
70 kilometers or less, and thus require reference stations to close in proximity to the
area of operation.
The medium and low frequency systems are more versatile, with ranges of up to 500 or
even 700 kilometers being available, but this extra coverage is generally at the expense
of update rate and hence accuracy and stability. These medium frequencies are also
more susceptible to interference caused by weather and dawn/dusk effects. The
Inmarsat and high frequency Systems are very much dependant on having line of sight
to the differential transmitter (i.e. the reference station or a communication satellite).

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The communications satellites provide the most flexible DGPS link solution (Figure
5.22). Update rates are generally at the five second level or faster and thus there is little
degradation of accuracy. Most Inmarsat DGPS suppliers have now designed frequency
taps which can extract the correction data from the vessels own lnmarsat
Communications system without affecting its communications capabilities. The
availability of multiple reference stations also allows the computation of a network
position solution using more than one reference station. This produces a more robust
and stable position with effective and automatic redundancy of reference stations.

Figure 5.22 UHF Platform Based Diff-link DGPS

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NETWORK DGPS
Some DPGS systems are able to accept multiple differential inputs obtained from widely
separated reference stations(Figure 5.23). The simplest method of deriving a position
using multiple differential signals is for the receiver to average a number of PRC values,
from different reference stations, weighting each by the distance to the reference
stations (highest weighting to the PRC values from the nearest reference station). A
more satisfactory solution involves a full least-squares computation using all PRCs
received. Both of these methods are referred to as decentralized systems. Another
method, the centralized system involves the computation of one set of PRCs ashore,
based on all the data from the reference stations, and this set of PRCs are then
transmitted to the user. This is the method used in the UDI Starfix Network package,
also the Sercel Veripos network, and the Racal Skyfix Network. In these systems,
reference station data is relayed to a Hub or network control center. Correction data is
then sent to the user in raw form; this is then processed on board to determine the best
solution, with the position of the vessel used to determine the optimum PRCs. Generally,
network DGPS systems provide greater stability and accuracy, and remove more of the
ionospheric error than single reference station systems. Also, Network systems are more
comprehensively monitored at the Hub stations, where user information or warning data
may be generated and sent out.

Figure 5.23 Network DGPS Configuration

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DGPS ACCURACY
The accuracy quoted for DGPS varies from one to five meters. Within a particular
constellation of satellites the accuracy varies between one and three meters, rising to
five meters during a constellation change.
PERFORMANCE AND PRACTICAL ASPECTS OF DGPS
Experience has shown that DGPS provides the best reliability when the vessel is in open
water. Degradation in the system may be experienced if the vessel is positioned
alongside a platform structure due to signal reflection (multi-path) or loss of signal line-
of-sight. Position jump may occur at changes in constellation configuration (picking up or
dropping of satellites). It is important that the receiving antenna for the satellite signals
be placed at the highest point in the vessel. This is impracticable in some vessels such
as crane barges with large mobile jib structures. Advanced receivers are able to mitigate
the effects of constellation change by adjusting the weighting of signals from newly
acquired satellites, ramping the weighting from zero when the satellite first rises above
the elevation mask, up to maximum when a few degrees above it. Reverse ramping is
applied as the setting satellite approaches the elevation mask.
One particular problem experienced by some operators has been system lock-up or
"G P S fre e ze . T h is is o fte n u n e xp la in e d , but GPS freeze can have catastrophic results
for the DP capability as the DP will consider the position data of high quality (e.g. very
stable) possibly rejecting other PRS in favor of the frozen GPS. If the vessel is slightly off
her set-position then continuous, apparently ineffective compensation from the thrusters
will result in drive-off.
Problems are occasionally reported of interference of DPGS signals caused by telex,
mobile phones, satcom kit or radar. This type of interference must be checked out on
installation.

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PERFORMANCE MONITORING OF DGPS DATA

Information is available to the operator within the DGPS system. Quality Assurance (QA)
software running with the DGPS system will provide data which, if interpreted correctly
allows the DPO to monitor the performance of the system, and to indicate to him the
quality of the data provided.
The DPO is able to monitor the system and determine if the system has deteriorated to a
marginal or unreliable condition. He is also able to predict future periods of unreliable or
unusable operation.
With respect to the GPS system, the performance parameters of importance are:
number of satellites, their signal strengths, their geometry, the pseudorange residuals,
the position standard deviation, the HDOP and the predicted satellite configuration.
Signal strength values are displayed, and the operator is able to detect a satellite
returning poor signals. This may be due to the satellite passing into an area where its
line of sight is interrupted. It may happen that the result is loss of that satellite from the
observed constellation, or the incidence of multipath reception causing a jump in
position. The geometry of the constellation has an important effect on the quality of the
position fixing; poor fixing is usually associated with a number of tracked satellites
occupying the same sector of the sky. In general the lower the satellites and the better
the spread around the horizon, the better will be the quality of (horizontal) fixing. The
value of HDOP will indicate this. The operator should be able to access data relating to
predicted satellite availability. For a given locality, the system should indicate a
prognosis of number of satellites available at all times, their geometry and HDOP values.
The operator may need to modify the data with his knowledge of possible sources of
satellite masking and consequent loss, due perhaps to crane movements.
Residuals are the differences in values between the observed ranges to satellites, and
the calculated ranges from the final position fix. If the position fix is determined from a
large "cocked hat" of lines of position, and thus subject to error, the residuals will be
large. In general the observer is looking for residuals of less than 3m, a position
standard deviation of a similar value, and HDOP values of less than 5.
With respect to the Differential corrections, the performance of the system is subject to a
number of factors. The rate at which PRCs are received, together with the AOC (Age of
Corrections, or latency of the data) have a major effect on the value of the data. The
operator should be looking for the data rate to be around 5 to 15 seconds, and the
latency of the data less than 10 seconds. This level of performance allows continued
operation even if one or two updates are lost through some momentary outage. With
slower update rates and/or higher latencies the loss of an update could make the DGPS
system unusable for DP reference.

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REDUNDANT GPS ARRANGEMENTS

For reliable operation the DGPS components should be powered through an
Uninterruptible Power Supply (UPS). A number of DP vessels utilize multiple DGPS
systems with different modes of differential link. In these cases, it is advisable that both
DGPS systems be powered through different UPS.
Care must be exercised when designing dual DGPS system installations. If these two
systems are to be considered completely separate for the purposes of DP system
redundancy, then those installing and operating the system must ensure that there are
no single-point failure modes present.
The semi-submersible "Iolair" conducted lengthy operations in the deepwater fields West
of Shetland using dual DGPS as the sole means of position reference. The redundancy
was provided in the duality of the DGPS installations. Great care was taken to ensure
that both systems were totally separate from each other, and each used different
hardware and supplier options. The weak link in the chain was in the Difflink
arrangements. Although the diff-links were sourced from Inmarsat A and B respectively,
both these services were provided from the same Inmarsat satellite, and both relied on
the same uplink dish at Eik. Failure of this uplink station resulted in the loss of both
DGPS systems simultaneously.

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5.3.3 GLONASS SYSTEM

GLONASS (The Global Navigation Satellite System) is the Russian counterpart to the
American GPS, being similar in design and operation. The system was initiated with the
first satellite launches in 1982, and the constellation consisted of 10 satellites by the year
2000. Past performance has shown the GLONASS satellites to be less robust and more
prone to failure.
Receivers are available that are able to combine the GLONASS and GPS signals into a
single solution. Having a greater number of satellites to draw on increases reliability,
improves geometry and improves accuracy.

5.3.4 HYDROACOUSTIC POSITION REFERENCE SYSTEM

This system uses one or more acoustic devices (transponders) placed on the seabed to
transmit an acoustic pulse to the ship mounted hydrophones/transducers. Reception of
the pulse can b e u se d to ca lcu la te th e sh ip s p o sitio n fro m th e kn o w n lo ca tio n o f th e
transponder. This system can be very accurate but does suffer from signal degradation
due to aeration and noise from the sea surface and thrusters. These systems also rely
on the input from vertical reference units to compensate for vessel roll and pitch. It has
good long-term accuracy but suffers from short-term noise and interruptions.
Hydroacoustic Positioning Reference Systems have the advantage of being vessel-
based and do not depend on the operation of third party systems like GPS/DGPS.
There are three main types of acoustic system Long Baseline (LBL), Short Baseline
(SBL) and Ultra Short Baseline (USBL). There are also some combinations and hybrids
of these basic types.
TRANSDUCERS
A transducer is an acoustic transmitter/receiver located at the end of a pole projecting
about three to four meters beneath the keel of the vessel. A typical DP vessel will be
equipped with multiple transducers to support the various hydroacoustic position
reference systems. The transducer assembly includes a mechanism for raising and
lowering the transducer head during transit. With the transducers deployed, the vessels
speed is restricted to 2 kts.
When voltage is applied to the transducer the internal elements will vibrate generating a
sound wave at a specific frequency. The opposite occurs when a sound wave impinges
on the transducer face. The sound wave induces a vibration in the elements which in
turn generates an electrical signal which gets sent to the computer for processing.
Transducer performance will be degraded during times of bad sea-state. Vessel rolling
motion during bad weather will generate turbulence as the transducer element moves
through the water as the vessel rolls. This is particularly severe in deeper draft vessels
where even gentle rolling results in quite high velocities at the transducer. Another
source of poor performance is the error caused by the pole bending and oscillating in
rolling conditions. Up to 0.5 deflection may be experienced.

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TRANSPONDERS
A transponder (Figure 5.24) is similar to a transducer in that it also transmits and
receives acoustic signals. The difference being transponders are positioned on the
seafloor and transmit an acoustic signal in response to an interrogation signal sent from
the vessel. A variety of transponder types are used, depending on the particular
application. They operate in the 15 kHz - 32 kHz band. When using multiple
transponders each must operate at discrete frequencies, separated by a minimum of
500 Hz, in order to allow identification of the transponder sending the signal and to avoid
interference between multiple replies. The transponder itself is battery powered and may
have rechargeable or replaceable batteries. Battery life is obviously limited, and will
depend on type of battery, functions available, low or high power operation, and
interrogation rate. For this last reason, it is normal to reduce the ping rate to the lowest
rate commensurate with effective positioning, as the higher ping rates will deplete the
batteries more quickly.

Figure 5.24 Sonardyne Transponder

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Transponders are anchored to the seafloor using a sinker weight and 1 - 2 meters of
mooring chain (Figure 5.25). The amount of weight used can vary from 60 - 150 kg
depending on the water depth and environmental conditions. The transponders are fitted
with a float to keep the unit vertical and off the seafloor.

Transducer
Protection
Wire Rope to Surface
Float (Typically not
used in Drilling)
Float
(Divinycell)

Transponder

1 2 m Mooring Line

150 kg Sinker

Figure 5.25 Transponder Mooring Arrangement - Simrad

Care must be taken when deploying transponders to ensure that the sinker weight is not
being lowered onto any seabed hardware, or into a location where there will be acoustic
shadowing. It is a good idea not to deploy transponders too close to ROV operations
where its umbilical can get fouled in the transponder's anchor chain and unwittingly drag
the transponder away in its travels. Perhaps the biggest source of interference is noise
and aeration from the vessel's thrusters and propellers. The DPO must consider the
acoustic path between Transducer and Transponder, and arrange to minimize the
amount of thruster wash that is directed into that path.
Retrieval of the transponders may either be done by a ROV or through remote release.
During remote release the transponder receives an acoustic release command from the
surface, the release hook at the base of the unit opens releasing the mooring tether to
the sinker weight. The transponder then floats to the surface carried by its fitted float.

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LONG BASELINE
At a minimum the Long Baseline Acoustic Position Reference System (Figure 5.26)
consists of three transponders on the sea bottom and a transducer on the vessel. The
basic principle behind this system is that it measures the amount of time required for a
signal to travel from the transducer to the transponder and back. This travel time is then
multiplied by the speed of sound in water to get a round trip distance. Knowing the range
to each of the transponders a relative position of the vessel can be calculated by
triangulation. The entire process is started by the surface transducer producing an
interrogation signal which is received by the transponders. The transponders then reply
with a return signal. To avoid signal interference each transponder replies after a
predetermined delay and with a unique frequency. This fixed time lapse between the
reception of the interrogation signal, and the transmission of the reply, ensures that the
transponder replies do not arrive at the transducer simultaneously. The processor is
aware of the delay time programmed into each transponder and factors this into the
calculation.
Most advanced systems will utilize more than three transponders and perhaps even
more than one transducer on the vessel to receive the reply signals. This provides an
element of redundancy along with multiple positions which can be averaged together to
improve accuracy.

Figure 5.26 Long Baseline Principles

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The long baseline system can provide very accurate positioning information. One
advantage of this system over the other acoustic system is the angle of incidence of the
return signal is not relevant. Thus a major source of error is eliminated; that of angular
distortion in reply signal paths due to ray bending or refraction. Errors in range
measurements caused by ray bending are less significant. The system may have a
sound velocity profile inserted to allow ray bending corrections to be applied. The
accuracy of the determined positions will depend on a number of factors, in particular the
accuracy of the sound velocity profile used, the number of ranges measured and the
geometrical angles of cut of the position circles.
Filtering takes place using a weighted least-squares analysis on the ranges measured.
Also since this system does not need to know the angle of incident of the return signal
there is no need for a VRS input, thus eliminating a potential failure point.
The position that is calculated is a relative position from the transponders and therefore
requires the location of the transponders to be known. This is performed through a
calibration process during system setup.

LBL ARRAY CALIBRATION

Prior to using an LBL system for positioning purposes, an array of transponders must be
laid and their positions accurately calibrated. This calibration may be Local or Global. If
Local calibration is used, the position of the transponders in the array is referenced to
one selected "master" transponder with co-ordinates set at 0, 0 (N,E). Global calibration
references the transponder positions to geographical locations by integration with an on-
board navigation system (e.g. DGPS). To achieve calibration, the vessel will lay the
array of transponders, spaced 500 to 1000 meters apart, around the area of operation.
The operator must input some data to the system relating to the positions of the
transponders. This information may be conveniently acquired if the system is a
combined LBL/USBL, and position information on transponders may be determined
using the USBL mode of operation. Once this initial data on transponder location and
depth is inserted, calibration will take place, with each transponder determining distance
from all the others within the array, and transmitting this data to the surface by acoustic
telemetry. A large number of range measurements are made with filtering taking place
using a weighted least-squares analysis of the range errors, or residuals. This ensures
that range measurements differing greatly from the mean have less impact on the
filtering than do those closer to the mean values. If the vessel is navigating also by
DGPS, then a facility exists to allow the calibration to become absolute, or Global, with
UTM co-ordinates attached to the transponder locations. The calibration process should
not take more than a few minutes to complete.
LBL POSITIONING
In general, LBL techniques allow more accurate positioning than USBL, but it is
necessary to deploy a number of transponders in the area of operation, and to obtain
calibration on them before positioning is possible. Redundancy is obtained by deploying
more transponders than the minimum necessary, but accuracy or positioning function
may be degraded or lost altogether on the loss of communication with one or more
transponders.
The results of tests made in water depths of 1800m and 1100m showed accuracies of
better than 1 m RMS without any filtering being necessary. In general, the accuracy is

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independent of water depth, and is better for higher than lower frequencies. Deeper
water requires lower frequencies in order to conserve transponder battery power. A
disadvantage of the LBL system is the lower update rates available in deeper water. It is
not possible to maintain the desired once-per-second data rate in waters deeper than
500m so it becomes necessary to reduce the update rate to 4 seconds or even longer.
For general DP position reference, USBL is a more versatile and flexible system,
providing adequate accuracy, and easily deployable anywhere. LBL systems are more
accurate over the specific area of the array, typically 0.1% water depth, but require
additional setup time.
SHORT BASELINE
The conventional short baseline system (Figure 5.27) uses an array of receiving
elements called hydrophones, which are mounted on the vessel. These hydrophones
make up an array and the distance between the hydrophones forms the baseline. Similar
to the long baseline system a minimum of three hydrophones are required, but the
baseline distance is much shorter since the array is mounted on the vessel verses the
seafloor. The system also utilizes a subsea beacon positioned on the seafloor to emit an
acoustic pulse. The time-of-arrival of this acoustic pulse is measured at each
hydrophone, and the differences in time-of-arrival are compared. Unlike the long
baseline system the actual distances of the beacon to the individual hydrophones are
not measured, but the distance differences are determined from the difference in time-of-
arrival. Knowing the geometry of the hydrophones the differences in time-of-arrival can
be used to compute the offset of the vessel to the beacon, and hence a relative position
of the vessel.
The subsea beacon can either be a pinger or a transponder. A pinger emits acoustic
pulses at a fixed ping rate, usually once per second. A transponder emits acoustic

Figure 5.27 Short Baseline Principles

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pulses only when interrogated by an interrogator installed on the vessel. One distinct
difference between the pinger and the transponder is the data rate. In the case of the
pinger, the data rate is fixed and cannot be controlled from the surface once the beacon
is deployed. Some pinger designs can be switched on, off, or released from their
anchors by a series of acoustic codes emitted from the vessel. As for the transponder, it
has to be interrogated from the surface and the data rate is entirely surface controlled.
However, for deepwater applications, the minimum time required to complete a data
cycle for the transponder can be several seconds due to the round trip distance between
the interrogator on the vessel and the transponder on the sea bed, and the speed of
sound in water.
Short baseline systems are typically fitted with four or more hydrophones to improve
redundancy and system reliability. For instance some of the Nautronix systems use six
or eight hydrophones in combination with four transponders to develop multiple ranging
solutions. The system then performs a least squares fit based on ALL the valid position
measurements and reports a single SBL solution to the DP system. Hydrophones
exhibiting a reduced S/N ratio are eliminated automatically from the solution, thereby
achieving a high level of redundancy. This use of redundant hydrophones also allows
some of the hydrophones to suffer from acoustic masking from local noise sources and
still retain full accuracy.
Another type of SBL system uses ranging principles similar to the LBL system but
slightly reversed. Here one of the hydrophones in the hull array is replaced with a
transducer and the seabed beacon is a transponder. As in the LBL system, this system
uses the transducer to send out an interrogation pulse which is received and replied to
by the transponder. A range is then determined for each hydrophone based on the time
delay observed between the transmission of the interrogation pulse and the reception of
the reply signal. The result is a number of range measurements from which a position
can be determined. This position is, of course, relative to the location of the seabed
beacon or transponder.
A significant advantage of SBL systems, when compared with Ultra Short Baseline
(USBL) and LBL systems in deeper water, is the update rate. With free-running beacons
on the seabed there is no delay associated with the interrogation of transponders. Data
rates may be maintained at the once-per-second desirable for DP purposes irrespective
of water depth, although this will not be true for the systems wherein a transponder is
interrogated for reply. The SBL systems also show a greater accuracy in deeper water
compared with USBL systems due to the lower impact of water noise as well as the
longer baselines. The SBL system is capable of achieving accuracies within 0.1% to
0.2% of slant range.
With any SBL system, the co-ordinate system is attached to the vessel (the x/y co-
ordinates of the hydrophones or transducers) and as such will roll, pitch and yaw with
the vessel's movement. This necessitates the inclusion of VRU and gyro units into the
system in order to enable the effects of vessel movement to be extracted.
Once common in drill ships, SBL acoustic position reference systems have generally
been superseded by USBL/SSBL and LBL systems but are fast making a comeback due
to the advantages mentioned above relating to deepwater operations.

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ULTRA SHORT BASELINE/SUPER SHORT BASELINE

The terms SSBL and USBL (Super short and Ultra short baseline) are synonymous
(Figure 5.28). In its basic configuration, the system consists of a "transducer unit"
mounted to the ship's bottom, and at least one transponder located on the seabed. The
transducer unit consists of multiple transmit and receive elements (transducers) closely
spaced together into one hull-mounted unit. Position measurements are based on range
and direction data determined from transponder replies resulting from interrogation. Up
to five transponders can be interrogated, in turn, within the same area. Simultaneous
use of multiple transponders is made possible by using different interrogation and reply
frequencies for each transponder.

Figure 5.28 Ultra Short Base Line Positioning Geometry - Simrad

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The system measures the range of a transponder relative to the transducer by

measuring the time elapsed between transmission of the interrogation signal and
reception of the reply. This time lapse is made up of the through-water return time of the
acoustic signal plus the turnaround time within the transponder. The latter is a fixed
known value, and once allowed for, the distance, or Slant Range may be deduced.
The direction of the incoming reply signal is determined from time-phase comparisons
made between pairs of transducer receiving elements within the transducer head.
Transducer heads can be very sophisticated with as many as 48 elements, spaced 2
inches or less apart, are used to make up the receiving unit within a transducer.
The time delay and the time-phase data is then combined with the roll and pitch values
obtained from the VRU in order to obtain a slant range and direction referenced to the
vessel co-ordinate frame.
The USBL system has a "Fixed Depth" or "Z-Lock" function which allows the operator to
enter a fixed water depth for the transponder. This improves the position data since the
variation in depth is removed from the calculation. This will be particularly useful when
the distance to the transponder is greater than about twice the water depth, (when large
horizontal angles are involved). The same effect may be obtained if a Depth transponder
is used, which has the ability to continuously relay data relating to the water depth from
an on-board pressure sensor.
The accuracy of the USBL system is usually in the range of 1% to 2% of water depth
although this depends on acoustic conditions. Problems exist when using the system in
very deepwater under poor acoustic conditions, such as strong tides, high noise levels,
large amounts of aeration or in particularly shallow water. Unlike other HPR systems, the
USBL system needs only one transducer and one transponder for effective positioning.
Using two transponders provides an element of redundancy, especially if two separate
transducers are being used for interrogation.

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FACTORS AFFECTING ACOUSTIC PROPAGATION

All hydroacoustic systems depend on the efficient propagation of acoustic (sound)
waves from one location to another. It is important that the various factors that affect the
propagation are understood. Acoustic signals will suffer from spreading, and attenuation
caused by absorption and scattering. Acoustics also suffer from refraction and noise
interference.

Spreading
Spreading of the acoustic energy is simply a function of distance. If an acoustic signal
originates at a position, and radiates from that position in a spherical pattern, there will
be a decrease in the signal intensity in proportion to the square of the distance. This is
because the energy within the signal will be spread over an increasing area, such that a
target (listening transponder) will intercept only a small proportion of the transmitted
energy.

Attenuation
Attenuation is a weakening of the acoustic signal, which is mostly caused by absorption
of the acoustic energy as it travels through the water. In this case, a proportion of the
acoustic energy will be converted to heat within the water. The amount of absorption
depends heavily on the frequency of the acoustic signal, and the temperature, salinity
and pressure of the water. Best results are obtained with signals of low frequency, within
the 10 - 30 kHz band. At higher frequencies than this the effective range reduces to
unacceptable levels. One system, the Nautronix ATS uses a multi-frequency "chirp" for
the interrogating pulse. If one frequency is masked or lost then the others should ensure
reception.

Scattering and Reflection

Any object or impurity in the water may cause scattering of the acoustic signal. This may
be fish, seaweed, air bubbles or any other solid obstruction encountered as the acoustic
signal passes through the water column. The reflection of acoustic signals off of objects
or the water surface may also cause interference. The reflected signal may be mistaken
for the wanted, non-reflected signal, or the reflected signal may combine with and
cancels out the wanted signal.

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Refraction (& Ray Bending)

Refraction or ray bending is a major source of inaccuracy and loss of signal in acoustic
systems (Figure 5.29). Ray bending is caused by variations in the speed of propagation
of acoustic energy, where this variation is due to temperature, salinity and pressure
(depth) differences in the water column. Water columns which are highly layered with
varying zones of water temperature and salinity will have more pronounced ray bending.

Figure 5.29 Refraction and Reflection of Acoustics

The reason ray bending poses such a problem is because most acoustic positioning
systems use reply-ranging as the primary positioning technique. With this principle,
the range between acoustic elements is determined from time-lapse measurements.
If significant ray bending has occurred then the acoustic signal will have traveled a
longer path than the straight-line distance, giving rise to ranging errors within the system.
Further, if ray bending has occurred, then the reply angle will be distorted. This will
result in significant errors with the USBL system which depends on an accurate angle
measurement. Many modern HPR systems allow the operator to input water column
data such that a ray profile is generated within the system, and all ray bending is
compensated for. This data may be manually input or entered as a file from an
external computer.

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Noise Interference
Noise interference is a further hazard to effective acoustic operations. An adequate
signal-to-noise (s/n) ratio must be maintained to ensure secure communications. Noise
conditions vary with sea state and with noise from propellers and thrusters. Noise may
also emanate from underwater operational elements, e.g. from ROV and drilling. Noise
may also be emitted from supply vessels working alongside, or from such diverse factors
as rain falling on the sea surface. The higher the s/n ratio, the more accurate will be the
position measurements obtained.

5.3.5 RISER ANGLE

The vertical angle of the marine riser at the lower ball joint (or flex joint) is critical to the
drilling operation since the drill string may wear against the inside of the upper part of the
BOP stack if the marine riser and the BOP stack are mis-aligned. Because of the
importance of this riser angle, an angle sensor is installed on the riser just above the ball
joint to monitor the ball joint angle continuously during drilling operations. A riser angle
reference system also uses this angle information to calculate the vessel offset from the
wellhead.
Like the taut wire system, the marine riser behavior in deepwater is affected by the
hydrodynamic drag on the riser. Moreover, the riser behavior is also affected by other
parameters such as the top tension, mud weight and buoyancy which all vary depending
on the drilling operation. Therefore, the riser angle systems currently should not be used
as a positioning input by the DP system.
Because riser dynamics are affected by so many parameters during operations,
ExxonMobil (URC) and Honeywell had jointly developed an adaptive riser angle
reference system (ARARS) for deepwater application in the late 1970s. It used both the
upper riser angle (at the slip joint) and the lower riser angle (at the ball joint) information
and the pre-programmed riser characteristics to adaptively compensate for the riser
dynamics and provide the vessel offset estimates. The system was built and
successfully field tested on the SEDCO 472 in 1980, but was not commercialized due to
the fall-off in deepwater interest in the 1980s and the subsequent emergence of the
DGPS system for deepwater.
There has been some renewed interest in using the riser angle as a position sensor and
managing the riser using the DP system. Kongsberg Simrad and others are developing
such systems.

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5.3.6 POOLING OF DATA

Modern DP systems are able to pool position reference data from two or more position
reference systems. If only one position reference system is enabled into the DP system
then it is simply calibrated, filtered and used, but if two or more are available, then some
form of pooling is required.
In all modern DP systems the pooling relies on weighted averaging. Various methods of
weighted averaging are possible. Weighting may be manually achieved, or automatic. If
automatic weighting principles are used, the basis for the weighting may be Variance or
Frequency. With Variance-based weighting, the weighting value will depend on the
spread or jitter exhibited with the positional data from each PRS, or it may be determined
from the offsets observed between successive measurements from an individual PRS as
compared with the modeled position.
A weighting system based on this principle (Variance-based) may suffer problems. For
example, a very low Variance value (thus high weighting) may result from a PRS which
is frozen, or has become a "perfect" position reference. Also, Variance-based pooling is
less useful when there are only two PRS. Further, the data update rate must be taken
into account, since a PRS with a high update frequency may appear to have a higher
apparent variance than one with a slow update.
Frequency-based weighting differentiates between HF (high frequency) and LF (low
frequency) variations in the observed position data. Position reference systems are
thus given two separate weightings, one for HF and one for LF. The best estimate of
position from that PRS is then the sum of the weighted average HF plus the weighted
average LF. Since the value of LF weighting decays only slowly, then the problems
arising from loss of one PRS are eliminated. The HF value is typically poor for acoustic
systems since frequent jumps and excursions are experienced, while the LF value is
usually good.

KALMAN FILTERING
The mathematical technique of Kalman filtering provides a method of combining
measurements from different sources in a statistically optimum manner. The requirement
of combining two or more PRS inputs within a DP system is an example of the use of
Kalman filtering.
Earlier generations of DP systems, before Kalman filtering, used PID controllers to
provide thruster commands based on the position offset of the vessel from the setpoint.
Kalman controllers work on a different principle, employing mathematical models of the
ve sse ls p o sitio n . T h e m a th e m a tica l m o d e l is d e te rm in e d fro m kn o w le d g e o f th e p re vio u s
position and of the forces acting on the vessel. The system then combines the modeled
and measured positions to determine the best estimate of the vessel position. This
estimated position is then used to modify the model. The weighting within the Kalman
filter on model or measurement will depend on the expected performance of the PRS. If
the PRS in question is "noisy", i.e. the variance is large, then greater weight should be
placed on the model. If the PRS are accurate, then greater weighting can be allocated to
the measurement position. The design of the Kalman filter will determine the reactions of
the control system in response to vessel excursions and erratic position measurements.

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VOTING
For redundant operation the DP vessel will usually (where possible) use three or more
PRS, allowing the DP system to apply Voting logic to the measurements. Voting will
involve taking the middle value, or Median of the three or more input values. For each
PRS input the offsets from the Median value are examined and checked against a
preset reject limit. The Median is used, not the average, since if averaging was adopted,
the inclusion of data from the erroneous system would pollute the average value, and
the good data would then show excessive offsets which might also result in their
being rejected.

POSITION REFERENCE DATA HANDLING

The following description relates to the Kongsberg Simrad process of automatic
Variance-based weighting involving Kalman filtering. Once on location the DP operator
selects the first PRS. The DP system looks for three successive returns within a spread
of 10m or less before the PRS is accepted into the system. At this point thruster control
can be turned over to the DP system. This initial PRS will show on-screen as "Reference
Origin", indicated by a small circle around the asterisk indicating the position of the
reference sensor.
When the second and subsequent PRS are selected, the acceptance criteria changes to
10 successive returns within 10m before acceptance into the DP system. Once two or
more PRS are accepted, it is recommended that the first-selected PRS be deselected,
and re-selected again. This allows a better calibration to take place, since the original
calibration was based on three returns only, while this later calibration is based on ten
returns.
For any PRS, circles are placed around a representative sample of position returns.
The size of the circle relates to the spread, in meters, of the sample of position
measurements. The DP system then determines a value for the radius of the circle,
called the INNOVATION. The value of the Innovation is set between 1.5 and 15 meters.
An Innovation of 1.5 indicates that the spread of position fixes from that particular PRS is
1.5m or better. The first stage of Kalman filtering deals with the Innovation values; this is
the Prediction Test, for which the Innovation is the limit. Any returns yielding positions
outside the Innovation window are rejected. This allows outliers (single spurious position
fixes at some distance from the vessel position) to be rejected. Further, any PRS which
has an Innovation value of greater than three times that of the smallest Innovation, is
rejected. This is the Variance Test, and generates the Standard Deviation Limit. This
ensures that PRSs which do not have high intrinsic accuracy are not allowed to pollute
the position fixing from more accurate systems. Note also the principle of setting the
minimum Innovation at 1.5m, even if the PRS is more accurate than this and would
otherwise generate a much smaller circle of, say 0.5m. If this value (0.5m) was set as
the Innovation, then the reject limit for other PRS would be unrealistically low (1.5m)
resulting in continuous rejection of perfectly acceptable data from backup PRS.

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A circle is shown for each PRS of the radius equal to the Innovation for that PRS (Figure
5.30). The Standard Deviation limit is shown centered on the display, which is the
predicted position.

Figure 5.30 Typical Position Reference Display Page - Simrad

Each PRS is assigned a Weighting value; this is inversely proportional to the Innovation
value, thus the weighting is based on the relative circle sizes.
The weighting values always total 1.0 regardless of how many PRS are enabled. Within
this, the larger the weighting, the smaller the Innovation or circle size. For all PRS the
measurements are filtered. Position reference inputs are sampled once per second. In
the above display the raw PRS data is shown as small crosses corresponding to each
PRS. This is unfiltered data so the crosses may exhibit significant movement. Filtering is
applied such that the new filtered measurement is equal to nine times the old filtered
measurements (Northings and Eastings) plus the new measurements, divided by ten.
This is the second stage of filtering. Filtered positions from this stage are displayed as
small circles on the display.

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The third stage of filtering concerns the statistical mix of the two or more PRS enabled,
in order to provide the calculation of the vessel position. If, for example, three PRS are
engaged; then we look separately at Northings and Eastings. It may happen that the
HPR system is giving noisy returns and is close to the Variance Test reject limit. The
statistical mix calculation (for Northing only, for illustration) is as follows:

Thus, from Table 5.3, we can see that the noisy measurements from the HPR are not
affecting the final position, and that the position depends on measurements from both
DGPS inputs, with a bias toward the more accurate input.

PRS No System Northing Weighting Product

1 DGPS1 -5.5m 0.3 -1.65
2 DGPS2 -5.0m 0.7 -3.30
3 HPR -7.5m 0.0 0.00
1.0 -5.15
Table 5.3 Statistical Mix of Reference Systems

When three or more PRS are deployed, a further rejection limit is set and displayed. This
is the Median Test Limit, and its radius is 6 meters. Its function is to generate rejection of
a jumping PRS measurement through majority voting, and is not affected by the Kalman
filtering.
If a single PRS is deployed then the first and second stage filtering will be carried out,
but all other noise in the measurements will be preserved in the positional calculation.
If two position references are deployed, one good and one poor, then it is possible for
the relative weightings to be 0.99 and 0.01. Under these circumstances the poor
reference will be frequently if not continually rejected. Another problem is that there is no
link between accuracy and reliability. It's possible that the "good" (reliable) PRS may
start to track-off giving inaccurate positioning information. At this point the DP system
knows only that the relative calibration is no longer correct, thus the system with the
lower weighting will be rejected in this case. Thus, with only two PRSs there is a danger
that an accurate PRS will be rejected while a poor or erroneous one will be retained and
used for positioning. This is a good argument for the use of three PRS in any operation
where positioning is vital or critical. It must be mentioned here that when using HPR
systems each system must be treated as a single PRS despite the number of
transponders used for redundancy purposes. This is because the system most likely
operates through a common transducer or transceivers. This will not be the case if two
separate and independent HPR systems are in use and there is no potential for a
common fault.

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The DPO should use caution in his choice of position reference systems. For any
operations requiring system redundancy it is necessary to utilize three position
references. Two PRS are not adequate, since there will arise the question as to which
one has failed when contradictory reference data is received from the two systems.
Three systems will give more security against this possibility, especially if the DP system
is programmed to apply a PRS voting or median check.
Where three PRS are required, the DPO should choose systems which have differing
principles. This reduces the probability of Common-mode failure, where one event may
result in the failure of multiple references. Common-mode failure is more likely to occur
in situations where the choice of PRS has included two or more of the same type of
system.

5.4 THRUSTERS
Thrusters provide the forces and moments to counter the environment and hold the
vessel on station. Effective and reliable propulsion and thruster systems are central to
the efficient operation of DP vessels. One fundamental requirement in thruster design
and selection is to have minimal aeration and cavitation because these are major
sources of noise. Thruster noise can severely degrade the performance and reliability of
the acoustic position reference system. The thruster layout will vary ship-to-ship, and will
depend on many factors. The design and function of the vessel will affect the choice of
thruster type and layout, as will other factors such as draft, level of redundancy required,
type of power plant, and hull configuration.
Three types of thruster make up the majority of units found on DP vessels, with a small
selection of other types used in a minority of vessels.
The three types are:
Main propeller(s),
Tunnel thrusters, and
Azimuth thrusters.
A propeller generates thrust from the lift forces on the wing section of its blades. To
change the amount of thrust, one of two (or possibly both) variables can be altered,
either the pitch of the propeller or its speed. Controllable-Pitch (CP) propellers run at a
constant rotation speed (rpm) and vary their thruster output by changing the pitch of the
blades. Fixed-Pitch (FP) propellers on the other hand vary their thruster output by
changing their rotational speed. These two variations of thrust control can be applied to
any of the three thruster types mentioned above. Controllable-Pitch and Fixed-Pitch
systems will be discussed in further detail is sections 5.4.4 and 5.4.5 respectively.

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5.4.1 MAIN PROPELLER

Main propellers, either single or twin screw, are provided in a similar fashion as on
conventional vessels (Figure 5.31). In DP vessels where the main propulsion system
forms part of the DP function the propellers are usually controllable pitch running at
constant r.p.m. This facilitates the use of motor driven shafts. Conventional rudders and
steering gear usually accompany the main propellers. Generally (though not exclusively)
the DP system does not include rudder control.
When the main propellers are used as part of the DP system it is important that, prior to
any DP operations, the rudder(s) be placed amidships and that any Autopilot be
disengaged. If the rudder is not amidships then ahead movements of the main propellers
will generate unwanted Sway and Yaw movements. DP system are typically set up with
a sensor to provide a "Rudder Not Amidships" alarm.
In the offshore industry, a significant number of workboats not built with DP capability in
mind have been converted to DP vessels. These vessels may demonstrate a less-than-
perfect propeller and thruster configuration due to constrictions of space, time and cost
during the conversion. Also to be considered is the power supply to the thrusters. In a
conversion, there may be inadequate power to meet the demand of the newly fitted
thrusters.

5.4.2 TUNNEL THRUSTERS

These units are not typically used on drilling rigs but are more commonly fitted on
smaller workboats and anchor handling vessels. Tunnel thrusters are mounted in the
bow of the vessel and only provide thrust in the transverse direction. Often tunnel
th ru ste rs a re u se d in co n ju n ctio n w ith th e ve sse ls m a in p ro p e lle r syste m

Figure 5.31 Glomar Jack Ryan Main Propeller

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One physical characteristic that must be kept in mind is that the effect of tunnel thrusters
is radically reduced if the vessel has more than about two knots headway or sternway.
The actual speed at which their efficiency is reduced varies from ship to ship. In some
vessels, it is possible to observe a slight but positive reverse thrust effect at certain
speeds. For this reason, vessels operating in a high current environment may
experience difficulties in maintaining heading control.
Effectiveness of tunnel thrusters also heavily depends on the length of the tunnel; the
longer the tunnel the less efficient the thruster. Tunnel thruster output may differ in each
direction. The design of a tunnel thruster will minimize this difference, but it is common to
find a tunnel thruster slightly more powerful in one direction than in the other.

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5.4.3 AZIMUTHING THRUSTERS

Azimuth Thrusters utilize C.P. or f.p. propellers mounted in short tunnels, which are
referred to by varying names such as ducts, shrouds or nozzles. Power is delivered to
the propellers down through a vertical drive shaft and geared via 90 bevel gears to a
short horizontal propeller shaft. The unit projects beneath the bottom of the vessel and
can be rotated to provide thrust in any direction. A wide range of azimuth thrusters are
available from a number of manufacturers, ranging from 600kW to 7500kW (800 H.P. to
10,000 H.P.) with propeller diameters ranging from around 2.0 m to over 5.0 m.

Figure 5.33 Two 40-Ton Azimuth

Thrusters Aft in Ship

Figure 5.32 Azimuthing Thruster

Typically a DP drill ship, uses six azimuthing thrusters; three at the bow and three aft.
When underway on passage, these units provide the steering function, and are linked to
the autopilot.

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In some semi-submersible rigs, azimuth thrusters may be fitted directly beneath the
pontoons; thus they are the deepest point of the vessel. This configuration is particularly
vulnerable to grounding damage, and every precaution must be taken to ensure this
does not occur. Some semi-submersible vessels have thrusters located on the upper
sides of the pontoons. This may be a safer arrangement when navigating in shallower
areas, but the thrusters are closer to the surface and therefore less effective due to the
greater potential for cavitation. In either configuration a semi-submersible will have a
minimum of four thrusters, one in each corner.
Another possible installation configuration is the canister-mounted thruster, in which the
whole unit including the drive motor, control units, shafts and propeller are built into a
cylindrical canister (Figure 5.34). The canister-mounted design provides the ability for
the canister to be retracted into the hull vertically or else pivoted into the hull in a
horizontal position. This facilitates repairs and servicing without the need for divers or
underwater work. The thrusters can also be retracted during transit mode to reduce
the amount of hydrodynamic drag on the hull.

Figure 5.34 Cannister-Mounted Azimuth Thruster

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It is normal for an azimuth thruster to have Ahead and Astern directions of operation.
The Ahead direction is the most efficient; the propeller blade design is optimized for this
direction, as is the nozzle design. This will also be the most advantageous direction
regarding the positioning of the propeller mountings and hub gearbox (these are
normally placed ahead of the propeller when operating in the "ahead" direction). When
operating in the reverse or "astern" direction the amount of thrust available drops off to
typically 60%. Thus it is normal for the DP system to operate these units in the "ahead"
direction at all times. However when maneuvering the vessel manually, the operator may
elect to reverse the direction of thrust for short periods as this is faster than rotating the
unit through 180. Some DP systems will force an azimuth thruster to rotate to operate in
the ahead mode. In others, if operating astern, when approx. 60% - 70% of reverse pitch
is reached, it will break away, rotate and operate in the ahead mode.
Note: This feature may be most disconcerting to the DPO if he is not expecting it!

DEAD ZONES
When multiple azimuth thrusters are fitted in close proximity to each other, it is
necessary to ensure that the exhaust wash from one thruster does not impinge on
another thruster. If this were to happen, the "downstream" thruster will become less
efficient and may overspeed and trip. In cases such as this the DP control software
must be programmed to prevent the thrusters from operating in these azimuth ranges
or dead zones.

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5.4.4 CONTROLLABLE-PITCH PROPELLERS

The majority of propellers found in DP-capable vessels are of the controllable-pitch
variety. This applies both to main propellers as well as tunnel and azimuth thrusters.
With controllable-pitch propellers, the propeller is driven at a constant speed, and the
pitch is varied hydraulically to change thrust. The thrust generated is broadly
proportionate to the pitch squared, so 50% pitch gives 25% thrust, 70% pitch
gives 49% thrust etc.
The main advantage of these thrusters is that they are a relatively inexpensive initial
investment, as they have a very simple drive and starter. The disadvantages are that
they have complicated mechanisms outside the hull that may require dry-docking for
repair. They also require a substantial amount of power at a low-pitch setting just to drive
the thruster around. Their mechanics and hydraulics need to be capable of withstanding
the arduous duty cycle of the DP control system, changing every few seconds, day-in-
day-out, sometimes for months on end.
All C.P. propellers suffer from similar characteristics and failure modes, and it is worth
discussing them here. C.P. propellers derive their pitch value from swiveling the blades
about a radial axis. All the blades pitch identically by means of a common crosshead
assembly fitted in the propeller hub. This crosshead causes rotation of the blades by
means of a crank mechanism. Crosshead movement is achieved by hydraulic actuator,
either located within the propeller hub, or fitted in an inboard location within the hollow
propeller shaft. Actuation in the latter case is by means of a pushrod within the shaft.
C.P. propellers all have a fail-safe mode, relating to a predetermined pitch value to
which the propeller will default if hydraulic pressure is lost. This may be Full Ahead or
Full Astern in supply/work boats. The Full Ahead fail-safe mode is intended to enable
the vessel to continue making way, albeit at reduced revolutions after a hydraulic failure.
This may be satisfactory in many situations, but could cause grief in a maneuvering
scenario. The Full Astern fail-safe state can be equally dangerous.

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C.P. propellers with an all-hydraulic hub, i.e. without spring loading, may fail in a number
of ways. The dynamic balance of the blades may allow them to remain at the set pitch
subsequent to a hydraulic failure, or the propeller may be specifically designed to fail "as
se t. D e p e n d in g o n th e sp e e d o f th e ve sse l a t th e tim e o f fa ilu re , th e p ro p e ller may well
return to zero pitch. DP vessels must have their C.P. propellers arranged to fail-safe to
zero pitch or as set upon loss of hydraulic pressure. This is not easily achieved, and this
failure mode is one that should be tested during the regular auditing of the vessel. Some
thruster manufacturers will arrange interlocks such that a hydraulic hub failure results in
an automatic trip or shutdown of that thruster.
Despite the above, it must be realized that C.P. propellers have a variety of failure
modes other than the result of a loss of hydraulic pressure. In view of this, the DPO
needs to monitor his propeller feedback closely, and if failure occurs, he must shut down
or trip that thruster immediately. It is possible for the wrong thruster to be shut down if
the DPO does not take extreme care in monitoring his instrumentation. An example of
what may happen is that, in a vessel with two bow tunnel thrusters, No 1 fails to full
pitch, thrusting to starboard. The DP system rapidly assesses the situation, including the
feedback thrust from No. 1, and correctly applies full thrust from No. 2, thrusting to port
in an attempt to compensate from the errant No. 1. The DPO looks at his system and
sees No. 1 thruster at maximum starboard thrust, and No. 2 at maximum port thrust. He
must carefully check his setpoint-feedback values on each of the two thrusters, together
with the alarms which have been generated, in order to come to the correct decision to
shut down No. 1 thruster.

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5.4.5 FIXED PITCH OR VARIABLE SPEED (VS) PROPELLERS

Here the propeller has a fixed pitch and thrust is changed by varying the rotational
speed. F.P. propellers have recently become more popular, with the advent of AC
Variable Frequency Drives that now offer a relatively inexpensive drive for thrusters
compared to past costs. There are also some new vessels and a number of older
vessels using DC electric drives, as these are often common to the drilling systems
drives. Their main advantage is that the complication is largely inside the vessel and can
be easily repaired. The disadvantages are that the drive electronics take up a lot of room
and are relatively expensive, compared to a controllable pitch system. They do,
however, offer a superior power factor and consume low power at low speed.
If required, they also allow the motor to be coupled directly to the propeller so a
gearbox is not required.
The relationship of thrust to speed is also a square law. However, a fixed-pitch propeller
can generally produce about 15 tons of thrust per 1000 hp, whereas a C.P. propeller
produces about 12.5 tons per 1000 hp. In addition, the Variable Speed thrusters tend to
be much less noisy and produce lower aeration than the Controllable Pitch thrusters, so
they are better for acoustics. Table 5.4 summarizes the main differences between the
two types of thrusters.

Factor CPP VS
Drive Simple Complicated
Thrust 12.5T per 1000 hp 15T per 1000 hp
Acoustics Poor Good
Base Load 25% at zero pitch Zero at zero speed
Power Factor Poor at low load Good through range
Failure modes Difficult to totally prevent full Easier to prevent full thrust
pitch
CAPEX Least Most
OPEX Most Least
Table 5.4 Comparison of Thruster Types

Most DP systems working with azimuth thrusters will incorporate a Fixed Azimuth or
biasing function. In calm conditions, a DP vessel often hunts or oscillates continuously in
position. This is because the propulsion units are underutilized - having nothing to "push
a g a in st. In su ch circu m sta n ce s, it m a y b e p o ssib le to re d u ce th e n u m b e r o f th ru ste rs
enabled. A large semisubmersible may be configured with eight azimuth thrusters -
two at each corner, and in calm or light conditions may work with just four. Even so, it
may happen that these thrusters are azimuthing continuously, causing a lot of wear and
tear on the steering gear. Selecting Fixed Azimuth or setting up a bias will allow the
system to set one or more thrusters at a fixed azimuth so that the other thrusters can
work against this force while still compensating for environmental forces. This function
is also utilized to optimize the operation of the power generation plant and will be further
discussed in Section 5.

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5.4.6 THRUSTER CONTROL SYSTEMS

In a typical modern diesel-electric DP vessel, thrusters and propellers are powered at a
high voltage, typically 3,300V or 6,000V. The thruster control systems are typically
supplied at 440V from the main switchboard. It is important that these control systems
have adequate blackout protection in the form of Uninterruptible Power Supply (UPS);
it is otherwise possible to have a partial blackout with loss of all 440V in the vessel. The
DP system is still functioning on its dedicated UPS, and the thrusters are running on the
high voltage power supply, but if no UPS is provided in the thruster control power supply,
then control of the running thrusters is lost. Thruster control systems are normally
electro-hydraulic, it being cheaper to run electric cables through the vessel than
pneumatic piping. As mentioned previously, C.P. thruster installations will exhibit a
number of failure modes, a failure within the control system may result in a completely
unexpected response, irrespective of the arrangements for "fail-sale" within the design of
the hub servo.

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5.4.7 THRUSTER FAILURE MODES

Bearings, gears and seals are all areas identified as troublesome.
Bearings supporting the propeller and drive shafts lead particularly arduous lives, and
failures have occurred within their design lives. Causes include improper maintenance
and inefficient lubrication, but poor design and manufacturing quality control are also
contributory. Vibration problems may result in overheating leading to bearing failure.
Damaged bearings may result in fragments of metal migrating to other parts of the unit
and causing further damage.
Water ingress is the biggest single factor in all thruster failures.
Water contamination of gearbox or other oil causes build-up of an emulsion sludge,
which is a poor lubricant. Subsequent bearing breakdown is accelerated by corrosion
caused by the seawater in the sludge. Modern thrusters are typically equipped with
sensors and alarms to detect water/oil contamination in the thruster gearboxes.
Lack of efficient lubrication will also cause problems within gearboxes.
These gears, particularly the bevel gears in the lower gearbox are susceptible to
overloading, pitting, cracking and broken teeth. The prime cause of these problems is
the breakdown of water seals allowing the ingress of water into the gearbox. Another
factor is inefficient circulation of gearbox oil allowing overheating to occur, resulting in
pitting of the gear teeth. Sampling and analysis of the oil is often impossible, since the
emulsion sludge may build up in the bottom of the lower gearbox unit, while sampling
takes place higher up in the unit or at the header tank, where cleaner oil is found.
Many of the problems identified are caused by seal failure.
Seals are perhaps the source of the largest number of thruster failures in DP vessels.
There are three types of seals in use, the blade O-rings in C.P. propellers, the propeller
shaft seal, and the steering gear seal in azimuth thrusters. All of these seals are
vulnerable to a variety of failure modes, with failure occurring within as little as one
month of fitting. Often, seals made by one manufacturer are fitted by the thruster
manufacturer or shipyard, leading to conflict over improper fitting and installation. One
obvious cause of seal failure is damage caused by wrapping ropes, lines, umbilicals etc.
around the propeller. This is an eternal problem, not always averted by fitting rope
guards over the seals.
Fixed pitch propellers have fewer failure modes compared to controllable pitch propellers
and are being more widely fitted.

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5.4.8 OPERATIONAL CONSIDERATIONS

When planning any DP operation, the DPOs must take into account the desired thruster
configuration. In some vessels the normal (or only) method of operation is to have all
thrusters and propellers running, but this is not the case in all vessels. In some vessels it
is acceptable to use less than the full spread of thrusters if the environmental and
operational conditions allow. A semi-submersible drilling rig may be equipped with eight
azimuth thrusters, but her normal operating pattern is to have four running. If adverse
weather conditions develop, then she will start another two thrusters. All eight will only
be engaged in very severe conditions. The DP operations manual for the vessel will
advise on the optimum combinations of thrusters for any conditions. In the absence of
this advice, the DPO must take into account the following factors, both separately and in
combination:
Any factors that may result in impaired thruster efficiency, such as thruster-thruster
interaction, or strong tidal forces.
Any degradation of performance implied from any automatic or manually-applied
thruster barring or inhibit functions.
The level of redundancy available and required. If the vessel is diesel-electric and
thruster supply is from a split switchboard, then care must be taken to ensure that,
with the envisaged reduced thruster configuration, maneuverability is maintained
subsequent to the loss of one section of the switchboard.
When the vessel is under DP control, it is important that any thruster actually running is
taken into DP control. The dangers of not complying with this cannot be emphasized too
highly. The DPO must realize that, if a thruster is running but not enabled, then the DP
system is not monitoring the feedback from that thruster; it thinks it is stopped and
generating zero thrust. If that thruster fails, particularly if the failure is to full pitch, then
the DP will not know about the failure and thus cannot compensate for the unwanted
thrust. The vessel will drive off location, the only compensation resulting from the vessel
positional and velocity errors detected. On the other hand, if that thruster had been
enabled, then a failure to full pitch should be detected by the DP system, which can
apply immediate and drastic compensation automatically from other thrusters. From the
foregoing it will be deduced that, if a thruster is not enabled, then it must be stopped, not
left idling at zero pitch.
Consideration must also be given to the fact that most of the hands onboard a rig are
non-marine-crew personnel and may have little concept of the seagoing environment,
especially when the weather turns foul. They must be made cognizant of the possibility
of equipment, cables, hoses, wires etc., being washed overboard which might tangle
with the thrusters and/or propellers. The loss of thrusters in this manner can totally wipe
out the vessel's DP capability. Good communication and house keeping will allow safe
working practices to prevail, thus preventing such problems.

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5.5 POWER SYSTEMS

Central to the consideration of any DP-capable vessel is the integrity of the power
generation, distribution and management system. Reliable power generation and
distribution is fundamental for a reliable DP system. The power system must be
configured with multiple units and redundant features to handle power demands that
range from very little in light weather to maximum in heavy weather, equipment
malfunctions as well as equipment maintenance requirements.
The thrusters will generally absorb more power than any other consumer on board.
Dynamic Positioning requires more power than any other ship function. It is often found
that DP vessels have a very high level of installed power. This is because the DP
function often requires large unpredictable changes of power load which can occur when
a vessel is on a heading into the wind, and the wind rapidly changes direction. It can be
seen that the power generation system needs to be flexible in order to avoid
unnecessary fuel consumption associated with running the power generation system
at full capacity.
The majority of DP capable vessels are powered by Diesel-Electric plant with all
thrusters and consumers electrically powered. An arrangement of this type is very
versatile and economical to operate. Diesel-generator sets may be taken off-line during
periods of low power demand or for maintenance while the vessel is in operation. The
need for economic operation at a variety of power-demand levels, the need for
redundancy in power, the ability to cater for large "hotel" or operational (non-propulsion)
loads together with the ability to react rapidly to changing environmental conditions
dictates that DP vessels are diesel-electric.
Redundancy in the power system is achieved within the design of the power distribution
layout, the number of generators installed, the power system protection installed, the
power management system fitted and the number of thrusters and propellers installed.
Other factors will include the number of engine rooms, the number of switchboards and
their location, and the level of redundancy within the service components of the power
plant, e.g. diesel cooling, fuel systems.

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5.5.1 POWER DISTRIBUTION

The electrical distribution system design will depend on the level of redundancy required.
To simplify the discussion a drillship configured to operate to equipment class III
standards will be considered. To meet the DP Class III requirements, the engineering
spaces are divided into two separate compartments; port and starboard. The equipment
and electrical distribution systems are completely redundant between the two engine
rooms. In the event of a casualty which renders one of the engine rooms unusable,
the other engine room is capable of providing enough power for stationkeeping.
The power plant in question consists of eight diesel generators each producing
4184 kW of 3-phase 60 Hz A.C. power at 6600 volts with a 0.8 power factor.
The diesel generators are divided evenly among the two engine rooms with two
generators supplying each HV busbar. The two HV busbars in each engine room
are typically connected through a tie bus breaker and are collectively referred to as
an HV switchboard.
The thrusters are largest load on the system. Power is directly supplied from the HV
switchboard to variable frequency drives (VFD). In this particular case the thrusters are
fixed pitch and the speed at which they turn is directly proportional to the frequency of
the a.c. power supplied. The DP system generates a control signal for each VFD to
regulate the frequency supplied to the thruster motors.
The remaining ship loads are supplied from the 480V AC buses while drilling loads are
supplied from the 600V DC buses. Transformers are used to step down the voltage from
the HV switchboard to supply these other buses.

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A simplified drawing of the power distribution system with some of the main loads are
shown in Figure 5.35.

DG-1 DG-2 DG-3 DG-4 DG-5 DG-6 DG-7 DG-8

HV Bus 1 HV Bus 2 HV Bus 3 HV Bus 4

XFMR XFMR XFMR XFMR XFMR XFMR XFMR XFMR

600 V SCR STBD 600 V SCR PORT

DC Drilling DC Drilling
Motors Motors

480V Switchboard (aft) 480V Switchboard (aft) 480V Switchboard (aft) 480V Switchboard (aft)

EDG

Emergency
Aux Aux Aux Aux Aux Aux
Switchboard
Panel Panel Panel Panel Panel Panel

Variable Variable Variable Variable Variable Variable

Frequency Frequency Frequency Frequency Frequency Frequency
Drive Drive Drive Drive Drive Drive

HPU1 Thruster HPU2 HPU1 Thruster HPU2 HPU1 Thruster HPU2 HPU1 Thruster HPU2 HPU1 Thruster HPU2 Thruster
#2 #1 #5 #4
HPU1 #6 HPU2
#3

DG = Diesel Generator EDG = Emergency Diesel Generator

HV Bus = High Voltage Bus HPU = Hydraulic Power Unit
XFMR = Transformer

Figure 5.35 Glomar Jack Ryan Electrical Distribution

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OPEN AND CLOSED BUS TIE

Ideally, each HV switchboard should be supplied by half the operating diesel generators,
and in turn supply half of the thrusters and other HV consumers. It is possible to connect
the port and starboard HV switchboards through two bus tie breakers.
If the network is operated with the bus tie closed, then the HV switchboards essentially
become common. In this configuration the system becomes more flexible as any diesel
generator may be assigned to the complete network rather than dedicated to one side
only. The network is more economically operated; in general less generators are
required for spinning reserve. Transient conditions due to starting large loads are less
severe with more generators on a single bus. Load shedding is not normally necessary
after the failure of one diesel generator. The network is less vulnerable to the effects of
control failures such as Governor over/under frequency, or Voltage regulator over/under
excitation. Not only does this configuration result in each diesel generator clocking up
lower running hours and thus reducing the maintenance frequency, but it generally
provides the flexibility to tag out a diesel generator for maintenance. However, there is a
risk associated with running in this configuration. A single-point failure has the potential
to cause total loss of power. A total loss of power, even briefly, will most likely result in
the vessel moving off location enough to warrant an Emergency Disconnect.
If the network is operated with the bus tie open, then the two sections of the switchboard
essentially become independent. This configuration is known as split bus. If the system
is correctly designed, then, in theory, no single-point failure should result in a total loss of
power. A failure mode exists, however, in which one side of the board is lost on an
overload trip; the DP system commands increased power from the remaining thrusters
on the good side of the board which may then trip due to it being overloaded. An efficient
power management system will protect against this. During critical operations, the
switchboards will be operated as single units, with bus ties open. This configuration is a
requirement for Class 3 operations.
Other considerations associated with running in the split plant mode include the following
points:
The system operation is less economical as there is an increased generation
requirement to cover redundancy.
More machines are required in order to maintain a spinning reserve.
The system is more reliant on the availability of all machines.
For these reasons, the system is far less flexible, and there will be greater running hours
and maintenance on all diesel generator sets. There is a potential for partial blackout or
brownout resulting from the failure of one diesel generator. This configuration may also
preclude the starting of large loads such as thruster motors. This is because the starting
current is far greater than full-load running current and will induce a severe transient on
the system. Therefore the network may have to be paralleled (bus tie closed) for starting
periods, then split out again after starting.

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5.5.2 POWER MANAGEMENT SYSTEM

The management of power consists of the business of having sufficient diesel
generators connected to the switchboards to provide immediate needs, while
economizing on fuel and running hours for diesel generators not being used. A diesel-
electric layout is very versatile in this respect, in that power is supplied from a discrete
number of diesel generators. The number running can be rapidly matched to the load on
the system. This type of installation is very versatile, allowing rapid and radical changes
in demand to be accommodated by the bringing online of extra diesel generators. DP
vessels, are particularly subject to fast changes in power demand, and must be able to
react quickly and efficiently to them.
In modern high-tech vessels, the Power Management is an automated, computer-based
system involving Diesel Generator Auto-start and Auto-stop, Start Blocking, Preferential
Trip functions, together with essential consumers, are protected by UPS and emergency
generation arrangements. The Power Management System (PMS) resides in dual
redundant Power Management Controllers; that is, redundant controllers in the Port
Switchboard Room and redundant controllers in the Starboard Switchboard room. The
system has the capability to react quickly in emergency situations such as generator
failures or to limit the power usage to the maximum allowable level to prevent system
blackout or brownout conditions during sudden power surges. To accompish this, it
performs several critical tasks:
1. Starts Main Engines as required to ensure sufficient power is available.
2. Sets limits on Drilling systems power usage based on online power capacity and
Dynamic Positioning System requirements.
3. Sets a limit on Dynamic Positioning System power usage based on online power
capacity.
4. Temporarily interrupts thruster operation if necessary to prevent a blackout.
In g e n e ra l, w h e n o n D P , th e P M S e n su re s th e re is a t le a st o n e g e n e ra to rs w o rth o f
spare capacity, so the loss of a generator can be tolerated. When a generator is lost, the
PMS starts (or facilitates quick starting of) another generator and brings it online in a
synchronized fashion. If the vessel gets to the stage where there are no more generators
available to start and power becomes limited, the PMS will trip non-essential loads. If
this is not enough, large loads might be phased back (e.g., drilling load). If this is still
in su fficie n t, th e D P co n tro l syste m s p o w e r m a n a g e m e n t fu n ctio n w ill p h a se b a ck o n th e
thruster demands to stay within the power available and avoid a black out. In this event,
the DP control system will prioritize control of the individual axes. With a mono hull drill
ship, the heading demand will be met first since loss of heading can substantially
increase the environmental forces on the vessel and thus increase thrust requirements.
In other applications, other axes may be given priority.

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In addition, the PMS also performs a number of secondary tasks conducive to

maintenance of a reliable power generation system. These more mundane tasks include
reminding the Engineer when an engine needs to be turned over and when an engine is
no longer needed and may be removed from operation.
Even though all PMSs function to prevent blackouts, the means by which they go about
managing the power generation system is unique to each manufacturer. The following is
a description of an ABB program used on board the Glomar Jack Ryan.
As conditions develop which require increased electrical power, the PMS will issue a
start recommendation when load on a bus reaches 90% of the value at which loss of a
diesel generator would cause the remaining diesel generators to be loaded in excess of
their extended time overload capacity, conservatively estimated to be 110% of capacity.
Thus, for these diesel generators with a design full load rating of 4,184 kW the start
recommendation will be issued when the loading on the generators would be 4,180KW
(0.9 x 1.1 x 4184) following the loss of a generator. An additional diesel generator is
automatically started with no operator action when loading would exceed 110% of the
capacity following the loss of one generator. For these particular engines this loading is
at 4,598 kW (1.1 x 4184).
Diesel generators may also be started manually in advance of operations which are
known to require additional power. Under normal operating conditions, diesel generators
will be started and connected to the network under the control of a soft-loading control
program. The time required to bring the diesel generator up to sharing its portion of the
load can be greatly reduced if the engine is in a pre-warmed standby status. The
PMS assists the operator in maintaining one or more generators in this pre-warmed
standby status. Under emergency start conditions the soft loading program is
typically overridden.
As electrical demand decreases the PMS will issue recommendations to reduce the
number on diesel generator online. This recommendation is issued at different load
levels depending on the number of generators operating but generally it is not desirable
to operate diesel engines below 15% loading. It is important to note that the PMS will not
automatically disconnect and stop a diesel generator set.
The above noted operating parameters may be reset by the Engineer to other values to
suit unforeseen circumstances. They should not be set to such values as to allow
engines to be significantly overloaded in the event of a generator or bus fault under any
load conditions.

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In addition to controlling the number of generators online, the PMS also limits DP system
and Drilling power availability to prevent system overloads. The PMS calculates and
advises how much power may be consumed for drilling and stationkeeping. For these
calculations an additional safety factor is established by assuming the diesel generator
capacity to be 95% of the equipment design capacity. Thus, for these diesel generators
in question the "kW Available" will be calculated as if its actual capacity were 3975 kW,
providing a 200 kW cushion. For the Drilling SCRs the available power is calculated to
be the total online power capacity (95% Capacity Factor applied) less the vessel hotel
load, and less the thruster loads. The DP system is provided a power limit in a similar
fashion. It is allowed to use the total online power capacity (95% capacity factor applied)
less hotel load and a small reserve (normally 2MW) for drilling to use in an emergency.
This reserve power may be altered if deemed necessary. If additional power is
demanded beyond the calculated available power, the PMS will restrict this increase
until additional diesel generators have been brought online.
It is recognized that there may be instances where unexpected loss of an online
generator could cause the remaining generators to be loaded beyond their ability to
support the power system and therefore to trip off line, resulting in a blackout.
To preclude this result, the PMS system will take immediate actions in the event
of a generator loss:
1. Issue a signal to all the thruster drives on the affected bus to shut down for a
one second period, which is sufficient time for the DP system to respond to the
reduced power availability by throttling back the thruster commands to revised
DP power available levels.
2. Issue a start signal to another generator powering the same bus as the failed
generator, which will result in the available power being restored to its pre-fault
level in less than 60 seconds.
3. Reduce the DP and Drilling Power Available signals to reflect the reduced
online generating capacity.
The thrusters are equipped with a load ramp feature which minimizes the transient on
the electrical system following the one second shutdown of the thrusters. Power to the
effected thrusters will be gradually restored per a pre-set ramping function to prevent the
tripping of the remaining online diesel generators. The time used to bring the thrusters
back to existing levels gives the system the time needed to start and synchronize (place
online) a replacement generator.
There are four HV buses which can be connected together in a single bus configuration
or in a large number of ways, even to the point of having four independent power
systems on the vessel. The PMS should be designed to handle all these possible
configurations. To that end, the PMS function is on a per bus basis. Handling of faults
and power limiting is therefore separate for the four different buses. Accordingly, when
the Engineer separates a particular bus section for maintenance purposes it will still
have the same power protection as if it were part of the single bus configuration.

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The single bus configuration is unfortunately subject to potential blackout under

particular circumstances. It is possible for a major fault on one bus to propagate across
the bus ties and thus cause all online generators to trip offline. In relatively benign
weather conditions where one may be certain of recovery from a blackout before the
vessel has drifted far enough to damage the well, or in operations where drilling has
been suspended for other reasons and there is no risk to the well from a blackout, the
single bus configuration may be employed. However, in all other circumstances, or when
weather begins to increase, it is advisable to operate in a split bus configuration with two
equal buses, one port and one starboard. In this configuration, it is possible to maintain
location long enough to perform an orderly wellhead disconnect even after a major
equipment failure or loss of a single compartment.

Note
Safe drilling operations will normally require the power generation
and distribution system to be operated in a split bus configuration.
This may result in additional main engines being online and may
result in increased fuel usage, but protects against a blackout
caused by catastrophic failure of a main switchboard.

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5.5.3 POWER SYSTEM PROTECTION

In addition to the PMS working to prevent blackouts, the electrical distribution system is
also equipped with other protective measures. Protection devices are used to detect
abnormal conditions within the power network, and isolate sections of the system to
protect against disruption to the overall network function. Since power protection is vital
to the safety and security of DP operations, it is essential that such devices be
maintained in full working order.
The abnormal power conditions referred to might be any of the following: Earth Fault,
Overload, Short Circuit, Under or Over Frequency or Voltage, Governor or Excitation
failure. Protection devices which detect, locate, indicate and remove faults include
Fuses, Protection Relays, Timers and Circuit Breakers. In many vessels these devices
remain untested and without operation for years, but they must operate with precision on
the occurrence of a fault. In a DP vessel the correct operation is quite critical.
Power protection for generators consists of relays providing protection against a
variety of faults. An overcurrent relay protects against the results of short circuit on
the bus bar. An overload relay provides thermal protection to the generator against
consumer overloads.
Reverse Power protection is provided to prevent the diesel generator from motoring
which may result from load management or governor failure. A Loss of Excitation relay
will protect the generator against the effects of such an event. Loss of Excitation in a
generator can impose a large reactive current which may result in overloading parallel
generators. Effective tripping of the faulty generator is essential to prevent the overload
trip of otherwise healthy diesel generator.
Transformers are normally provided with overload, earth fault, and overcurrent protection
relays. Motors are protected from short circuit protection by fuses, with Motor Protection
Relays providing protection from Earth faults and Overload.

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5.5.4 BLACKOUT
In order to prevent Blackouts, it is normal to split the switchboard system into two or
more parts, connected by means of bus tie switches. Blackouts may occur in two ways.
One way stems from the correct operation of the protection system on a faulty generator
causing this machine to trip. This causes the remaining healthy diesel generators to
operate in a transient fluctuating condition while attempting to return the system to
normal. These transient conditions may cause the healthy diesel generators to trip due
to operating conditions being outside acceptable limits.
The other cause of blackout conditions arises where the installed protection devices are
unable to discriminate, resulting in the trip of one or more healthy diesel generators
because of faults relating to a malfunctioning generator. In general, the greater the
amount of connected generating capacity, the lower is the risk of total blackout.
A major consideration is that of the open or closed status of the bus tie switches
A common failure mode occurs where a governor failure in one generator leads to a
disturbance in the load sharing. That machine takes an inordinate share of the total load,
and may lead to a reverse power situation arising with another generator. If there are
only two diesel generators onboard, a blackout situation may occur, as the generator
running on reverse power will shut down (if it is otherwise healthy) on reverse current
protection, while the generator suffering governor failure shuts down on overload.
Power shortages and blackout situations will result in severe consequences to the
operation. As discussed in the previous sections a number of lines of defenses exist to
ensure continuity of power supply to essential consumers. Without this backup it is
possible for a power problem to result in total loss of thrusters, with consequent drift-off
position. Subsequent to such a problem the vital factor is the time taken to restore power
to essential circuits and services. If this time is too great then a drift-off may escalate into
a major catastrophe. It is obvious that a total blackout is to be avoided, and a number of
measures are taken to ensure such an event does not occur. These measures include
the provision of redundancy into power systems where deemed necessary, and the
provision of power protection devices and power management systems.

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5.6 DP SYSTEM RELIABILITY

DP system reliability and stationkeeping accuracy can be impacted by a number of
factors:
Inadequate thruster capacity to fully counter the environmental forces.
Insufficient power or faulty power management leading to loss of power to some
or all of the thrusters.
Bias or noise in the position reference sensors.
Controller error.
Failure or malfunctioning of any of the required equipment, and most commonly.
Operator error (e.g. inappropriate position reference selection, errors leading
black-out).

5.6.1 REDUNDANCY CONCEPTS AND REQUIREMENTS

Since the consequences of losing station can be serious (riser, BOP and wellhead
damage), DP systems must be highly reliable. As with any complex system, DP
component failures are inevitable, and it is therefore imperative to have a certain amount
of built-in redundancy. Components can be either temporarily or permanently out of
order. Temporary can mean from 10 to 20 seconds in the case of the primary reference
system, such as acoustic signal drop-outs, or it can mean the time between shipyard
visits when, for example, major thruster repair work is required. The need for high
system reliability requires that the primary reference (e.g. acoustic) is not only redundant
but is also backed by other dissimilar systems, such as satellite based systems, which
do not lose signal for the same reasons that the primary system does.
To make best use of all the redundant equipment, there must be a method of
automatically and smoothly switching (bumpless transfer) to the functioning piece of
equipment. The onboard DP computer normally monitors the equipment status and
performs most of the switching automatically. However, on some vessels, certain
switching may have to be done manually.

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5.6.2 FAILURE MODES AND EFFECTS ANALYSIS (FMEA)

A failure modes and effects analysis is the primary tool to confirm that the appropriate
level of redundancy is designed into a DP vessel. The FMEA identifies all single-point
failures and their consequences and provides valuable insight into system operation.
The FMEA should comprise both a paper study and subsequent tests during dockside
testing or sea trials to determine consequences of failures impossible to analyze on
paper. The FMEA should reflect the as-built condition of the vessel and be updated if the
vessel is modified.

5.6.3 REGULATORY AND CLASS REQUIREMENTS FOR

REDUNDANCY LEVELS
International Maritime Organization (IMO) and the International Marine Contractor's
Association (IMCA) both have published guidelines giving information on accepted
standards of redundancy levels. The IMO guidelines base the level of redundancy on 3
equipment classes. The IMCA also refers to the IMO equipment classes but provides
additional information on redundancy levels for specific equipment. Classification
Societies (Lloyds, ABS and DNV) all generally refer to compliance with these equipment
classes in their DP Class notations.
Class 1 limited redundancy (normally just a back up joystick control). Loss of
position can occur with a single failure
Class 2 redundant system No single failure, hidden failure or single inadvertent
act of mal-operation can cause significant loss of position. A full Failure Modes and
Effects Analysis (FMEA) of the DP system must also have been conducted.
Automatic bumpless changeover from primary to back-up equipment is required.
Class 3 All of Class 2 requirements plus ability to withstand the loss of a
compartment due to fire or flood. Therefore, the vessel is required have separate
engine rooms, switchboard rooms, split HV switchboards, cable runs, etc. This
implies a significant increase in installed power (and hence cost) in order to maintain
position following loss of an engine room. A dual DP control system is a class 2
requirement; a back up DP control system and necessary equipment installed in a
separate room, separated by an A60 bulkhead is required for Class 3. Changeover
to the third DP control system in a separate room has to be smooth.

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The decision of whether to opt for Class 2 or Class 3 is a balanced decision based on
the cost of purchasing a system, plus the probability of having a physical failure and the
associated risks and potential costs. Generally, as the economic consequences of a loss
of position increases, so does the level of hardware redundancy installed. It should be
noted, however, that Class 3 involves much greater complexity and some question if it
really provides greater reliability. The majority of modern, new-build MODUS have Class
3 systems while the earlier generation vessels had Class 2 systems (Table 5.5).

BODY CLASS 2 CLASS 3

IMO (International Maritime Organization) Class 2 Class 3

IMCA (International Marine Contractors Assn) Class 2 Class 3

ABS (American Bureau of Shipping) DPS 2 DPS 3

LRS (Lloyds Register of Shipping) AA AAA

DNV (Det Norske Veritas) AUTR AUTRO

BV (Bureau Veritas) MAR MARS

Table 5.5 - Classification of DP Systems

Equipment Class 2 or 3 requires a much greater level of redundancy. In diesel-electric

vessels of this type it is necessary that maneuverability be retained after "worst case"
switchboard failure. This means that if one complete section of a split switchboard is lost,
then effective positioning must be maintained using the spread of thrusters available on
the remaining intact section(s) of switchboard. The power distribution network is such
that whatever section of switchboard is lost, remaining sections supply a spread of
thrusters which is capable of positioning the vessel.

5.6.4 CONSEQUENCE ANALYSIS

Modern DP systems are equipped with software to continuously analyze the
consequences of failures and alert the operator if those consequences are serious
enough to compromise stationkeeping.

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5.6.5 SPECIFICATION, EVALUATION, AND TESTING

OF A DP VESSEL
When a DP drilling vessel is acquired, whether by new construction, by leasing an
existing operating DP vessel or by converting a moored vessel for DP operations, careful
consideration should be given to the specification, evaluation, and testing of the dynamic
positioning system. The following is a list of major tasks for general consideration. Some
of the items apply to new construction or a major conversion of an existing vessel and
hence may not be necessary when leasing a DP vessel.
1. Development of a set of comprehensive specifications based on the required DP
operations of the vessel and the anticipated environments at the potential work
areas, including class requirement (e.g. Class 2 or 3).
2. Detailed review of the proposed DP vessels with respect to their operating
features, redundancy, thruster sizing, power management, dynamic
characteristics, etc. Detailed stationkeeping and vessel motion analyses
may be required to assist in the evaluations.
3. Development of detailed factory acceptance, dockside, and sea trial test plans. In
addition to verifying the system capability, detailed and thorough testing will help
identify hidden system bugs.
4. Close monitoring of all phases of system design, fabrication, and testing.
This helps control the work schedule and identify potential problem areas
at an early stage.

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5.7 OPERATIONS

5.7.1 GENERAL REQUIREMENTS

Careful selection of a good DP vessel is not in itself sufficient to ensure safe and efficient
DP drilling operations. The use of dynamic positioning during critical operations calls for
carefully worked out operating procedures and contingency plans. It is also essential to
have reliable and dedicated communication lines between the DP control room and the
drill floor, and between the DP control room and the engine control room. Some
important additional considerations are:
Selection and training of DP operators and supervisors.
Procedures for arrival and start-up at a new location including system
check-out procedures.
Written operating procedures and contingency plans, including a clear line
of authority, not only for day-to-day operations but also for emergency
situations.
Start-up seminar to familiarize the operating personnel with the intended
drilling operation, the anticipated environmental conditions at the work
location, and the stationkeeping capability of the DP vessel.

The need to rapidly disconnect the riser from the BOP stack also imposes some special
requirements.
1. In deepwater, a multiplex BOP control system is required to both reduce time
to execute necessary controls in an emergency and to avoid large umbilicals
that are difficult to handle.
2. the need for quick disconnect requires guidelineless operation and results in
modified designs for the guide base, lower marine riser package, and BOP
stack. Also, sophisticated acoustic systems and/or TV systems are required
for reentry operations.
A well designed data recording system is required to record all of the critical data
continuously and provide the relevant information for a post-event analysis. During an
emergency situation, the operating personnel would be very busy in handling the
emergency and in restoring control of the vessel. The operator would not have time to
accurately record the details of the event which are usually very important for the post-
event analysis. This analysis is necessary to diagnose the causes of the event so that
corrective actions can be taken. This data logging system can also provide a continuous
system performance monitoring capability which is very useful for the system
maintenance and during system performance evaluations.
Daily engineering records of all the critical parameters of the drilling operations, including
stationkeeping, are also useful for maintaining a close surveillance of the operating
conditions. This helps identify any degrading equipment or system performance under
certain operating conditions. These daily records are also useful for post-event analysis
as well as documentation of the drilling operation.

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5.7.2 SYSTEM CAPACITY ASSESSMENT

DP system capability plots are used during the design of the DP vessel to decide on the
size of the thrusters needed to counteract the environments the vessel is expected to
work in. These are generally plots showing how much wind (and associated waves) a
vessel can take from various angles for a particular current and set of thrusters.
Generally a number of plots are produced for a particular current all thrusters at 100%,
all thrusters at 80%, least significant thruster failed, most significant thruster failed, worst
switchboard failure. An example is shown in Figure 5.36.

Figure 5.36 - Example DP System Capability Plot

These plots are of great use operationally as well, and being theoretical plots, they are
modified in the light of actual experience. Modern DP control systems include some
form of online capability predictor for both present and future conditions. This allows
the operator to not only monitor the prevailing situation, but also investigate some
what if scenarios.

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5.7.3 EMERGENCY DISCONNECT

A DP vessel can move off station involuntarily due to operator error, system malfunction
and/or heavy weather. In the case of heavy weather, the limits of the thruster capability
could be reached and the vessel gradually loses its position. System malfunction
resulting in unacceptable loss of position can be put into two categories: Drive-Off and
Drift-Off. Drive-off occurs when, due to either position reference system or thruster
control malfunction, the controller commands the thrusters to full power in the wrong
direction. A drift-off situation occurs when all power is lost to the thrusters in a power
loss situation and the vessel is left to drift.
Whatever the cause of such a loss of position, serious riser and BOP stack damage
could occur leading to a significant amount of downtime. Therefore, the DP computer is
often programmed to issue alarms to warn the DP operator and the driller when certain
predetermined limits of offset from the wellhead have been exceeded.
A yellow light warning alarm is typically used to indicate that the driller should start the
hang off procedure and prepare to disconnect the marine riser from the BOP stack.
When a red light disconnect alarm is indicated, the operating procedures typically
require the driller to activate the emergency disconnect sequence.
The yellow light setting (generally 2% to 3% of water-depth) is based on past experience
and water depth. This alarm should be set such that its limit is not frequently exceeded,
but allows the drilling crew sufficient time to complete the hang-off procedure
(approximately 30 seconds) prior to receiving a disconnect signal.
The criteria for setting the red light alarm (generally 4% to 6% of water depth) is
based on the rig's ability to safely disconnect the riser prior to reaching the limiting
value of any one of several critical parameters such as the ball joint angle, slip joint
stroke, tensioner stroke, riser and casing stresses. The time required to complete the
emergency disconnect sequence (EDS) varies depending on the type of BOP control
system. A typical multiplex BOP control system requires approximately 30 seconds to
complete the EDS.
Some vessels employ a blue light to indicate loss of system capability (e.g., thruster
down for maintenance).
A detailed drive-off and drift-off analysis is also conducted by skilled analysts to calculate
the time and distance traveled by the vessel under various power settings and
environmental conditions. This is done to help establish the yellow and red light alarms
at specific vessel offsets from the wellhead.

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5.7.4 OPERATOR COMPETENCY AND TRAINING

Specially trained personnel are required to operate the DP system with its sophisticated
electronic equipment. A competent and alert operator often can, when required, override
the automatic control system to prevent potentially disastrous consequences resulting
from system component failures.
In selecting DP operating personnel, it is important for the prospective operator to have
a basic understanding of electronics and a certain level of practical experience with
electronic equipment. Such an operator is also likely to provide good maintenance while
operating the DP system. Some of the better operators may develop the capability to
identify malfunctioning components and provide troubleshooting at sea when the system
fails. It is also desirable for the operator to have some knowledge and experience with
marine operations. Most vessels employ separate technicians who are responsible for
DP system maintenance.
Special training is usually required to familiarize operating personnel with the particular
DP system and equipment and provide a basic understanding of the theory of operation.
All of the system manufacturers offer relevant training courses. The operators should
also be trained to deal with simulated contingency conditions to better prepare them for
taking proper control of the vessel in a real emergency condition. Most systems offer
training simulators for operator practice on board the DP vessel.
The success of a DP operation depends highly on all of the system operators - not just
those who operate the DP control system. There are also the engine room staff who
operate and maintain the power plant and its ancillaries; the deck crew who deploy the
acoustic devices, and the technicians who maintain the DP control system. The skills
and close cooperation between all these personnel is key to the successful operation of
the vessel on DP.

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5.7.5 DP OPERATING INCIDENTS

Incidents on DP have been collected and reported by DP vessels since 1980. An
incident is defined as an unplanned loss of position due to either equipment malfunction
or operator error. Every year around 50% of such incidents have been attributed to
human error, occurring in all areas. They include the deck crew lifting the wrong acoustic
beacon, an engine room operator shutting down the wrong thruster, a DP operator
re-loading the online computer; etc.
Although the frequency of incidents on a "per year" basis has remained essentially
constant over the reporting period, the incidents "per vessel" has declined since the
actual number of vessels using DP has increased. This improvement and its expected
continuation can be attributed to several factors:
Increased awareness, when in DP control, of the importance of their actions
among all concerned.
Improved team work and communications between all operators, including those
not directly concerned (e.g., divers, driller, crane operators).
Improved design of all systems drawn from the experience of previous vessels,
particularly the design of the operator interface and the provision of more useful
information than on early systems.
Improved training and certification of all operators.
A base of experienced operators that has grown over the years.
In 1988, the operators in Europe formed a DP Vessel Owners Association (DPVOA) to
regulate their own industry and commission work on projects that were mutually
beneficial. This association has produced improvements in the industry in many areas,
but particularly in requirements for the training and certification of operators and the
design and operation of DP vessels. In 1995, the DPVOA merged with the International
Association of Diving Contractors (IADC) to form the International Marine Contractors
Association (IMCA).
In the U.S., the Marine Technology Society's DP committee is establishing an internet
website to collect DP loss-of-stationkeeping incident reports. All DP drilling contractors
are urged to participate, and the site will be available to all DP users/operators in 2001.
National authorities have also significantly contributed to these improvements in the
early days of DP in the North Sea by publishing operating guidelines (Department of
Energy, in conjunction with the Norwegian Petroleum Directorate). These guidelines
were deemed necessary after a number of serious accidents and near misses. In
addition, the classification societies produced rules for DP vessels to be built to, which
started with DNV in Norway and was soon followed by Lloyds.

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5.8 DRIVE OFF/DRIFT ANALYSIS

5.8.1 OVERVIEW
Dynamically positioned vessels occasionally experience unexpected drive off or
drift off.
A drive off occurs when the DP control system receives an erroneous signal
(such as an erroneous position signal) and rapidly increases thrust to quickly
move the vessel to the new location.
A drift off occurs when the power to the thrusters is lost and the vessel is
forced off station by the environment.
In order to cope with these unexpected emergencies in a systematic manner and
prevent damage to equipment or possible loss of the well, watch circles are established
so that key personnel know how and when to react.
T yp ica lly, a n o p e ra tin g w a tch circle (g re e n w a tch circle ) is e sta b lish e d fo r d rillin g
operations (Figure 5.37). The operating watch circle may be 1-2% water depth (WD). In
th e e ve n t th a t th e ve sse l m o ve s o u tsid e th e g re e n w a tch circle a n d p a sse s th ro u g h th e
ye llo w w a tch circle , typ ica lly 3 % W D , th e D rille r h a n g s o ff th e d rill strin g a n d m a ke s
preparations to release the riser. If the vessel continues to move off station and exceeds
th e re d w a tch circle (typ ica lly 5 % W D ), th e D rille r in itia te s th e e m e rg e n cy d isco n n e ct
sequence (ESD) which activates a series of functions in the BOP stack and then
unlatches the LMRP connector. See Section 12 for information on emergency
disconnects.

Figure 5.37 Typical Watch Circles

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DYNAMIC POSITIONING

5.8.2 WATCH CIRCLES

P la ce m e n t o f th e ye llo w a n d re d w a tch circle s a re w e ll/rig sp e cific a n d w ill d e p e n d o n
several factors such as the maximum environmental conditions anticipated at the
location, the water depth, bottom soil conditions and the riser location. Consequently, a
d rive o ff/d rift o ff a n a lysis sh o u ld b e co n d u cte d fo r e a ch w e ll.

5.8.3 ENVIRONMENT
Drive-off & Drift-off analyses will be performed by URC for both the 95%
non-exceedance and one year return period environment. Typically the
95% non-exceedance environment will provide larger operating circles yet
the probability of exceeding this environmental criteria is more likely. The one year
return period environment, on the other hand, is more conservative, yet in some
instances, the watch circles will be operationally too restrictive.

5.8.4 CRITERIA
As the rig moves off location, due to either a malfunction in the DP system (drive-off) or
a loss of power (drift-off), the riser will lean placing angles in the flex joints while the slip
joint & tensioners will stoke out to accommodate the longer distance between the rig and
the wellhead. The Drive-off/Drift-off Analysis determines how each of these components
will behave with vessel offset. The goal is to establish which of these components
reaches its operating limit first and at what corresponding vessel offset.
Table 5.6 lists the component limiting criteria used in the example.
Item Criteria
Lower Flex Joint Angle Degrees 8
Upper Flex Joint Angle Degrees 8
Slip Joint Stroke Ft (65-ft maximum stroke) 30
Riser Tensioner Stroke (65 ft Maximum stroke) 30
Table 5.6 Limiting Criteria for Glomar Jack Ryan

The limits are rig specific. The limits included in Table 5.6 where used for the Dynamine
well drilled in 3300 ft of water in Trinidad with the Glomar Jack Ryan drillship and are for
p u rp o se s o f illu stra tin g th e d rive o ff/d rift o ff m e th o d o lo g y.

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DYNAMIC POSITIONING

5.8.5 ANALYSIS PROCEDURE

Prior to performing the Drive-off/Drift-off Analysis, the Metocean Criteria must be
established for the area of operation, and a Riser Analysis must be completed to
determine the minimum riser tensions (MRT). The MRTs are based on the specific riser
configuration, water depth and maximum anticipated mud weights.
It is recommended that a Structural Casing Analysis be performed in conjunction with
the Drive-off/Drift-off Analysis to determine the stresses/loads in the wellhead connector
and structural casing.
A typical Drive-off/Drift-off Analysis will model BOP/wellhead interface as a rigid bottom
connection, which results in a conservative estimate for the lower flex joint angle and
bending moments through the BOP stack, at the wellhead and in the conductor/casing
strings. While safe, this approach will lim it th e ve sse l o ffse t to a sm a ll re d w a tch circle
since the BOP and structural casing are not allowed to deflect in the soil. The inclusion
of soil characteristics in the calculation allows for larger vessel excursions from the
wellbore centerline before the criteria limits listed in Table 5.6 are reached. This in turn
in cre a se s th e re d w a tch circle d ista n ce fro m th e w e llb o re ce n te rlin e , w h ich p ro vid e s th e
rig crew with additional time to recover from an incident before the EDS sequence must
be initiated to release the riser and LMRP.

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DYNAMIC POSITIONING

RISER ANALYSIS RESULTS FROM URC

Figure 5.38 illustrates the results of the drift off analysis for the Dynamine well drilled in
Trinidad with the Glomar Jack Ryan. Similar results were developed for the drive-off
scenario. Both results must be taken into consideration so that the most limiting watch
circles can be established.

Jack Ryan - Trinidad - 95% Environment - 17 ppg Mud - Drift-Off

15 0
Offset (%) & Angles (degrees)

10 15

Stroke (feet)
5 30

0 45

-5 60
0 50 100 150 200 250 300
Time (seconds)

Figure 5.38 Drive Off/Drift Off Analysis

Results
In each case the analyses assumes the vessel has zero offset from the desired location
when the incident starts. Figure 5.39 shows how each of the riser components and the
vessel move with time.
The trend in each line is as one would expected. The vessel offset line starts at zero as
assumed by the analysis. As time elapses the vessel gains momentum and moves off
location at an increasing rate as depicted by the exponential characteristic in the curve.
As expected the flex joint angles increase with time as the vessel moves further away.
What can also be deduced from this graph is that the lower flex joint (LFJ) angle is
increasing at a faster rate then the upper flex joint (UPJ) angle. This is because of the
high mud weight used in the analysis which is causing a sag or bow to occur in the riser.
A single curve is used for the slip joint and tensioner because of the 1:1 relationship,
where the tensioners stroke out one ft for every ft of slip joint movement. (explain why
we start at 5' - high tide? Riser configured for heave?). In this example the slip joint and
tensioners are already stroked out by 5' when the drift-off started.

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INTERPRETATION OF ANALYSIS RESULTS

For the drift-off case, lower flex joint angle is the limiting component reaching its limit of
8o within 245 seconds after the start of the incident. This corresponds to a vessel offset
of 11% of water depth. For a water depth of 3,300 ft, this converts to an offset distance
of 363 ft.

Jack Ryan - Trinidad - 95% Environment - 17 ppg Mud - Drift-Off

15 0
Offset (%) & Angles (degrees)

10 15
Flex Joint Angle Limit

Stroke (feet)
5 30

0 45
Required
Disconnect
Time

-5 60
0 50 100 150 200 250 300
Time (seconds)
Figure 5.39 Drift Off Analysis Results with LFJ
Limit
The riser and LMRP should be lifting off of the BOP at or before the time when the lower
flex joint angle reaches its limit. This sets the required disconnect time. Failure to
disconnect at or before this time would result in damage to the LFJ or other riser
components. The emergency disconnect sequence typically requires 45-60 seconds to
complete a series of functions before the command is given to unlatch the LMRP
connector. This sequence of functions is discussed in more detail in Section 12.

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DYNAMIC POSITIONING

As shown in Figure 5.40, the EDS is assumed to take 45 seconds, and this amount of
time is subtracted from the required disconnect time. Therefore the EDS must be
initiated no later than 200 seconds after the start of the drift-off incident. This
corresponds to a vessel offset of 7.9% WD, which establishes the maximum setting point
for the red watch circle.
The yellow watch circle is established by subtracting an additional 60 seconds which is
the time needed by the driller to hang-off the drill pipe before the EDS can be initiated.
As shown in Figure 5.40 the maximum setting for the "yellow" watch circle for the drift-
off case is 4.3% WD.

Jack Ryan - Trinidad - 95% Environment - 17 ppg Mud - Drift-Off

15 0
Offset (%) & Angles (degrees)

10 15

Stroke (feet)
5 30

0 45
Required
60 sec for 45 sec Disconnect
Driller hangoff for EDS Time

-5 60
0 50 100 150 200 250 300
Time (seconds)

Figure 40 Drift Off Analysis Results with Watch Circle Criteria

T h e g re e n w a tch circle sh o u ld b e se t a t 1 .0 % o f W D . A D P ve sse l sh ould be able to

maintain station within 10 meters of the wellbore location.
Finally, a similar interpretation must be made of the drive-off results to determine which
of the two scenarios is more limiting. After establishing the disconnect criteria, it is
recommended that these offset results be fed into a Structural Casing or Riser Weak
Point Analysis to determine if the bending moments at the wellhead connector and in the
casing are within allowable limits.

5.9 REFERENCES
Dynamic Positioning, David Bray, Oilfield Publications Limited, April 2000

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MOORING DESIGN AND OPERATIONS

6
Section

6.0 MODU MOORING DESIGN AND OPERATIONS

OBJECTIVES
On completion of this section, you will be able to:

State the major functions of a mooring system for a mobile offshore drilling unit.

Identify the principal elements of a mooring system.

State the advantages and disadvantages of all-wire, all-chain, and chain/wire rope
combinations.

State variables affecting mooring performance.

Describe the steps in a quasi-static mooring analysis

State maximum line tension and approximate offset criteria for drilling and standby
conditions.

State the basis for establishing the anchor test pull tension.

List the requirements for a mooring analysis.

Describe normal procedures for anchor deployment and retrieval.

List the steps to reduce mooring loads during a storm.

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MOORING DESIGN AND OPERATIONS

CONTENTS PAGE

6.0 MODU MOORING DESIGN AND OPERATIONS ............................................................................. 1

OBJECTIVES ..................................................................................................................................... 1
CONTENTS........................................................................................................................................ 2
6.1 INTRODUCTION ............................................................................................................................... 4
6.2 PRINCIPLES OF MOORING ............................................................................................................. 5
6.3 FUNCTION OF A SPREAD MOORING SYSTEM............................................................................. 7
6.4 MOORING HARDWARE OVERVIEW ............................................................................................. 10
6.4.1 RIG COMPONENTS: ............................................................................................................ 11
6.4.2 MOORING LEG COMPONENTS ............................................................................................. 21
6.5 MOORING HARDWARE ................................................................................................................. 23
6.5.1 CONVENTIONAL DRAG EMBEDMENT ANCHORS ................................................................... 23
6.5.2 ANCHORS CAPABLE OF WITHSTANDING VERTICAL LOADS .................................................. 30
6.5.3 MOORING CHAIN ................................................................................................................ 31
6.5.4 MOORING WIRE ................................................................................................................. 36
6.5.5 CHAIN CONNECTING HARDWARE ........................................................................................ 39
6.5.6 KENTER LINKS ................................................................................................................... 40
6.5.7 C CONNECTING LINK ...................................................................................................... 41
6.5.8 R AMFOR CONNECTING LINK ........................................................................................... 42
6.5.9 BRUCE LINK ...................................................................................................................... 43
6.5.10 WIRE ROPE CONNECTING HARDWARE ................................................................................ 44
6.5.11 MISCELLANEOUS CONNECTIONS AND FITTINGS USED IN MOORING SYSTEMS....................... 48
6.6 MOORING EQUIPMENT/INSPECTIONS ........................................................................................ 52
6.6.1 MOORING LINE COMPONENTS ............................................................................................ 52
6.6.2 WINCHING EQUIPMENT ....................................................................................................... 54
6.6.3 MONITORING EQUIPMENT ................................................................................................... 55
6.6.4 INSPECTION FREQUENCY.................................................................................................... 55
6.7 SPREAD MOORING SYSTEM TYPES ........................................................................................... 56
6.7.1 ALL WIRE ROPE SYSTEMS ................................................................................................. 57
6.7.2 ALL CHAIN SYSTEMS ......................................................................................................... 57
6.7.3 CHAIN/WIRE ROPE COMBINATION SYSTEMS ....................................................................... 57
6.7.4 THE BASIC CATENARY SHAPE ............................................................................................ 60
6.7.5 SPREAD MOORING PATTERNS ............................................................................................ 62
6.7.6 DIFFERENCES BETWEEN PERMANENT AND TEMPORARY MOORINGS ................................... 63
6.8 DESIGN AND ANALYSIS ............................................................................................................... 65
6.8.1 PURPOSE .......................................................................................................................... 65
6.8.2 VARIABLES AFFECTING MOORING PERFORMANCE .............................................................. 66
6.8.3 VESSEL ENVIRONMENTAL FORCE COEFFICIENTS ................................................................ 67
6.8.4 MOORING ANALYSIS METHODS .......................................................................................... 76
6.8.5 DESIGN CRITERIA .............................................................................................................. 80
6.8.6 INFORMATION REQUIRED FOR MOORING ANALYSIS: ............................................................ 86
6.8.7 RESULTS OF THE MOORING ANALYSIS ................................................................................ 91
6.9 ANCHOR HANDLING VESSELS (AHV) ......................................................................................... 92
6.10 MOORING DEPLOYMENT PROCEDURE ..................................................................................... 95
6.10.1 MOVING RIG ONTO LOCATION ............................................................................................. 96
6.10.2 ANCHORING SEQUENCING .................................................................................................. 97
6.10.3 PROOF LOADING/OPERATING TENSIONS........................................................................... 101
6.11 ANCHOR RECOVERY PROCEDURES ........................................................................................ 102

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MOORING DESIGN AND OPERATIONS

6.12 SPECIAL OPERATIONS/NEW TECHNOLOGY ........................................................................... 103

6.12.1 PRE-SET MOORING SYSTEMS........................................................................................... 103
6.12.2 INSERT WIRE MOORING SYSTEM ...................................................................................... 104
6.12.3 LINE MANAGEMENT ......................................................................................................... 105
6.12.4 SAFE ZONE...................................................................................................................... 106
6.12.5 SUCTION ANCHOR MOORING ............................................................................................ 107
6.12.6 SEPLA ........................................................................................................................... 109
6.12.7 VERTICAL LOAD ANCHOR (VLA) ...................................................................................... 113
6.12.8 SYNTHETIC FIBER ROPE................................................................................................... 115
REFERENCES ........................................................................................................................................... 116

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MOORING DESIGN AND OPERATIONS

6.1 INTRODUCTION
Stationkeeping, or the ability of a vessel to hold position against the effects of the
environment, either using moorings or Dynamic Positioning (DP), is a critical part of the
drilling operation. The state-of-the-art in stationkeeping technology has advanced
considerably in recent years. Deepwater, ten years ago, was considered about 3,000 ft.
In 2001, exploration drilling was conducted from a DP vessel in nearly 10,000-ft of water and
from a moored vessel in 9,000 ft of water.
This chapter focuses on the basics of spread mooring systems. Topics include how a
mooring system works, mooring analysis, and information on mooring hardware. Mooring
system operation and installation will also be covered in this section.

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MOORING DESIGN AND OPERATIONS

6.2 PRINCIPLES OF MOORING

Mobile Offshore Drilling Units (MODUs) can be held on station with either a multi-point spread
system or a system that allows the vessel to weathervane (change its heading) into the
direction of the prevailing environment. A multi-point spread mooring system does not allow
the vessel to appreciably change its heading. Since most semisubmersibles are shaped so
that the imposed environmental forces do not substantially differ with heading, those currently
in operation use spread moorings without weathervaning capability. Figure 6.1 shows a
perspective view of a typical semisubmersible MODU equipped with an eight point spread
mooring system (sometimes a nine, ten, or twelve leg system is used depending on the type
of vessel).

Figure 6.1 Semisubmersible with a Catenary Spread Mooring System

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MOORING DESIGN AND OPERATIONS

Semisubmersibles spread moorings for up to about 5,000 ft water depth and either DP
or special preset moorings in greater water depths. All vessels used for long-term production
operations are moored, and the majority of vessels used for development drilling tend to
be moored.
For the purpose of this section, only multi-point non-weathervaning spread moorings are
addressed. DP systems are discussed in Section 5.0.

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MOORING DESIGN AND OPERATIONS

6.3 FUNCTION OF A SPREAD MOORING SYSTEM

A vessel is said to be moored if it is connected to the seafloor with a multi-point spread
mooring system. In most cases, in water depths up to about 5,000 feet, Catenary Spread
Mooring (CSM) systems are employed. The differences in these systems are discussed later.
Most spread moored drilling vessels use an eight leg mooring system, but some also use
nine or ten leg systems (depending on the design).
T he prim ary function of a vessels m ooring system w illbe to hold the vesselon station w ithin
specified tolerances in operating and storm conditions so it may perform the function for
which it was designed. As the vessel is subjected to forces caused by wind, wave and
current, it will tend to displace (or offset) from a centrally located position within the mooring
spread. As it offsets, a restoring force is created that limits the extent of vessel
displacement. This basic mooring principle is shown in Figure 6.2. The restoring force is
generated by the changes in tension among the mooring lines; the more it displaces, the
more tensions adjust until balanced with the environmental loads. As the forces caused by
the environment are not generally constant in value or direction, the rig will tend to wander in
amount and direction of the offset.

Figure 6.2 - Forces on moored MODU

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MOORING DESIGN AND OPERATIONS

A secondary mooring system function is to allow adjustment of the horizontal position of the
vessel, through manipulation of the mooring lines. Adjustment may be necessary to
counteract offsets due to weather and enable drilling, workover or well maintenance
operations to be continued (e.g., in loop current conditions). In certain applications, this
horizontal movement will also allow operations to be continued in extreme conditions.
Horizontal vessel movements are also used when handling heavy loads as a risk mitigation
should the load be dropped.
The offset limits specified for a particular vessel mooring will largely depend on the function it
will perform and/or the limiting weather conditions in which the function must be performed.
With vessels engaged in drilling, the drilling riser design generally governs how far the vessel
can offset before causing operational problems or overstressing the ball/flex joint. Design
offset limits are usually somewhere between 2% and 4% of water depth while drilling and
between 8% and 10% with the riser connected in a non-rotating mode.
Each mooring line exerts a horizontal and vertical load on the vessel. The sum of the
horizontal tensions counteracts the environmental loads on the vessel. The tension in each
mooring line is established through a combination of the horizontal forces (mean
environmental loads) to which the rig is being subjected and the mooring component weight
(chain and/wire) suspended off the seafloor plus any vertical forces at the seafloor (vertical
component). When a rig is first moored on location, an initial tension is imposed on the
mooring legs to set the anchors. This tension is known as the test load tension. After all the
anchors are test loaded, the tension in the mooring lines is reduced to an operating tension
or pretension. The greater the pretension, the more suspended line will be picked up off the
seafloor. Higher pretensions tend to make the mooring system stiffer, i.e. restoring forces
increase faster with offset.
Obviously, the tension on the windward mooring system legs (the legs facing toward the
direction of the prevailing environment) will be greater than that imposed on the leeward
legs (the legs directed away from the environment). The amount of tension in the windward
legs is also impacted by the tension in the leeward legs since tension in the windward legs
has to offset the tension in the leeward legs. This is why operating tensions in the leeward
mooring legs are often reduced in storm or high current conditions, plus slackening leeward
lines also reduce vessel offset. If a rig is abandoned due to the approach of a storm, tensions
are often reduced in all legs for the same reason.
The performance of a mooring system is impacted by the stiffness of each leg. Stiffness of a
mooring leg is a function of mooring line equipment, geometry, pretension, and mooring line
elasticity. Stiffness can be defined as the tangential slope of a restoring force curve at a given
rig offset. This curve is known as the Load Excursion Curve. An example of a Load
Excursion Curve is shown in Figure 6.3, showing the restoring force of a single mooring leg
(Line No. 5) with the environment directed toward the rig at 245 related to true North. It also
shows the restoring force of the combined mooring system (solid line). Figure 6.4 shows a
plan view of the mooring pattern for the particular rig in question explaining the location of line
No.5 and the direction of the environment (in the quartering direction).
Before a detailed look at the environmental loads on the mooring system can be made, a
description of the components of this system should be discussed. The following section
gives an overview of the elements that make up the mooring system.

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 MOORING DESIGN AND OPERATIONS
Load / Vessel Excursion
1000

Mooring Line #5
Total System Restoring Force
Stiffness: Slope of Tangent Line
800 Mooring Stiffness = 2200 lbs/ft

Mean Environmental Load = 640 kips

Load / Tension, kips

600

400

#5 Tension = 550 kips

200

0
0 50 100 150 200 250 300 350

Figure 6.3 Load Excursion Curve Mean Offset Distance, ft

F igure 6 .4 S pread M ooring Pattern (note line # 5 at 4 oclock)

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MOORING DESIGN AND OPERATIONS

6.4 MOORING HARDWARE OVERVIEW

A mooring system can be split into a number of elements that will differ according to the
mooring type chosen and whether it is conventionally deployed from the rig or the moorings
are preset and the vessel attached later. This section gives an overview of the mooring
elements.
For the purposes of this section, a conventional combination wire/chain system is chosen to
explain the various elements. Figure 6.5 illustrates the various system elements.

Winch/Windlass
s

Waterline

Fairlead

Mooring Wire
Suspended Length

Anchor / Chain
Chain / Wire Connection
X-Over Connection
Grounded Chain

Mud Line
Chain Touchdown Point Drag Embedment Anchor

Figure 6.5 Catenary Mooring Components

The basic elements can be split into two major categories, as follows:

Rig Components elements normally included or mounted on the rig;

Mooring Leg Components elements normally installed off the rig.

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MOORING DESIGN AND OPERATIONS

6.4.1 RIG COMPONENTS:

Wire Winches and/or Chain WindlassesGenerally, the term winch refers to the machinery
used to spool and store wire rope, and a windlass is used to control the movement of chain.
The prime mover used to drive winches and windlasses aboard drilling vessels is normally an
AC, DC, or hydraulic motor. The control systems may be local (winch house) or remote (on
the bridge) or both. Braking systems include band brakes, disc brakes, and dynamic motor
brakes. The dynamic brake helps control payout of the wire/chain during anchor deployment
operations.
WINDLASS
The windlass consists of a power-driven wildcat or sprocket designed for only one size of
chain. Use of a specific size and type of chain is necessary because a different pitch length,
bar diameter, or width of the chain links would prevent the chain from properly meshing with
the wildcat sprockets. The chain is typically stored directly below the windlass in a chain
locker. The chain leaves the chain locker goes over the windlass sprocket (one rap) and then
continues overboard to the fairlead. C hain sizes range from 2 to 3 -3/16. T he w indlass has
a brake holding powers from 1,400,000-200,000 lbs and a stall pull of 730,000-235,000 lbs.
Figures 6.6, 6.7, and 6.8 illustrate a windlass system.

Figure 6.6 - Side view of Windlass

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MOORING DESIGN AND OPERATIONS

Chain going over sprocket

Band Brake

Drive Linkage to
second Windlass
Hydro Dynamic Brake

Figure 6.7 - Rear view of Windlass

Figure 6.8 - Chain and Sprocket

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MOORING DESIGN AND OPERATIONS

WINCH
A winch is designed to provide a means for spooling and storing line. Although the sizes and
types of winches vary, their basic design and function are similar. The winch drum can
support multiple sizes of wire rope. Therefore, if the wire rope is changed to an alternate size
than was originally used, the drum will not need to be modified. However, the level winding
sheave may need upgrading. The draw back to a single drum winch is that as the number of
wire wraps increases on the drum, the maximum line tension capability decreases (see
Figure 6.15). W ire rope sizes range from 2 to 3 -1/2. T he m aximum length is limited by the
drum size. The lengths range from 3,000 - 6,000-ft. The winch has a brake holding powers
from 830,000 - 300,000-lbs and a stall-pull of 700,000 - 320,000 lbs. Figures 6.9 and 6.10
illustrate the winch system.

Figure 6.9 - Winch System

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MOORING DESIGN AND OPERATIONS

Figure 6.10 - Front View of Winch

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MOORING DESIGN AND OPERATIONS

COMBINATION WINCH/WINDLASS
On deepwater rigs, a combination dual drum traction winch with storage reels is often used.
The combination wire/chain system is built into a combined unit for each leg. Some of the
more modern rigs sometimes include wire winches and/or storage reels in the lower hull to
reduce deck load. The wire is directed from the lower hull location to the deck level, via
sheaves. Figures 6.11, 6.12, and 6.13 illustrate a dual traction winch/windlass combination,
notice that the two are coupled together with a single drive train. On the combination system,
the chain and wire sizes, wire length, and line pull capabilities are the same as the
conventional system. The traction winch can handle up to 3-7/5" wire rope and since it
utilizes a storage reel, lengths in excess of 10,000-ft are common. An another important
feature of the traction winch is its ability to provide constant pull since the wire is always on
the bottom wrap.
Wire or chain tension measuring devices generally employ strain gauges, load cells, or
amp/load conversion tables. Load cells or stain gauges are typically located under the
winch/windlass frame. The tension reading for the winch/windlass can be converted from the
amps applied the motor in order to initiate motion. See Figure 6.14. These systems should
be calibrated before running anchors.

Winch/Windlass #1

Winch/Windlass #2

Storage Reel #1

Storage Reel #2

Figure 6.11 Deck Layout for Combination Traction Winch/Windlass System

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MOORING DESIGN AND OPERATIONS

Dual Drum Traction Winch Windlass Chain Sprocket

Drive Train
Storage Reel
Figure 6.12 - Close-up Picture of Combination System

F igure 6 .1 3 C om bination T raction W inch/W indlass S ystem

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MOORING DESIGN AND OPERATIONS

Skagit / Smatco TMWW 375 / 52

Traction Winch

800

700 Low Gear Stall

High Gear Stall
600

500
Tension, Kips

400

300

200

100

0
0 200 400 600 800 1000 1200 1400 1600
AMPS

Figure 6.14 Figure 6.14 Load vs Amp Chart for Traction Winch

Winch Drum Loading

Example AHV Drum Barrel = 36" diameter
Tension capacity decreases
as wire layers increase due
to longer moment arm

@ maximum torque

Load capacity with wire on first

layer (bare drum) = 550 kips
Flange = 102" diameter

Load capacity with wire on outer

layer = 550 x 36 / 102 = 194 kip s
65% Reduction

Figure 6.15 Winch Drum Loading

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MOORING DESIGN AND OPERATIONS

Chain Lockers - These are chain storage compartments usually mounted within the lower
part of the columns or underdeck.
Chain Stoppers: Stopper is designed to Chain Windlass Pawl
take the full load of the mooring line and
thus direct the load off the windlass. The
stoppers are separate from the windlass
and are either a set of hydraulic rams or
steel plate. With the stopper engaged,
routine maintenance of the windlass can
be safely performed.
Pawl: The pawl is a mechanical break
that is part of the winch or windlass,
usually located on the outer rim of the
drum. The pawl is designed to take the
full load of the mooring line and is a
back up to the drum brake (Figures
6.16 and 6.17). Figure 6.16

Band Brake 3-3/4 W ire R op e

P aw l U n en gaged

Figure 6.17 - Front View of Traction Winch/Windlass Combination System

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Wire and/or Chain Fairleads - These allow the chain

and/or wire mooring sections to be led from the winch or PCC
windlass and away from the rig. Usually the fairleads are
specified for each leg. The fairleads are normally
designed to rotate in the horizontal plane to allow for axial
angular changes where the mooring lines enter the
fairleads, to account for surge, sway and varying watch
circle of the rig. Fairleader

Anchor Bolsters. - These are usually steel tubular

structures welded to the rig below the lower hull fairleads
to allow the anchors to be racked when the rig is in transit
from one location to another. The bolster also protects
the pontoon from the wire/chain during mooring
deployment/recovery. The bolster is also called a Bolster
cowcatcher, since it resembles the frame fixed on front of
locomotives that absorbed the impact associated with
hitting a cow, if one happened to wander on the track.
It is important in deepwater mooring to consider contact
of the mooring line with the bolster during deployment, Figure 6.18
retrieval, and operation. The angle of a line between the
bolster edge and the fairlead is used in the analysis
(Figures 6.18 and 6.19).

column

fairlead
angle
= 37
bolster

pontoon
Figure 6.19 - Chain Fairlead and Fairlead/Bolster Angle

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Permanent Chain Chasers (PCCs) - PCCs are devices used during anchor deployment and
recovery, normally stored or secured to the rig when the rig is moored. The PCC consists of a
chase collar, 10 to 20 ft of chain, and 90 to 100 ft of wire rope. The chain from the anchor
runs through the chase collar, therefore the ID of the collar should be large enough to pass
any connecting links or swivels (Figure 6.20).

Anchor Shank

Anchor Shackle

Wide Body Chaser

Figure 6.20 - Permanent Chain Chaser

Pendant Lines: Pendant lines were used on the first moored MODUs to set and recover the
anchors. They were similar to the PPC device except that once the anchor had been set, the
pendant line would be connected to a buoy and left at the anchor location. This worked well
in shallow water. Currently, few rigs are outfitted with pendant lines, and most have gone to
the PCC instead.

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Tri-Link This connection is used in a wire/chain system and enables the last section of
chain to be connected to the first section of wire (Figure 6.21). The operational
procedure for making this crossover is in Section 6.8.2.

Windlass Winch
Winch Side
Windlass Side

Chain / Wire Connector

Tri-Link

Crossover
Platform Chain / Wire Connector
Tri-Link

Fairlead

Figure 6.21

6.4.2 MOORING LEG COMPONENTS

Catenary Section (or suspended section) of Wire and/or Chain - This will usually be
chain on rigs designed for shallow water. For deeper water combination/wire chain systems,
the system will be mainly wire with some chain suspended off the seafloor.
Ground Section - In most cases, this will be chain. Due to cyclic loading on the mooring
system, the grounded line will move (vertically & horizontally) across the seafloor. This motion
can reduce the life of wire mooring lines (sand/soil embedding in the wire strands resulting in
internal abrasion). Therefore, enough chain should be run to ensure that the wire does not lie
on the bottom during operating conditions.
Anchor System - Various pile and drag embedment anchor types exist, depending on
whether the specified mooring system is a catenary spread mooring or taut leg mooring,
where horizontal or vertical anchor loads may be experienced.
Wire and/or Chain Connectors (sometimes referred to as Connection Jewelry) - Many
connector types exist, depending on the service requirements and hardware type being
connected together.

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Connectors: There are basically five types of connectors used in the mooring line:
1. Shackle: It consists of a bow, which is closed by a pin. A shackle is typically used to
connect the shank of the anchor to the mooring chain.
2. C o n n e ctin g lin k K e n te r typ e : T h e co n n e ctin g lin k ke n te r typ e is m o st co m m o n ly
used for the connection two pieces of chain mooring line, where the terminations of
the two pieces have the same dimensions (i.e. the 2 eyes of the link are the same
size). The kenter links have a shorter fatigue life that the chain.
3. C o n n e ctin g lin k C typ e : L ike th e ke n te r lin k, th e C lin k is u se d fo r th e co n n e c tion of
two pieces of mooring line with terminations that have the same dimensions. The
main difference between the kenter and C link is the way that the connector is
opened and closed. The C-link is also easier to disassemble than the Kenter link
4. Connectin g lin k P e a r sh a p e d : T h e p e a r sh a p e d lin k is u se d fo r th e co n n e ctio n o f tw o
pieces of mooring line with terminations that have different dimensions.
5. Swivels: A swivel is used to relieve the twist and torque that builds up in the mooring
line and is important in a chain/wire combination system due to the torque in the wire
under high tension. The swivel is often placed a few links from the anchor point
and/or between the chain-wire crossover point. Under heavy loads, conventional
swivels may not be able to rotate, thus allowing the torque to twist or knot the chain.
Newly designed swivels are able to function under heavy loads due to a special
bearing surfaces inside the swivel that reduces the friction.
Spring Buoy: Spring Buoys are surface or subsurface buoys that are connected to a
catenary mooring line. In deepwater, they help reduce the weight of the mooring lines.
They also reduce the effects of line dynamics in deepwater (dampen reactionary forces).
They can also be used to hold up the mooring line if it crosses over pipelines or other
subsea equipment.
Piggy-Back: Is the practice of using two or more anchors in order to obtain holding
power greater than can be achieved with one only. Typically, the PCC wire from the first
or lead anchor is used to set the second or outboard anchor.
The mooring leg components will be discussed in detail in the Section 7.

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6.5 MOORING HARDWARE

This section details components and equipment used in mooring systems and
operations.
6.5.1 CONVENTIONAL DRAG EMBEDMENT ANCHORS
A Drag Embedment Anchor (DEA) is an anchor that achieves holding capacity through drag
embedment techniques after deployment to the seafloor. The embedment is obtained by
heaving at the surface on the mooring line to which the DEA is connected. DEA holding
capacity is defined as the maximum capacity the anchor can withstand at a constant pull.
Generally, when a DEA starts to slip, its holding capacity will drop. Holding capacity is a
function of:

Anchor Type Fluke area, fluke angle, fluke shape, anchor weight, tripping palms,
stabilizer bars, etc. Figure 6.22 shows components of a modern DEA.

Behavior During and After Deployment Opening of the flukes, penetration of the
flukes, depth of burial of the anchor, stability of the anchor during dragging, soil
behavior over the fluke.

Figure 6.22 Stevpris Drag Embedment Type Anchor

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Figure 6.23 Bruce FFTS

Figure 6.24 Bruce TS

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D ue to the w ide variation of im pacting factors, the prediction of an anchors holding pow er is
difficult. Exact holding power can only be determined after the anchor is deployed and test
loaded.
Anchor performance data for the specific anchor type and soil condition should be obtained if
possible. In the absence of credible anchor performance data, Figure 6.26 and 6.27 may be
used to estimate the holding power of anchors commonly used to moor floating vessels.
Figures 6.26 and 6.27 are reproduced from Techdata sheet 83-08R except that the holding
capacity curves for the Moorfast (or Offdrill II) and Stevpris anchor were upgraded. The
upgrading of these two curves was based on model and field experience acquired in recent
years. The design curves presented in these two figures represents in general the lower
bounds of the test data. The tests used to develop the curves were performed at a limited
number of sites. As a result, the curves are for use in generic soil types such as soft clay and
sand. Recent studies indicate, however, that several parameters such as soil strength profile,
lead line type (wire rope versus chain), cyclic loading, and anchor soaking may significantly
influence anchor performance in soft clay. In addition, some high efficiency anchors have
demonstrated substantial resistance to vertical load in soft clay. Furthermore, there are new
version of high efficiency anchors that are not covered by these two figures. These issues are
addressed in Appendix B of API RP 2SK.
Note: The holding capacity curves in Figures 6.26 and 6.27 do not include a safety factor.
The allowable safety factors for anchor loads are substantially lower than those for line
tensions. The rationale is to have the anchor moved instead of the mooring line broken in the
event of mooring overload. Anchor movements of the most loaded lines would normally
cause favorable redistribution of the mooring loads among the mooring lines resulting in
lower line tensions and anchor loads for these lines. This would help the mooring system
survive storm environments exceeding the maximum design environment.

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DEAs have been used as long as people have sailed the seas. Many types have existed over
the years. Today there are two categories used by vessels:
1. Fixed fluke types.
2. Adjustable fluke types.
Figure 6.25 overviews of the DEAs commonly manufactured until the 1980s. Several of
these are still in use, e.g. Moorfast, Offdrill II, Bruce TS, Flipper Delta. Fixed fluke types were
developed specifically for drilling and construction operations where ultra-high holding
capacity is important. Until about 1970, the majority of DEAs were constructed from cast
steel. Currently, the fixed fluke, twin shank types are all fabricated from plate steel, reducing
weight per fluke area and making the anchors much more efficient.

Figure 6.25 - Anchor Types commonly used through the 1980s

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Figure 6.25 - Anchor Holding Capacity in Mud or Soft Clay

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Figure 6.26 - Anchor Holding Capacity in Sand or Hard Clay

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Industry standards for the design of mooring systems (API RP 2SK) allow an angle of 5 at
the seafloor in the intact line condition and 10 in the damaged line condition for Deep
Embedment Anchors.
The majority of DEAs have the ability to adjust the fluke angle in different soil types. Figure
6.28 shows an explanation of fluke adjustment on the modern DEA (Bruce flat-fluke type).

Figure 6.28 - Setting Mechanism for Bruce DENLA Anchor

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6.5.2 ANCHORS CAPABLE OF WITHSTANDING VERTICAL LOADS

Tension Leg Moorings (TLMs) require anchors that are capable of withstanding vertical loads.
Anchoring options for vertical load MODU applications include the following:
Suction Embedment Anchor (SEA)
Vertically Loaded Anchor (VLA)
Suction Embedment Plate Anchor (SEPLA)
Conventional high holding power DEAs are not an option in many cases because of their
inability to withstand large vertical loads (beyond angles of 18 at the seafloor). In some
cases, for technical or cost reasons, SEAs, VLAs and SEPLAs are viable options for MODU
TLMs. SEAs have been used to moor a floating drilling rig at several locations between 6,000
and 8,000 ft water depth in the Gulf of Mexico. SEPLAs have been used at several locations
up to about 6,000 ft and VLAs have been used for mooring TLMs in Brazil. See Section 6.12
for more details on these anchors.

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6.5.3 MOORING CHAIN

Chain for offshore mooring use is constructed from a steel bar of specified diameter and
material composition. The chain link is formed by heating and bending the bar using special
equipment. The link is then joined to the next link and closed using electric flash-butt welding
techniques, with an internal stud added using a special hydraulic press. A typical chain
manufacturing process is shown in Figures 6.29 through 6.33. The stud is introduced to
ensure the chain maintains its shape, especially when being heaved over windlass lugs (or
wildcats) under high loads, as typically seen during mooring operations on a floating drilling
rig. The studs also tend to reduce the chance of the chain knotting or tangling in chain lockers
or when stored in a pile. Chain manufactured in this method is known as studlink chain.

Figure 6.29 Chain Manufacturing Link Heating and Shaping

Figure 6.30 - Chain Manufacturing - Flash Welding Link

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Figure 6.31 & 6.32 - Chain Manufacturing - Stud Insertion & Flash Butt Weld Grinding

Figure 6.33- Chain Manufacturing - NDT & Proof Loading

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CHAIN GRADES
Until the 1960s, studlink chain had been provided for ship anchor chain using Grade 1 and 2
steel bar stock, based on the amount of strength in the chain required. The U.S. Navy
required higher strength chain, and a Grade 3 was introduced. Baldt, a supplier of chain to
the U.S. Navy, also introduced a di-lock type that had higher strength than Grade 3. Offshore
drilling required chain with greater strength than Grade 3. Due to capacity problems at Baldt,
two chain manufacturers in Sweden (Ramnas and Lujsnes) were approached to make high
strength chain as an alternative to the di-lock. This heralded the introduction of Oil Rig Quality
(ORQ) chain that was specifically intended for use by MODUs. API introduced a standard for
the manufacture of the ORQ chain (API RP 2F). Other chain manufacturers (Vicinay,
Hamanka, Nippon) also developed the capability to make ORQ chain.
In the early 1980s, all the chain manufacturers developed a still higher strength chain initially
known as Grade 4 (or K4), which was about 25% stronger than ORQ chain. Due to
manufacturing problems (mostly during heat treatment), all the chain manufacturers
experienced K4 chain failures between 1982 and 1984. In 1985, the Norwegian Classification
Society, DNV, introduced a new chain specification (Specification for Offshore Chain C.N 2.6)
that dealt with the manufacturing and quality control aspects of high strength chain, including
bar stock supply. This specification introduced the NV K3 and NV K4 (rig) grades. The
American Bureau of Shipping (ABS) followed with their own specification (Guide for
Certification of Offshore Chain) that introduced RQ 3 and RQ 4 Grades (similar to NVK 3 and
NVK 4). In 1993, a new document was introduced by the International Association of
Classification Societies (IACS) known as W.22. This document, updated in 1999, is the main
guide for chain manufacture and quality control today. All the classification societies now
have similar documents.
Since the introduction of the NVK and RQ chain grades, there have been only a few failures
of the higher strength grades, mainly because of localized fatigue problems.
The breaking strength for various sizes and grades of mooring chain are listed in Table 6.1

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MOORING DESIGN AND OPERATIONS

Diameter Dimensions Air Weight (lbs/ft) Water Weight (lbs/ft) B re a kin g T e st L o a d B T L (kip s)
(in) Length (in) Width (in) Stud Studless Stud Studless ORQ ORQ + 20% Grade 4
2 12.0 7.2 38 35 33.0 30.4 489 587 635
2 3/16 13.1 7.9 45 42 39.1 36.5 579 695 752
2 1/4 13.5 8.1 48 44 41.7 38.3 611 733 793
2 5/16 13.9 8.3 51 46 44.3 40.0 643 772 835
2 3/8 14.3 8.6 54 49 46.9 42.6 676 811 878
2 1/2 15.0 9.0 59 54 51.3 46.9 744 893 967
2 5/8 15.8 9.5 65 60 56.5 52.2 815 978 1,059
2 11/16 16.1 9.7 69 63 60.0 54.8 852 1,022 1,106
2 3/4 16.5 9.9 72 66 62.6 57.4 889 1,067 1,154
2 7/8 17.3 10.4 79 72 68.7 62.6 965 1,158 1,253
3 18.0 10.8 86 78 74.8 67.8 1,044 1,253 1,356
3 1/16 18.4 11.0 89 81 77.4 70.4 1,084 1,301 1,408
3 1/8 18.8 11.3 93 85 80.9 73.9 1,125 1,350 1,461
3 3/16 19.1 11.5 97 88 84.3 76.5 1,167 1,400 1,515
3 1/4 19.5 11.7 100 92 86.9 80.0 1,209 1,451 1,570
3 5/16 19.9 11.9 104 95 90.4 82.6 1,251 1,501 1,625
3 3/8 20.3 12.2 108 99 93.9 86.1 1,295 1,554 1,681
3 1/2 21.0 12.6 116 106 100.9 92.2 1,383 1,660 1,796
3 9/16 21.4 12.8 121 110 105.2 95.6 1,428 1,714 1,854
3 5/8 21.8 13.1 125 114 108.7 99.1 1,473 1,768 1,913
3 3/4 22.5 13.5 134 122 116.5 106.1 1,566 1,879 2,033
3 7/8 23.3 14.0 143 130 124.3 113.0 1,660 1,992 2,156
3 15/16 23.6 14.2 147 135 127.8 117.4 1,708 2,050 2,218
4 24.0 14.4 152 139 132.1 120.8 1,756 2,107 2,281
4 1/8 24.8 14.9 162 148 140.8 128.7 1,855 2,226 2,408
4 1/4 25.5 15.3 172 157 149.5 136.5 1,955 2,346 2,538
4 3/8 26.3 15.8 182 166 158.2 144.3 2,057 2,468 2,671
4 1/2 27.0 16.2 192 176 166.9 153.0 2,160 2,592 2,805
4 5/8 27.8 16.7 203 186 176.5 161.7 2,265 2,718 2,941
4 3/4 28.5 17.1 214 196 186.1 170.4 2,372 2,846 3,080
4 7/8 29.3 17.6 226 206 196.5 179.1 2,480 2,976 3,220
5 30.0 18.0 238 217 206.9 188.7 2,589 3,107 3,362

Table 6.1 - Chain Data

Note: In the absence of more accurate data, the following approximations can be used:
Let D = Nominal diameter of chain in inches

ORQ breaking strength (kips) = 116 D2

Grade 4 breaking strength (kips) = 151 D2

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CHAIN FAILURE
A major problem with studlink chain is that the studs can work loose. If this happens, the
studs may fall out. With Chain Grades 1 to 3, it was common practice to weld the studs
during the manufacturing process (usually prior to heat treatment). With the higher strength
chains, stud welding has been found to cause premature cracking and fatigue failures at the
weld zones. A new type of oversized stud was introduced that eliminated the need for stud
welding (see Figure 6.30). Drilling contractors did not like the unwelded studs since it was
necessary for the chain to be periodically sent back to the factory to hydraulically re-affix the
studs (with the associated cost and operating problems). For this reason, a chain grade was
specified by some drilling contractors that fell somewhere between ORQ and K4 in strength
(ORQ +10% and ORQ +20%). The theoretical reason for these new grades was to allow the
studs to be welded while still utilizing a higher strength material. This approach has not been
totally accepted by the classification societies. At least one chain manufacturer (Ramnas) has
developed an asymmetrical stud and a means to insert these studs into the chain link under
tension to minimize the extent of chain stud loosening.
Another issue with mooring operations using chain, especially where combination wire/chain
systems are specified, is the question of torque. Six-strand wire commonly used in floating
drilling rig mooring operations (see Section 5.5.6) generates substantial torque under tension
changes. Chain has a natural tendency to freely rotate (about 3 a link) without any
resistance at all (acting very much like a free swivel). Once all the free rotation has been
taken up, the chain acts very much like a bar of steel and resists further rotation. Further
enforced rotation will cause the chain to knot and tangle. For this reason, swivels are used
between the chain/anchor and chain/wire connections.

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6.5.4 MOORING WIRE

Wire consists of three basic components; wires that form each strand; multi-wire strands that
are helically laid around a core; and the central core. These components are shown in
Figures 6.34 and 6.35. The most common wire construction used for offshore drilling is
six-strands x 36 wires wound around an Independent Wire Rope Core; thus the wire
construction is known as 6 x 36 IWRC. Some of the newer generation rigs are using
6 x 41, 6 x 46 or a greater number of wires in each strand.

Figure 6.34 - Wire Rope Components

Figure 6.35 End View of Six Strand Wire Rope

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Like chain, wire rope is fabricated from steel with different grades based on required tensile
strengths. The most commonly used grades in the offshore drilling industry are Extra
Improved Plow Steel (EIPS) and Extra Extra Improved Plow Steel (EEIPS). Another issue
concerning wire rope for floating drilling rig operations is that the type of lubricant Wire ropes
used in MODU mooring systems is usually changed out every five to eight years, depending
on usage, the type of mooring equipment and the amount of wear and tear. For MODU
operations, no elaborate lubricants are used (generally petroleum based only) and only
standard galvanization is employed for corrosion protection.
All types of six strand wire rope generate torque when placed under tension. As the tension in
the wire changes, so do the torque characteristics. When used in combination with chain, a
swivel is often placed between the connection of the chain and wire to minimize the amount
of twisting transferred into the chain. While the swivel will alleviate some of the twist transfer
problems, over time, its use has been found to cause the wire rope to unlay and reduce the
fatigue life of the wire rope. The whole question of torque and the design and use of swivels
used in this application is not completely understood at present, therefore, it is not discussed
further in this section, but an overview of swivels is given in Section 6.5.7.
Spiral strand wire rope is often used for floating production applications. In these applications,
longevity is more critical than easy handling, since the rope will only be handled during the
initial installation. Spiral strand is similar to a bridge strand parallel lay construction with a
slight helix angle introduced into the strands. Spiral strand can be manufactured to be torque
balanced so that it does not introduce any torque when tensioned. Therefore, it can be
connected to chain with no twisting problems. Spiral strand has a longer fatigue life than six
strand wire, but it has to be handled very carefully to prevent damage during installation. It
can never be used in conjunction with or while connected to six strand wire or it will be
severely damaged. Generally speaking, spiral strand is not used around fairleads, unless a
very large diameter sheave or roller is used in the fairlead or a large radius bending shoe is
employed.
The breaking strength for various sizes and grades of wire rope are listed in Table 6.2.

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Diameter Air Weight Water Weight C a ta lo g B re a kin g S tre n g th C B S (kip s)

(in) (lb/ft) (lb/ft) EIPS EEIPS EEEIPS
2 7.40 6.14 396 434 494
2 1/4 7.99 6.63 494 544 604
2 1/2 9.36 7.77 604 664 739
2 3/4 11.60 9.63 736 794 893
3 12.77 10.60 856 936 1080
3 1/4 13.37 11.10 984 1086 1224
3 1/2 16.63 13.80 1144 1242 1453
3 3/4 17.95 14.90 1290 1410 1565
4 18.92 15.70 1466 1586 1753
4 1/4 20.96 17.40 1589 -------- 1852
4 1/2 22.65 18.80 1776 -------- 2061
4 3/4 25.54 21.20 1962 -------- 2260
5 29.16 24.20 2156 -------- 2502

Table 6.2 - Wire Rope Data

Note: In the absence of more accurate data, the following approximations can be used:
Let D = Nominal diameter of wire in inches

EIPS breaking strength (kips) = 83 D2

EEIPS breaking strength (kips) = 96 D2

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6.5.5 CHAIN CONNECTING HARDWARE

Historically, chain manufacturers supplied chain in 15 fathom (90 ft) shots for ships anchor
chain. The shots are then joined with special chain connecting links that are assembled
and disassembled as necessary. With the advent of offshore drilling and production, it is
preferred that chain be supplied in continuous links, and today all chain manufacturers
have that capability.
From time to time, it is necessary to change out or add sections of chain to MODU mooring.
Therefore, chain connecting links are still necessary. Chain connecting hardware should have
the following properties:
Ability to pass over the windlass wildcats without jamming.
Strength and fatigue life similar to the base chain.
Ability to readily make-up and disconnect in the field.
Acceptable fatigue life
There are five types of connecting links typically used in the field. Section 6.5.6 overviews
these connecting links.

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6.5.6 KENTER LINKS

A Kenter link is a special chain connecting link type that can be assembled from four major
pieces (Figure 6.36). The body sections of the link are constructed from forged steel with the
interlocking surfaces machined. The body can be made in the same grades as chain and in
sizes up to 6. T he centraltapered pin is usually constructed from stainless steel. T he
components of different links are not interchangeable. The tapered pin is usually secured
after link assembly by driving it into position with a punch and applying a lead plug. Kenter
links are often used to connect wire segments.

Figure 6.36 - Exploded Diagram of Kenter Link

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6.5.7 C C O N N E C TIN G LIN K

The C connecting link (also sometimes called a Baldt link) is a common alternative to a
Kenter link, especially where ease of assembly is required. The link shown in Figure 6.37
com prises a m ain body section shaped like a C constructed of forged steelw ith m achined
end pieces. Two interlocking sections, secured with a tapered pin, make up the insert piece,
which is secured by a lead plug. The links can also be furnished in a pear shaped
configuration, Figure 6.38, where one end has a larger internal diameter than the other for
use in connecting chain to anchors or different size chains.

F igure 6 .38 E xploded D iagram of

Typical Anchor Connecting Link

Figure 6.37 - Exploded diagram of C Connecting Link

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6.5.8 R A M FO R C O N N E C TIN G LINK

The Ramfor connecting link, Figure 6.39, has the same basic outside shape as the Kenter
link, however, it has a different interlocking shaped head in the interior mating zone to
increase surface contact bearing area. This gives superior stress distribution and, therefore,
better fatigue life than the Kenter link. The Ramfor link is assembled and disassembled in a
fashion similar to the Kenter link.

Figure 6.39 R A M FO R Connecting Link

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MOORING DESIGN AND OPERATIONS

6.5.9 BRUCE LINK

The Bruce chain connecting link, Figure 6.40, is composed of two C-shaped half links with a
T-shaped square lug head (with slightly angled mating surfaces) on the end of each half. Two
specially formed shells are used to transversely clamp the lug heads together on each side
by compressing them into alignment and expanding them through the inclined end planes.
This action produces a tensile preload in the shells in excess of the chain proofload. The
shells are fastened together with high strength bolts. All the parts are constructed of forged
steel. Bruce links have a superior fatigue life to the chain connecting links previously
mentioned, but they are more difficult to assemble and, therefore, are usually only used
where it is necessary to join chain sections on permanent mooring systems.

Figure 6.40 - Exploded View of Bruce Connecting Link

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6.5.10 WIRE ROPE CONNECTING HARDWARE

Wire rope used in the offshore mooring industry is generally terminated using splicing
techniques, swaging locking or special sockets.
While much used in the shipping industry in the past, hand or mechanically applied splicing
nowadays is only used with rigging slings and special lifting gear used in the offshore lifting
and construction industry. Up until the 70s, most mooring and pendant wires used for MODU
operations w ere term inated w ith a hard eye, sw aging locking proce ss, involving forming an
eye around a steel thimble and then locking the two sections of wire above the thimble with a
hydraulically applied collar.
In the 1970s, contractors and operators started to use spelter sockets as end terminations
for mooring wires. A socket is a cast, forged, or prefabricated steel end fitting. Figure 6.39
shows a comparison of spelter sockets used in both production (permanent mooring) and
drilling (temporary mooring) applications.

Figure 6.41 - Comparison of Socket Designs for Spiral Strand & 6 Strand Wire Rope

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To put a spelter socket on the end of a wire rope, the wire is inserted through a hole in the
base of the socket, unwound, and carefully cleaned. Either lead, lead/zinc alloy, or resin is
applied to seal and affix the opened w ires w ithin the socket body. T his form s a plug that
essentially prevents the wire from being pulled. The socketing process for MODUs can be
performed in the field by experienced personnel. For large permanent moorings, the process
is complicated and should be performed in a controlled environment (Figure 6.42).

Figure 6.42 - Proper Method to Clean Wire Strands for Resin Socket

Sockets can be either open or closed in configuration (Figure 6.45). Their length and size will
largely depend on the type of wire and application for which it is being used (e.g., permanent
or temporary moorings). The ratio of socketed wire section length and wire diameter is about
6.8 for 6 strand wire rope. Note that the spiral strand socket is considerable longer than the 6
strand socket. Due to the lower flexibility of the wire, the socket used for spiral strand is
normally fitted with an additional flex relief boot to minimize stress concentrations at the
wire/socket interface.

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Forged, closed spelter sockets are the preferred choice for MODU moorings. Currently
practically all contractors use an extra-heavy duty type (often referred to P eew ee or
G oldnose). Figure 6.43 shows a close-up photo of this socket type. The preferred method
for connecting to sections of mooring w ire is to em ploy either a K enter or C connecting link
as noted in Figure 6.44. The main reason for the chain connecting link being used in this
application is to minimize or prevent damage to the mooring wires when the connection is
spooled on AHV winch drums during installation and recovery. If the wire is spooled on top of
a connection that uses other hardware types, the sharp edges will damage and cut the wire.
Wires are also sometimes connected using a closed socket with the bow fed directly into an
open socket (Figure 6.45). This type connection is mainly used with tow wires, rather than
with MODU mooring systems.

Figure 6.43 - Examples of Lowery "Peewee" Extra Heavy Duty Closed Socket Being Used in the Field

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Figure 6.44 - Spelter Heavy Duty "Peewee" Socket connected using "C" Connecting Link

Figure 6.45 - Closed Spelter Socket Connected to Open Spelter Socket

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6.5.11 MISCELLANEOUS CONNECTIONS AND FITTINGS USED IN MOORING SYSTEMS

D C O N N E C T IN G S H A C K LES
V arious D connecting shackles are available for use as connectors in mooring systems.
Figure 6.46 shows examples of bolt-type shackles (used when connecting mooring
sections). The means for securing the shackle pins varies with the application. Some
examples of securing mechanisms include a threaded pin and nut (with stainless steel
cotter securing pin), a stainless steel locking taper pin, a bolted horseshoe clip, or even
tack welding. If welding is used, the effect of the heat on the shackle base metal has
to be considered.

Figure 6.46 - Examples of typical bolt type "D" shackles

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W ide body shackles (Figure 6.47) are sometimes used during mooring installations where
soft eye installation slings or grommets are required during the release of a mooring line over
the stern roller of an AHV.

Figure 6.47 - Wide Body Shackle

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SWIVELS
Swivels are often used to connect a chain and anchor or with combination wire/chain
systems between the wire and chain sections. Conventional 6-strand wire rope construction
produces high torque under tension, and the swivels are designed to minimize the transfer of
torque from the wire into the chain. Examples of swivels commonly used in mooring systems
are shown in Figure 6.48. The photo in Figure 6.49 shows the attachment of a swivel to an
anchor. It should be noted that the sw ivelis connected through a D shackle in this case,
which eliminates side loading on the ears of the swivel.

Figure 6.48 - Example of a Mooring Swivel Connected to Anchor with "D" Shackle

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Figure 6.49 - Photo of Mooring Swivel Connected to Anchor with a "D" Shackle

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6.6 MOORING EQUIPMENT/INSPECTIONS

Specifications and conditions of the mooring components should be in accordance with those
assumed or required by the mooring analysis.
6.6.1 MOORING LINE COMPONENTS
Primary anchors should be of a type and size that meet the holding capacity
requirements determined by the mooring analysis. This is of particular importance in
cases where site specific conditions require the mobile offshore unit's standard anchors
to be upgraded. Where anchor holding problems can be relieved by the use of
piggyback anchors as indicated by mooring analysis or previous knowledge of the site,
sufficient anchors and connecting chain or wire rope of a suitable design should be
available. Piggybacks are not an available option in deepwater, due to installation and
pendant issues.
Mooring wire rope should have an independent wire rope core (IWRC). Wires should be
galvanized. Blocking compound of good quality should be used to fill the spaces
between the wires. The ends of each rope section should be terminated with resin or
zinc poured sockets. Wire ropes should be less than eight years old.
Mooring chain should be stud link chain less than ten years old manufactured according
to one of the following specifications.

API Spec. 2F

ABS Guide for the Certification of Offshore Mooring Chain

DnV Certification Notes No. 2.6

IACS Chain Spec.

Connecting links, such as shackles, Kenter, and Baldt links, should be made of forged
material. They should be fully inspected by MPI during rig mobilization. The number of
connecting links in a mooring line should not exceed an average of one per 400 feet
outboard line length. Furthermore, the total number of connecting links in a mooring line
should be no more than ten, excluding the connecting links at the anchor end.
K4 connecting links (Baldt, Kenter, or pear), employed in mooring lines whose failure
could reasonably result in impact of the failed line with a pipeline or subsea installation
or vessel impact with an adjacent structure, should not be used without a metallurgical
verification of impact strength performed by a laboratory independent of the
manufacturer. Such verification would normally require destructive testing of sample
links
(i.e. one out of ten) from the same lot, and be independent of any original certificate.

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Requirements and specifications of synthetic ropes, such as nylon and polyester, should
be determined by a mooring analysis. They should not be used in operations that require
frequent deployment and retrieval of the rope.
PCC or Pendant lines should consist of chain, wire rope, and connecting hardware.
Synthetic ropes are not acceptable.
Buoys should be constructed from steel or synthetic material. Surface buoys (pendant or
mid-line) should be sized for no more than 40% submerged. They should incorporate
measures such as compartmentalizing or foam filling to minimize the risk of sinking in
case of buoy damage. Sub-surface mid-line buoys should be rated for use at the
required depth of operation identified in the mooring analysis.
Sufficient mooring line should be left on the mobile offshore unit to permit moving the
unit 300 ft off-station in any direction in case of emergency.

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6.6.2 WINCHING EQUIPMENT

Winches or windlasses should have a stall capacity capable of supplying the maximum
test load required in the mooring analysis. Test load capacity can be provided by
multiple winches if this is reflected in the test loading procedures.
Winches or windlasses should be equipped with dynamic brakes in water depths beyond
1000 feet. Band brakes alone are not acceptable for deepwater operations.
Winches or windlasses should be operable both locally and from a central control room.
The intent of operation from a central control room is to avoid the risk of having people
manning the local controls in bad weather, and/or to avoid delays in going to local
controls when quick action is needed. Winches or windlasses can be operable only
locally, if the following conditions are met:
Weather and operating conditions allow operations to be executed safely from
local winch controls.
Mooring line management is not needed to meet operating or maximum design
mooring conditions, even with failure of thrusters (if used). Possible locations for
consideration of this reduced requirement are Southeast Asia, West Africa and
Gulf of Mexico.

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6.6.3 MONITORING EQUIPMENT

Mobile units should be equipped with an accurate, calibrated system for measuring
mooring line tensions. This is important for running out mooring line effectively, testing
anchor holding capacity (i.e. test loading) and maintaining minimum tensions when
mooring over subsea obstructions. Such a capability is also essential in order to monitor
the performance of the mooring system and to undertake measures to reduce line
tension. Line tension should be continuously displayed at each winch and be relayed to
a second display in a manned control room. A system, preferably automatic, should be
provided for recording line tensions. This system should record at intervals of at least
once every 30 minutes during storm conditions.
Mobile offshore units should be equipped with an accurate system for measuring
mooring line payout. As a minimum, payout should be continuously displayed at each
winch and, preferably, relayed to a central control room.
Mobile offshore units should be equipped with a system for accurately monitoring the
position of the vessel at critical times (e.g. MODU with marine riser connected). Where a
semi-rigid link to a fixed object is available (e.g. link bridge from tender to platform), this
can be used to monitor mobile offshore unit position. For MODU applications, the system
must be available to provide mobile offshore unit bearing and distance off, in relation to
the wellhead or point of riser attachment.

6.6.4 INSPECTION FREQUENCY

The interval between inspections should be less than 18 months for wire rope and 36
months for chain.

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6.7 SPREAD MOORING SYSTEM TYPES

Various types of spread moorings are used by drilling MODUs depending on water depths
and application. Figure 6.50 is shown to illustrate elevations views of the various types of
Catenary Spread Moorings (CSMs). Figure 6.51 shows elevations of Taut Leg Moorings
(TLMs). Table 6.3 summarizes the usual applications of the various types of mooring
systems.

Mooring Type Approximate Installation

System No. Water Depth
Range (ft)
1 All Chain or all Wire CSM 250 2,000 Self-deployed or preset
2 Combination Wire/Chain 2,000 7,500 Self-deployed or preset
CSM
3 Combination Wire/Chain 5,000 7,500 Self-deployed or preset
CSM
4 Combination Wire/Chain 3,000 8,000 Preset for locations requiring
TLM * limited seabed footprint
5 Combination Wire/ 3,000 8,000 Preset locations requiring
Polyester/Chain TLM * limited seabed footprint
6&7 Combination Wire/ 7,500 10,000 Preset
Polyester/Chain TLM *

Table 6.3 - Mooring System Applications And Pertinent Factors Of The Systems.

* May include submersible buoys to reduce vertical loads on rig,

especially in water depths > 5000 feet.

As you can see from Table 6.3, mooring systems can be divided into three categories:
All wire rope systems
All chain systems
And a chain/wire rope combinations (this would include inserts like polyester)
The advantages and limitation of each system are discussed below.

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6.7.1 ALL WIRE ROPE SYSTEMS

Wire rope is more lightweight than chain. Therefore, in general, wire rope provides more
restoring force in deepwater than chain and requires lower operating tensions. However, to
prevent anchor uplift, much longer line length is required for an all wire rope system. Also,
wear due to abrasion between wire rope and a hard seafloor can sometimes become a
problem. All wire rope systems are generally found on rigs operating in mild environments
such as West Africa.

6.7.2 ALL CHAIN SYSTEMS

Chain is very durable for offshore operations. It has better resistance to bottom abrasion and
contributes significantly to anchor holding capacity (added weight on bottom). However,
because of its heavy weight, it is unsuitable for deeper water operations (water depths
exceeding 1500 ft). During anchor deployment, an all chain system requires a windlass with a
large shaft horsepower and braking capacity. In addition, anchor-handling vessels (AHV)
must have larger bollard pull capacities to deploy the anchor. Further discussion on AHVs
can be found in Section 6.9.

6.7.3 CHAIN/WIRE ROPE COMBINATION SYSTEMS

In this system, the chain is outboard between the anchor and the wire rope. By proper
selection of the lengths of chain and wire rope, a combination system offers the advantages
of low operating tension requirements, high restoring force, added anchor holding capacity,
and good resistance to bottom abrasion. These advantages make it the best system for
deepwater operations. Anchor deployment and retrieval are generally more time consuming
with a combination system since a crossover must be made to connect the chain to wire.
Combination line systems can either use a combination winch/windlass or the chain/wire can
be inserted into the mooring leg via the AHV. For instance if a rig only has an all wire system
and winch, the AHV can insert chain between the anchor and the outboard end of the wire
rope. If a rig only has a chain and windlass system, the AHV can insert wire rope into the
mooring leg somewhere in the suspended section of chain. The wire would cross back over
to chain on the outboard side of the fairleader. See Section 6.12.2 for more explanation of the
wire insert process.

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Figure 6.50 - Catenary Mooring Leg Components

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Figure 6.51 - Taut Leg Mooring System Components

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6.7.4 THE BASIC CATENARY SHAPE

The basic catenary illustrated in Figure 6.52 consists of a single line type with a uniform
linear mass density (i.e., a chain mooring line). Consider the mooring chain anchored on the
seabed and hanging from the vessel fairlead. The forces in the mooring chain are as follows:
The horizontal force is constant throughout the mooring chain from the
seabed to the fairlead.
The vertical force is equal to the submerged weight of the suspended length
of the chain at each point along the mooring line (the length of the chain from
the point of interest to the seabed times its submerged weight density).
The tension in the chain is the vector sum of the horizontal and vertical forces.
The tension in the chain at the seabed touchdown point is equal to the
horizontal force since no chain is suspended.
The tension in the chain at the anchor is reduced by the frictional force
between the chain and the seabed.

Tension at
winch / windlass

Suspended line Water Depth

Mud line Grounded line

Figure 6.52 - The Basic Mooring Catenary

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The following equation can be used to estimate the mooring parameters:

S = T-dW/W {(T/T-dW)2 1}0.5

Where S = suspended line length (ft)

T = tension at upper end of the line (lbs)
d = water depth (ft)
W = submerged weight of mooring line (lb/ft)

Other basic catenary relationships include:

(d+ (Th / W))2 = S2 + (Th/W)2

d = (Th / W) (Cosh(WX/Th)-1)

S = (Th / W) Sinh(WX/Th)

Where S = suspended line length (ft)

Th = horizontal component of tension at upper end of the line (lbs)
d = water depth (ft)
W = submerged weight of mooring line (lb/ft)
X = horizontal distance from fairlead to the touch down point of grounded line

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6.7.5 SPREAD MOORING PATTERNS

The spacing of mooring lines around a MODU is known as the mooring pattern. Many
possible arrangements are used depending on the number of mooring legs, the type of
vessel and loads being subjected on it, the prevailing direction of the environment and
seafloor obstructions which might hinder the path of a particular mooring leg.
Various mooring pattern combinations are shown in Figure 6.53. The most commonly used
with semisubmersibles are the 30-60 and symmetrical types (A and B). The 30 is measured
from the port forward to the first point anchor. The 60 is measured from the port forward to
the first breast anchor. In some areas, where strong winds and currents are expected to
prevail from a specific direction, asymmetric or skewed patterns might be used (G and H).

Figure 6.53 - Possible Spread Mooring Patterns

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6.7.6 DIFFERENCES BETWEEN PERMANENT AND

TEMPORARY MOORINGS
For the purposes of this section, a permanent mooring is defined as a mooring that will
provide stationkeeping for a floating facility over a period of several years with only minimal
maintenance. In most cases, this will mean the vessel will be engaged in floating production
activities. The design period could be ten years or more and may be in excess of twenty
years. T w o notable exam ples are E xxons Lena Guyed Tower moorings that had an original
design life of tw enty years and S hells Auger TLP lateral moorings, which had an original
design life of thirty five years. On the other hand, a temporary mooring is one that will see
service for relatively short periods (weeks or months at a time), such as would be used with a
MODU engaged in drilling operations. The ability to lift and inspect the mooring components
when the rig is moved enables a different design and maintenance philosophy to be adopted.
The differences between the permanent and temporary moorings can be categorized
as follows:

Selection of criteria used in the design of the system.

Type and size of mooring components.

Method used in performing analysis.

Methods for performing installation.

Inspection and maintenance philosophy.

In the US, according to accepted industry standards (API RP 2SK Recommended Practice
for Design and Analysis of Stationkeeping Systems for Floating Structures), the design
criteria selected for a permanent mooring system in survival conditions is recommended to be
a 100 year return period storm. For a MODU, a five-year return period storm can be used if
the vessel is to be moored away from other structures, and a ten-year storm should be used
if it will be moored close to other structures. To understand the magnitude of load difference,
Table 6.4 shows a comparison of environmental loads for the fifth generation MODU Ocean
Confidence. This rig was chosen because it represents the type of vessel that might be
employed for deepwater drilling, as well as production operations.

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COMPARISON OF DESIGN CRITERIA AND ENVIRONMENTAL LOADS BETWEEN

PERMANENT AND TEMPORARY MOORINGS
(OCEAN CONFIDENCE)
Temporary Moorings (Drilling) Permanent Moorings
(Production)
Metocean Criteria 10-Year Hurricane 100-Year Hurricane
1-hour Sustained Wind 60 kts 77.6 kts
Surface Current 1.48 kts 2.49 kts
Significant Waves 25.0 ft @ 12.0 sec 41.7 ft @ 14.9 sec
Environmental Forces
Wind 549 kips 918.4 kips
Current 83.0 kips 234.8 kips
Waves 127.9 kips 183.2 kips
Total Environmental
Force 760 kips 1336.3 kips
Table 6.4 - Comparison of environmental loads for the fifth generation
Floating Drilling Rig Ocean Confidence

Another major difference between the two mooring types is the method used in analyzing and
designing the systems. For a temporary drilling mooring, API RP 2SK recommends a quasi-
static analysis since the effects of line dynamics are accommodated through the use of
relatively conservative safety factors. The document also recommends a more rigorous
dynamic analysis be used for the final design of a permanent mooring system, while safety
factors may be relaxed to reflect that some uncertainty in line tension prediction is removed.
The more stringent design criteria results in components of a permanent mooring being
considerably larger than a temporary mooring. For instance, the required chain size for the
Ocean Confidence, when engaged in exploration drilling, is three inch K4 Grade, with a
weight per ft in air of 90 lbs. For a permanent mooring the required chain size would be in
excess of five inch K4 grade, with a weight per foot in air of 238 lbs. All other mooring
component sizes are increased as well; meaning the overall component weight in a
permanent mooring system will be more than double that of a temporary system.
The impact on the method and cost of the installation of a production vessel mooring
system will be considerable.
A different philosophy exists between permanent and temporary moorings with regard to
mooring component inspection and maintenance. Mooring components for drilling and
construction operations can be readily inspected after being recovered between wells when
they are out of the water. It is important to replace components in these temporary systems
on a regular schedule as necessary. On production vessels, it is not normally practical to
inspect mooring components out of the water. Subsea inspection techniques of these
components are complicated, expensive, and only partially effective at best. Therefore, these
components are typically designed or selected to last the life of the field.
The remainder of the sections only deal with temporary mooring systems.

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6.8 DESIGN AND ANALYSIS

6.8.1 PURPOSE
The purpose of the mooring analysis is to determine if the vessel can maintain position while
meeting the design and safety standards. Therefore, the goal is to optimize the combination
of mooring components (chain, wire rope, synthetic rope, and anchors) that, when deployed
in the field, provide the required stationkeeping capability for various operations. The mooring
design balances various constraints, such as the existing mooring components, that can limit
certain facets of an ideal mooring design. Furthermore, the mooring design must work within
established guidelines to ensure the mooring is sufficiently capable of protecting the MODU,
the riser and other nearby structures.
Mooring analysis and equipment reviews shall be performed as a part of the floating rig
contractor and anchor handling vessel selection, and whenever site or environmental
conditions exceed the original design basis. The mooring analysis can be conducted by
the ExxonMobil Upstream Research Company (URC), a drilling or third party contractor,
and/or the drilling engineer. Depending on the activity level and complexity of the
analysis, it may take URC several months to complete the work. The drilling contractor
can typically conduct the analysis much quicker since they will have an archive of
studies conducted for the particular rig (unless it is a new built). Third party contractors
can also conduct the analysis in relatively quickly (less than a month). The drilling
engineer should be able to conduct the analysis in about a few days, once all the
required information is gathered. The following items outline when an analysis is
required and by whom:

Analysis by URC is required unless already conducted for similar water depth, in
same area, with the same rig.

All newly constructed rigs should be analyzed by URC.

Otherwise, the drilling and/or third party contractor, or the DrillMoor Quasi-Static
Mooring Analysis can be used.
If the drilling engineer conducts the analysis, it should be calibrated against prior URC
w o rk. N o m a tte r w h o co n d u cts th e a n a lysis, it w ill b e th e d rillin g e n g in e e rs re sp o n sib ility
to develop the deployment and retrieval procedures.
It is essential to have a good design basis at the start of the mooring design cycle. The
design basis should reflect the current industry guidelines and standards. In addition, it should
include information on any operations that may be unique or require special attention. These
may include offset limitations during drilling, details of seafloor obstructions, and the distance
between well locations within or near the mooring spread.

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6.8.2 VARIABLES AFFECTING MOORING PERFORMANCE

Several variables affect the overall performance of any mooring system. The chief variables
include:
The mean environmental loads produced by current, wind and waves force the Floating
Drilling Rig to move off the well center. Wind and current loads are proportional to the square
of the wind and current velocities.
The vessel type dictates whether the environmental loads are relatively uniform with attack
angle (as for a semisubmersible) or highly dependent on attack angle (as for a drillship).
The vessel Response Amplitude Operators (RAOs) determine how much the vessel will
move under wave action. The larger the RAOs are, the more sensitive the vessel is to wave
action. RAOs are very sensitive to both wave direction and wave period and depend very
strongly on the vessels underw ater geom etry.
The mooring system's stiffness dictates the distance the vessel will move in the mooring
under the influence of environmental loads. A vessel will have a lower mean offset if it has a
mooring with a high stiffness and, conversely, a higher mean offset if it has a mooring with a
low stiffness. Furthermore, the vessel's second order motions depend on the mooring
stiffness _ second order motions increase as mooring stiffness is reduced. Some factors that
affect the mooring stiffness are mooring line pretension, weight in water, mooring line
elasticity, the total mooring line length and the fairlead-anchor distance.
The pretension in the mooring determines the mean load in the mooring lines as well as the
mooring stiffness. High pretension generally leads to high mooring stiffness. However, high
pretension also leads to high mooring line loads under storm conditions. It also increases
fatigue loading on a day-to-day basis.
Another significant factor in mooring design is water depth. The water depth dictates the
mooring system components.
In shallow water, all chain moorings may be used with a relatively low pretension since the
weight of the system will dampen environmental effects.
In deepwater (up to 6,000 ft), wire rope becomes a major component because of its higher
strength to weight ratio compared to chain. Furthermore, the requirements to maintain station
in deepwater are significantly more challenging than those for shallow water.
In very deepwater, synthetic ropes are attractive because of both increased strength to
weight ratio and elasticity. The use of synthetic rope reduces the mean load at the fairlead
due to mooring line weight. In addition, the mooring line is less resistant to stretching caused
by the first and second order vessel motions; therefore, maximum line tensions are reduced.
More information regarding synthetic fiber rope is located in Section 6.12.8.

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6.8.3 VESSEL ENVIRONMENTAL FORCE COEFFICIENTS

Current, wind, waves and swell create forces that act on a vessel and tend to push it off
location. These are known as environmental forces. Coefficients required to calculate these
environmental forces are typically provided by the vessel owner and are derived from model
testing.

CURRENT FORCES
Data for the magnitude, direction, and seasonal variation of surface currents should be
obtained for the area of operations.
Current forces are due to viscous drag on the submerged portion of the vessel hull and scale
with the square of the current velocity:
Fcurrent Ccurrent Vcurrent
2

where the drag coefficient Ccurrent depends on the current heading with respect to the vessel.
For semisubmersible vessels, current forces are higher at operating draft than at survival
draft and are higher from the beam than from the bow (sometimes significantly so).
Current force coefficients are the scaling factors used to determine the load on the vessel in
different areas. The two methods for estimating current force coefficients are numerical
calculations based on the projected areas of the underwater surfaces per API RP 2SK
guidelines and wind tunnel testing. Current forces are calculated for bow, quartering and
beam attack angles.
It should be noted that current is typically higher at the surface than further down the water
colum n, but it generally does not vary significantly over a vessels draft. G enerally use the
surface current value when calculating the current force on the vessel.
Figure 6.54 shows an example of a comparison of current force calculations based on drag
coefficients derived from model testing and numerical calculations from API RP 2SK. Notice
that force or current load is greater in the operating draft.

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Current Speed Vs Current Force

Comparing Load Coefficients - Quartering
1000 Environment

Survival Draft (API RP 2SK)

900 Survival Draft (Model Testing)
Operating Draft (API RP 2SK)
800 Operating Draft (Model Testing)
Current Force, kips

700 Load Coefficients @ Operating Draft

2
Model Testing = 59.2 kips/knot
2
API RP 2SK = 74.6 kips/knot
600

Load Coefficients @ Survival Draft

500 Model Testing = 48.7 kips/knot
2

2
API RP 2SK = 59.2 kips/knot
400

300

200

100

0
0 0.5 1 1.5 2 2.5 3 3.5
Current Speed, knots

Figure 6.54 - Current Drag Coefficients

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WIND FORCES
Wind forces are due to viscous drag on the exposed portion of the vessel hull, superstructure,
and scale with the square of the wind velocity.
Fwind Cwind Vwind
2

where drag coefficient Cwind depends on the wind heading with respect to the vessel.
For semisubmersibles, wind forces are higher at survival draft than at operating draft,
and there is some variation in overall force due to change in heading.
Wind force coefficients are the scaling factors used to determine the load on the vessel in
different areas. The two methods for estimating wind force coefficients are numerical
calculations based on the projected areas of the exposed surfaces per API RP 2SK
guidelines and wind tunnel testing. Wind forces are reported for bow, quarter and beam
attack angles.
See Figure 6.55 for an example comparison of drag coefficients derived from wind model
testing and numerical calculations from API RP 2SK. Note: Force or wind load is greater in
the survival draft.

Wind Speed Vs Wind Force

Comparing Load Coefficients - Quartering
800 Environment

Survival Draft (API RP 2SK)

700 Survival Draft (Model Testing)
Operating Draft (API RP 2SK)
Operating Draft (Model Testing)
600
Load Coefficients @ Survival Draft
2
Model Testing = 0.151 kips/knot
2
500 API RP 2SK = 0.145 kips/knot
Wind Force, kips

Load Coefficients @ Survival Draft

2
400 Model Testing = 0.168 kips/knot
2
API RP 2SK = 0.166 kips/knot

300

200

100

0
0 10 20 30 40 50 60 70
Wind Speed, knots

Figure 6.55 - Wind Drag Coefficients

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The design wind speed for use in the mooring analysis should be selected in accordance
with the following criteria:
1. The maximum wind speed averaged over a one-minute interval should be used in
Quasi-Static analysis. Other time-varying speeds are often reported by URC and
others. You will sometimes see 10-minute or 1-hour average velocities, these are
known as low-frequency wind forces. In order to adjust the wind velocities of various
average time intervals the following equation can be used:
Vt = Vhr
Where:
Vt = wind velocity for the average time interval t.
= Time factor from Table 6.5
Vhr = 1 hour average wind velocity

Wind Velocity Time Factor

Time Factor
Time Factor
Average Time Period t Non-Tropical
Tropical
1 hour 1.00 1.00
10 min 1.06 1.10
1 min 1.18 1.30

Table 6.5 - Wind Velocity Time Factor

2. The wind speed should be based on an elevation of 33-ft (10-m) above still
water level.
3. The design wind speed should be selected for the most severe season during
which operations are to be conducted at a given site.

WAVE FORCES
Wave forces are made up of three components:
1. Mean Wave Drift Force.
2. First Order or High Frequency Motion (independent of the mooring system, it is the
vessels response to the waves).
3. Second Order or Low Frequency Motion (a function of stiffness & dampening, it is the
resonance of the mooring system) .

MEAN WAVE DRIFT FORCES

Wave drift forces are the averaged forces produced by the force of the waves on the vessel
hull. For semisubmersibles, wave drift forces are higher at operating draft than at survival
draft and are higher for beam waves than for bow waves.

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Wave drift force coefficients are the scaling factors used to determine the load on the vessel.
The two methods for estimating wave drift force coefficients are numerical calculations
through radiation/diffraction hydrodynamic models and scale model testing in a wave tank.
They are reported for bow, quarter and beam attack angles.
The basic measure of wave height is called significant wave height represented by Hs. Hs is
equal to the average of the highest 1/3 of the waves passing a point. This method is used
because it is roughly equivalent to what a trained observer would estimate as the wave height
for a given series of waves.
The maximum wave height is larger than the significant wave height. A rule of thumb is that
the maximum wave height is estimated to be 1.9 to 2.2 times the significant wave height. The
design wave height should be determined based on the statistical wave height distribution for
the design case environment. Figure 6.56 offers a comparison of wave drift forces at the
survival and operating draft. Notice that the difference in force or wave load is minimal
between the survival and the operating draft, but the difference in the beam and bow
directions are significant.
FIRST ORDER (HIGH FREQUENCY) MOTIONS
First order, or high frequency, motions are determined using vessel Response Amplitude
Operators (RAOs), complex scaling factors describing the vessel motions response to waves.
RAOs are typically listed as amplitude and phase combinations at selected wave periods for
each of the six degrees of freedom - surge, sway, heave, roll, pitch, and yaw, at various wave
headings relative to bow. Like the wave-drift force coefficients, RAOs can be calculated either

Significant Wave Height vs Wave Force

Comparing Survival and Operating Drafts - Beam / Quartering Environments

160

Operating Draft (Quartering)

140
Survival Draft (Quartering)
Operating Draft (Beam)
Survival Draft (Beam)

120
Wave Force, Kips

100

80

60

40

20

Note: On this particual rig, the wave loads on the Beam and Bow are the same.
0
0 5 10 15 20 25 30 35 40 45

Sig. Wave Height, ft

Figure 6.56 - Wave Forces

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numerically through radiation/diffraction hydrodynamic models or through scale model testing

in a wave tank.
The first order motions are largely independent of the vessel mooring system.
There are no standard conventions for RAO units, directions or phases. Therefore, the units
for these factors must determined on a case by case basis.

Translational RAOs - These are generally dimensionless, although they can be

given as ft/ft (or m/m) to explicitly state the amount of motion per unit wave
amplitude.

Rotational RAOs - These are given any number of ways, such as deg/ft, deg/m,
rad/ft, rad/m or, more rarely, dimensionless (referenced to the wave slope as /
rather than wave amplitude).

Positive Directions and Rotations Verify which direction is set as positive.

Phase Angles for RAOs The units of the phase angles are in either degrees or
radians (and are obvious if not explicitly stated). The phase angles may be either
lagging or leading and referenced to the wave crest, trough or null point.
Figure 6.58 shows a typical first order motion at the fairlead.

10

6
Amplitude of Motion (ft)

2
Surge
0 Sway
Heave
-2

-4

-6

-8

-10
0 4 8 12 16 20 24 28 32 36
Time (sec)
Figure 6.58 - High Frequency Motion at Fairlead

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SECOND ORDER (LOW FREQUENCY) MOTIONS

Second order, or low frequency, motions are analogous to the motions of a spring-mass
system. The mass is equivalent to the vessel mass plus the hydrodynamic added mass. The
total mass is on the order of tens of thousands of tons. The spring constant is equivalent to
the mooring system stiffness at the mean offset and is on the order of a few kips per foot. The
natural period of the second order motions ranges from 100 seconds for small vessels to
nearly 300 seconds for very large vessels. Second order motions are typically calculated only
for motions in the horizontal plane (surge, sway and yaw). Both wave and wind spectra
contribute to second order motions.
Figure 6.59 shows a typical second order motion at the fairlead.

80

60

40
amplitude of motion (ft)

20

Surge
0 Sway
Heave

-20

-40

-60

-80
0 40 80 120 160 200 240 280 320 360
time (sec)

Figure 6.59 Low Frequency Motion at Fairlead

Note: The motions illustrated in Figures 6.58 and 6.59 are for regular waves.
Generally, seas have random waves, and the motions would be more complex.

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COMBINED HIGH AND LOW FREQUENCY MOTIONS

Essentially, a vessel oscillates about the mean offset that is caused by the environmental
load. The amplitude of the oscillation is a vector combination of the high and low frequency
motions as illustrated in Figure 6.60. The combined effect of these motions, called "surge" in
the DrillMoor program, is added to the steady component or force (mean wave drift force).
The combined effect will be covered in section 6.8.4 Quasi-Static Analysis.
The wave height versus wave period relationships should be accurately determined from
oceanographic data for the area of operation. The period can significantly affect surge
amplitudes and mean drift forces. For cases where measured data are not available,
Figure 6.61 can be used.

Figure 6.60 - High and Low Frequency Motions

Figure 6.61 - Wave Height vs Wave Period

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SUMMARY OF ENVIRONMENTAL FORCES

Current, wind, waves and swell forces impart loads of varying degrees depending on the
respected environmental heading. The vessel draft and overall dimensions also impacts
the amount of load that the vessel experiences. Table 6.6 summaries the environmental
loads for the Marine 700 MODU for the 95% non-exceedance and 10-year environment
at the Diana-Hoover location.

Environment 95% Non-Exceedance 10-Year Environment

Wind (knots) 28 68
Wave (ft) 9 25
Current (knots) 0.80 1.40

95% Non-Exceedance 10-Year Environment

Bow Beam Quartering Bow Beam Quartering
Wind (kips) 85 91 117 554 605 772
Wave (kips) 30 30 26 92 92 72
Current (kips) 14 42 37 39 104 95
Total (kips) 130 164 180 686 801 939
Table 6.6 Environmental Loads for Marine 700 MODU at the Diana-Hoover location

For this particular rig and environmental condition, the following conclusions can be
made:
Of the three environmental forces, the wind force imparts the largest load.
The wind force imparts the largest load in the quartering direction.
The wave force imparts the largest load in the bow and beam direction (equivalent
loads).
The current force imparts the largest load in the beam direction.
The following section describes various methods for conducting a mooring analysis.

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6.8.4 MOORING ANALYSIS METHODS

There are three methods for conducting a mooring analysis, Static, Quasi-Static, and
Dynamic. This section describes the various methods used in mooring design. It also
describes the results that may be derived from each method.

STATIC ANALYSIS
Single mooring line Static Analysis is the first step in the design. This type of analysis
provides the following information:

The line profile under as ran pretension and test tensions.

Anchor to fairlead distance.

Length of anchor line on bottom.

Line angle at the fairlead (check for bolster contact).

Tension and line angle at the anchor.

A preliminary estimate of line clearance with various obstructions.

Single line static analysis is usually performed for only one mooring line in the system,
because the others are the same. If line geometries vary due to clearance requirements, or
due to a complicated seafloor bathymetry, it may be desirable to check other line patterns.

QUASI-STATIC ANALYSIS
Quasi-Static Analysis: In this approach, the dynamic wave loads are taken into account by
statically offsetting the vessel by an appropriately defined wave induced motion. Vertical
fairlead motions and dynamic wave effects associated with mass, damping, and fluid
acceleration are neglected. Research in mooring line dynamics has shown that the reliability
of the mooring designs base on this method can vary widely depending on the vessel type,
water depth, and line configuration. Nevertheless, because of the conservative factors of
safety that are introduced with this method, it is appropriate for temporary mooring systems.
The following steps outline the Quasi-Static analysis:

A vessel heading and the mooring spread pattern that maximizes the operating time
while still meeting safety factor requirements is selected.

The environmental criteria (wind, wave, and current) data is entered for the maximum
operating, maximum design, and any other desired condition.

A mooring response graph is generated, as shown in Figures 6.62b & 6.63. (This
particular graph is for the Marine 700 in 4600-ft of water with a chain/wire combination
system and a quartering environment)

The designer analyzes the maximum operating condition to verify the pretension selected
keeps the maximum offset to within 3% of water depth. For each attack angle (beam,
bow, and quartering), calculations determine the environmental loads, the maximum
vessel offset, and the tension in the mooring lines and anchors.

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Next, the designer analyzes the maximum design condition. For each attack angle
(beam, bow, and quartering), calculations determine the environmental loads, the
maximum vessel offset, and the tension in the mooring lines and anchors.

If the rig is equipped with thruster-assist, it may be used in the operating condition to
reduce the line and anchor tensions. However, caution should be exercised in assuming
thrusters are available at 100% efficiency in the maximum design case.

The following steps summarize the Quasi-Static analysis:

1. A graph of the mean environmental forces (wind, current, mean drift force) verses the
restoring force is generated. See Figure 6.62a. The environmental force (180 kips in
this example) is resisted by the mooring system. The two opposing forces reach
equilibrium (static condition) at an offset of 54-ft or 1.2% of water depth.

2. The effects of the High Frequency and Low Frequency motions (called "surge" in
DrillMoor) are added to the mean offset. See Figure 6.62b. The combined HF and LF
motions add an additional 11-ft of offset which also increases the line and anchor
tensions. Therefore, the total or maximum offset (65-ft in this example) is equal to the
sum of the mean offset and the surge.

Mooring Response Curves

95% Non-Exceedance
600

540 Restoring Force

480

420
Environmental Load, kips

360

300

240
Environmental Load = 180 kips
180

120

60
Mean Offset = 54 ft
0
0 10 20 30 40 50 60 70
Offset, ft 54 ft = 1.2% WD
Figure 6.62a - Mooring Response Graph

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Mooring Response Curves
95% Non-Exceedance
600
Restoring Force
540 Maximum Anchor Load
Maximum Line Load
480
Line Load of 435 kips = 30% Capacity
420
Load / Tension, kips

360

300

240 Anchor Load of 201 kips = 24% Capacity

180
Environmental Load = 180 kips
120

60
Mean Offset = 54ft 11ft Surge Max Offset = 65ft
0
0 10 20 30 40 50 60 70 80
Offset, ft 65 ft = 1.4% of WD

Figure 6.62b - Mooring Response Graph (95%-Nonexceedanc Environment)

Mooring Response Curves

10-Year Environment
1500
Restoring Force
1350 Maximum Anchor Load
Maximum Line Load
1200

1050
Environmental Load = 939 kips
Load / Tension, kips

900
Line Load of 765 kips = 53% Capacity
750

600
Anchor Load of 632 kips = 77% Capacity

450

300
Surge = 29ft
150
Mean Offset = 262ft Max Offset = 291ft
0
0 50 100 150 200 250 300 350
Offset, ft 291 ft = 6.3% of WD

Figure 6.63 - Mooring Response Graph (10-year Environment)

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This procedure is called quasi-static analysis because, although there is some estimate of the
vessel motions, all calculations are performed as if the vessel is stationary in its maximum
offset position. Quasi-static analysis is performed for various attack angles (typically bow,
beam, and quartering) for both intact and damaged mooring conditions.

Figures 6.62b and 6.63 also illustrate typical mooring response graphs for the 95% non-
exceedance and 10-year environments. The three curves represented in the graphs are
the total system restoring force, maximum loaded line, and maximum loaded anchor.
The graph also includes the mean and maximum vessel offsets. These curves are used
to evaluate the response of the mooring system and ensure the design standards are
meet. During the analysis, the following mooring components are modified in order to
optimize the design:
Chain length
Wire length
Operating or Pre-Tensions
Rig heading
Mooring pattern
Line management (slackening leeward lines) is also a method used to ensure the design
standards are met. See Section 6.12.3 for more information on line management.

C. DYNAMIC ANALYSIS
Only a general overview of the Dynamic analysis will be covered in this section since the
depth of the topic is beyond the scope of the manual. More information on the subject
can be found in the API RP 2SK.
Dynamic analysis accounts for the time varying effects due to mass, damping, and fluid
accelerations. In this approach, the time-varying fairlead motions are calculated from the
ve sse ls su rg e , sw a y, h e a ve , p itch , ro ll a n d ya w m o tio n s. G e n e ra lly it is su fficie n t to
account for only the vertical and horizontal fairlead motions in the plane of the mooring
line. Dynamic models are used to predict mooring line responses to the fairlead motions.
The majority of the mooring analysis conducted for MODUs will be with Quasi-Static
method. The Dynamic method is used if the Quasi-Static results do not meet the design
criteria. The Dynamic method is more accurate and thus the design safety factors are
lower. Table 6.8 compares Quasi-Static and Dynamic safety factors.

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6.8.5 DESIGN CRITERIA

This section addresses the criteria used to evaluate the mooring performance of a vessel.
T he sum m ary that follow s is based on the A P I R ecom m ended P ractice 2S K for D esign and
A nalysis of S tationkeeping S ystem s for F loating S tructures and the E xxonM obilU pstream
D esign G uidance D ocum ent M ooring S ystem s for M obile O ffshore U nits.
The environmental data obtained from URC will be used in the mooring analysis to determine
the stationkeeping ability of the vessel. The resulting vessel offset and equipment loads will
be analyzed for both the Maximum Design Environment and the Maximum Operating
Environment.
The Maximum Design Environment is defined as the combination of wind, waves, and
current for which the mooring system is designed. Usually, the analysis for this condition
is conducted with the riser disconnected and the vessel at the survival draft. If the
operating location is mild and plans do not involve disconnecting and coming to survival
draft (e.g. West Africa), the maximum design is evaluated at operating draft. The
resulting offset needs to be within the riser limits.
The survival draft of a vessel brings the vessel higher out of the water to prevent waves
fro m sla m m in g th e u n d e r d e ck. W h e n th e ve sse l is a t su rviva l d ra ft, th e w a ve a n d
current forces acting on the rig are reduced, but the wind forces are increased. This is
due to the amount of surface area exposed to the environment. For example, the Marine
700 has a drilling or operating draft of 78 ft (36 ft air gap) and a survival draft of 59 ft (55
ft air gap).
The Maximum Operating Environment is defined as that combination of the maximum
wind, waves, and current in which drilling operations can be conducted. Therefore, this
analysis condition should be conducted with the riser connected, the vessel at drilling
draft, and drillstring rotating.

MAXIMUM DESIGN ENVIRONMENT

D e p e n d in g o n th e rig s lo ca tio n w ith re sp e ct to o th e r o ffsh o re stru ctu re s, e ith e r a five o r
ten-year (return period) environment should be used in the analysis. The five-year
environment has a one in five chance of occurring in a given year. As you would expect,
the magnitude of the ten-year environment is larger that the five-year. However, the
consequence of a mooring failure with a rig next to a production facility or with a mooring
leg over a pipeline substantiate the higher design standard.

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5-Year Environment
Special attention should be given to operations in an area of tropical cyclones such as
the Gulf of Mexico (hurricane) and South China Sea offshore China (typhoon). These
areas are characterized by generally mild environment combined with severe storms
during the cyclone season. For operations out of the cyclone season, the 5-year
environment can be determined using the environmental data excluding tropical
cyclones. For operations during the cyclone season, the tropical cyclone data should be
included, and the design wind speed should not be lower than 60 knots (one-minute
average at 10-m/33-ft elevation).
The return period can be reduced for certain operations during the tropical cyclone
season provided the following conditions are met:
A risk analysis is conducted to evaluate the consequences of a
mooring failure.
Operations personnel evacuation or move the vessel is planned
and executed before arrival of a tropical cyclone.
A weather forecast system with local environmental feedback is
available to provide accurate forecasting.
There is no other structure within five miles of the operation.
The reduced return period in this case should be determined by the risk analysis, but it
should not be less than one year.
10-Year Environment
When a vessel is operating in an area within five-miles of other offshore facilities or
equipment, a minimum of a 10-year return period should be used in the analysis. In a
tropical cyclone area, for operations out of the cyclone season, the 10-year environment
can be determined using the environmental data excluding tropical cyclones. For
operations during the cyclone season, the tropical cyclone data should be included,
and the design wind speed should not be lower than 70 knots (1-minute average
at 10-m/33-ft elevation).

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MAXIMUM OPERATING ENVIRONMENT

For drilling operations, the maximum operating environment should be analyzed for the
95% non-exceedance environment. The 95% non-exceedance environment is defined
as the maximum environment that the rig will experience 95% of the time. A second
environment (standby) is usually run for the one-year return period. This environment is
analyzed with the riser connected, operating draft, but no drillstring rotation. For both of
these environments, the mooring system must maintain station within a certain offset in
order to prevent damage to the drilling riser. The maximum offset will be determined by
the riser analysis. However, the rule-of-thumb for the mooring analysis is 3% offset for
the 95% non-exceedance and 10% offset for the 1-year environment. At 3% offset, the
ball joint or flex joint angle of the drilling riser should be low enough for drilling operations
(rotating) to continue. At 10% offset, the drilling riser can remain connected, but drilling
operations (rotating) must stop. Each drilling contractor will set the limits of operation for
the rotating and non-rotating condition, so this information should be obtained prior to
conducting the analysis.

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ANALYSIS CONDITIONS
For the mooring analysis, several conditions should be examined. These include the
mooring line condition (wire and/or chain), tensions (line and anchor), and vessel offset.
Other criteria such as clearance requirements should be examined where mooring lines
cross over pipelines or other subsea equipment.
Line Condition: Intact, Damaged, Transient
Intact condition refers to the condition in which all mooring lines are intact. Damage
condition refers to the condition in which the vessel settles at a new equilibrium position
after a mooring line breakage. Transient condition refers to the condition in which the
vessel is subjected to transient motions (overshooting) after a mooring line breakage
before it settles at the new equilibrium position. The conditions to be analyzed are in
Table 6.7:

Type of Operation Conditions to be Analyzed

Away from other structures (5 miles) Intact/Damaged/Transient*
Mooring lines over pipelines Intact/Damaged/Transient*
Vessel next to a platform Intact/Damaged/Transient

Table 6.7 Conditions to be Analyzed

* To be analyzed only for the purpose of providing vessel offsets

for drilling riser and casing analysis.
URC typically recommends setting high operating tensions to reduce offset in line failure
scenario, thus reducing the loads on the structural casing/wellhead and riser.
Nevertheless, high operating tension, reduces the fatigue life of the line. The drilling
contractor will also have criteria for the operating tensions, and any differences need to
be resolved prior to operations. If line slackening is the contractors strategy to manage
loads, clear procedures need to be in place.

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Line Tension
Tension limits and equivalent factors of safety for various conditions and analysis
methods are provided below. These criteria apply to the maximum design condition. No
checking is required for the line tension under the maximum operating condition and the
maximum connected condition for the drilling riser. The different analysis criteria are
located in Table 6.8.

Condition Analysis Method Tension Limit (% of Equivalent

Nominal Breaking Safety Factor
Strength)
Intact Quasi-static 50 2.00
Intact Dynamic 60 1.67
Damaged Quasi-static 70 1.43
Damaged Dynamic 80 1.25
Transient Quasi-static 85 1.18
Transient Dynamic 95 1.05

Table 6.8 Analysis Criteria

Anchor Holding Requirements

A factor of safety of 1.0 should be maintained for the maximum anchor load (horizontal)
from a quasi-static analysis under the maximum design environment with all mooring
lines being intact. This factor of safety can be reduced to 0.8 if the anchor load is from a
dynamic analysis.
Drag anchors should not be subjected to vertical (uplift) loads in normal operating
conditions. However, vertical loads can be applied in survival conditions to certain high-
efficiency type anchors (e.g., Stevpris and Bruce FFTS).
Vertical loads can be applied in survival conditions only.

The maximum line angle at the mudline under the Maximum Design Environment
is less than 10o for the damage condition, and less than 5o for the intact condition.
Most drag embedment anchors have adjustable flukes/shanks. The amount of
adjustment will be anchor specific, but generally, the setting is either wide open (50
degrees) or closed (30 degrees). In soils such as sand and medium to hard clay, an
anchor with a fluke/shank angle of 30 degrees will give the highest holding power. If
used in soft clay or mud a 50 degrees fluke/shank angle is appropriate. The
manufacturer will have hold capacity charts for various anchor weights and soil
condition. This data should be compared to the anchor holding capacity charts in the API
RP 2SK (See Figures 6.25 & 6.26).

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CLEARANCE REQUIREMENTS
The clearances between the floating vessel or its mooring components and other marine
installations should be determined. Clearance requirements are provided below.

Where a mooring line crosses a pipeline within the elevated part of its catenary, a
minimum vertical clearance of 30 feet under the intact condition should be maintained.
A mooring line can contact a protected pipeline provided this contact remains throughout
the full range of predicted intact line tensions. The contact point must not occur in the
"thrashing zone" i.e. the catenary touch down point.

Where two mooring lines cross, a minimum vertical clearance of 30 feet is required
for the intact condition.

A minimum horizontal clearance of 30 feet should be maintained between the

floating unit (or its mooring lines) and any other installation. This clearance is
required in various conditions, including transient conditions.

If a marine installation lies in the dragging path between the anchor and the mobile
offshore unit, the anchor should be at least 1000 feet from the marine installation.
Otherwise, the anchor should be at least 300 feet from the marine installation.

INSTALLATION
The mooring installation is also evaluated in order to ensure that both the MODU and the
anchor-handling vessel (AHV) can safely handle the loads and determine the AHV
requirements. The DrillMoor program can be used to evaluate the associated loads during
the running/retrieving of the anchors and to develop procedures.

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6.8.6 INFORMATION REQUIRED FOR MOORING ANALYSIS:

Generally, when a mooring analysis is to be conducted, the drill site has been identified
and the analysis is used to screen possible rig candidates. However, there are situations
when a rig has been identified and the analysis is used to determine the environmental
and water depth limits of that rig. In this situation, the analysis may identify rig
modifications such as adding chain or larger anchors to improve the rigs stationkeeping
capabilities. Information on mooring equipment specifications for the analysis may found
in the rig contract or by consulting the rig OIM/Barge Engineer. The OIM/Barge Engineer
ca n a lso p ro vid e in fo rm a tio n o n th e ir o p e ra tin g p ro ce d u re s/p ra ctice s, th e e q u ip m e n ts
working limits, and any company policies regarding mooring/stationkeeping. Additionally,
information/specifications can be found in the Mobile Drilling Units database, rig
co n tra cto rs w e b site o r th e 4 0 + rig d a ta b a se cu rre n tly in clu d e d in th e D rillM o o r p ro g ra m .

The Mobil Units database will be available on the intranet in the coming months.

The DrillMoor program is an in-house software developed by ExxonMobil (Stan

Christman) and can be found by going to the Windows Start button/
Engineering/Drilling Design & Surveillance/Floating Drilling/DrillMoor.
The following is a summary of the information is required for a mooring analysis:

PROPOSED MODU HEADING

Due to the varying geometry of a drilling rig, environmental loads on the mooring system
during operations can be greatly affected and significantly reduced by adjusting or
a lig n in g th e rig s h e a d in g so th a t th e p re d o m in a n t e n viro n m e n t (w in d , w a ve s, cu rrent)
contacts the vessel on the bow. This is especially true in areas of high surface currents
such as the Gulf of Mexico where loop/eddy currents are present. The heading can also
be adjusted to increase the distance between an anchor and any submerged equipment
such as pipelines. Factors to consider before changing the heading include the location
o f rig s co m m u n ica tio n e q u ip m e n t (sa te llite ), p ro vid in g a sh e lte re d e n viro n m e n t o n a
leeward side during workboat loading/offloading operations, and access to the primary
crane.

PROPOSED ANCHOR PATTERN

Similarly to the rig heading, changing the anchor pattern can reduce loads on different
mooring components or provide greater separation between an anchor or mooring line
and a subsea obstacle. Each rig will have a particular mooring pattern for its design, but
there are situations where a change in the pattern may be acceptable. This change may
be needed to reduce the environmental loading on a single component or to provide
greater separation between a mooring leg and a subsea obstacle such as a pipeline. For
instance, a rig with a designed pattern of 30-60 might be skewed to 23-67 in order to
maximize the distance from subsea equipment and one of the anchors.

DETAILED FIELD MAP, WATER DEPTH, AND BATHYMETRY:

A detailed field plat showing water depth contours, old wells, pipelines, subsea
equipment, and anchor exclusion zones should be obtained for each location. In special
cases (i.e. taut mooring design), other geotechnical data such as shallow geology, side-

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scan sonar records, soil strength data should be obtained for the analysis. A survey
contractor like Racal, Fugro, or John Chance can provide field maps with subsea
obstructions.
A simple Excel spreadsheet can be developed to evaluate several mooring patters and
rig headings. This data should include any subsea equipment or obstructions and can be
plotted in the X & Y coordinate system. See Figure 6.64.

Proposed Anchor Location

Diana Northern Drill Site

9830000

9825000
8
1
Rig Heading 20 Deg.
7
9820000
Northing, ft

2
9815000
6

Pipe Line

9810000

3
5
9805000

Pipe Line 4
Pipe Line

9800000
1015000 1020000 1025000 1030000 1035000 1040000 1045000 1050000
Easting, ft

Figure 6.64 Rid Heading/Mooring Pattern Graph

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ENVIRONMENTAL DATA
Environmental data is usually obtained from ExxonMobil Upstream Research Company
(URC) and can be a long lead-time item. Depending on the location, the environmental
data that is available may be limited and is usually analyzed over the entire year. For
short-term operations, this data may be conservative unless the operations are to be
conducted during the months of extreme weather.

ENVIRONMENTAL CRITERIA
The industry recognizes two classifications of environmental conditions when evaluating
mooring systems: maximum design condition and maximum operating condition. The
crite ria to b e u se d w ill b e d e te rm in e d b a se d o n th e rig s p ro xim ity to o th e r o ffsh o re
installations/subsea equipment. For rigs operating near other offshore installations,
where the consequence of a mooring failure would be higher, a 10-year return period is
used. A further explanation of determining the environmental criteria is provided in
Section 6.8.5.

RIG SPECIFIC DATA

1. Environment Coefficients: These can either be calculated based on API RP
2SK Appendix A or by using model-testing data for the specific rig. The DrillMoor
program will automatically calculate the coefficients using the rig dimension or
you can manually input the model data. DrillMoor also has a database of rig
design types with average coefficients that can be selected. See Section 6.8.3 on
environment coefficients.
2. Survival and Operating Draft: Published data from rig contractor.
3. Survival and Operating Displacement: The DrillMoor program will
automatically calculate the displacement using the rig dimension. The calculated
value can then be compared to the published rig data.
4. Rig Drawing and Principal Vessel Dimensions: The DrillMoor program lists
the required vessel dimensions. Once the dimensions are entered, the vessel
displacement calculation can be compared to the published data.
5. Equipment Specifications: These will include anchor type/weight, wire/chain,
mooring line map including all connectors, winches/windlass, and thrusters.
The following Mooring Analysis Data Sheet (Figure 6.65) was developed as a checklist
for information required to conduct an analysis.

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MOORING ANALYSIS DATA SHEET

Rig Name: Well Name:
Normal Mooring Pattern:
Country: Mooring Leg

ANCHORS 1 2 3 4 5 6 7 8

Type

Weight (kips)

Fluke Setting
(degrees)
Bolster Angle
(degrees)
CHAIN

Size (in)

Weight in air
(lbs/ft)

Grade

Usable Length
(ft)
Breaking Strength
B T L (kip s)
WIRE ROPE

Size (in)

Usable Length
(ft)
Breaking Strength
C T B (kip s)
Weight in air
(lbs/ft)
Winch / Windlass / Winch Type
Tension Capacities Drum / Traction
Stall (kips)

Figure 6.65 - Mooring Analysis Data Sheet - Page 1 of 2

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MOORING ANALYSIS DATA SHEET

VESSEL DIMENSIONS
(ASSUMING RIG IS NOT LISTED IN DRILLMOOR PROGRAM)
Pontoons Draft
Height (ft) Survival (ft)
Length (ft) Operating (ft)
Width (ft)
1 2 3 4 5 6 7 8
Column Diameter
(in)
Vessel Dimensions (all elevations relative to keel)
Main Deck Length (ft) Derrick Elevation (ft)
Main Deck Width (ft) Derrick Width (ft)
Main Deck Elevation to Top Brace Trans Elevation (ft)
(ft)
Main Deck Elevation to Brace Trans Diameter (ft)
Bottom (ft)

Deck Houses 1 2 3 Brace Diagonal Diameter (ft)

Elevation

Length (ft) Displacement Survival (mt)

Width (ft) Displacement Operating (mt)
Environmental Data / Coefficients (kips/knot2)

Bow Beam Quartering Bow Beam Quartering

Wind - Operating Current - Operating

Wind - Survival Current - Survival

1 2 3 4 5 6 7 8
Water Depth at
radius 2 x WD , ft
Water Depth at Seafloor Type Well Location X&Y / Grid (ft)
Well Location (ft) (clay / Sand) X: Y:
Thruster Output Seafloor Obstruction Well Location Lat / Long
(kips) (attach Plat)
Thruster Yes / No (Yes / No) Lat: Long:
Azumuthing
Desired Rig
Heading
(degrees grid)

Figure 6.65 - Mooring Analysis Data Sheet - Page 2 of 2

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6.8.7 RESULTS OF THE MOORING ANALYSIS

The mooring analysis is somewhat of an iterative process. Once you have input the data into
DrillMoor, it is then a matter of running cases with varying line lengths, rig headings, and
operating tensions to meet the design criteria. The analysis results will include:
line tensions,.
anchor loads.
vessel offsets.
and suspended line lengths.
From the results, a recommendation on the following can be made:
mooring pattern.
rig heading,.
line lengths,.
anchor test tension,
The anchors shall be tested to the Maximum Design case load (mean value, i.e.
without surge). If the anchors are high efficiency type (Stevpris, Bruce FFTS), a
test load of 1/3 the anchor capacity may be used.
operating and mooring test load.
and operating and survival strategy.
It is possible that line slackening is needed to meet the design criteria. Any rig upgrades,
modifications, and risk issues can also be identified during the analysis.

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6.9 ANCHOR HANDLING VESSELS (AHV)

A mooring deployment analysis determines AHV requirements. The following summary
describes the various AHV sizes, equipment, and applications. The DrillMoor program
contains a module on anchor deployment/recovery. The equipment specification for over
40 AHVs are included in the program. The AHV contractor can also provide the vessel
equipment specifications.
A n im p o rta n t ch a ra cte ristic o f th e A H V s is th e B o lla rd P u ll. B o lla rd p u ll is th e m a xim u m
continuous pulling force that the workboat can exert when pulling against a stationary
object at zero forward speed. The bollard pull of a particular ship is a function of the
horsepower available to the propellers, the hull design and the environment, etc. The
rated Bollard of a ship is determined experimentally by the ship pulling against a
stationary object (anchor on the seafloor, pile, etc) in a calm wind and seastate and
measuring the line tension. Factors which can reduce bollard pull are vessel heading
relative to th e p u ll, re d u ce d e fficie n cy o f th e p o w e r p la n t w ith u se a n d e n viro n m e n ta l
condition. Heavy seastate and winds can have a large impact on the bollard pull of an
anchor handling vessel or a tug. Bollard efficiency in all operations is typically 90%.

There are numerous AHV sizes and manufacturers, but for this summary, they will be
divided into 3 classes (small, medium, and large).
Small: > 6000 BHP or 80-90 Tons Bollard Pull.
Medium: 6000 12000 BHP or 90-165 Tons Bollard Pull.
Large: > 12,000 BHP or 165 200 Tons Bollard Pull.
The following equation converts break horse power to bollard pull:
(BHP x 27.5 )/1000 = Bollard pull (kips)
AHVs are equipped with multiple winches of various sizes and tensioning capabilities.
Currently the largest conventional wire wrap winch is capable of 1,000,000 lbs of pull
(bare drum). Keep in mind that, as the layers increase on the winch drum, the tension
capacity decreases. There are a few AHVs that are equipped with traction winches.
These winches have the maximum pull always available.
Anchor handing vessels should be equipped with a stern roller and a shark jaw or
equivalent remote controlled pendant holding device. They should have sufficient
bollard pull and winch pull for the intended operation. These needs can be assessed
with DrillMoor.

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The shark jaw, is a hydraulically operated mechanical stop that can support the weight
of line outboard of the vessel while connections are made. The pop up pin (or guide) is
a set of hydraulic operated alignment rollers (vertical) that keep the mooring line/work
wire centered on vessel. The stern roller is a heavy-duty cylinder made into the stern of
the vessel that will turn/roll, as the line is dragged across. This reduces wear on the
mooring components and to the stern of the AHV (Figure 6.66).

Figure 6.65 - AHV Deck Layout

The water depth and associated line loads will generally dictate the AHV size
requirements. For instance, in shallow water the mooring line may be all chain and the
suspended load minimal. Therefore, the winch capacity of the AHV will not be as critical
as the bollard pull. The bollard pull on the other hand will be critical since the AHV must
drag the chain across the seafloor during the stretch out. In deepwater both the winch
size and bollard pull are important.
Figures 6.67 and 6.68 illustrate a medium size AHV.

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Figure 6.67 - Decking Anchor

Figure 56

Figure 6.68 - Preparing to inspect mooring connections at anchor

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6.10 MOORING DEPLOYMENT PROCEDURE

By the time of deployment, all of the site-specific information should be known. There
are a few naming conventions that are important to writing an effective procedure. The
first is the anchor numbering convention (Figure 6.69). The outside anchors are called
point (or main) anchors and the inside anchors are called breast anchors. The typical
numbering convention is that the point anchor on the forward starboard side is the
number one anchor. The remaining anchors are numbered clockwise. The numbering
convention should be discussed with the contractor prior to writing any procedures to
avoid confusion. The default numbering system in the DrillMoor program is the breast
anchor on the forward port side is the number one anchor. The remaining anchors are
numbered clockwise.

Rig Heading
8
1
7

Breast Anchors

Point
6 (main) 3
Anchors

5 4

Figure 6.69 Anchor Numbering Convention

The normal convention is to run out the point anchors first followed by the breast
anchors. Once the first point anchor is set, the next anchor would be the one on the
opposite side of first anchor deployed. For instance if the number four anchor is ran first,
the next anchor would be the number eight (for a eight line mooring system). Then the
next set of opposing point anchors would be run. The reason for running the anchors in
such a manor is to have the first anchors maintain station as soon as possible. Weather
conditions and subsea equipment will also drive which set of anchors is set first.
The following is a summary for setting anchors in 1000 ft to 5000 ft of water with drag
embedment anchors and a chain/wire combination system.

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6.10.1 MOVING RIG ONTO LOCATION

The rig is moved onto location with either a tug or a tug/AHV combination. The number
and size of vessels required for the rig move are usually stated in the rig contract. Prior
to arriving on the location, the tugs and AHV are positioned for deployment of the first
anchor. The rig is then towed onto location taking into account the weather and desired
final rig heading.
If two AHVs and a tug are used, an AHV would be positioned on each of the first two
anchors to be deployed approximately five miles from location and towed the final
distance. The AHV on the stern anchor will steer the rig while the AHV/tug on the bow
tows the rig over the location. If the rig is equipped with thrusters, they are used to
steer the rig.
Prior to reaching location, the weather heading should be monitored so that the drift of
the rig during mooring operations can be taken into account. If subsea obstructions are
at the location, the rig should be positioned so that the fairleads are never over any
obstructions during deployment or recovery of the moorings.

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6.10.2 ANCHORING SEQUENCING

At the start of the anchoring sequence, the rig crane will pass the PCC wire to the AHV.
The AHV will first connect the PCC wire to the work wire on the AHV. The winch
operator on the rig will then start to pay out chain/wire from the rig in order to unbolster
the anchor. The AHV will maintain tension on the work wire so that the chase collar does
not slide down over (off) the shank of the anchor as it is unbolstered. This will prevent
the anchor for spinning and ensure that it is in the correct alignment for deployment
(Figure 6.70). In some cases, the anchor will be decked on the AHV so that the
connections on the anchor can be inspected. The anchor can also be pulled up to the
stern roller of the AHV so that the crew can make sure the chase collar/shank are in the
correct position for deployment.

AHV receives PCC wire from rig crane

PCC is secured in AHV shark jaw and rig crane is released
PCC is connected to AHV workwire string by a connecting link
AHV uses bollard pull to apply tension to PCC and keep chaser at anchor shank
Rig winch begins controlled pay out of mooring system

Figure 6.70

One of the two stern point Canchors will

ONVENTIONALCATENA be
RYANCHO the
RMOORING first anchor set. Time the setting of this
anchor such that when it lands on bottom, the rig will be over the drill location. The
anchor will act as a brake. Typically, the rig will pass one of the stern anchors to an AHV
ju st b e fo re th e rig is o ve r th a t a n ch o rs se ttin g p o sitio n . T h e n a s th e rig m o ve s fo rw a rd
toward the drill site, the rig will pay out chain/wire for that anchor as the AHV maintains
its position over the drop site. The rig and AHV will time the setting of that anchor such
that the anchor hits bottom as the rig reaches the drill location. The second anchor set
will be the point anchor on the bow of the rig, opposite to the first anchor set. After the
second anchor is set and the rig is over the drill site, the remaining anchors will be set in
pairs (2 opposing anchors), if two AHVs are used.
Once all the chain has been run, the rig will need to cross over to wire. This is
accomplished via the Tri-Link and chain/wire connection (See Figure 6.4). The Tri-Link
is located in the chain leg approximately 100 ft from the end (the end is referred to as the
bitter end). The chain pay-out stops once the Tri-Link comes over the windlass and is
just above the crossover platform. A short piece of chain is connected to the wire from
the winch. This chain is connected to one eye of the Tri-Link. The windlass then pays out

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another 1 to 2 feet of chain and the load is transferred to the winch. The chain from the
windlass can then be disconnected at the Tri-Link and the deployment process
continues via the wire/winch (See Figure 6.71).

AHV proceeds out along proposed rig bearing of mooring line

AHV maintains


tension on anchor as rig winch pays out chain

Perform transition

from chain to wire (if applicable- AHV may reduce bollard
pull at this stage to minimize load on rig)
AHV winch pays out work wire and rig pays out mooring line simultaneously, if
possible. Otherwise, load sharing sequences are initiated

Figure 6.71

CONVENTIONAL CATENARY ANCHOR MOORING

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The amount of work wire used during deployment is critical to ensuring the anchors are
set and holding. The rule-of-thumb for the work wire length during deployment is 1.3
times the water depth. The AHV will have an electronic depth finder on board, but it is
important to include the estimated depth at each anchor location in the deployment
procedure to expedite the process. After the rig has deployed the designed length of
chain/wire and the AHV has deployed 1.3 times the water depth of work wire, the anchor
will be just past the setting location. The winch operator on the rig will read a tension
approximately equal to weight of the mooring chain/wire paid out (assuming all the line is
suspended). To stretch out the mooring leg, the AHV will increase power until bollard
power and the winch tension will approximately equal the weight of the work wire, PCC
w ire , a n d th e a n ch o r. T h is is ca lle d stre tch in g o u t. T h e A H V w ill re m a in a t th is p o w e r
setting until forward movement of the AHV stops. If the job is designed correctly, the
anchor will be 100ft 200ft off bottom (See Figure 6.72)

Rig has


all mooring line paid out, rig winches are secured
AHV pays out workwire until 1.3 x WD
AHV increases bollard power to stretch line until clear of seafloor
stre tch o u t o r u n til b o lla rd p u ll o f ve sse l p ro vid e s m a xim u m
achievable tension on mooring line.

Water Depth
not to scale

Figure 6.72

CONVENTIONAL CATENARY ANCHOR MOORING

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Once the mooring line has been stretched out, the AHV will quickly reduce bollard power
to 10-20%. The weight of the mooring line will drag the AHV backwards as the
anchor/line fall to the seafloor. As the anchor is falling, the catenary shape of the
mooring line will also pull the anchor toward the rig. The AHV will communicate to the rig
that the anchor is on bottom, and the coordinates of the rig and AHV should be noted.
If all went well, the anchor will embed in the seafloor and the rig winch will still have
tension. An estimate of the final anchor location should be made to within + or -100 ft.
This is done by taking the horizontal distance from the rig to the AHV and subtracting
out the distance the AHV is from the anchor (See Figure 6.73). The DrillMoor program
can be used to make this calculation. This information will be critical in recovering
the anchors.

AHV now reduces

power to allow anchor to set on seafloor before
the catenary of mooring line falls toward the rig.
The rig may now heave in to a satisfactory tension while the
chaser is returned to the rig.

Figure 6.73

Once the anchor is on bottom, the AHV will then chase the PCC wire back to rig. It is a
good practice to tension up with the rig winch to load the anchor to a value at least equal
to its weight while the AHV isCONVENTIONAL
chasing in. CATENARY ANCHOR MOORING
This is to ensure that the anchor is set correctly
before the AHV moves to the next anchor. The DrillMoor program can be used to
determine the appropriate winch tension and the resulting anchor tension (line weight,
anchor weight, and seafloor drag must be taken into account).
For deepwater mooring operations, it is necessary to ensure that the chase wire is tight
on the drum before deploying each anchor. If the wire is not tight on the drum, the weight
of the mooring leg may cause the wire to become entangled on the drum or to slip during
later high load payout. If needed, to tighten the wire on the drum, the AHV will redeploy
the wire after taking the PCC for the next anchor and re-spool the wire while maintaining
sufficient bollard pull to tighten the wire.

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6.10.3 PROOF LOADING/OPERATING TENSIONS

Each anchor will be proof tested once all of the anchors have been deployed. The
anchors will be tested to the design load determined from the mooring analysis. The
anchors will be tested in pairs (opposing anchors) so that the winch has something to
pull against. The first anchors that were deployed should be the first tested since they
have had the longest time setting into the seabed. The proof load tension should be held
for 15 minutes. It is a good practice to have the winch operators record the line hauled in
vs. tension. It is easier to determine if an anchor is not set properly from the graph of this
data. Anchors should not drag more than 100-ft in setting (See Figure 6.74). Once the
first pair of anchors have been successfully proof tested, their tensions will be reduced to
the operating tension.

Mooring Line Out vs. Winch Tension

Anchor Test Loads
600

Anchor #4
550
Anchor #5

Anchor #6

500 Anchor #7

Anchor #8
Winch Tension, Kips

450

400
Anchor #8 Slipping

350

300

Hauling line in to test anchors

250
9300 9200 9100 9000 8900 8800 8700 8600
Mooring Line Outboard, ft

Figure 6.74 - Anchor Proof Loading Graph

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6.11 ANCHOR RECOVERY PROCEDURES

At the start of the recovery sequence, the rig crane will pass the PCC wire to the AHV.
The AHV will first connect the PCC wire to the work wire. The first anchors recovered will
be the breast anchors. The last anchors recovered should be the ones that will best
maintain station under the current weather conditions. The rule-of-thumb for the work
wire length during recovery is 1.2 times the water depth. The rig should remain at the
operating tension (minimal line on bottom) so that chase collar can easily slide down to
the anchor. The AHV will increase the bollard power to ensure that the chase collar is on
the anchor. Once the chase collar is on the anchor, the AHV will reduce bollard power
and haul in the work wire to scope of 1.1 times the water depth. The AHV will then slowly
increase the bollard power so that the resulting line load is equal to 50% of the work wire
breaking strength. The goal is to impart the maximum uplift at the anchor with the AHV
while the rig imparts a horizontal load to cause it to fail (unseat more toward rig). It
may take several attempts to unseat the anchor. Each time the AHV will haul in another
50-ft. It will take less bollard pull to impart 50% of the work wire breaking strength, as the
scope is decreased. There is a fine line between applying the maximum uplift at the
anchor and staying below the breaking strength of the work wire. In most cases,
patience is more important than horsepower.
After the anchor is unseated, the rig will start to haul in the chain/wire. Once all of the
mooring line has been hauled in, the anchor will be bolstered and the AHV will pass the
PCC back to the rig.

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6.12 SPECIAL OPERATIONS/NEW TECHNOLOGY

6.12.1 PRE-SET MOORING SYSTEMS
If a situ a tio n re q u ire s u p g ra d in g a rig s m o o rin g syste m fo r a d e sire d w a te r d e p th o r a s
special location conditions dictate, it may be cost effective to pre-install an enhanced
mooring system for the rig to use at that drilling location. Anchors, chain and wire can be
installed on the location prior to rig arrival and out of the "critical path" time of rig
operations. Some of the rig's standard mooring components may need to be removed
prior to arrival at the present location. Once the rig arrives at the drilling location, the
rig s m o o rin g e q u ip m e n t is th e n co n n e cte d to th e p re in sta lle d syste m w ith o n e o r tw o
anchor handling vessels. A single anchor-handling vessel can install each leg of the
preset mooring system.
The mooring leg components are transported to location and deployed at the designated
coordinates. Surface buoys are commonly attached to each pre-deployed leg for
recovery when the rig is connected. Once the rig arrives on location, the anchor handling
vessels connect the rig to the pre-installed mooring lines.
T h e d isco n n e ctio n o f th e rig is a cco m p lish e d in a sim ila r m a n n e r w ith e ith e r th e rig s
mooring components being reinstalled or the rig being moved to another preset
mooring system.
A preset system may allow the rig connection to be completed in less time than is
required to run the rig's own mooring system. However, this is influenced by whether the
rig s o w n m o o rin g co m p o n e n ts h a ve to b e re m o ve d o r re in sta lle d o n th e rig a n d va rio u s
other factors that may affect the mooring procedure. Any potential time savings should
be weighed against the cost of the preset system.
Water depth, length of well drilling schedule, and vessel and rig day rates all play a
significant role in determining the economics of a pre-set scenario. Generally, it is most
economical to use the rig's own moorings. The preset system becomes economical
w h e n it is n e ce ssa ry to su p p le m e n t th e rig s m o o rin g s to a sig n ifica n t d e g re e , b e yo n d
the simple extension wire addition, or if seabed features or pipeline interference make
conventional anchor deployment impractical.

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6.12.2 INSERT WIRE MOORING SYSTEM

F o r lo ca tio n s w h e re th e w a te r d e p th o f th e rig s co n ve n tio n a l ca te n a ry m o o rin g syste m is
not sufficient, the length of the mooring legs can be extended with the addition of
extension wires in each mooring leg. This enhancement extends the length of the
mooring legs for the rig, thus allowing the rig to operate in greater water depths. This
process is typically used with a rig equipped with an all chain mooring system.
The process of accomplishing this upgrade requires two anchor handling vessels, each
equipped w ith a sharks jaw or equivalent. O ne vesselis required to installthe extension
wire into the mooring leg while the other vessel deploys the mooring leg. The process begins
with one anchor handling vessel receiving the rig chaser and holding the anchor while the rig
deploys chain to a predetermined length. The second vessel catches the mooring chain with
a j-lock chaser and brings the mooring chain on the deck of the AHV. The rig chain is taken
apart at a designated point, and a section of wire is inserted and connected back to the rig
chain. The anchor is then pulled out to the proposed anchor drop point and lowered to the
seabed. The rig tensions the mooring leg to apply the required tension with the chain in the
windlass. With the exception of inserting additional wire, the mooring operation remains the
same as the conventional catenary mooring. Recovery of the mooring leg is the reverse of
the installation.
With this operation, the time required to set or recover the extension wire mooring leg is
approximately 12 hours per leg in extreme water depths with multiple extension wires;
thus allowing two anchor handling vessels to complete this operation in 96 hours.
Influences from water depth, weather and rig operation are similar to the conventional
catenary mooring operation.

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MOORING DESIGN AND OPERATIONS

6.12.3 LINE MANAGEMENT

Crew intervention in mooring management is to be minimized during normal drilling
operations. However, line adjustments are often made to maintain the mean position of the
vessel over the desired location as the weather changes. In areas with high variations in
operating environment such as off the mouth of the Amazon and Trinidad, frequent line
management may be necessary to maintain the vessel within the appropriate watch circle.
Line management usually consists of a combination of paying out leeward lines to reduce
winch loading and pulling in weather lines when possible. When a rig is evacuated in
preparation for a storm, all lines are adjusted a predetermined amount before leaving the rig.
There must be sufficient chain outboard of the fairlead and in the MODUs chain lockers to
accommodate adjusting the position of the MODU within the mooring spread to provide
adequate adjustment. The typical adjustment length is 300 ft. In addition, periodic adjustment
(i.e. weekly) of wire system is desirable to avoid concentrated fatigue from the fairlead at one
place in the wire. If multiple wells are going to be drilled from one spread, added adjustment
capability must be provided.

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6.12.4 SAFE ZONE

In development drilling, there is subsea equipment such as templates, flow manifolds, and
wellheads that could be damaged if something were dropped from the rig. For this reason, a
safe zone is designated from where all heavy lifts should be made. See Figure 6.75. Line
management is used to offset the rig from the drill site and into the safe zone. The safe zone
location should be addressed during the risk assessment and the following items should be
considered:

Distance and direction to the safe zone.

Can the safe zone be reached by operating four winch/windlasses

(direction of safe zone between opposing point and breast anchors)?
This will expedite the moving the rig.

Can the primary crane be utilized from the safe zone?

Safe Zone

Figure 6.75 - Safe Zone Established for Multiple Well Drill Site

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MOORING DESIGN AND OPERATIONS

6.12.5 SUCTION ANCHOR MOORING

A new advancement in preset mooring system for ultra-deepwater is the Suction Anchor
System. This recently developed mooring system uses a suction caisson as the anchor. The
caisson is cylindrical in shape with the bottom end open. Embedment of the anchor is
accomplished by using an ROV to pump water out of the top of the caisson until it is fully
penetrated into the seabed. The process is simply reversed to recover the anchor.
The advantage of the suction anchor mooring system is the anchor's ability to hold at
higher uplift angles, thereby reducing the circumference of the mooring pattern and
reducing the watch circle maintained by the rig. The Suction Anchor System provides
excellent performance in ultra-deepwater and allows a rig to significantly extend its water
depth capability.
Another advantage of the suction anchor is the ability to target an exact location, soil
holding properties and alignment to the rig, allowing confidence in its ultimate holding
capacity. A rig and location specific mooring analysis can determine the desired
configuration for each system.
Installation of the Suction Anchor System (Figures 6.76, 6.77 and 6.78) is accomplished
prior to rig arrival by one vessel with ROV capability. The anchor is positioned
overboard, lowered and pumped into the seabed. The mooring line is attached and
suspended with a surface or submersible buoy. Once the rig is on location, it is
connected to the mooring legs by one or two anchor handling vessels in a short amount
of time, typically three to four hours per leg. The recovery of the system is a simple
process with the suction anchor being pumped out of the seabed and recovered over the
stern of the vessel.
The limitation of the system is the need to install the anchors with a vessel fitted with an
ROV for anchor installation and mooring line connection. Another disadvantage of this
system is the time associated with setting the piles. Because the piles are so large, the
AHV can only handle a few piles at a time, therefore it takes several trips back to shore
to complete the operation. The typical suction pile size is 12 ft diameter by 60 ft long and
9-1/2 ft diameter by 70 ft long. On a recent job in the GOM at a water depth of 9000 ft ,
the first 4 suction piles were set in 17 hours and the remaining 4 were set in 19 hours.
But a 77 hour round trip to shore to load the last 4 piles was required, so the total job
time was 113 hours.
In a recent survey of venders (01/01/02) the costs associated with suction anchors
are as follows:

To buy 9-1 /2 b y 7 0 syste m is $ 2 2 5 k 275k/anchor

To rent 9-1 /2 b y 7 0 syste m is $ 1 9 5 250/anchor/day

In 2002, a MODU was moored up with suction piles/polyester inserts in 9000-ft of water
in the GOM.

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MOORING DESIGN AND OPERATIONS

Figure 6.76 Deploying Suction Pile

Figure 6.77 Setting Suction Pile

Figure 6.78 Connecting rig to Suction Pile

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MOORING DESIGN AND OPERATIONS

6.12.6 SEPLA
The Suction Embedded Plate Anchor or SEPLA is a newly developed anchor system that
uses a suction follower (similar to a suction pile) to embed a plate anchor. The suction
follower is immediately retracted once the plate anchor is brought to design soil depth and
can be reused to install additional plate anchors.
The SEPLA consists of a rectangular fluke with a full-length keying flap running along its top
edge (Figure 6.79). The keying flap is mounted with an offset hinge such that soil pressure
along its top edge will force the flap to rotate with respect to the fluke, effectively quadrupling
the vertical end bearing area and preventing it from moving back up its installation track when
tensioned. The mooring line is attached to the fluke by means of twin plate steel shanks.
For installation, the SEPLA is mounted in slots at the bottom of the follower and retained by
the mooring line and recovery bridle (Figure 6.80). The mooring line is connected to the
SEPLA and the top of the suction follower during the deployment and is spooled off a winch
installed on either the SEPLA installation vessel or a separate AHV (Figure 6.81). The
suction follower, with the SEPLA slotted into its base, is lowered to the seafloor, allowed to
self-penetrate and then suction embedded in a manner similar to a suction pile. Once the
SEPLA has reached its design penetration depth, the mooring line and retrieval bridle that
hold the SEPLA secure in the bottom of the follower are released by the installation ROV.
The pump flow direction is then revered and water is pumped back into the follower. The
follower moves upward, leaving the SEPLA in place (Figure 6.82). Tension in the follower
recovery wire, in combination with the positive pressure provided by the pump, will extract
the follower from the seafloor. The follower is then recovered to the installation vessel for
deployment of the next SEPLA.
At this time, the mooring line is tensioned by the installation vessel in the direction that the
S E P LA is to be loaded. T his keying tension w ill:

Pull the initially vertical mooring line through the soil so that it forms the classic
inverse catenary shape from the mudline to the anchor shackle.

Start rotation of the SEPLA fluke to an orientation perpendicular to the direction of the
mooring line at the end.

Set the keying flap to prevent further loss of penetration beyond that which is
necessary to set he keying flap.
The SEPLA is now ready to develop its full pullout capacity. Regardless of the initial
orientation of the fluke to the mooring line, the SEPLA with its long, rigid shank will rotate to
present the maximum projected area to the direction of pull ensuring ultimate pullout capacity,
based on the anchors penetration depth and soil properties, is achieved.
Full scale offshore testing of the SEPLA in 1999 resulted in a successful test of 543 kips
tension at the anchor.
In a recent survey of venders (01/01/02) the cost associated with the SEPLA system is
as follows:

To buy system is $80k to $90k per anchor, no rental information was available.
In 2001, a MODU was moored up with SEPLA anchors/polyester inserts in 6200-ft of
water in the GOM.

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MOORING DESIGN AND OPERATIONS

Figure 6.79 - SEPLA and Follower on AHV deck

Figure 6.80 - SEPLA loaded into Follower

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MOORING DESIGN AND OPERATIONS

Figure 6.81 - SEPLA system lowered over AHV stern roller (notice A-frame)

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MOORING DESIGN AND OPERATIONS

Figure 6.82 - SEPLA System

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MOORING DESIGN AND OPERATIONS

6.12.7 VERTICAL LOAD ANCHOR (VLA)

The Stevnamta VLA is a new design in which a traditionally rigid shank has been replaced by
a system of wires connected to a plate(Figure 6.83). The anchor is designed to accept
vertical (or normal) loads and is installed as a conventional drag embedment anchor with a
horizontal load to the mudline to obtain the deepest penetration possible. By changing the
point of pulling at the anchor, vertical (or normal) loading of the fluke is obtained thus
mobilizing the maximum possible soil resistance (Figure 6.84). As a VLA is deeply
embedded and always loaded in the direction normal to the fluke, the load can be applied in
any direction. Consequently the anchor is ideal for taut-leg mooring systems.

Figure 6.83 - Top view of Stevmanta VLA

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MOORING DESIGN AND OPERATIONS

Figure 6.84 Side and end view of Stevmanta VLA

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MOORING DESIGN AND OPERATIONS

6.12.8 SYNTHETIC FIBER ROPE

A recent development is the use of synthetic fiber ropes as mooring line. Typical
materials that can be used are polyester and high modulus polyethylene (Dyneema).
The major advantage of the synthetic fiber ropes is the light weight of the material and
the high elasticity (to absorb energy in a taut mooring system). The synthetic fiber rope
is generally terminated with a special spool and shackle for connection to other
components in the mooring system (similar to a wire insert). Since this is a relatively new
product in the offshore industry, historical performance data is limited. Table 6.10
contains the published breaking strengths for various sizes of polyester rope.

Diameter Breaking Air Weight (lb/ft) Water Weight (lb/ft)

(in) Load (kips) @ 2% MBL @ 20% MBL @ 2@ MBL @ 20% MBL
4.45 809 5.85 5.47 1.40 1.31
5.10 1102 7.67 7.17 1.84 1.71
5.54 1323 9.02 8.43 2.16 2.01
6.06 1616 10.8 10.08 2.58 2.41
6.54 1911 12.57 11.72 3.01 2.8
7.09 2277 14.76 13.75 3.53 3.29
7.50 2573 16.49 15.37 3.94 3.68
8.07 3014 19.09 17.78 4.56 4.25
8.51 3380 21.24 19.78 5.08 4.73
9.02 3821 23.81 22.16 5.69 5.3
9.49 4261 26.37 24.54 6.31 5.87

Table 6.10 Polyester Rope Data

The synthetic fiber rope is either rented in a long-term contract (four to five years) or
purchased from the supplier.
In a recent survey of venders (01/01/02), the costs associated with synthetic systems
are as follows:

Rent 9500ft x 8 legs is $6500 to $7000 /day (4-1/2 year contract)

Purchase 2500 ft x 8 legs is $485k

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MOORING DESIGN AND OPERATIONS

REFERENCES
Exxon Upstream Design Guidance Manual, Section III Mobil Offshore Unit Mooring
Systems, located on the LAN: I:\EMDC\Drilling\Technical\Tech
Library\Manuals\Design Guidance\Mooring.PDF

API RP 2SK, Recommended Practice for Design and Analysis of Stationkeeping

Systems for Floating Structures, Second Edition, December 1996 (Effective March 1,
1997).

API RP 2I, Recommended Practice for In-Service Inspection of Mooring Hardware

for Floating Drilling Units, Second Edition, November 1, 1996.

API Spec 2F, Specification for Mooring Chain, Sixth Edition, June 1, 1997.

The Inspection and Discard of Wire Mooring Lines, Supplement for Participants in a
JIP on an Appraisal of Discarded Mooring Ropes, Noble Denton & Associates,
London, December 1992.

Guide for the Certification of Offshore Mooring Chain, American Bureau of Shipping,
1999.

Certification of Offshore Mooring Chain, DnV Certification Notes No. 2.6, August
1995.

Final Draft UR Offshore Mooring Chain, International Association of Classification

Societies, November 6, 1992.

API RP 2M, Recommended Practice for Qualification Testing of Steel Anchor

Designs for Floating Structures, May 1, 1996.

API RP 2Q, Recommended Practice for Design, Selection, Operation and

Maintenance of Marine Drilling Riser Systems, November 1, 1993.

Dunnavant, T. W., and Kwan, C-T. T., Centrifuge Modeling and Parametric Analyses
of Drag Anchor Behavior, OTC Paper 7202, Houston, May 1993.

Bruce Anchor Group: www.bruceanchor.co.uk

Vryhof Companies: www.vryhof.com

Vryhof Anchor Manual 2000, Global Share/Drilling Technical Share/Library/Mooring

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 7
OPEN WATER OPERATIONS
Section

7.0 OPEN WATER OPERATIONS

OBJECTIVES
On completion of this lesson, you will be able to:

List the typical scope of work for an ROV supporting drill rig operations.

List the types of guidance systems used for floating drilling operations and the
advantages of each.

List the two methods for spudding a subsea well and describe the differences.

List forces involved on structural casing and design requirements for structural
casing.

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OPEN WATER OPERATIONS

CONTENTS Page

7.0 OPEN WATER OPERATIONS .......................................................................................................... 1

OBJECTIVES ..................................................................................................................................... 1
CONTENTS........................................................................................................................................ 2
7.1 REMOTELY OPERATED VECHILES (ROVS).................................................................................. 4
7.1.1 INTRODUCTION ................................................................................................................ 4
7.1.2 TYPICAL SCOPE OF WORK ............................................................................................. 5
7.1.3 ROV TYPE ......................................................................................................................... 6
7.1.4 ROV OPERATIONS ........................................................................................................... 8
7.1.5 DRILLING ENHANCEMENTS TO ASSIST ROV OPERATIONS ..................................... 11
7.1.6 ROV LIMITATIONS.......................................................................................................... 11
7.1.7 ROV TERMS .................................................................................................................... 12
7.2 WELLHEAD COMPONENTS FOR OPEN WATER OPERATIONS ............................................... 13
7.2.1 GUIDANCE SYSTEMS .................................................................................................... 16
7.2.2 GUIDELINE SYSTEM ...................................................................................................... 16
7.2.3 GUIDELINELESS SYSTEM ............................................................................................. 18
7.3 STRUCTURAL CASING ................................................................................................................. 20
7.3.1 INTRODUCTION .............................................................................................................. 21
7.3.2 DESIGN CRITERIA OVERVIEW ..................................................................................... 22
7.3.3 STRUCTURAL CASING DESIGN ................................................................................... 23
7.3.4 WELLHEAD STICK UP AND MUD LINE SOIL STRENGTH ........................................... 25
7.3.5 VERTICAL LOADING - PULLOUT/SINKING .................................................................. 26
7.3.6 CASING SELECTION ...................................................................................................... 27
7.3.7 CONNECTOR SELECTION ............................................................................................. 28
7.3.8 JETTING STRUCTURAL CASING VERSUS CEMENTING IN A DRILLED HOLE ......... 29
7.3.9 JETTING STRUCTURAL CASING .................................................................................. 30
7.3.10 PREPARATIONS TO RUNNING STRUCTURAL CASING ............................................. 31
7.3.11 RUNNING STRUCTURAL CASING................................................................................. 33
7.3.12 MAKE UP LOW WELLHEAD INTO MUD MAT/PERMANENT GUIDEBASE .................. 33
7.3.13 INSTALLATION OF JETTING STRING ........................................................................... 35
7.3.14 MAKING UP WELLHEAD RUNNING TOOL.................................................................... 36
7.3.15 RIH WITH CASING AND LANDING STRING .................................................................. 38
7.3.16 JETTING STRUCTURAL CASING .................................................................................. 39
7.3.17 RELEASE RUNNING TOOL: POOH OR DRILL AHEAD ................................................ 43
7.3.18 WOB GUIDELINES.......................................................................................................... 44
7.3.19 RECIPROCATION GUIDELINES .................................................................................... 45
7.3.20 GUIDELINES FOR GUIDEBASE ROTATION ................................................................. 46
7.3.21 SETTING 30 IN. CASING IN 36 IN. DRILLED HOLE ....................................................... 47
7.3.22 RUN TGB AND ESTABLISH GUIDELINES ..................................................................... 47
7.3.23 DRILL HOLE FOR STRUCTURAL CASING.................................................................... 48
7.3.24 DRILLING 36 IN. HOLE WITHOUT TGB.......................................................................... 50
7.3.25 RUNNING STRUCTURAL CASING................................................................................. 51

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OPEN WATER OPERATIONS

7.3.27 RUNNING DRILL PIPE CEMENT STINGER.................................................................... 52

7.3.28 MAKE UP WELLHEAD RUNNING TOOL........................................................................ 52
7.3.29 RUNNING STRUCTURAL CASING STRING ON DRILL PIPE ........................................ 53
7.3.30 CIRCULATING AND CEMENTING 30 IN. CASING ......................................................... 54
7.3.31 RELEASE RUNNING TOOL ............................................................................................ 55
7.4 CONDUCTOR CASING................................................................................................................... 56
7.4.1 ENGINEERING DESIGN CRITERIA ................................................................................ 56
7.4.2 BENDING/BUCKLING ..................................................................................................... 57
7.4.3 BURST ............................................................................................................................. 59
7.4.4 COLLAPSE ...................................................................................................................... 59
7.4.5 CONNECTOR SELECTION ............................................................................................. 59
7.4.6 DRILLING CONDUCTOR HOLE RISERLESS VERSUS WITH PIN CONNECTOR
AND RISER ...................................................................................................................... 60
7.4.7 PILOT HOLES ................................................................................................................. 61
7.4.8 CASING RUNNING PREPARATIONS............................................................................. 63
7.4.9 RUNNING CONDUCTOR CASING WITH GUIDELINES ................................................. 64
7.4.10 MAKING UP 18-3/4 IN. HIGH-PRESSURE WELLHEAD JOINT...................................... 66
7.4.11 RUNNING DRILL PIPE CEMENTING STINGER ............................................................. 67
7.4.12 RUNNING CONDUCTOR CASING ON DRILL PIPE LANDING STRING ........................ 69
7.4.13 CIRCULATING AND CEMENTING 20 IN. CASING ......................................................... 72
7.4.14 SLURRY DESIGN ............................................................................................................ 72
7.4.15 CEMENTING AND DISPLACEMENT OPERATIONS ...................................................... 73
7.5 SPECIAL CONSIDERATIONS ........................................................................................................ 75
7.5.1 HIGH CURRENTS ........................................................................................................... 75
7.5.2 SHALLOW WATER FLOWS ........................................................................................... 77
7.5.3 DRILL WITH MUD P U M P AND D U M P CONCEPT .................................................... 78
7.5.4 SPECIAL CEMENTING OPERATIONS ........................................................................... 79

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OPEN WATER OPERATIONS

7.1 REMOTELY OPERATED VECHILES (ROVS)

7.1.1 INTRODUCTION
When performing open water operations from a floating drilling rig, operations are
typically assisted by an ROV installed on the drilling rig. An ROV, as illustrated in Figure
7.1, is an unmanned, remotely controlled, tethered vehicle with video cameras for
observing subsea operations and one or more manipulator arms for performing work
around the drilling location. ROVs are built in many different sizes and forms depending
on the tasks required and can be as simple as a video eyeball to a heavy multi-functional
work vehicle which can have the dexterity of divers and can operate in water depths up
to 10,000 ft. The operational advantages of an ROV over a diver is that they have
unlimited endurance at subsea conditions and can perform in hazardous conditions
where the liability of putting a man in the water would not be allowed.

Figure 7.1 ROV Operations

A typical ROV is deployed using an umbilical that supplies both the control/video signal
and electrical power. The typical ROV will use electrical power to operate hydraulic
pumps to power the thrusters and manipulator arms. To provide maneuverability of the
vehicle subsea, most ROVs are equipped with a tether that connects the vehicle back to
the umbilical. To improve communication and video signals, the ROV umbilical for
deepwater ROVs is typically equipped with fiber optic conductor within the umbilical.

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OPEN WATER OPERATIONS

TYPICAL SCOPE OF WORK

For support during drilling operations, the ROV is typically only used to provide video
pictures back to the rig floor and to assist guidance of tools into the wellbore. Listed
below is a summary of tasks where an ROV may be used during drilling and completion
operations.

MOVE IN RIG UP (MIRU) AND SPUD SUPPORT:

Perform bottom surveys when moving onto location. This survey confirms that no
obstructions are on the seafloor when the well is spudded.
Place acoustic beacons for DP rigs.
Visually monitor jetting structural casing.
Assist stab-in of drilling assemblies into the wellbore.
Monitor returns at the seafloor with the sonar while drilling the structural or
conductor hole riserless to detect shallow gas.
Visually monitor conductor casing running and cementing operations.
Retrieve cement samples to confirm cement returns to the mud line.

DRILLING AND COMPLETION SUPPORT

Visually monitor the alignment and installation of the BOP stack onto the
wellhead.
Inspect/monitor the riser, BOPs, and slope indicators.
Inject glycol/methanol to prevent or remove hydrates from subsea connectors.
Jet/remove hydrates from BOP wellhead connector.
Actuate hydraulic functions on the BOP stack or subsea tree with hot stabs.
Actuate and verify valve status on subsea trees.
Replace ring gaskets.
Cutt/reestablishing guidelines.
Provide video when inspecting subsea equipment for pressure or control
system leaks.
Assist in recovery of dropped objects.

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OPEN WATER OPERATIONS

RIG DOWN MOVE OFF (RDMO) AND P&A SUPPORT

Provide video and assist stabbing tools in the wellhead during P&A operations.
Install and/or remove wellhead corrosion caps.
Inject corrosion inhibitor into the wellhead during abandonment operations.
Assist in recovering lost mooring equipment.
Replace/recover acoustic beacons.
Place explosives during P&A operations.
Perform video and sonar bottom survey to meet regulatory compliance.
As ROVs developed over the years, they have increased in their functionality and are
now an integral part of most floating drilling operations. As an example of functionality, a
string of 22 in. casing that was stuck +/- 600 ft off bottom on a GOM ultra-deepwater well
in 2001 was cut by the ROV to allow the stuck section of casing to be recovered and the
well reentered. This operation was conducted utilizing the manipulator arms and a
hydraulic grinder attached to the ROV.

7.1.3 ROV TYPE

The types of ROVs used for drill rig support will generally be similar for all operations
except for water depth and system horsepower. This is true because most systems built
today are all designed with similar capabilities and equipment types. The three basic
ROV classes are:

Pure Observation Systems - the smallest systems and are typically only
equipped with a video camera. These systems are small, relatively inexpensive
and can be mobilized and setup quickly while occupying a minimum amount of
deck space.
Work Systems typically tethered, equipped with multiple cameras and at least
one manipulator arm. These systems are typically installed on the rig for the
duration of a project and utilize a deck mounted a-frame system for deployment.
Work systems are frequently used for drill rig support with the most common
systems types being the Scorpio, Recon, and Hydra (Figure 7.2). Water depth
rating for these systems typically range up to 1500 meters.

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OPEN WATER OPERATIONS

Special Purpose Systems designed and built for special and unique jobs such
as cable laying operations, seafloor salvage operations, and heavy support
operations. These systems (Figures 7.2, 7.3 and 7.4) may be used on ultra-
deepwater operations but are typically only used for drill rig support during
subsea completion and/or template operations.

Top Hat tether

management system
Figure 7.3 ROV Operations
from a Support Vessel

Buoyancy material

Figure 7.2 Hydra ROV

Manipulator Arms
Figure 7.4 Scorpio ROV

The selection of the ROV is typically made prior to mobilization and installed on the rig
for use during the term of the rig contract. The selection of the ROV is typically based on
the following factors:

Water depth.
Operating Environment High Current.
Planned scope of work (i.e. drilling support, operating subsea trees, and
connecting jumpers or umbilical for subsea equipment).
Cost of work system.
Complexity of engineering interface (e.g. drilling support only or subsea Xmas
tree/template completion included).
Typically, water depth and planned work scope drive ROV work system selection.
If the system is to only provide minimal tasks to support-drilling operations, the most
cost-effective system that can operate in the environment is usually selected. If
multiple complex operations are to be performed such as supporting and installing
subsea trees, then the system capabilities and tooling would be included as
important selection criteria.

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OPEN WATER OPERATIONS

High technology titanium manipulators are not usually required for drilling rig support
work. The best manipulators are robust, rig repairable and weldable, and possess
sufficient dexterity to perform the required work scope. Manipulators that provide fine
motor skills in excess of that required by anticipated work scope are a false economy.
Field reliability is typically more valuable than unnecessary dexterity.

Given no incentive to perform otherwise, ROV companies routinely provide a reduced

scope and depth of spares to reduce their working capital overhead for the project.
If this is permitted, the economic risk of ROV downtime may affect operations and could
cause rig delays. Therefore, the ROV contract should always provide sufficient scope
and depth of spares to keep the ROV effectively operating for the duration of the project.

The most cost effective ROV system is one that can consistently do the work required
in a timely manner. When an ROV has to be consistently recovered to make tooling
adjustments, changes or repairs, the rig time cost incurred will easily offset a low cost
ROV operating or standby day rate.

7.1.4 ROV OPERATIONS

The ROV is a remotely operated submarine that carries fixed ballast to give it slightly
negative buoyancy for a planned given payload. Typical payloads for ROVs range from
45 pounds for a free-swimming vehicle to 500 pounds for a heavy work system. The
instrumentation used to operate the ROV resembles that of a light airplane, including
a rtificia l h o rizo n , m a g n e tic co m p a ss, a ltitu d e . T h e p ilo t u se s a jo y stick to fly th e
vehicle.
The vehicle is deployed from the drilling rig down to the water depth of interest in a cage
o r g a ra g e , su sp e n d e d b y a w in ch , u m b ilica l a n d g a n try o n rig a s illu stra te d in Figure
7.5. The ROV flies out of the cage, trailing a very flexible tether cable. The tether is
usually about 600 ft long giving the ROV a very good work radius. The cage and tether
system also help to isolate most of the drilling vessel heave from the ROV.

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ROV Handling
System
deploying ROV
over the side
of a drilling
vessel.

Figure 7.5 ROV Deployment

R O V s th a t o p e ra te w ith o u t a te th e r a re ca lle d F re e S w im m in g a n d a re u se d p rim a rily

for observation only. Free swimming ROVs are typically not used for drill rig support.

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The ROV uses electrical power to drive hydraulic pumps, which in turn power hydraulic
motors, which drive the thrusters on the vehicle. Controls for the ROV are typically
electro-hydraulic, and the telemetry is normally all electronic. Newest generation ROVs
for deepwater are sometimes powered with all electric motors. Onboard sonar permits
the ROV to determine the location of other objects when optical visibility does not exist.
Sonar can also be used to identify gas bubbles within drilling spoil plumes as well as
determine vehicle location by ranging distances and compass azimuths from other
objects on the seafloor, whose location is known.

Every effort must be made to do ROV work out of critical path. However, if the ROV
experiences difficulty in performing a particular task, the resulting delay can place the
ROV work in the critical path. By its nature, ROV intervention work can be slow and
tedious. When done in the critical path, it is very costly in rig time.

The Company should always plan its ROV work with the ROV crews 24 to 48 hours in
advance, to ensure that the vehicle and required tooling are working and ready for use.

The ROV crew should develop a table of required end effectors, number of
required turns, and required torque for all Xmas tree and template valves.
ROV Company should have 100% redundancy for all mission critical tooling.
ROV crew should have a seafloor photograph file of all subsea components
requiring ROV intervention.
Once competent ROV crews are familiar with rig operations and subsea
equipment, ROV personnel changes should be avoided.
ROV maintenance should be performed during long drilling periods and rig moves,
so that the ROV will always be ready to work when required. The ROV will always be
heavily used during the spud and finish of a well. Any day the ROV is not in use, it
should be a day of preventative maintenance for the ROV crew. ROV maintenance and
downtime should always be documented on the ROV daily work log.

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7.1.5 DRILLING ENHANCEMENTS TO ASSIST ROV

OPERATIONS
To assist the ROV and make better use of the vehicle, the following is lists
enhancements and modifications that are usually made to the drilling equipment
before it is deployed subsea.

Paint equipment or items (e.g., casing, drill pipe, guide lines, BOP funnels,
connector indicators) that need to be viewed with the video camera a white or
yellow color.
Paint indicator rings or contrasting colors around small items that need to be
identified subsea (e.g., ring gaskets, indicator rods).
Provide handles at locations (e.g. BOP hot stabs, guidebase, actuator panel on
subsea tree) where the ROV is to perform work or standby to provide video for
an extended time.
Utilize floats or sonar reflectors to assist in locating the wellbore and/or
equipment placed on the seafloor.

7.1.6 ROV LIMITATIONS

It is important to be aware of the normal limitations on ROV work. For example,
manipulators that are designed for normal rig support work are sturdy and robust, and
may not have the sensitivity and reach required for some non-routine jobs. Also, all
visual presentations from the ROV are two-dimensional and depth perception is
sometimes difficult to gauge. To compensate for this limitation, the presentations can be
viewed from two different camera angles (90 degrees apart) to provide the depth
perception unavailable from the one-dimensional camera. In addition, depth perception
can also be enhanced by the use of a color camera. Frequently, an experienced capable
pilot can often compensate for most equipment limitations.

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7.1.7 ROV TERMS

Caged Systems refers to a tethered system that provides a cage (garage) that is
attached to the umbilical and is used to store and deploy the ROV vehicle.
Top Hat System tethered system where the ROV is deployed below a tether
management frame and release subsea for deployment.
Umbilical steel cable that contains the communication and electrical conductors and is
used to deploy the ROV and cage. The umbilical is stored on a winch and may include
fiber optics for the communications conductor.
Tether neutrally buoyant cable that is stored in the cage and allows the vehicle to
swim freely from the cage and umbilical. The tether also separates the vehicle from the
rig heave.
Vehicle refers to the underwater robot that includes the camera, manipulator arms and
sonar.
Handling system refers to the surface deployment equipment that usually includes an
a-frame, winch, and power unit.
Cursor A cursor is a frame that rides up and down on guidelines or rails that are
mounted to the rig and used to stabilize the ROV from rig motion when it is being
deployed or recovered through the air gap.
Control Console Central control station that is used by the operator to control the
system. The control console typically includes video monitors, video recording
equipment, joysticks to control the vehicle, and controls for the manipulator arms.
Arm refers to the manipulator arms. Manipulator arms can be either 4, 5, or 7
function and operate similar to a human arm. Some manipulator arms may also
include 360o rotation.
Jaws - refers to the hands on the manipulator arm.

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7.2 WELLHEAD COMPONENTS FOR OPEN

WATER OPERATIONS

During the open water operations section of the

well, the following list of wellhead components TGB J-slot Running Tool
may be used based on the requirements of the
well. This equipment will include the low and high-
pressure wellheads along the particular guidance
system to the utilized. The wellhead components
for this section are: Compartments for
weight material
Temporary Guidebase The temporary
guidebase (TGB), as illustrated in Figure 7.6, is
typically a large metal base (box) that provides a
center opening to establish the wellbore and
attachments for the guidelines. The TGB is
typically filled with barite or another weighted Guidelines
material to anchor the base to the seafloor while
maintaining tension with the guidelines. The TGB TGB
is set on the seafloor using a TGB running tool Figure 7.6 Vetco Temporary Guidebase
with drill pipe. with Drill Pipe J-slot Running Tool

Low pressure wellhead housing The

low pressure wellhead (Figure 7.7) is
installed at the top of the structural casing GRA
and provides a connection for the running Low Pressure
tool, a profile to latch a pin connector and Wellhead Housing
a landing profile for the high pressure
wellhead housing. The low-pressure
housing is supplied by the wellhead
manufacturer with a butt weld prep and
welded to a joint of structural casing.

Mud Mat The mud mat is typically a Guidebase latch

large flat base (Figure 7.7) that is and latch profile
GRA base same as
equipped with a center opening to base for PGB. Mud Mat
accommodate the structural casing. The
center opening is typically equipped with
cam ring type latch that attaches the mud
mat to a profile installed in the structural
casing. Mud mats can range in size from
10 ft x 10 ft to 16 ft x 16 ft.

Figure 7.7 Vetco Low Pressure Housing with

Mud Mat, PGB Base,and GRA installed

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Guidelineless Reentry Adapter (GRA) The GRA is guidance frame (funnel)

(Figure 7.7) attached to the top of the low-pressure wellhead and used to align and
guide the BOP stack over the high-pressure wellhead. The GRA is typically used when
operating from a DP rig and can be retrieved from the wellhead with a special retrieval
tool.

Permanent Guidebase (PGB) The PGB illustrated in Figure 7.8 is a guide frame that
latches to an external profile at the top of the low pressure wellhead and is equipped
with four guidepost that are used to guide the BOP stack over the high pressure
wellhead. For the Vetco MS-700 wellhead system, the lower section of the PGB is also
used with the GRA assembly when the guideposts are removed and the GRA frame
installed. PGBs can be retrieved from the wellhead during a plug and abandonment with
a special retrieval tool.

Guideposts
with guidelines
Low pressure installed
wellhead housing

PGB

Figure 7.8 Permanent Guidebase

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High Pressure Wellhead Housing The high-pressure wellhead housing is installed

(welded) onto a joint of conductor casing and run with the conductor casing. The high-
pressure wellhead housing is available in 16 in. or 18 in. with either 10,000 or
15,000 psi working pressures. The most common system is the 18 in., 15, 000 psi.
The high-pressure wellhead housing lands in the low-pressure housing and provides the
connection between the wellbore and the BOP stack. All subsequent casing strings are
landed in the high-pressure wellhead housing with a seal assembly installed to provide
the annulus seal. The typical high-pressure wellhead is typically designed for three
casing strings with special systems available that can accommodate four casing strings.
Figure 7.9 illustrates the Vetco MS-700 low and high pressure wellheads with 13 3/8 in.
installed on the left half of the wellhead and 13 3/8 in./9 5/8 in. casing installed on the
right side of the wellhead.

Latch profile for Vetco H-4

High Pressure wellhead by BOP connector
Wellhead Housing

Latch ring that latches the low and

high pressure wellheads together

Low Pressure
Wellhead Housing

Conductor Casing
Structural Casing

Figure 7.9 Vetco MS-700 High Pressure Wellhead Housing

Installed in the Low Pressure Wellhead Housing

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7.2.1 GUIDANCE SYSTEMS

Two systems are used to permit entry into the wellbore from a floating drilling vessel. In
water depths less than 3,000 ft and when working with a straight hydraulic BOP control
system, a guideline system is most often used. The guideline system uses four cables
attached to either the temporary guidebase (TGB) or the permanent guidebase (PGB),
on the seafloor and attached back at the rig with guideline tensioners. When working in
deeper water or with a DP rig a guidelineless system is most often used. A guideline-
less system will typically have either an up-funnel installed on the low-pressure housing
or a down funnel installed on the BOP stack. An ROV is used in conjunction with this
system to assist with stabbing casing and bottom hole assemblies into the wellbore and
landing the BOP stack.

7.2.2 GUIDELINE SYSTEM

Guideline entry and reentry systems provide a straightforward means of lowering
equipment and tools into the wellbore. The guideline system consists of a temporary
and/or permanent guidebase with guidelines installed at a six-ft radius running back to
the rig and attached to guideline tensioners.

To establish guidelines at the seafloor before beginning any

drilling operations, a TGB is run and positioned at the well
location. The TGB is typically used, when the structural casing
must be set by drilling and cementing or if seafloor visibility
would preclude relocating the hole with an ROV. The
installation of the TGB is accomplished by lowering the TGB to
the seafloor on drill pipe with guidelines, generally in. non-
rotating wire rope, permanently attached to the guidebase. The
guidelines are then used to guide the drilling assembly and
structural casing into the wellbore.
Installed on the low pressure housing with the structural casing
is the PGB that includes four 7 12 ft guideposts that are used
to guide the BOP stack over the wellhead. If the structural
casing is to be jetted into place, the guidelines will be attached
to the PGB and the TGB is not used.
Figure 7.10 illustrates a guideline system being used to guide
the structural casing into the wellbore
The use of guidelines is complicated by the fact that they are
connect to the seafloor and to a rig that is in constant motion
and must be tensioned to keep them as vertical as possible
while subsea equipment is run. To maintain this tension,
shipboard guideline tensioners (Figure 7.11) that typically have
16,000-lb capacity and are similar to the riser tensioners are
used to maintain the guideline tension. The guideline tensioners
are typically mounted in the moon pool and are controlled by
one common air supply system.
Figure 7.10 Guideline System

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Air Pressure Vessel

Low Pressure Seal
High Pressure Oil

Fixed Orifice

Low Pressure Air

Accumulator

Air-Oil Reservoir
25 40 psi

High Pressure Seals

Cylinder

Turn Down Sheave

Low Pressure Air

High Pressure Air
Low Pressure Oil
High Pressure Oil
Figure 7.11 Typical Guideline Tensioner System

Tension is maintained by adjusting the high-pressure air that supplies pressure to oil
beneath the tensioner piston. Tensioners are typically double sheaved to allow a piston
stroke of 12.5 ft to provide 50 ft of heave compensation.
While maintaining guideline tension with only the TGB in place, a compromise must
sometimes be made to provide adequate tension to guide the tools into the wellbore, but
minimized enough to prevent lifting the guidebase from the seafloor.
After the BOP stack has been run, the riser establishes the path to the well. The
guidelines remain in place to provide guidance after the BOP stack is recovered at the
end of the well. When using a straight hydraulic BOP control system, the guidelines are
also used to guide the BOP control pod during deployment and retrieval. This process
allows the control pod to be retrieved independently of the LMRP when repair of a
control pod is required.
If the structural casing is jetted into location, the well location would be established when
the casing tags bottom with the guidelines attached to the PGB installed at the top of the
structural casing. After the structural casing is jetted in place, the guidelines would be
used to guide tools into the wellbore and the BOP stack over the wellhead after the
conductor casing is in place. If a guideline is broken after installation, the broken
guideline can be cut away and re-established with either ROV assistance or with tugger
wire conveyed tools supplied by the wellhead manufacturer.

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7.2.3 GUIDELINELESS SYSTEM

The guidelineless system is typically used when operating in deepwater, operating with a
multiplex BOP control system or operating from a D/P rig. The guidelineless system will
typically either have an up funnel (Figure 7.12) installed on the low-pressure housing or
a down funnel (Figure 7.13) installed on the BOP stack. A guidelineless system is
always used when drilling from a DP rig to allow for an emergency disconnect during a
drive off or drift off condition. See Section 12 for information on Emergency Disconnect.

Stack Connector

GRA (Stack not pictured)

(Up-funnel)

Down
Funnel
Slope Indicators

Mud Mat

Figure 7.12 Guidelineless Reentry System Figure 7.13 Down Funnel Guidelineless System

When operating in deepwater, a well is typically spudded, by jetting the structural casing
into place. The structural casing location is determined by surveying the rig on location
at the surface and the casing is jetted into place to establish the well location. If the BOP
stack is not equipped with a down funnel, a Guidelineless Reentry Adapter (GRA) shown
in Figure 7 will be installed on the low-pressure housing which is welded to the top joint
of structural casing. The GRA is essentially an up funnel sized to received the wellhead
connector and align it over the wellhead. Drilling assemblies and the conductor casing
are also stabbed into the structural casing using the GRA with assistance from the ROV
and by repositioning the rig with the D/P system or the anchor winches.

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If the BOP stack is equipped with a down funnel, the structural casing will be installed
without a guidance system. The drilling assembly for the conductor casing and the
conductor casing are stabbed into the structural casing with assistance from the ROV
and by re-positioning the rig either by the D/P system or the anchor winches. After the
conductor casing is installed, the BOP stack is stabbed onto the high pressure housing
by repositioning the rig and final alignment is achieved by the down funnel installed on
the bottom of the stack.

The clearance for the down funnel between the wellheads, guide frames, slope indicator
b ra cke ts, a n d va lve o u tle ts is critica l sin ce th e rig s B O P sta ck m u st b e a b le to
sufficiently swallow the high-pressure wellhead housing and land out without any
obstructions. If the wellhead and funnel are from the same manufacturer, this is typically
not a problem. When using equipment from different manufacturers or when working on
a previously installed wellhead system, detailed drawing and dimensions should always
be used to verify that the stack and funnel can align over the wellhead without
interference.

However, considerable planning and engineering should be done, if using a wellhead

syste m m a d e b y so m e o n e o th e r th a t th e m a ke r o f th e rig s B O P sta ck re -entry system.
This is to ensure that the BOP stack wellhead connector can be locked onto the 18-3/4
in. high-pressure wellhead, without interference from the GRA.

As illustrated in Figure 7.14, the guidelineless system can also be used when the hole
for the structural casing is drilled and the casing is cemented into place. In this scenario,
clear seafloor visibility is necessary for the ROV to locate the pre-drilled hole and
coordinate the rig movement required, to stab the casing into the wellbore.

After the casing is landed and cemented, the drilling assemblies and/or BOP stack are
stabbed into the structural casing with assistance from the ROV and by re-positioning
the rig either by the D/P system or the anchor winches as noted above.

Although either system can be used on a moored rig regardless of water depth, the
guideline system is typically used when water depths are less than 3000 ft, but they
have been used in water depths up to 5000 ft. As the industry moved into the ultra-
deepwater in the mid 1990s, more and more moored rigs began to operate guidelineless
due to the problems associated with guideline entanglement and the additional time
required to deploy and retrieve the lines. Guidelines can be especially difficult to manage
in ultra-deepwater when operating in a high current environment.

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Buoy markers placed by

ROV to mark wellbore and
assist re-entry due to Cutting build up from
poor visibility drilling hole for
structural casing

Figure 7.14 Stabbing Structural Casing into Pre-drill Hole

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7.3 STRUCTURAL CASING

7.3.1 INTRODUCTION
Structural casing is the first casing installed on subsea wells and is designed to provide
the support foundation for the accumulated weight of the subsequent casing strings. The
structural casing is also designed to provide the foundation for supporting the weight of
the BOP stack and resistance to all environmental bending moments that will be
encountered. During design of the structural casing, loading between the inner string of
casing is ignored and the structural casing is designed without considering the strength
of any inner casing strings.

Additionally, the structural casing provides sufficient hole integrity while drilling the hole
for the conductor casing. The capability of the structural casing to withstand these loads
is a function of the following:

Size (OD), wall thickness, and strength of the casing itself.

Tensile and bending strength of the casing connector used.
Strength of the soil in which it is set.
How true to vertical the structural casing is set.
Length of casing that remains unsupported above the seafloor (commonly
referred to as wellhead stick up).

The two most common sizes for structural casing are 30 in. and 36 in. with a 1.5 in. wall
thickness. Other common sizes for structural casing depending on bending strength
requirements, are:

30 in., 310 lb/ft, 1.0 in. wall thickness.

36 in., 557 lb/ft, 2.0 in. wall thickness.
38 in., xxx lb/ft, 1.5 in. wall thickness.

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7.3.2 DESIGN CRITERIA OVERVIEW

The structural casing must be designed to withstand all of the axial and bending loads
that could be applied to the casing during drilling. If the design is for a development well,
then the possible additional loading from a tension leg platform (TLP) or other production
system must also be considered. Exploration wells that will be abandoned at the end of
the project may be designed to less strenuous criteria.

To ensure transfer of the load between the 18 in. high-pressure wellhead to the to
structural casing, the 18 in. wellhead housing can be rigidly locked down onto the low-
pressure wellhead housing after the conductor casing string is landed. Successful rigid
lock down causes the two wellheads to act as one component preventing cyclic
movement, which could cause fatigue failure in the conductor casing below the
wellhead. Rigid lock down provides increased fatigue resistance, but not increased
bending capacity.

To ensure that the wellbore can withstand the bending and axial loads imposed while
drilling; the structural casing is designed considering no load sharing between the
structural and conductor casing. This approach is necessary since load sharing between
the two strings may not be achieved due to the possibility of uncemented annulus. In
addition, the bending moment contribution of the conductor string is relatively small since
it is a function of the fourth power of the diameter.

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7.3.3 STRUCTURAL CASING DESIGN

Bending and axial loading are the main considerations in structural casing design. The
following factors, as illustrated in Figure 7.15, determine the magnitude of these loads:

Bending loading
factors:

Lateral loading at
flex joint due to
riser loads.
Wellhead and
BOP stickup
above the mud
line.
Soil strength
below the mud
line.
BOP and wellhead
angle (affects both
vertical loading
and bending).
FLEX JOINT
Axial loading
factors:
Vertical loading at
flex joint due to
riser loads.
BOP weight
(buoyed).
Wellhead and
casing weight
(buoyed) of all Figure 7.15 Loads and Bending Moments
subsequent
casing strings.

Design for bending is generally calculated assuming that the structural casing is not
fixed at the mud line and that some degree of deflection in the casing occurs for some
distance below the mud line due to the soil strength. This deflection will move the fixed
point of the casing below the mud line and cause a longer moment arm.

When coupled with the resistance from the soil strength, the required bending strength
of the casing will be less since it will be assisted by the strength of the soil and
distributed over a longer interval.

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For areas where soil strength data is unavailable or when a comprehensive analysis will
not be performed, a conservative calculation would be to design the casing assuming a
fixed point at the component mud line. This approach though will generally result in an
over design with larger casing and wellheads than required.

LATERAL LOADING

To keep the riser straight and prevent it from buckling, a large vertical load is applied to
the riser with the riser tensioners. The amount of riser tension that must be applied is
equal to the buoyed weight of the riser, the differential weight of the mud in the riser and
seawater, and an amount of overpull to place the neutral plane down into the BOP stack.
For DP rigs, the amount of riser tension should also be sufficient (typically 50 100 kips
of additional tension is required) to provide confident emergency LMRP and riser
disconnect, with manageable recoil.

The axial overpull of the riser tension at the top of the BOP stack is transmitted
through the flex joint and the LMRP at the top of the BOP stack. In a perfect case,
this overpull would have no horizontal component. However, the reality of floating
drilling is that the wellhead and BOP stack will never be completely vertical and there
will always be some horizontal loading resulting from how far off vertical the structural
casing was set or rig offset.

Also certain situations such as emergency disconnect, stationkeeping failure of a DP rig,

and mooring failure on a moored rig can impose large lateral loads on the structural
casing. These loads are transferred through a flex joint (stiffness of about 20 to 25 kip-ft
per degree of angle change) that permits bending at angles to about 10o either side of
center between the riser and the top of the BOP stack. During these loads, the BOPs
and structural casing may deflect several degrees depending on soil and casing
stiffness. For cases where the LMRP connector must successfully disconnect under
these loads, the combined axial and bending loads during these offsets must be within
the design limits of the LWRP connector. Beyond this, emergency disconnect cannot
occur, and the structural casing would be subjected to these excessive combined loads.
These loads are estimated in the riser analysis and should be used during the design of
the structural casing.

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7.3.4 WELLHEAD STICK UP AND MUD LINE SOIL STRENGTH

The total height from the mud line to the flex joint has a large impact on the amount of
bending force applied to the structural casing. Typically the structural casing is installed
with the low-pressure wellhead about 7 to 10 ft above the visible mud line. This distance
is to ensure ROV visibility and provide for acceptable bending radius of flow lines during
completion operations. The higher the wellhead stick up, the longer the moment arm
applied to structural casing. Computer modeling or empirical experience in an area can
determine if wellhead stick up is excessive.

The typical BOP stack is about 50 ft tall and results in a 60 to 62 ft total moment arm
from the flex joint to the visible mud line. Thus any deviation from vertical by the
structural casing and the low-pressure wellhead will impart a bending moment to the
LMRP connector, affecting its ability to disconnect and reconnect.

If soil at the mud line were strong such as granite, the stickup height distance would be
all that is needed to calculate the bending stress in the structural casing at the mud line.
However, soil strengths can be very weak and tend to decrease with water depth. The
soil strength for a given area will usually be known from offset well data or compressive
strength analysis of core samples. A bit set down test can be run to check these soil
strength estimates. Usually a 26 in. bit with 5 kips set down weight and no pumps will
stop penetrating at 150-p si co m p re ssive so il stre n g th . T h is d e fin e s th e co m p e te n t m u d
lin e ve rsu s th e visib le m u d lin e o r m u rk lin e . S e a flo o r m u d a b o ve th e co m p e te n t m u d
line does not contribute to structural casing bending resistance.

Since soft clays are generally found near the mud line, the structural casing will deflect
as it is laterally loaded until the soil develops more resistance and the pipe increases its
bending stress. As the pipe deflects, a cavity will be formed along the pipe from the
cyclic loading as the pipe moves back and forth. If excessive defection occurs, wear
and/or failure of the casing just below the mud line may occur.

Soil strength can also be used to determine whether or not structural casing can be
jetted in, and if so, how many joints or whether the structural casing must be cemented
in a drilled hole. Typical depths for structural casing are three to four joints or about 100
ft of casing below the visible mud line if an oversize hole is drilled and the structural
casing cemented. If the structural casing is jetted, the typical setting depths are normally
five to seven joints or about 200 to 300 ft of casing below the visible mud line, depending
on soil strength, potential loads, and experience in the area.

Soil strength, casing OD, wall thickness, casing connector bending strength, and
anticipated lateral loading will also determine whether an unexpected excessive stick up
height will be acceptable for a given location.

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7.3.5 VERTICAL LOADING - PULLOUT/SINKING

The total vertical loading in the structural casing is composed of the bending and axial
loads. Axial stresses are the result of overpull from the riser tension minus the down
weight of the BOP stack, subsea wellhead and the total casing weights.

Pull out is where the planned or excessive riser tension pulls the structural casing out
of the seafloor. Sinking is where the structural casing and wellhead might subside
below the visible mud line. Since the hole for the conductor casing is normally drilled
riserless, and riser tension is not applied until after the BOP stack is in place, pull out
is not an issue.

Sinking of the structural casing can always potentially be a problem. Selecting the proper
setting depth, whether the hole is drilled and the casing cemented or the structural
casing jetted, is critical in preventing the casing from sinking. Typical soil strengths for
the Gulf of Mexico and West Africa require around 120 ft of casing when drilled and
cemented and 240 to 300 ft when the casing is jetted to prevent sinking. Guidelines for
ca lcu la tin g m in im u m ca sin g le n g th s fo r va rio u s so il stre n g th s a re a va ila b le in th e IA D C
D e e p w a te r W e ll C o n tro l G u id e lin e s.

In addition to proper casing setting depth, prudent operational procedures such as:

operating with reduced pump rates when drilling directly below the structural
casing shoe to prevent wash out.
avoiding excess pipe reciprocation while jetting and allowing sufficient time
for skin tension to develop after the casing is in place before releasing the
running tool.
conductor casing cementing procedures that restrict set down of the
conductor casing string onto the structural casing to 50 kips until the
conductor casing is cemented.
Additionally, a mud mat may be run on the low-pressure wellhead assembly, to reduce
the possibility of the structural casing sinking. This is frequently done in deepwater due
to the reduced seafloor soil strength present from the lack of overburden pressure.
For a 16 ft x 16 ft square mud mat, about 150 kips of axial load is provided to support the
stru ctu ra l ca sin g a fte r it is p la ce d o r p ro vid e a n o g o sto p in d ica to r d u rin g je ttin g
operations. The additional axial load-bearing capability of the mud mat may also allow
earlier release of the running tool, thus decreasing the soak time required to for the skin
friction of the soil to develop.

In practice, a pull out/sinking analysis is not done during the design of the structural
casing.

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7.3.6 CASING SELECTION

Structural casing larger than 30 is typically X-52, ERW seam line pipe. Depending on
strength requirements, other grades that are available are Grade B (36 ksi) or X-56 pipe
with X-65/80 grade pipe available on special request. Tensile strengths greater than
X-56 are typically not used due to the difficulties in the seam welding the pipe and
installing the connectors. Wall thickness for all pipe sizes can vary from 1.0 to 2.0 in.
with a combination of wall thickness used in most casing string designs.

The casing extension joint that is welded to the low-pressure wellhead and the next
one/two intermediate joints will typically have a greater wall thickness (e.g., 1.5 in.
instead of 1.0 in.) to provide sufficient design-bending strength. This ensures that the
higher bending strength 1.5 in. wall pipe extends b e lo w th e co m p e te n t m u d lin e .
Normally, the larger, higher bending strength pipe is only required for the upper 80 ft
and a pipe with less wall thickness can be used for the remainder of the string.

Due to the normal 30 or 36 in. OD size for typical structural casing used, the API
Specification for Line Pipe is used for specification of wall thickness and grade. Weld-on
connectors, either threaded or squinch type are normally used, and information on
tensile and bending should be obtained from the manufa ctu re rs ca ta lo g .

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7.3.7 CONNECTOR SELECTION

There are two major types of welded casing connectors for structural casing: threaded
and quick stab.

In general, quick stab or squinch type connectors have looser manufacturing tolerances
than do threaded connectors of the same size, wall thickness, and grade. Typically, this
means that threaded type connectors have more bending strength and pressure rating
than quick stab connectors of the same size, weight, and grade. All structural casing
welds on connectors use an o-ring seal for pressure containment.

The quick stab connectors all use a pin up by box down approach, where a
load-bearing snap ring inside the box latches into a load bearing profile on the base of
the pin. Common quick stab connectors are the Vetco ALT-2 (Figure 7.16) and Drill-
Quip HD-90.

Threaded structural casing connectors typically use an easy to stab, pin up by box down,
aggressive fast pitch thread that can make-up with as little as - turn. Common
threaded connectors used are the Vetco RL-1 (Figure 7.17), RL-4, and Drill-Quip H-90
MT/QT.

Figure 7.16 - Vetco ALT-2 Squinch

Figure 7.17 Vetco RL-1S Quick
Joint Connector
Stab, Rapid Lock Connector

Generally speaking, quick stab connectors are only used when structural casing will be
cemented in a predrilled hole. This is because of the large cross sectional area
presented by the quick stab connector makes casing difficult to jet and may limit the
number of joints that can be jetted, increasing the risk of insufficient structural pipe being
set or excessive stick up.

Structural casing that is used for jetting operations is typically equipped with threaded
connectors that are more streamlined and have less cross sectional shoulder to impede
the casing as it is jetted. Connectors flush on the outside diameter are also available.

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7.3.8 JETTING STRUCTURAL CASING VERSUS CEMENTING

IN A DRILLED HOLE
The two methods used to set structural casing are as follows:

Jet the structural casing directly into the seafloor (Figure 7.18) using an internal
jetting string, or
Drill the hole (Figure 7.19) for the structural casing tailored in-depth to accept the
planned structural casing string, leaving the necessary stick up above the mud
line while placing the casing float shoe on bottom.
If the structural casing can be jetted, typical rig economics will dictate jetting as the most
cost efficient technique to use. Structural casing with near flush joint weld on connectors
are typically used.

Bottom conditions and seafloor soil strength determine if the structural casing can be
jetted in. If the structural casing cannot be jetted, a hole will be drilled and the casing run
and cemented. Bottom conditions that typically prohibit jetting are a hard sandy bottom,
coral, and boulders or glacial debris.

Returns through
running tools

Mud Mat

Structural Casing

Returns to TGB
seafloor

Seafloor

Bit & Mud Motor

Figure 7.18 Jetting Structural Casing Figure 7.19 Drilling Hole for
into Place Structural Casing

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7.3.9 JETTING STRUCTURAL CASING

Casing jetting is a technique used to eliminate the risk of losing the hole when the drilling
assembly is pulled from unconsolidated, alluvial deposits such as those found in the Gulf
of Mexico and West Africa. Jetting structural casing is an operation where a mud motor
is used to simultaneously drill in and set the structural casing. The jetting internal bottom
assembly typically contains a bit, mud motor, drill collars and subs connected to the
running string to space the bit for proper space out below the casing.

During jetting operations, a pilot hole is drilled by a bit powered by a mud motor. As the
casing forces itself into the formation under its own weight, it not only wedges additional
formation into the bit where it is drilled up by the bit but also forms a continuous seal.
Cuttings are then carried up the internal annulus and ejected through ports in the
running tool.

The weight of the casing assembly is slacked off from an initial start weight of
approximately 10,000 pounds, gradually increasing with penetration to nearly 80% of
total available weight at full depth. The controlled light starting weight aids in setting the
casing at or near vertical while the 80% maximum weight provides a safety margin to
keep the neutral weight point below the running tool.

The washing out of the formation inside the structural casing eliminates the internal
friction, leaving only the external soil friction which then lets the casing force itself into
the formation by its own weight. However, as the casing penetrates the formation, side
frictional forces absorb ever-increasing portions of applied weight until very little,
if any, remains for penetration of the casing into the soil. The string is worked until
drag (overpull) is lowered to an acceptable level that allows an effective ROP
within WOB guidelines.

The casing jetting is usually done with at 9 5/8 in. mud motor with a medium to low
torque range. The important factor is to ensure that the motor provides a flow rate of
1000 1200 gpm. If the motor is unable to provide this flow rate, a jet sub is typically
included in the jetting assembly to increase the flow and assist in cleaning the inside
diameter of the casing.

The most common bit for jetting 30 or 36 in. casing is a 26 in. soft formation rock bit.
Other bit sizes that can be used are 20, 24, 28 or 31.5 in. bits. The 38 and 31.5 in. bits
are typically special order bits. The space out of the bit is important to hole enlargement
ahead of the bit and to allow the bit to drill hard streaks that may be encountered. The
recommended space out for the bit is 6 in. (+/- 3 in.) below the bottom of the casing. For
a typical 26 in. bit, the nozzles will be approximately 8 in. inside the casing when the
bottom of the cones extend 6 in. outside the casing.

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7.3.10 PREPARING TO RUN STRUCTURAL CASING

Prior to running the structural Depth indicator

casing, the casing and internal marks painted on
jetting string should be tallied casing.
and the proper components
selected to provide the desired
bit UT of 6 in. As indicated in
Figure 7.20, casing joints should
be tallied to account for overall
length and proper makeup of all
connections. Since connector
makeup varies per type of
connector and manufacturer, the
service representative should be
consulted to determine the
correct measurement point.

To enhance visibility for the ROV

and to provide a reference for
pipe movement, the bevel jet
shoe joint should be painted with
Measurement points for
horizontal stripes every five-ft. In different connector types
addition, the low-pressure
wellhead should also be painted
with stripes every ft starting at
the top of the 30 in. wellhead
housing to provide a
measurement of pipe stick up
once the casing is in place.

Figure 7.20 Casing Measurement Points

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When tallying the internal jetting string components, items such as the wellhead running
tool should be split to provide measurements of the tool length above and below the top
of the wellhead as illustrated in Figure 7.21. The structural casing and jetting string
should be tallied to provide approximately 6 in. of bit stick out (+/- 3 in.) below the casing
as illustrated in Figure 7.22. If required, the jet shoe joint may be cut and beveled to
match the jet string and provide the proper stick out. If the bevel joint is cut, caution
should be taken to ensure that the joint is cut straight since an uneven cut may cause
the casing to build angle as it is jetted.

Figure 7.21 Running Tool Measurement Points Figure 7.22 Recommended Bit Stickout

The jetting assembly and cam actuated running tool (CART) are made and stood back in
the derrick prior to running the structural casing to minimize the time casing remains
suspended from the rig in open water.

Prior to running the structural casing, components such as the mud mat, PGB or GRA
must be installed in the moon pool to allow the casing to be run through the opening.

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7.3.11 RUNNING STRUCTURAL CASING

Depending on the connection type, the structural casing can be run with side door or the
new horseshoe elevators or slings attached to landing shoes. If the casing connector is
flush, a lifting clamp can be installed around the joint to provide a shoulder for the
elevators. When running casing with slings and landing shoes, the welds on the
landing shoes should be inspected and the load rating provided. The slings should
also be certified.

Since the mud mat and/or PGB are installed

around the low pressure housing, the structural
casing must be run through the mud mat or PGB
as illustrated in Figure 7.23. As the structural
casing is run, the joints are typically torqued with
manual bull tongs to the recommended torque.
Anti-rotation tab/keys should be positioned
during makeup and the anti-rotation tabs or keys
should be utilized. The anti-rotation tabs/keys
are used to maximize resistance to back off by
reactive torque from mud motor. Vibration
caused by sea currents can also back joints off.
Joints that do not make-up within the
recommended torque to allow proper alignment
of the anti rotation tabs/key should be rejected.

While testing the mud motor on a jetting

assembly for a well in West Africa in 1997, three
joints of 30 in. structural casing with Vetco RL-4S
connectors were dropped when a connector
without the locking tab energized backed off.
Due to the fast pitch, quick makeup of these
connections, the connector is prone to releasing
Figure 7.23 Installation of Casing
with only minimal rotation (1/4 turn or less) when
With Jetting String In Derrick And
weight is suspended on the connection, as it was
Guidebases Positioned In Moon Pool
when the jetting assembly was tested.

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7.3.12 MAKE UP LOW PRESSURE WELLHEAD INTO

MUD MAT/PERMANENT GUIDEBASE
The structural casing is typically lowered to the moon pool and hung-off on the mud mat
and/or PGB as pictured in Figure 7.24 to provide an open rotary for running the jetting
string. Make up of the wellhead housing to the PGB requires the alignment of the
cement ports on PGB with the ports on the wellhead housing and energizing latch rings
to secure to the wellhead housing to the mud mat and/or PGB.

After makeup of the wellhead housing, it is important to record the weight of the casing
for use in determining the neutral weight required to release the running tool after the
casing is in place.

Note: Since the weight of the structural casing can be quite large, the capacity of the
spider beams or BOP transporter should be verified to ensure that adequate capacity is
available.

Slope Indicators
Cement Ports

Figure 7.24 Landing out L/P Wellhead Housing in PGB in the

Moon pool prior to deployment

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
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7.3.13 INSTALLATION OF JETTING STRING

The jetting string is run from the derrick
(Figure 7.25) with the required subs to space
out the bit below the jet shoe joint to the pre-
determined distance. The jetting string will
typically include:

26 in. bit.
9-5/8 in. low torque mud motor with 0o
bend and stabilizer sleeve. If the drill
ahead tool is used, the near bit
stabilizer may be omitted to prevent
angle build while drilling ahead.
Float sub with solid float. A solid float
is used to prevent U-tubing up the drill
string on connections and to prevent
flow up the drill string if a kick is taken.
If a jet sub is used, the float should be
installed above the jet sub.
Jet sub (required only if the flow
capacity of the mud motor is less than
the flow rate required 1000 gpm)
String stabilizer.
Drill collars, space out subs, and
crossovers as required.
If a drill-ahead tool is being used, the
BHA should include needed MWD
Figure 7.25 Installation
tools.
Of Jetting Assembly With
Structural Casing
Suspended In Moon Pool.

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7.3.14 MAKING UP WELLHEAD RUNNING TOOL

As illustrated in Figure 7.26, the cam actuated running tool (CART) is stabbed into the
wellhead and made up with left-hand rotation. To monitor the rotation of the running tool
and count rotation turns subsea; a white/yellow vertical stripe should be painted down
the drill pipe and across top of running tool.

Note: If using Vetco MS 700 retrievable guidebase (RGB), ensure the running tool has
a hold-down mechanism to prevent early release of RGB.

Make-up of cam actuated running tool

(CART) into wellhead on rig floor.
Profile of running tool top
with bull plug removed
circulation ports.

Bull plugs

Figure 7.26 Installing CART into Low Pressure Wellhead

Housing with Jetting Assembly Suspended Below.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
OPEN WATER OPERATIONS

To allow circulation while jetting in the casing, bull plugs are removed from the top of the
running tool. Prior to running the assembly subsea, the weight of the casing and jetting
string should be recorded to use in determining the neutral weight required to release
the running tool after jetting the casing into place.

After stabbing the running tool into the wellhead, the ROV should verify the bit stick out
below the casing (Figure 7.27) and the weight of the jetting string should be recorded.
Since depth perception is difficult when viewing equipment with the ROV (Note bit
extension photo), a reference mark can be painted on the bit indicating the desired
extension distance (six inches) to assist in determining the proper bit extension.

Figure 7.27 Bit Stickout As Observed By ROV After Making Up Wellhead Running
Tool.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
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7.3.15 RIH WITH CASING AND LANDING STRING

When operating in areas with high wind and waves, it is important to minimize the time
that the wellhead and guidebase/mud mat are in the splash zone (Figure 7.28) to
prevent damage to the equipment or running tool. If a guidebase and guidelines are
being run in conjunction with the wellhead, caution should be taken to ensure that the
pipe does not rotate and twist the guidelines.

When operating in ultra-

deepwater, high strength drill
pipe should be used due to the
high ook loads that will be seen
from the total of the weight of
the landing string, casing and
overpull required while jetting.
When calculating tensile
capacity for the landing string,
overpulls of at least 100 kips
should be used.

Figure 7.28 Moving Guidebases

Through Splash Zone.

Prior to tagging bottom with the casing as illustrated in

Figure 7.29, the final rig position should be verified
with the surveyors and the top drive brake applied to
prevent left-hand rotation of the casing caused by the
reactive torque from the mud motor. The pipe
measurements should be checked at this time to
ensure that a connection will not be required during the
last 30 ft of jetting operations. If a connection is Mud line
required, singles should be removed or added to the Figure 7.29
landing string. Pick-up and slack off weights should Suspending Casing and
also be recorded to confirm buoyed weight of the Jetting Assembly above
casing and inner jetting string. The ROV should Mud line while final
re-inspect the wellhead running tool and record the checks are made.
slope indicator readings.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
OPEN WATER OPERATIONS

7.3.16 JETTING STRUCTURAL CASING

Prior to tagging the mud line with the casing, the following should be confirmed to ensure
that delays will be minimized during the jetting operations:

Have ROV check guidebase and guideline orientation to ensure that casing has
not rotated. ROV should also check running tool to ensure that it has not rotated
and record the position of each of the slope indicators.
Test the mud motor and ensure that pumps, valves, seawater and gel sweeps
are aligned and ready to use.
Calculate footage for last stand to be jetted to ensure that at least 30 ft will
remain when casing is at TD. If needed, singles should be added or removed
from the landing string.
Release boats that may be tied to the rig to prevent excessive rig movement.

ROV should then be positioned up current to monitor the jetting operations. When the
ROV is in position, the casing should be slacked off to tag the mud line and the depth
recorded as the murk line depth. It should be noted that depth will off by the stretch of
the drill pipe due the weight of the casing and landing string.

After recording the murk line depth, continue to slack off

without pumping (Figure 7.30) until the casing is either 10 ft
below the mud line or 10,000 pounds of WOB is achieved.
Slacking off deeper than this depth may cause the formation
to pack-off at the stabilizer blade and make it more difficult to
circulate up the inside of the casing or cause the bit
nozzles to plug. As the
drill pipe is slacked
off, it should be
marked in 5 ft or
1 meter
intervals at
the rotary
table
throughout
the jetting
operations.

Re-check PGB
slope indicator
for change with
ROV and orientation
of PGB. Note any changes
in PGB inclination or orientation, so any required Figure 7.30 Tagging
corrections can be made. bottom with jetting assembly
and establishing location.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
OPEN WATER OPERATIONS

After recording the slope indicator reading, the ROV should then be repositioned at the
mud line to monitor jetting operations. If an MWD is in the inner jetting string, it can be
used to verify plumb of jetting string.

After positioning the

ROV (Figure 7.31) start
First 50 ft,
Pumps at 80% of
pumps and bring up to
desired or 10K 80% of the full rate and
maximum WOB start penetration
immediately on the
Apply WOB per motor starting to rotate
maximum WOB the bit. The ROP initially
table and work should be limited only
pipe as needed. by the 10,000 WOB and
ROV monitors
for signs or
may be as high as 300
broaching ft per hour, but the
WOB and penetration
should be maintained to
prevent washing out a
large hole section in the
soft sediments. If any
problems occur, the
pumps should be
Keep pipe moving stopped and the
to prevent hole problems corrected
Pilot hole drilled by bit is
enlargement below while jetting operations
sealed as structural casing
the bit. are shallow below
moves down
the mud line.
Figure 7.31 Startup Of Figure 7.32 WOB Increases Caused By
Jetting Operations Increased Formation Friction (Drag).

During jetting operations, a pilot hole is drilled by a bit powered by a mud motor and the
casing forces itself into the formation under its own weight. As the casing slides down
the hole, it wedges additional formation into the
bit where it is drilled up by the bit allowing the
casing to form a continuous seal with the
formation. Cuttings drilled by the bit are carried
up the internal annulus and ejected through ports
in the running tool (Figure 7.33).

As drilling continues, the best practice for jetting

is to keep the pipe moving (Figure 7.32) as
opposed to increasing the weight and letting it
drill off. Gradually increase slack off weight but
do not exceed the maximum of 80% of buoyed Figure 7.33 Returns While Jetting
weight of casing below the mud line. Through Wellhead Running Tool.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
OPEN WATER OPERATIONS

After jetting +/- 50 ft below the mud line, the pumps should be increased to 1000 to 1200
gpm while monitoring the outside of the casing for broaching. During jetting operations,
the pump rate should be kept constant to allow the mud motor differential pressure to be
monitored.

When ROP slows significantly or the maximum weight is

required to jet, the pipe should be reciprocated to reduce
wall sticking as illustrated in Figure 7.34. Work casing
high and fast enough, each reciprocation to break drag
back to normal. If drag does not break back to n o rm a l,
Work pipe if
co n tin u e to re cip ro ca te p ip e u n til d ra g is n o rm a l. G e l
ROP decreases
significantly,
sweeps may also be pumped to coincide with working the
before pipe to assist in reducing the drag.
connections,
and during Unless heave is excessive, it is best to perform jetting
delays. operations without the motion compensator due to the
large variations in weights seen while jetting and working
the pipe. Slack off weights (WOB) can reach 80 to100
Work pipe at a
kips and overpull while working the pipe can reach 100
quick and
consistent
kips above string weight. Do not exceed 80% of safe
pace. tension limit on drill pipe. The safe tension limit is buoyed
weight of string plus maximum hook load of drill pipe per
API RP-7G.
Increase WOB
slowly after Frequently monitor jetting operation with ROV to ensure
working pipe. that the wellhead running tool is not rotating and that the
vertical scribe line is in the same position, PGB
orientation has not changed, and that guidelines have not
Figure 7.34 Reciprocating twisted. The ROV will need to verify orientation against
The Casing To Reduce The his gyrocompass since no reference point will be
Formation Friction. available to visualize guidebase rotation.

To assist hole cleaning, high viscosity sweeps should be pumped at mid-stand and
before each connection. The pipe should also be reciprocated the full length and worked
until the drag frees up before making each connection.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
OPEN WATER OPERATIONS

Since set down weight can be as much as 100 kips less due to WOB when the casing
reaches TD, it can be difficult to determine if the casing is at the correct depth from pipe
measurements at the surface. If the water is too cloudy for the ROV to see reference
marks on the casing, the following procedure (Figure 7.35) can be used to determine
the distance remaining to be jetted:

Dirt line mark

Visibility poor due to cloud With pipe above cloud,

from returns exiting the ROV is able to record
flow ports on the running dirt line mark and
tool. Unable to read depth distance remaining to
marking on wellhead joint be jetted.
with ROV

Figure 7.35 Working Casing Prior To Reaching TD To

Determine Remaining Distance To Be Jetted.

Mark the drill pipe at the rotary and record the string weight with current WOB.
Shut down pumps and work casing up quickly to bring the dirt line mark on the
casing above the plume.
Using the ROV, record the distance from the dirt mark to the desired location on
the reference marks painted on the casing. This the distance remaining that needs
to be jetted.
Slack the casing back to the mark place on the drill pipe prior to picking up the
casing and measure in the remaining distance to be jetted. Typical stickup for the
structural casing is 7 10 ft.
At TD, a high viscosity pill is typically pumped and casing allowed to soak while
supporting the landing string with the compensator to allow wall friction to secure the
casing in place. After shutting down the pumps and allowing visibility to clear, the angle
from the slope indicators should be checked with the ROV.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
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7.3.17 RELEASE RUNNING TOOL: POOH OR DRILL AHEAD

After allowing the casing to soak, typically one to four hours, the drill string is slacked off
to neutral running and inner jetting string weight while observing the slope indicators with
the ROV. If there is no change in slope indicator reading and the casing does not move,
the wellhead running tool is released with right hand rotation and the jetting string pulled
back to the surface.

T h e ru n n in g to o ls d e sig n re le a se p o in t is a t a n e u tra l w e ig h t co n d itio n th a t a llo w s a ca m

to freely move the retaining dogs in or out depending on the direction the stem is turned.
When the tool is to be released, the slacked off weight is set to equal the casing weight
in clu d in g th e g u id e b a se a n d /o r m u d m a t. T h is is th e w e ig h t th a t h a s b e e n p la n te d a n d
the remaining weight is suspended from the rig. This is not a true neutral weight point, as
in neutral weight point of a drill string between compression and tension. It is a neutral
weight point of the running tool where the casing is held up by friction with the BHA and
drill string being in tension but not exerting an up or down force on the running tool.

If a drill-ahead tool is used, the running tool and inner stem are released allowing the drill
string to be slacked off. After releasing the running tool, the first 15 to 20 ft should be
drilled without pipe rotation and with reduced pump rate to prevent damage to the
running tool and wash out below the structural casing. On the trip out of the hole after
drilling the hole for the conductor casing, the stem is pulled up into the wellhead running
tool and the running tool retrieved to the surface.

Note: Before tripping in the hole with the casing and jetting assembly, the single above
the running tool should be painted white to provide an indicator of the stem location so
that the running tool is not pulled out of the wellhead on a wiper trip.

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7.3.18 WOB GUIDELINES

Casing jetting operations use a pendulum effect to jet in the structural casing. Control of
the weight is a major factor in keeping the casing string vertical while maintaining an
effective rate of penetration. Applying too much weight at any given depth could lead to
angle increase while too little weight could lead to slow rate of penetration, soil erosion
or cause the string to be worked too often.

A common method is to establish the maximum weight-per-ft using that, which equals
the casing and BHA weight below the mud line. A simpler method is dividing the casing
and BHA weight by the length and rounding down to a convenient weight.

The applied weight maximum assures the majority of compression in the casing is below
the mud line where it is supported and limits bending forces above the mud line. It also
establishes a weight that should be reached before reciprocation is considered to
prevent overworking of the soil.

Applied weight must never exceed the total available weight (casing, BHA, guidebase),
as the landing string will be put into compression and quickly bend. A 20% safety margin
should be used under normal conditions.

Another weight that is critical is the weight that places the neutral weight point at
the running tool. If this condition is reached, it puts the running tool in a condition
where the stem could turn and possibly release the tool or over-torque the tool to
the latched position.

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7.3.19 RECIPROCATION GUIDELINES

The friction of the formation against the casing is the force that holds the structural
casing in place. During jetting operations, the internal formation friction has been
eliminated or drilled out allowing the weight of the casing assembly to force itself into the
soil. As the penetration depth increases, external friction increases absorbing much if not
all of the slacked off weight. In order to overcome this friction, the string must be
reciprocated or worked.

Failure to work the string in an effective and timely manner is one of the chief causes of
casing being set too high. Excess weight application can cause the angle to deviate from
vertical and staying in one spot too long encourages soil erosion, which can weaken the
so ils a b ility to h o ld th e ca sin g , which will require additional soak time.

When the rate of penetration slows significantly with a constant applied weight, either the
weight must be increased within the limits for the current depth or the string must be
re cip ro ca te d to le sse n th e so ils grip on the casing.

The frequency of working cannot be predetermined and can vary with each well with soil
conditions dictating the frequency that the pipe must be worked. Using the WOB
guidelines helpd prevent over or under working the casing.

The following is a list of guidelines for working structural casing:

Monitor initial pick up for excess overpull and then work at normal rate.
Work the pipe at a fast pace (>1 ft/sec) to liquefy soil and reduce the friction.
Work at a constant pace as the rate influences weight indicator reading.
Work at a consistent pace to enable comparisons to be made at different depths.
Work until overpull has been reduced to an acceptable level relative to hole
depth.
Overpull in upper section is reduced to less than 10,000 pounds
Overpull is allowed to slowly build in lower sections as conditions warrant.
Overpull should be only be reduced slightly as setting depth is neared.
Work before each connection to near zero overpull.
Return to bottom and gradually bring rate and weight back up, do not spud
bottom.

The string must also be worked to near zero drag before connecting, as the string will be
stationary for the time required for makeup. This is the main reason that planning should
be done to eliminate a connection in the last 30 ft.

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7.3.20 GUIDELINES FOR GUIDEBASE ROTATION

Many wellhead systems use a guidebase with guidelines that must not rotate to a point
where proper installation of other subsea equipment is prevented. It is impossible to
know if this occurs without an ROV and can be difficult to determine using an ROV,
since it must rely on sighting across guideposts to reference a compass heading.

Mud motors may impart reactive torque to the left as the bit turns to the right. This
problem may be more pronounced with higher torque mud motors. During jetting
operations, many casing strings turn to the left, but a substantial number also turn to the
right. Other causes of this rotation include the formations and torque which is trapped
during connection make up and worked up the string. On the typical job, the rotation of
the guidebase is not such that it needs correcting.

If necessary, the guidebase rotation can be corrected and should be done with the string
as high as possible. This is another reason that adjustments should be made to the drill
string before beginning to allow a long run to bottom on the last stand (i.e., pick up or
layout singles to ensure connection will not be made during last 30 ft). This allows the
most pick up distance.

The turning of structural casing must be done with caution or not at all. The major
concern is the possibility of turning or releasing the running tool. The string should only
be turned in small increments and only with close monitoring. Turning the string works
because of two factors, the tool is difficult to turn when it is not at neutral weight and the
friction has a limited amount of force that it can apply to hold the casing in place. When
the casing is moved upward, friction attempts to hold the casing (tensional force),
leaving little if any friction to counteract the torque force. Torque virtually disappears
when the string is moved vertically and, for this reason, the string can be turned at or
near full depth if required.

Methods to turn the casing string:

Assure each step will be done with caution while monitoring or do not do it.
Make sure the running tool is not at neutral weight point.
Pre-load 2000 to 5000 ft/pounds of torque in the top drive keeping below level
that affect running tool or drill string connections.
Have Driller turn string in small increments of 90 degrees of less while checking
the running tool.
Return to bottom and check to see if turn was achieved. Check running tool.
Repeat procedure until desired effects are achieved, monitoring during the entire
operation.
If turn achieved, release top drive brake to eliminate any trapped torque.
Also, some PGBs, like the Vetco SG-5 may be unpinned and rotated to the correct
guideline orientation and then pinned back by the ROV.

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7.3.21 SETTING 30 IN. CASING IN 36 IN. DRILLED HOLE

When bottom conditions do not permit jetting, the structural casing will be run and
cemented in a pre-drilled hole. The hole size is typically 36 in. for 30 in. casing and 42 in.
for 36 in. casing and can be drilled with or without the assistance of a temporary
guidebase (TGB). The use of a TGB requires the investment of a round trip to the
seafloor and back, but eliminates the risk of not being able to re-enter the hole with the
structural casing string. If a TGB is not run, the casing must be stabbed into the hole with
ROV assistance. If high tidal currents are known to exist, a TGB may be beneficial.

7.3.22 RUN TGB AND ESTABLISH GUIDELINES

The temporary guidebase (Figure 7.36) is used to establish a well location on the
seafloor and provide a means to attach the guidelines subsea. Since tension must be
applied to the guidelines to keep them
straight, the TGB is typically loaded with a
sufficient amount of sack barite to provide TGB J-slot Running Tool
weight greater than required guideline
tension. A slope indicator is usually
installed on the TGB to provide an
indication of the initial angle when the base Compartments for
is landed. weight material

The TGB is run to bottom with a gimbaled

running tool on drill pipe. While running the
TGB, it is important to ensure that the pipe
is not allowed to rotate and twist the
guidelines. Prior to landing the TGB on
bottom, the location should be confirmed Guidelines
with the surveyors. After landing the TGB
TGB
on the seafloor, the guideline tensioners
are pressured to the desired guideline
Figure 7.36 TGB & Running Tool
tension and the j-slot running tool is
released from the TGB.

A TGB is typically not used in water depths greater than 2000 ft or when jetting in
structural casing. If a TGB is not used, the ROV will normally place marker buoys next to
the structural casing hole to assist in locating the hole when stabbing tools or casing
(Figure 7.36).

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7.3.23 DRILL HOLE FOR STRUCTURAL CASING

The hole for the structural casing is drilled to match the length of the
casing. Prior to drilling, the casing is measured and the hole is drilled
to match the casing length minus the desired wellhead stickup
above the mud line.

The hole for the structural casing is typically drilled with a pilot bit
and hole opener (Figure 7.37). For 30 in. casing a 26 in. bit x 36 in.
hole opener assembly is used and for 36 in. casing, a 26 in. bit x 42
in. hole opener assembly is typically used. To prevent bit darting, a
full gauge stabilizer or tandem hole opener assembly is run. The
pilot bit can be thread locked, to prevent inadvertent downhole back-
off of bit.

To enhance observation by the ROV or subsea TV camera, the bit

and hole opener should be painted white. White rings should also be
painted every ft for first 10 ft, and then every 5 ft on first drill collar.
It is important when working in open water with a BHA, that visual
confirmation is made with the assembly to ensure that downward
movement of the assembly subsea matches the movement of the
assembly in the rotary. Assemblies can bow over and break
when working in open water without significant changes in
weight indicator readings.

Since it can be difficult to obtain accurate depth measurements

when working in open water due to the unsupported drill string, a
white ring can be painted on the BHA at a distance from the hole
Figure 7.37 Hole
opener equal to the hole depth to be drilled. As the well is drilled, the
Opener & Bit
ROV verifies the correct depth when the painted white ring is even
with top of the TGB funnel.

To guide the assembly into the TGB, Four in. (hemp) guide ropes are typically
installed about 10 ft above bit, centering the assembly between the guidelines. As the
assembly is stabbed into the TGB, the four guide ropes will break free and allow the
assembly to enter the wellbore. For areas with high environmental loads, a second set of
guide ropes may be required and will be typically installed 10 to 15 ft above the first set
of guide ropes.

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After stabbing into the TGB, the hole will typically be jetted or drilled with a very slow
rotary until the hole openers and/or stabilizers are below the TGB. In addition, for the
first 40 ft the hole is typically drilled with a reduced flow rate and minimal weight and
rotary to ensure that the assembly does not become entangled in the TGB or guidelines
and to prevent washing out below the TGB. After the first 30 to 40 ft are drilled the flow
rate is typically increased to 1000 to 1200 gpm and the interval drilled with seawater and
high viscosity sweeps to clean the hole. At TD, the depth is confirmed and the indicator
mark on the BHA at the top of the TGB funnel is confirmed as the primary reference
mark for TD. RKB pipe measurements are also confirmed, taking into account tide
changes adjusted from guideline tide gauge measurements or tide charts.

At TD, the hole will typically be swept with a high viscosity sweep and a wiper trip made
to the mud line. After the wiper trip, the hole will typically be filled with high viscosity mud
to assist keeping the hole open while running the casing.

Since the angle of the BOP stack will be reflected by the structural casing, a survey
should be taken at TD to determine the hole angle. Hole angles less than 1.5o are
preferred. If operating in an area with deep currents, hole angle may be affect by the
offset of the BHA when it initially tags the bottom. On a 3300 ft water depth well, drilled
offshore of Trinidad in 2000, with a 2.0 knot current extending down to 2000 ft, the BHA
had an initial angle of 5+ degrees when surveyed with the MWD tool at 30 ft below the
mud line. To correct for this angle, the rig was repositioned over the wellbore after a
location had been established and an additional survey taken to confirm the angle was
within acceptable tolerance. Drilling in open water with high current may also require the
use of a mud motor to minimize drill pipe fatigue potentially caused by the offset and
bow in the drill string.

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7.3.24 DRILLING 36 IN. HOLE WITHOUT TGB

When the hole for the structural casing is drilled without a TGB, the procedure to spud
differs in the following:

TGB is not run.

The final survey is taken when bit tags bottom and establishes the location.
ROV buoys placed adjacent to hole location are used to assist in re-locating the
to stab in the casing or drilling assemblies.
Guidelines are established when the structural casing and PGB are run.

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7.3.25 RUNNING STRUCTURAL CASING:

Prior to running the structural casing, the permanent guidebase (PGB), if used, would be
positioned in the moon pool and the guidelines attached to the guideposts unless the
guidelines are already in place with the TGB. The PGB is typically placed on the spider
beams or the BOP transporter so it is directly beneath the rotary while the casing is run
through the opening in the PGB. To determine the angle of the structural casing, slope
indicators are installed on the PGB.

If TGB was run, connect the 4 guide ropes about 10 ft above bottom of float shoe to the
guidelines. Guide ropes are typically attached to the casing by welding an attachment
(e.g., chain link, large nut, flat bar ring) at 90 degree intervals around the casing with the
guide ropes attached using the same
technique as with 36 in. drilling BHA. After
the casing enters the water, it should be
filled with seawater until the ROV verifies
that the water is flowing out of the shoe
joint.

Prior to making up the wellhead housing

joint, it is typically painted white with black
rings every foot and numbers every five ft
starting with the top of the 30 in. wellhead
housing, to measure stick up (Figure
7.38). This contrasting color is need so
that the video from the ROV can easily
identify the casing as it moves subsea.
The first 20 ft of guideline above the PGB
is also typically painted white to provide a
reference for the guidelines prior to Figure 7.38 Land out depth of casing indicated
reaching the guidebase. by reference marks painted on wellhead joint.

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7.3.27 RUNNING DRILL PIPE CEMENT STINGER:

After the low pressure wellhead housing
is made up and landed in the rotary, a
cement stinger is run inside the
structural casing to place the end of the
stinger +/- 50 ft from the shoe. The
cement stinger is typically the same drill
pipe from the drill string and is run using
a small set of bowl and slips (Figure
7.39) or two sets of elevators. A false
rotary C plate is placed on the wellhead
to support the bowl/slips as the cement
stinger is run. The stinger is used to
minimize cement displacement and to
Figure 7.39 Cement Stinger being run with C
e n su re a p lu g d isp la ce m e n t sin ce
plate false rotary and bowl and slips.
wiper plugs are not used.

7.3.28 MAKE UP WELLHEAD RUNNING TOOL

After making up the cement stinger, the wellhead running tool is made up into the low-
pressure housing and the housing lowered to the moon pool and the low pressure
housing connected to the PGB. The PGB and low-pressure housing are orientated to
align the cement ports on the low-pressure housing (Figure 7.24) and the guidebase
attached with a latch ring. Prior to running the casing subsea, a white/yellow vertical
stripe should be painted down drill pipe and across top of running tool to monitor rotation
of the tool and to enable the rotations to be counted subsea. The bleed port/valve should
also be left open on the wellhead running tool so that the air can be displaced from the
top of the casing after it enters the water.

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7.3.29 RUNNING STRUCTURAL CASING STRING ON

DRILL PIPE
Lower the casing into the water and submerge the guidebase below the splash zone to
minimize the wave action against the casing and running string. After the assembly is
below the splash zone, seawater is circulated to fill the remaining volume of casing and
to displace the air from the open port in the running tool. After the casing is completely
filled with seawater and the air is no longer venting from the running tool, the casing is
typically picked just above the water line and wellhead technician is lowered on a riding
belt to close circulation port/valve on the running tool. The buoyed weight of structural
casing string should be recorded to provide a reference for the neutral weight needed to
release the running tool.

While tripping to the seafloor with the casing, the 4 guide ropes, guidelines, CART
should be monitored with the ROV, and the drill crew should ensure that the running
string is not allowed to rotate. Prior to entering the wellbore (approximately 20 ft above
seafloor), the motion compensator should be opened and pressured to support the entire
weight of the drill string.

While monitoring with the subsea TV or ROV, the float shoe should be stabbed in the
wellbore. During stab-in, the set down weight should be limited to 5 kips to prevent
buckling of the structural casing. If the casing is being stabbed into a TGB, the
guidelines and slope indicator should be monitored to determine if the casing is
tagging/hitting the as it enters the wellbore. If necessary, the guideline tension may
be adjusted to reposition or change the angle of the TGB.

Continue to run in the hole with the casing limiting the set down weight, to a maximum of
80% of the buoyed casing weight below the mud line. Tag bottom with the casing and
confirm proper stickup and slope indicator readings with the ROV. If the angle from slope
indicators is excessive, the rig may be repositioned to align the casing vertically.

If the casing extends too deep, or if the wellbore is unable to support the casing, the
casing is typically supported with the motion compensator during cementing and until the
cement can support the weight of the casing. If this is down, the driller needs to monitor
and adjust weight down as required to keep incoming tide from picking up on both
conductor and structural casing.

Prior to landing out the casing, the cementing manifold that is stood back in the derrick is
made up to the landing string. The typical cementing manifold typically consists of a drill
pipe double, safety valve, side door pump-in sub or top drive cement head, safety valve,
and a pup joint for proper space out. The cementing stand is typically spaced out such
that when the casing is landed out, the lower safety valve is about 12 to 15 ft above the
rig floor at maximum tide and heave.

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7.3.30 CIRCULATING AND CEMENTING 30 IN. CASING

Typically the casing and landing string will be held stationary with the motion
compensator after the casing is landed on bottom. With the string support by the motion
compensator, the rig motion will complicate the rig-up of the cementing lines and may
require additional safety precautions.

Cementing the structural casing is similar to most cement jobs except that returns must
be monitored subsea with the ROV. Listed below is a summary of the typical steps for
cementing the structural casing:

Circulate at least the capacity of running string, inner-cementing string, and

casing capacity from end of stinger to float shoe to ensure that no obstructions
are in the string.
Observe TGB guideline marks for TGB possible sinking. Observe TGB for
possible sinking with ROV.
Mix and pump cement. Typical cement job will be a tail slurry with 100% open
hole volume excess and an accelerator to reduce the set time.
During pumping operations, the ROV will be used to monitor the seafloor for
good returns. To verify cement returns to the surface, a fluorescent dye can be
added to the spacer pumped ahead of the cement. For subsea cementing
operations, the casing is not reciprocated since it may compromise the correct
land out position should be pipe become stuck.
For the structural casing where wiper plugs are not used, the cement unit will be
used to displace the cement to the desired depth, typically leaving around 30-40
ft of cement inside of the casing. Have ROV monitor well for cement returns and
record time cement returns are observed.
After displacing the cement, the floats are checked and the weight of the casing
is slacked off and the ROV monitors the wellhead and guidebase for movement.
If the wellhead or guidebase moves or sinks, the casing will be held with the
block until the cement is set.
When planning the cement job for the structural casing, it is important to obtain and use
actual seafloor temperatures for the cement pilot testing to determine pump and
thickening times. For a surface well, the typical approach would be to err with a higher
temperature to ensure that sufficient pump time is available. However, with subsea wells
where the seafloor temperature can be as low as 40oF, this approach may cause the
cement to take up to 24 hours to thicken and result in rig delays due to waiting on
cement time prior to releasing the running tool.

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7.3.31 RELEASE RUNNING TOOL

If all casing weight can be slacked off with no change in slope indicators, the block is
slacked off to the neutral weight of the running string and cement stinger. With the string
at neutral weight, the wellhead CART is released by rotating the landing string to the
right. Due to rig motion and force required to rotate the landing string in deepwater, the
top drive is typically used to release the running tool. During rotation, the ROV monitors
the running tool to confirm the correct amount of rotation subsea at the wellhead. In
deepwater, additional turns may be required at the surface before the corresponding
amount of turns as noted subsea.

If the slope indicator changes when the string is slacked off to neutral weight, the casing
weight is picked back up and the casing is held in place until the cement surface
samples harden.

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CONDUCTOR CASING

In floating drilling, the next string of casing to be set after structural casing is conductor
casing. The most common size for conductor casing is 20 in., 133 pounds/ft or 169
pounds/ft. The purpose of this casing string is to provide sufficient hole integrity to drill
the surface hole. This casing string will include the 18-3/4 in. high-pressure wellhead
housing and will typically be set to a minimum of 1000 ft below the mud line (BML) and
commonly set around 2000 ft BML. The BOP stack will be installed onto the high-
pressure wellhead after the conductor casing is set to provide a well control barrier for
the remainder of the well.

7.4.1 ENGINEERING DESIGN CRITERIA

In floating drilling, conductor casing has four design criteria:

Bending/Buckling.
Burst.
Collapse.
Connector selection:
Make-up.
Bending strength.

E a ch o f th e crite ria s liste d a b o ve w ill b e d iscu sse d in d e ta il b e lo w . T o p te n sio n fro m th e

riser is not a concern since the weight of the BOP stack will offset top tension from the
riser tensioners.

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7.4.2 BENDING/BUCKLING
Since the structural casing is designed to accommodate all bending loads, the main
buckling and bending risk for 20 in. conductor casing occurs when it is run. This is
because it is always run in open water where there is no lateral support. The following
causes bending and buckling loads imposed on the conductor casing:

Vessel motion can place large bending loads on the casing when it is sitting in
the slips. This problem is mainly associated with the older smaller drill ships and
semisubmersibles that experience excessive roll. Excessive vessel motion can
cause the bending moment on the casing at the rotary where the casing is fixed
in the slips. This problem is exaggerated as the casing weight increases and the
pipe becomes more fixed (unable to rock) in the slips.

Deep currents and currents greater than 2 knots can place large bending loads
on conductor casing while it is being run. Anytime current can push the 20 in.
casing against the side of the moon pool; bending failure of the casing is a real
risk. High currents can also cause vortex-induced vibration, which can cause
fatigue failure.

The most common buckling risk to conductor casing is excessive set down
weight from tagging a bridge when running the casing. This can be mitigated by
good running procedures and practices; and by always running 20 in. casing in a
clean hole with sufficiently dense spotting mud in the hole. Unsupported casing
can be difficult to detect when working in open water since the weight indicator
typically does not change as the pipe bends in open water.

The largest buckling load in designing 20 in. casing is the weight of all
subsequent casing strings, the weight of the inner cementing string, and the
weight of the BOP stack, assuming top 800 ft of casing unsupported by cement
and no load sharing with the structural casing string.

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Current Speed

Current Speed

Figure 40 Current Effect on Casing

during Deployment Operations

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7.4.3 BURST
The 20 in. conductor casing should provide sufficient burst resistance so that the
formation will always fail before the casing. Typically, 20 in. 133 ppf X-56 or 20 in.
169 ppf X-56 casing is used as conductor casing on floating rigs. This casing has an
API burst of 3060 psi/4500 psi.

This burst capability of the conductor casing is important because the well will be shut-in
if a kick occurs and not diverted. In practice, the BOPs, not the diverter, will always be
the preferred immediate response to a kick taken while drilling below conductor casing.
When 20 in. is set 1000 ft or deeper below the mud line, the potential weaknesses of the
Regan type diverter used on floating rigs and the slip joint inner barrel packing typically
make shut-in the safest option.

7.4.4 COLLAPSE
The most likely threat of collapse to the 20 in. conductor casing string is human error in
not filling the casing and/or landing string as the casing is run. One common mistake that
has caused the collapse of 20 in. casing is failure to consider the hydrostatic exerted by
the fluid column in the landing string. In deepwater, this can be the majority of the
collapse pressure exerted on the casing. The additional pressure exerted by heavy pad
mud spotted in the conductor hole and/or cement in the annulus should also be
considered when verifying the collapse resistance of the casing.

Using heavier pipe such as 133-ppf versus 94-ppf can give roughly three times more
collapse resistance. However, procedures and practices must still be used to ensure that
every joint of casing is filled and all of the air is displaced from beneath the running tool
as the casing is run.

7.4.5 CONNECTOR SELECTIONS

The connector must provide as a minimum, the same tensile, bending, and burst
resistance as required for the conductor casing. Typically, proprietary weld on threaded
connectors will be used for the 20 in. conductor casing string. Due to vessel motion
causing cross threaded make up, API connections such as buttress are typically not
used for the 20 in. conductor casing string on floating rigs.

Typical connectors used for conductor casing are the Vetco RL-4S, RL-1 or Dril-Quip H-
90 connector in box up by pin down mode for this casing string.

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7.4.6 DRILLING CONDUCTOR HOLE RISERLESS VERSUS

WITH PIN CONNECTOR AND RISER
The two options for drilling the conductor hole is riserless allowing returns to the seafloor
or installing a pin connector and taking returns at the rig. The most common practice
within the industry is to drill the conductor hole riserless due to the additional time
required to run a pin connector and risks associated with handling a shallow gas kick
with a floating rig diverter system. For information on pin connectors, refer to Section 9.

Advantages and disadvantages of riserless drilling are:

If the well kicks on a shallow water location, the resulting gas boil will typically push
the rig off to one side of it. As the brakes are released on the down-wind anchor
winches, the potential energy of the mooring system moves the rig off location.
Increasing water depth mitigates the risk of fire and loss of water buoyancy
from a kick at the seafloor.
As grave as having the well kick at the seafloor beneath the rig is, it is less
risky than having a riser in place. The riser provides a large capacity conduit
to take the kicking well flow to the rig floor, where the diverter system may be
inadequate to handle the flow.
Drilling the conductor hole with a pin connector and bringing mud returns to the rig
can be beneficial when working in shallow water. But, it would most likely cause lost
returns when used in water depths greater than 1000 ft due to the increased column
height above the structural casing shoe.

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7.4.7 PILOT HOLES

In new areas where the geology is uncertain or areas where shallow seismic indicates
possible shallow gas or over-pressured water sands, a pilot hole can be drilled to
explore the shallow reservoirs.

A pilot hole is used to assist in well killing since the smaller annulus provides additional
ECD and less volume to be filled with mud. A typical pilot hole size is 9 7/8 in. and is
drilled with 8 in. drill collars and seawater. Pilot holes are generally used in one of the
two following formats:

Position the rig off location 300 to 500 ft and drill the pilot hole to the proposed
conductor casing setting depth. This option allows shallow reservoirs to be explored
and the final conductor hole depth to be adjusted based on shallow hazards
encountered. The disadvantage to this option is that it may provide a broaching path
to the seafloor from the final wellbore location and it can be difficult to plug and
abandon the pilot hole.

Set the conductor casing and drill the pilot hole to conductor casing setting depth
beneath the structural casing. This method also provides the smaller hole for well-kill
operations and can be more economical since it does not require the pilot hole to be
plugged. The disadvantage of this method is that after drilling into a shallow hazard,
the hazard must be isolated to allow the hole to be opened to full bore. Loss of the
pilot wellbore due a shallow flow could also cause the structural casing and other
wellbore to the lost.

After drilling the pilot hole, it is typically opened in one pass with stacked hole openers
(15 by 26 in.).

If prior experience in a given area indicates this hole can be drilled with seawater and
shallow seismic indicates no hazards, then the conductor hole section can be drilled with
a full size bit. The conductor hole is typically drilled with seawater using high viscosity
gel sweeps and wiper trips to clean the hole. For deepwater locations, drilling is usually
performed with a rotary assembly, but precautions must be taken to ensure the drill
string remains in tension in the open water section. It is not uncommon to find bent joints
of drill pipe or heavy weight drill pipe after completing the open water section on a
deepwater location. If the location is prone to high currents, it may be necessary to drill
the open water section with a mud motor to minimize the fatigue on the pipe as it is
rotated in open water.

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When drilling the conductor hole interval, it is typical to maintain a volume (400 to 500
bbls) of weighted kill mud (12.0 to 14.0 ppg). The actual volume and weight of this fluid
is usually determined by the dynamic kill analysis, rig storage capacity, and the
perceived risk of encountering shallow gas. If a pilot hole is drilled, this mud would be
used to perform the dynamic kill and provide overbalance on the formation. If a full
gauge hole is drilled, the volume of weighted mud would be available to spot in the hole
after reaching TD and to stabilize the well if small water or gas sands were encountered.

In the GOM, shallow water flows (SWF) are common in some deepwater regions and
are routinely drilled with a weighted mud while allowing returns to exit at the seafloor.
This method provides the necessary hydrostatic below the mud line to control the SWF
and allows the interval to be drilled and isolated with casing. Depending on the interval
to be drilled, this method can require 10,000 15,000 barrels of weighted mud to
successfully drill the interval.

Figure 7.41 - Drilling Conductor Hole Blind

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7.4.8 CASING RUNNING PREPARATIONS

A fte r d rillin g th e h o le to T D , p a d m u d is typ ica lly sp o tte d in th e h o le to a ssist ke e p in g
the hole open while running the casing. Mud weight for the spotting fluid typically ranges
from 9.0 ppg high viscosity gel mud to 14.0 ppg mud. In addition to weight, the chloride
content of the mud may also be increased with either sodium or calcium chloride to
inhibit shale hydration in the shallow formations. When spotting weighted fluid to provide
density to control shallow formations, water loss control may also be adjusted with
bridging material to prevent seepage losses to the highly permeable shallow formations
and hydrostatic pressure loss . The mud may be spotted before or after the wiper trip.

Since the conductor casing does not provide the bending strength required to support
the wellhead free standing above the mud line, it is critical that the 20 in. casing go all
the way to planned setting depth to properly land out onto the low pressure wellhead.
Since pup joints are not used with the conductor casing, the casing is typically measured
beforehand and the hole depth drilled to match the casing length to ensure that sufficient
rat hole remains for fill as the casing is run. Rat hole lengths typically range from 30 to
50 ft depending on hole conditions and experience in the area.

To minimize the time that the hole is open, the following items are typically preformed
out of critical path:

Prepare the 18 3/4 in. high-pressure wellhead joint either on the wiper trip or prior to
drilling the conductor hole by:

Painting white indicator rings around the joint every 5 ft from the landing shoulder
of the high-pressure housing down and one-ft indicators between the rings.
These would be used to measure unexpected premature stick up.
Measure weld on centralizer ribs to ensure that they will go into the low-pressure
wellhead housing.
Inspect all sealing areas in 18-3/4 in. wellhead housing for scoring.
To provide for easy make up of the 18-3/4 in. high-pressure wellhead joint, an easy
to stab, non threaded connector may be used to compensate for the top heavy hard
to stab wellhead. This is especially important on rigs that are sensitive to rig motion.
If guidelines are being used, four chain links are welded onto the 20 in. shoe joint at
360o, 90o, 180o, and 270o above the float shoe to provide an anchor point for the
rope guides. Distance from shoe for placement of the links is determined by the
height of the guidepost to ensure that shoe stabs into structural casing before the
guide ropes break. A typical distance is post length plus five ft.
Also, a rotating ring can be installed on the casing between stop collars and rope
guidelines connected to it at 360o, 90o, 180o, and 270o.
Paint depth marks on the shoe joint at five-ft intervals to assist the ROV video.
Clean connectors, install o-rings, and replace protectors. Visually inspect conductor
casing for foreign material that may plug the float shoe.

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7.4.9 RUNNING CONDUCTOR CASING WITH GUIDELINES

Prior to beginning casing operations, a table with maximum set down weight for any
given float shoe depth, in 100 ft increments should be developed to prevent buckling the
casing in open water. Maximum set down weight limits are typically limited to 80% of
buoyed conductor casing weight, below the mud line. When running the casing in a hole
filled with weighted pad mud, the additional buoyed force should be considered when
determining the maximum set down weight.

Since the landing string requires rotation to release the wellhead running tool, the casing
is typically landed with the landing string made up into the top drive. Prior to beginning
casing operations, a cement stand consisting of either a top drive cement head of a side
door pump-in sub with safety valves located above and below is made up into a stand of
pipe and placed in the derrick. To allow for proper space out of the cement head above
the floor, singles may need to be added or removed from the landing string as the casing
is run in the hole. If changes to the landing string are required, it should be made during
the first couple of stands to prevent the long delays after the casing enters open hole. A
typical space out for the cement head is 15 ft above the floor to provide contingency for
rig offset and heave.

As the casing is made up, the float shoe joint should be filled with seawater and the
observed in the moon pool to ensure that the water can drain freely. If guidelines are
used, the guide ropes are connected to the chain links welded to the shoe joint and
attached to the guidelines. Guide ropes are usually attached to the guidelines (Figure
7.42) by either looping a short section of chain around the line that can fall away when
the rope breaks from the chain or by attaching small shackles around the guidelines. If
shackles are used, they will remain on top of the guideposts and could cause
interference for other guidance equipment.

Guide Ropes installed with

shackles onto the guidelines

Figure 7.42 Guide ropes installed from conductor casing to guide

lines.

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Quick start, easy stab

connector design

Figure 7.43 Vetco RL-1S Quick Start Easy Stab

Connector

Since the connectors that are typically used on conductor casing are quick stab (Figure
7.43), it is important to ensure that the proper torque is applied to all connections and the
locking tabs are installed. Quick stab connections can back-out with as little as 1/4 turn,
especially with weight suspended below. After making up the first joint into the shoe
joint, it is typical to energize all locking tabs to provide added resistance to prevent
backing off the joint while drilling the cement and float shoe. For the remainder of the
casing, only two locking tabs are typically used to allow the two remaining tabs to be
used as backup should the casing need to the laid down and rerun. During makeup, any
joints that do not align properly to allow the tabs to be energized should be rejected and
replaced. If the wellhead joint is equipped with a quick stab connector, all tabs should be
energized to prevent the connection from backing out during P&A cutting operations.

To assist the ROV in identifying the movement of the casing with video camera, white
reference lines are typically painted at each connection. This indicator line enhances the
video and provides a reference as the pipe moves into the wellbore.

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7.4.10 MAKING UP 18-3/4 IN. HIGH-PRESSURE

WELLHEAD JOINT
The wellhead is typically handled and made-up into the string using a wellhead running
tool installed in the wellhead with a short drill pipe pup joint and the drill pipe elevators.
The wellhead running tool is required since the wellhead does not provide a shoulder for
side door casing elevators. After making up the wellhead into the casing string, the
wellhead and casing string are lowered to either land out the wellhead in the rotary or on
a false rotary in the moon pool. After landing out the wellhead, the running tool is
removed to allow the cement stinger to be installed.

Depending on testing requirements after the BOP is installed, the nominal seat protector
(NSP) may or may not be installed in the wellhead before it is run. For information on the
NSP, refer to Section 8.

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7.4.11 RUNNING DRILL PIPE CEMENTING STINGER

Since cement wiper plugs are almost never used with 20 in. conductor casing, a cement
stinger is used to improve displacement, and to reduce cement contamination and
displacement time. The cement stinger is typically a section of the drill string and is run
to +/-100 ft of the shoe. The placement of the cement stinger is based on the volume of
cement to be left in the casing and the accuracy of the displacement. Since it may be
necessary to wait on cement and hold the casing in place after the cement job, it is
important to ensure the cement is displaced a safe distance below the stinger, yet still
maintain sufficient volume to allow the casing to be tested against the cement.

The cement stinger is run by installing a false rotary type C-plate on top of wellhead
(Figures 7.44 and 7.45) and using a small set of bowl and slips used to secure the drill
pipe. If a small set of bowl and slips are not available, two sets of drill pipe elevators can
be used to install the cement stinger.

Figure 7.44 Wellhead False Rotary

Figure 7.45 C Plate F or W ellhead F alse R otary

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After the cement stinger is installed, the 18 in. wellhead running tool is made up to the
stinger and the running tool secured to the wellhead by wellhead technician. To provide
a reference for alignment of the running tool alignment key and rotation of the tool stem,
a vertical anti-rotation mark should be painted on the 18 in. CART and the key slot
location. These paint marks will be used to visually confirm proper make up of the 18
in. CART into the wellhead as the casing is run and proper release of the 18 in. CART
after the cement job.

While running the cement stinger and working around the top of the wellhead, it is
important that the sealing area on the wellhead be protected and that the maximum
recommended torque be applied to the drill pipe-cementing stinger.

For wells where the water depth is less than the casing length, it will be necessary to
stab the casing into the wellbore and makeup the cement stinger while the casing is
stationary in open hole. To minimize the possibility of sticking the casing, operations
should be planned to minimize the time that the casing is stationary.

Located on the top of the 18 in. wellhead running tool are bleed ports that are used to
vent the air that is trapped beneath running tool after it is installed. To vent this trapped
air, the wellhead must be lowered to the waterline and seawater circulated through the
cement stinger to fill the void area and vent the trapped air (Figure 7.46). After the air is
vented, the wellhead is raised above the splash zone to allow the wellhead technician to
be lowered on
a riding belt to
close the
bleed ports.

Note: A void
filled with air
is caused by
the inability
to fill the
casing on
the inside
above the
height of the
sealevel on
the outside.

If the casing
is already
stabbed into
the wellbore Figure 7.46 Air Trapped in Casing
when the
running tool is installed, the wellhead is sometimes lowered below the waterline to allow
the void to gravity fill with seawater. This is necessary since circulation through the
landing string and cement stinger could also displace some of the pad mud from the
open hole.

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7.4.12 RUNNING CONDUCTOR CASING ON DRILL PIPE

LANDING STRING
As the casing is run in the hole on the landing string, it is important that the landing string
be filled to maintain adequate hydrostatic on the inside of the casing to prevent collapse
of the casing. Prior to beginning casing operations, the hydrostatic pressures should be
calculated to determine the critical depth for potential casing collapse. This is especially
important when working in ultra-deepwater wells where the water depth can be 6000 to
8000 ft and the casing TD can be up to 10000 ft.

As the casing is lowered, the ROV should be

20 in. Conductor Casing
positioned to assist and monitor the casing as it is
stabbed into wellbore and run in the hole. During
the movement of the casing in open water, the
video from the ROV is used to monitor the wellbore
for returns from the low-pressure wellhead housing
as the casing is slacked off and to prevent buckling
of the unsupported casing in open water. Monitoring
for returns is important since surge pressures
caused while running the large OD conductor
casing can cause the shallow weak formation to
break down and lead to poor cement displacement. Threaded
Connectors

While working in open water, it is critical that the

Driller monitor the ROV video continually as the
pipe is slacked off. When the casing is unsupported
in open water, the normal practice of watching the
weight indicator is insufficient to determine when
the pipe has hit an obstruction and the casing has
quit moving subsea. When the casing hits an
obstruction, the casing can buckle in open water
without a further reduction in the weight indicator. 20 in. Float Shoe

If a floating vessel is experiencing substantial

heave, the motion compensator may be aligned to
Low Pressure
begin compensating should the casing land on the Wellhead Housing
wellhead or tag an obstruction as it enters the
wellhead. Typically the compensator will not be Temporary
Guidebase
needed and is not used since the response time
may prevent the Driller from slacking off as quickly
as needed to stab the casing into the wellhead.
Figure 7.47 Running Conductor
Casing into Low Pressure
Wellhead Housing

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As the casing is stabbed into the wellhead, the guide ropes will land on the top of the
guideposts and break away as the casing is lowered. If currents or other environmental
forces have offset the casing to where the guide ropes do not properly align the casing,
the following are typically used to align the casing:

Loosen or tighten guidelines as needed to reposition and center the casing

over the low-pressure wellhead housing.
Reposition the rig using the anchor winches to align the casing over the
wellhead.
Have the ROV to push the casing over the wellhead as the Driller slacks off
the casing.
If the casing is being run without the assistance of guidelines and guide ropes, the rig
will need to be repositioned to align the casing close to the wellhead. After the casing
has been positioned close to the wellhead, the ROV can typically push the casing to
make the final alignment. During the repositioning of the rig, it is critical that the ROV
provide direction and distance for the rig move.

If casing will not go down at maximum set down weight or if the casing is not moving
subsea to coincide with the movement of the casing at the surface, the top drive is
typically made-up and mud or seawater circulated and washed through obstructions.
If weighted mud was spotted in the hole and circulation is required, it is important to
remember that the seawater inside the casing will be circulated into the open hole and
will result in a reduction of hydrostatic pressure. If circulation is required and hydrostatic
pressure must be maintained, weighted fluid should be displaced into the casing before
it enters the wellbore, and a volume of mud should be available to use to wash the
casing to bottom, if required.

If extreme hole conditions exist, where heavy mud must be spotted in the open hole, and
high set down weights are required to get the casing in the hole; a stab-in float collar can
be used to allow the cement stinger to be stabbed in and sealed to the float collar. In this
configuration, the annulus between the stinger and the casing can be filled with weighted
mud to provide additional casing weight, and the volume of seawater that must be
circulated from the casing is minimized.

Another change that will be noted if weighted mud was spotted in the wellbore will be a
loss in casing weight as the casing enters the wellbore. This loss in weight is caused by
the buoyed effect of the casing since the weighted mud will be on the outside with
seawater on the inside of the casing. This reduction in weight must be considered when
determining the available casing weight below the mud line to prevent buckling the
casing in open water. This loss in weight is sometimes mistaken for an increase in drag
as the casing is lowered. To determine if the loss of weight is drag or from the buoyed
effect (casing floating), the pick up weight can be used for a comparison.

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When the casing reaches total depth, a cementing stand from the derrick is typically
made up to the top drive and used to wash down the casing, if required, and land-out the
casing. When the last stand is made up from the derrick, the motion compensator should
be opened and aligned to land-out the casing on the wellhead and support the casing
and landing during cementing operations.

With the assistance of the ROV, the 18 in. wellhead is landed on the low pressure
wellhead with a set-down weight of 50 kips to allow the 18 in. wellhead to latch into the
low-pressure wellhead housing. After the weight is set down, the slope indicators should
be checked with the ROV to determine if the additional weight caused movement in the
wellhead housing. To confirm a proper latch into the wellhead, a 50 kips overpull test
above buoyed weight of casing, landing string, and air weight of blocks is performed.
After a successful overpull test, slack back to the original set-down weight and hold until
after the cement job.

Figure 7.47 High Pressure Wellhead Landed in Low Pressure Wellhead Housing

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7.4.13 CIRCULATING AND CEMENTING 20 IN. CASING

After landing the casing, circulation is typically established with seawater at a reduced
rate of 1-2 bpm with a minimum of landing string, cement stinger and casing capacity
below the cement stinger circulated. Once circulation is established, the pump rate is
staged up to the same or slightly more than the pump rate that will be used to cement
the conductor casing or about six to eight bpm. Returns while circulating and cementing
are through the cement ports on the low-pressure housing and must be monitored with
the ROV for possible lost returns.

If maintaining hydrostatic is critical due to exposed formations, weighted mud may be

required for circulation prior to cementing, and a minimum of only the landing string,
cement stinger and casing volume below the stinger may be circulated to ensure the
string is open prior to cementing.

7.4.14 SLURRY DESIGN

To achieve the most lateral strength and to best manage potential bending stresses that
could be imposed on the structural and conductor casing after the conductor casing is
cemented, a good cement overlap and bond must exist between the conductor and the
structural casing. The cement volumes and slurry should be designed to achieve this
bond and overlap.

Typically, the lead slurry will be an extended (prehydrated bentonite or sodium silicate)
lighter weight slurry (11.0 to 11.5 ppg) designed to bring cement to the seafloor, without
losing returns. The tail cement will typically cover 500 ft above the shoe and consist of
N e a t ce m e n t m ixe d fro m 1 5 .6 to 1 6 .2 p p g d e p e n d in g o n th e cla ss o f ce m e n t u se d .
Verify collapse resistance of 20 in. casing is sufficient for height of tail cement planned.
If required, reduce height of tail.

Slurry volumes for conductor casing are typically calculated using 100% excess of open
hole annular volume. Caliper logs or volumes calculated from mud circulation is typically
not available for this hole section. Cement tests should be performed for all slurries
using actual material samples, mix water from rig and under shallow formation
conditions (e.g. low temperature if operating in deepwater).

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7.4.15 CEMENTING AND DISPLACEMENT OPERATIONS

Prior to beginning cementing operations the ROV should be positioned to monitor the
cementing ports on the low pressure housing for returns during the entire job. Since the
mud and cement look very similar when viewed from the ROV, it will be very difficult to
determine if cement returns reach the seafloor. To help identify cement returns at the
seafloor, a fluorescent dye spacer may be pumped prior to the cement and viewed with
the ROV color camera.

Cementing operations for the conductor casing are typically very large and can take up
to three hours to mix, pump and displace. Mix and pump rates for the lead slurry can
range up to seven to eight bpm and with the tail slurry typically mixed at rates of four to
six bpm. High pump rates are beneficial in helping ensure good displacement due to the
large annular volume.

Since the cement stinger is +/-100 ft from the float shoe and the displacement volume
will be relatively small, the cement unit is used to displace the cement with seawater at
rates of six to eight bpm. During displacement, the pump rate is typically reduced to two
to three bpm prior to the cement exiting the cement stinger with the cement displaced to
50-70 ft of the shoe. When displacing the cement for the conductor casing it is important
to ensure that adequate cement remains in the casing to provide a casing test.

After displacing cement, the pressure is bled off to verify that the float shoe is holding.
If float is not holding, pump back the amount bled off and hold pressure until surface
samples are hard. If float is holding, slack off remaining 20 in. casing weight onto the
structural casing and check slope indicators with the ROV for change from vertical.
If no change in the slope indicator and the wellhead shows no sign of sinking, the
18 in. CART tool may be released.

If the slope indicator does change, hold casing weight with motion compensator for at
least four hours or until surface samples are hard. After the cement samples are set,
attempt to slack off 20 in. casing weight onto structural casing and recheck the slope
indicators.

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Once the conductor casing weight can be fully transferred to structural casing with
PGB slope indicator reading acceptable angle, release 18 in. CART and retrieve the
running tool and cement stinger. Caution should be taken as the cement stinger is pulled
from the wellhead to prevent damage to the sealing area within the wellhead and the
ring gasket area. When pulling out with the cement stinger, space out so that a
connection is not made with the end of the drill pipe stinger at the 18-3/4 in. wellhead.

Figure 7.48 - High Pressure Housing Landed

& 20 In. Casing Cemented (Running Tool Released)

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7.5 SPECIAL CONSIDERATIONS

7.5.1 HIGH CURRENTS

In certain areas of the world such as the Gulf Mexico, offshore Trinidad and the northern
coast of Brazil, high currents and eddies resulting from the Gulf Stream and the Guinea
current are quite common in many deepwater locations of these areas. Currents in these
areas have been measured as high as 3+ knots at the surface with 1+ knot currents as
deep as 2000 ft and have greatly impacted all open water operations. Currents as high
as 6 Knots have been recorded in the South China Sea. Figure 7.49 is a current profile
from a recent ExxonMobil deepwater drilling location with currents greater than 1 knot
down to 700 meters (2300 ft). Operating in this current profile proved very difficult to
perform open water operations. On initial spudding with a pilot hole drilling assembly, the
drill string tagged the seafloor with an angle of 5+ degree angle and completion of the
water open operations required 30+ days.

-100

-200
Knots
-300 0.25 black dotted
0.50 cyan dotted
0.75 blue dotted
-400 1.00 green
Depth (m) 1.25 red
1.50 yellow
-500 1.75 magenta
2.00 black
-600 2.25 cyan
2.50 blue

-700

-800

-900

-1000
2/10 2/11 2/12 2/13 2/14 2/15 2/16 2/17 2/18 2/19 2/20 2/21
Date(2001)

Figure 7.49 - Current Profile

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When spudding a well in an area where high currents are expected, a profile should be
obtained prior to beginning operations so that equipment can be designed and/or
modified. Listed below are some of the potential problems and solutions that have been
used when performing open water operations in this environment.

Drill strings or casing may be subjected to vortex induced vibration (VIV) that could
cause failure of the casing or drill pipe. For conductor casing, strakes have been
installed to reduce VIV.
When initially spudding the bottom and establishing location with either a bit or
casing jetting assembly, the wellbore can be offset 200 to 300 ft from the surveyed
position at the surface. Even if the offset location is within the location tolerance, the
well will mostly likely to spudded with an unacceptable angle
When running large bore tubulars in the high current environments, drag from the
current may offset the pipe such that it will not safely pass through the rotary without
unacceptable drag. Options to work around this have been to, provide a slight list to
the vessel to coincide with the angle of the pipe, when working with a DP rig, move
the rig up current and allow the rig to drift with the current as the pipe is run, or use
stab-in float equipment and fill the casing with heavy mud to decrease the angle.
Unacceptable bending loads on the pipe or casing. High bending loads typically
occur at the slip area where the stiff bending moment arm exists. Work around for
this problem has been to use a centering device in the moon pool or to secure the
pipe on the rotary in a set of tapered elevators instead of slips. The elevators allow
the pipe to rotate on the tool joint taper and minimize the bending moment.
If the current is only high at the surface, the angle will decrease as the pipe is run and
additional weight is placed below the current. If the current runs deep as shown in
Figure 7.50, the offset will tend to get worse as long as the same size pipe is being
deployed. When running casing on the landing string, the angle will tend to decrease as
the landing string is run since a smaller cross sectional is exposed to the higher surface
current with the heavier weight suspended below.

Figure 7.50 Current Profile Affecting Open Water Casing

operations

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7.5.2 SHALLOW WATER FLOWS

Shallow water flows (SWF) have been experienced in several deepwater exploration
areas. These flows normally occur either while drilling the 26 in. conductor hole or when
the conductor casing cement job reaches transition while setting up. These SWF have
occurred at depths from 200 to 2000 ft below the mud line (BML). These SWF are
extremely difficult to stop due to the narrow margin between pore pressure and fracture
pressure. Over the last 15 years, SWF has been a recurring and extremely costly
problem in deepwater wells. SWF has caused structural casing to buckle resulting in
uncontrolled flow to the seafloor, loss of subsea completion template slots, and
subsidence of subsea completion templates, threatening entire development projects.

T h e C o m p a n ys stra te g y fo r m a n a g in g th e S W F risks is to a ccu ra te ly p re d ict if S W F is

likely in a well, and if so, to use preemptive methods to manage the hazards. Prediction
is usually based on offset well and seismic data, and channel or slump features
indicating sand in the shallow hazard survey. To successfully manage SWF risks,
engineering must accurately predict the depth of SWF sands, their pore pressure, and
fracture gradient of the conductor hole section. The successful method to drill and case
off SWF sands is to drill with mud of sufficient density to avoid flow, and then to case
and cement the conductor casing with fast set cement slurry, to avoid SWF after
cementing. Both methods are discussed in detail below.

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7.5.3 DRILL WITH MUD P U M P A N D D U M P C O N C EPT

These SWF sands are typically 9.3 to 9.4 ppg pore pressure and will flow if drilled with
seawater. The formation integrity is insufficient to drill the conductor hole section with
m u d u sin g th e p in co n n e cto r a n d rise r. T h u s, th e cu rre n t b e st p ra ctice is to p u m p a n d
d u m p . T h is is th e p ra ctice o f d rillin g th e 2 6 in . co n d u cto r h o le w ith m u d , w ith o u t re tu rn s
to the seafloor. 10.5 12.5 p p g m u d is u su a lly u se d in p u m p a n d d u m p o p e ra tio n s.

The mud weight used is typically the maximum that can be used and still keep a
0.3 ppg margin between mud weight and formation fracture.
Where confidence of SWF sand depth prediction is high, the hole section can be
drilled with seawater and prehydrated gel sweeps until about 75 to 50 ft above
shallowest predicted SWF sand, and then use weighted mud.

METHOD AND PRACTICE

Drill 1000 ft section of 26 in. hole blind at about 100 ft per hour, with a circulation rate of
800 1000 gpm. This requires a larger amount of mud than the rig can normally carry.
Thus, the rig would build a large volume of 16.0 ppg mud and then water back the
weight with seawater to that required (10.5 to 12.5 ppg) in the suction pit just before it is
pumped downhole.

When the required hole depth and rat hole are made, the well is displaced to
required mud weight with a low fluid loss mud, with low flat gel strength
(YP ~ 10 and PV ~ 15) to facilitate cementing. Density of spotting mud should be
sufficient to kill the SWF, but not so heavy as to fracture weak zones or balloon.
The ROV should monitor returns for SWF from the time the conductor hole is started
until surface casing is successfully cemented.

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7.5.4 SPECIAL CEMENTING OPERATIONS

CONCEPT

Conductor casing by open hole annuli with SWF zones exposed must be successfully
cemented to provide a seal to eliminate SWF and to structurally support the conductor
casing. The current best practice for this is to use a fast-setting nitrogen foam cement.
The nitrogen reduces the density of the cement slurry to below the formation fracture
weight. The special fine grind of the cement causes the cement to have a right angle set
item, with no transition. This should preclude the SWF zone from flowing once the
cement starts to set. A typical inner cementing stinger will be run inside the conductor
casing to about 150 ft above the float shoe. Activities after mixing and displacing cement
are the same as would follow any conductor casing cement displacement. These would
include monitoring for wellhead subsidence while slacking off conductor casing weight
onto low-pressure wellhead housing and rigidly locking the 18-3/4 in. high-pressure
wellhead onto the low-pressure wellhead.

METHOD AND PRACTICE:

Circulating and conditioning mud to cement: Once the conductor casing is landed
out with 50 kips down, the cement job will begin. Except for the 50 bbl lead spacer
ahead that is 0.2 ppg heavier than the kill mud, the well will not be circulated prior to
cementing. The ROV will have jetting tool ready to use and stand by to observe open
cement ports on low-pressure wellhead housing. If there is any question that the cement
ports might be plugged, the ROV should clean them out.
Cement slurry design: Cement slurries planned to isolate SWF consist of a large
foamed lead slurry and small unfoamed neat cement tail slurry. A 50-bbl spacer
weighing 0.2 ppg more than kill mud left in hole, should be pumped ahead of the
lead slurry.

Lead slurry:
Slurry volume includes 200% casing by open hole excess.
Lead slurry is designed fast set after about five hours thickening time.
Nitrogen is staged into cement going downhole to maintain density at
0.5 ppg > than mud weight left in hole.
Slurry is mixed and pumped at four to six bpm.

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Tail slurry:
Slurry volume includes 100% casing by open hole excess.
Tail slurry is designed to fast set after about 3-3/4 hours thickening time.
Lead slurry density 15.2 ppg.
Lead slurry is not foamed with nitrogen.
Slurry is mixed and pumped at four bpm.

Displacement:
Cement will be displaced at eight to twelve bpm with seawater.
Slow down displacement rate to three bpm for the last 20 bbls of displacement.
Displace cement to leave about 100 ft cement sump inside conductor casing.
Displace cement with cementing pump only.
Have ROV close all cement port ball valves immediately after displacement pumped.
Check float valve and continue per normal conductor casing cement job.

Safety:
Hold JSA meeting before rigging up and starting nitrogen foam cement job.
Ensure that all Chiksan connections and swivels are properly hobbled with
competent safety chains and clamps.
Pressure test nitrogen lines with water, not nitrogen.
Use hand held radios to ensure good communication between nitrogen pump,
cementing unit, rig floor, and cement bulk tanks.

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8
CASING/CEMENTING OPERATIONS Section

8.0 SUBSEA WELLHEADS & CASING/CEMENTING

OPERATIONS

OBJECTIVES

The intent of the material in this section is to cover the differences in wellhead and
casing/cementing operations conducted from a floating rig and the same operations
conducted from a rig with surface wellhead equipment. A basic understanding of
surface wellhead equipment and casing/cementing operations is required. Special
situations that may arise during these types of operations on a floating rigs are also
covered.

On completion of this section, you will be able to:

Describe the major differences between surface and subsea wellhead equipment.

List the number and size of casing strings that are run on a typical well drilled from a
floating rig.

List the major components of a subsea wellhead system.

Name five manufacturers of subsea wellhead equipment.

Describe the two primary methods for actuating casing hanger seal assemblies and
two types of sealing elements.

Describe the major differences between subsea release wiper plugs and similar
equipment used during cementing operations with surface wellhead equipment.

State the procedure to take if a casing hanger seal assembly fails to test.

Describe the corrective action that must be taken if casing becomes stuck off bottom
on a well drilled from a floating rig.

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

CONTENTS Page

8.0 SUBSEA WELLHEADS & CASING/CEMENTING OPERATIONS ................................................. 1

OBJECTIVES ................................................................................................................................... 1
8.1 EQUIPMENT AND TOOL DESCRIPTION ....................................................................................... 3
8.1.1 INTRODUCTION..................................................................................................................... 3
8.1.2 DESIGN FEATURES AND CAPABILITIES .................................................................................. 8
8.1.3 OVERVIEW OF WELLHEAD COMPONENTS ............................................................................ 11
8.1.4 OVERVIEW OF TOOLS ......................................................................................................... 15
8.1.5 SEAL ASSEMBLIES ............................................................................................................. 22
8.2 CASING OPERATIONS ................................................................................................................. 28
8.2.1 INTRODUCTION................................................................................................................... 28
8.2.2 GUIDELINES AND PRECAUTIONS ......................................................................................... 28
8.2.3 SETTING AND TESTING THE SEAL ASSEMBLY ....................................................................... 34
8.3 CEMENT EQUIPMENT/HEAD MAKEUP AND OPERATIONS ..................................................... 37
8.3.1 INTRODUCTION................................................................................................................... 37
8.3.2 SPECIAL EQUIPMENT ......................................................................................................... 39
8.4 SPECIAL SITUATIONS ................................................................................................................. 44
8.4.1 LEAKING SEAL ASSEMBLY ................................................................................................. 44
8.4.2 STUCK CASING/CASING PATCH INSTALLATION ................................................................... 46
8.4.3 LARGE BORE WELLHEADS ................................................................................................. 48
8.4.4 DRILQUIP THIRTY INCH TOP UP SYSTEM (TITUS) ............................................................... 50

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

8.1 EQUIPMENT AND TOOL DESCRIPTION

8.1.1 INTRODUCTION

Wellheads, casing hangers and seal assemblies used at either the surface or subsea
must be designed to meet the following requirements:
1. The wellhead must have enough strength and stiffness to support the blowout
preventers during drilling/completion operations and Christmas tree equipment if the
well is produced.
2. The wellhead and casing hangers must be capable of supporting the weight of the
casing strings suspended from the wellhead.
3. The wellhead must provide a housing and sealing surface that, along with suitable
seals, is capable of containing fluids and pressures up to the rated working pressure.
It is difficult to meet these requirements at the surface and even more difficult subsea. In
addition, the subsea wellhead must be capable of resisting the bending moments
im p o se d b y th e flo a tin g d rillin g ve sse ls m o ve m e n t o ff lo ca tio n a n d , a lo n g w ith the
structural casings strings, the forces exerted by a tensioned riser. The first subsea
wellheads used for floating drilling rigs were adaptations of surface wellhead equipment
and were manufactured by CIW. Vetco and National Oilwell entered the subsea
wellhead market in the early 1970s. Many early floating rigs used low pressure (~ 5k
psi) two stack wellhead systems (typically 21-1/4 in. & 13-5/8 in.) that were bulky and
inefficient. After the mid-1970s, the Industry standardized on 18-3/4 in. 10k psi BOP
equipment with a few 16-3/4 in. systems used in special applications such as
dynamically positioned (DP) drillships. Beginning around the mid-1980s, most new
floating rigs and rig upgrades were equipped with 18-3/4 in. 15k psi BOP equipment
due to Industry demands. Deeper water and higher pressures required the development
of 18-3/4 in. 15k psi subsea wellhead systems with metal-to-metal seal assemblies.
Further challenges are pushing the Industry to develop 20k psi BOP and subsea
wellhead systems.
Refer to EMDC Drilling OIMS Manual, Element 3, Drilling Design Standards for a list of
acceptable subsea wellhead systems (based on successful ExxonMobil field
experience). At the time of this writing, the list includes systems from ABB Vetco Gray,
DrilQuip, Cameron, FMC and Kvaerner National. Vetco is currently providing about 40
to 50% of the subsea wellhead equipment used by the entire Industry. The remainder of
the market is divided among DrilQuip, Cameron and FMC, with National providing < 5%.
F o r sim p licity a n d d u e to th e a m o u n t o f e q u ip m e n t th a t is ru n w o rld w id e , V e tco s M S -700
system will be used for discussion and illustration. This is not meant to imply that this is
the best system or the only system to consider, but rather that it is representative of the
typical equipment that will be encountered. Actual selection should be based on specific
requirements, current experience, cost, availability, etc. The manufacturer must provide
detailed information on equipment specifications, running tools and procedures for the
equipment that is selected.

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

Typical subsea wellhead equipment is shown in Figure 8.1. Similar equipment with a
retrievable Permanent Guidebase (PGB) used with moored floating rigs is shown in
Figure 8.2. Figure 8.3 shows a Guidelineless Re-entry Assembly (GRA) that is used
with Dynamically Positioned (DP) rigs. The low pressure wellhead housing is run on the
structural casing (typically 30 in. to 36 in.) which can either be drilled and cemented or
jetted-in. The 18-3/4 in. high pressure wellhead housing is run on the conductor casing
(typically 20 in. to 22 in.) and lands-out and latches into the low pressure housing. The
18-3/4 in. high pressure housing provides a means to connect to the subsea BOP stack
(or subsea Christmas tree if the well is produced) and suspend casing strings that are
run below the conductor casing. Most subsea wellhead manufacturers allow their BOP
connector profile to be cut on other manufacturers wellheads to avoid the need to
change out the hydraulic BOP wellhead connector each time a different subsea wellhead
system is used. Operationally, the conductor casing and high pressure wellhead are run
on drill pipe or landing string. The high pressure wellhead is landed and latched into the
low pressure wellhead, and the conductor casing is cemented to the mudline. The
subsea BOP stack and riser are then run, and the BOP hydraulic connector is clamped
to the top of the high pressure wellhead. Drilling is then ready to proceed for
subsequent casing strings.

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CASING/CEMENTING OPERATIONS

18-3 /4 H ig h P re ssu re
Wellhead Housing

7 C a sin g H a n g e r 3 0 .9 1
& Annulus Seal

9-5 /8 C a sin g H a n g e r
& Annulus Seal 5 4 .8 3

Low Pressure
Wellhead Housing

13-3 /8 C a sin g H a n g e r
& Annulus Seal

F igure 8 .1 V etco M S - 7 0 0 , 1 8 S ubsea W ellhead S ystem (S how n W ithout G uidebase)

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

Figure 8.2 Vetco

MS-700 Subsea Wellhead
System With Retrievable
Permanent Guide Base
(PGB)

Figure 8.3 Vetco MS-700

Subsea Wellhead System
With Funnel Up Guidelineless
Re-Entry Assembly (GRA)

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

Each string of casing that is run below the conductor is remotely landed and sealed in
the 18-3/4 in. high pressure housing, as shown in Figure 8.3.
Note: The casing hanger and seal assemblies (commonly called pack-offs) stack one on
top of the other inside high pressure housing. 13-3/8 in. casing is typically the first string
run, landed and packed-off inside the high pressure wellhead. After running the 13-3/8
in. casing, each subsequent string has its own hanger and seal assembly that land on
top of the previous seal assembly. In this example, 9-5/8 in. casing and 7 in. casing
have been run below the 13-3/8 in. casing.
Note: If the seal assemblies run inside the high pressure wellhead leak, pressure is also
applied to the outer and inner casing strings and shallower formations. This could cause
the outer casing to burst, cause an underground blowout or collapse the inner casing
string if the leak occurs during pressure testing. Unlike surface wellhead equipment,
subsea wellhead equipment does not have a means for monitoring or for relieving
pressure build-up in the casing annuli below each seal assembly. This is a major
difference between surface and subsea wellhead equipment. Great care must be taken
in running and testing the seal assemblies on subsea wellhead equipment. Procedures
for running, testing and repairing/replacing seal assemblies will be discussed later in this
section. Also related to the pressure build-up in the casing annuli is a phenomenon
known as Annular Pressure Build-up (APB), which is extremely critical on high
pressure/high temperature (HP/HT) subsea production wells or subsea wells that are
tied-back to surface structure. APB has resulted in the failure of several non-EM
operated wells in the US GOM. APB will be discussed further under Cementing
Operations.

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

8.1.2 DESIGN FEATURES AND CAPABILITIES

Subsea wellhead equipment is designated by the inner diameter (ID) and pressure rating
of the high pressure wellhead housing. The required ID depends on the size of the BOP
stack that the floating rig is equipped with. Systems are available in 18-3/4 in. and 16-
3/4 in. sizes and 10k and 15k psi pressure ratings. Very few 16-3/4 in. systems are
currently manufactured, as their use is generally limited to the few remaining older
drillships that are still equipped with 16-3/4 in. BOP stacks. API Specification 17D (Spec
17D) covers subsea wellhead equipment. Standard subsea wellhead systems are
typically rated between 2.5 and 3.0 million ft-lbs bending and 6.0 to 7.0 million lbs load
capacity.
Bending load ratings are typically governed by the wall thickness of the high pressure
wellhead housings and how the high and low pressure wellheads interact together.
Standard subsea wellhead systems will generally have a high pressure housing outer
diameter (OD) of about 27 in. To obtain a higher bending rating, the high pressure
housing OD is increased (to as much as 30 in.), the high pressure to low pressure
wellhead housing interface is strengthened, and a special high strength wellhead
connector is required. The wellhead load capacity is the sum of the maximum combined
casing loads plus the test pressure load at the full rated working pressure. For an 18-3/4
in. inner diameter (ID), 15k psi working pressure wellhead, the test pressure load is
equivalent to 4.1 million (M) lb. Table 8.1 lists ratings for various manufacturers 18-3/4
in., 15k psi subsea wellhead systems that the student is most likely to encounter.

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

Subsea Wellhead Sizes and Working Pressure/Bending/Load Ratings

Manufacturer System Name Size Pressure Bending Load

Capacity
Vetco MS-700 18-3 /4 15k psi 3.9 M ft-lb 7.1 M lb
Vetco Super MS-700 18-3 /4 15k psi 7.0 M ft-lb 7.0 M lb
Vetco MS-700 Full Bore 18-3/4 15k psi 3.9 M ft-lb 6.1 M lb

DrilQuip SS-15 18-3 /4 15k psi 5.75 M ft- 7.0 M lb

lb
DrilQuip SS-15ES 18-3 /4 15k psi 9.0 M ft-lb 7.0 M lb
DrilQuip SS-15ES BigBore 18-3 /4 15k psi 8.0 M ft-lb 7.5 M lb

FMC UWD-15 18-3 /4 15k psi 4.4 M ft-lb 7.1 M lb

Cameron STM-15 18-3 /4 15k psi 2.5 M ft-lb 7.0 M lb

National SB 18-3 /4 15k psi 4.5 M ft-lb 6.4 M lb

Kvaerner
Table 8.1 Subsea Wellhead Sizes and Working Pressure/Bending/Load Ratings

Most manufacturers offer both three-hanger and four-hanger high pressure wellhead
housings, although four-hanger housings are becoming less popular. A typical casing
program for the three-hanger housing is 36 or 30 in. x 20 in. x 13-3/8 in. x 9-5/8 in. x 7
in., with the three casings strings in bold type landed in the high pressure wellhead. For
the 4-hanger housing it is 36 or 30 in. x 20 in. x 16 in. x 13-3/8 in. x 9-5/8 in. x 7 in.,
again with the four casing strings in bold type landed in the high pressure wellhead.
With most four-hanger systems wellhead housings, a dummy 16 in. hanger must be run
if the 16 in. casing is not needed. If 16 in. protective casing is required, the current trend
is to run a three-hanger wellhead housing with a 16 in. low pressure (typically 5,000 psi
rating) hanger profile sub welded into the 20 in. casing below the high pressure
wellhead. This effectively converts the three-hanger wellhead into a four-hanger
wellhead and does not require a dummy 16 in. hanger if the 16 in. liner is not run.

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

Note: The hanger profile sub can be run directly below the 18-3/4 in. high pressure
housing (leaves none of the 20 in. casing exposed) or can be run deeper in the string
(requires higher burst rating for the 20 in. casing that is left exposed after running the 16
in. liner). The former option is desirable if there is concern with leaking 20 in. casing
connections whereas the latter option should be considered if there is a high potential for
sticking the 16 in. liner off bottom. The student should consult with experienced
individuals and local practice.
For deepwater applications where shallow water flow is a problem, most wellhead
manufacturers also provide a low pressure hanger profile sub below the low pressure
wellhead housing that allows running an additional string of 26 in. or 24 in. casing below
the structural casing. With the addition of an 11-3/4 in. liner hung off the bottom of the
13-3/8 in. casing, this brings the total number of available casings strings to eight:
36 in. x 26 in. or 24 in. x 20 in. x 16 in. liner x 13-3/8 in. x 11-3/4 in. liner x 9-5/8 in. x 7 in.
Several manufacturers (Vetco and DrilQuip) now offer large bore wellhead systems with
an additional 18 in. low pressure hanger profile sub run in the 22 in. casing below the
18-3/4 in. high pressure wellhead. This increases the total number of available casing
strings to nine: 36 in. x 26 in. x 22 in. x 18 in. liner x 16 in. liner x 13-3/8 in. x 11-3/4 in.
liner x 9-5/8 in. x 7 in.. Large bore wellhead systems will be discussed further under
Special Situations at the end of this section.
The subsea wellhead housing is subjected to the same bending forces as the structural
casing and must be able to resist these forces without failing or sustaining damage.
Although subsea wellhead housings are generally thick wall construction and made of
moderate to high yield material, bending ratings are especially important in deeper water
and for wells drilled from dynamically positioned (DP) rigs. Bending ratings for various
subsea wellhead systems are listed in Table 8.1. These ratings and the strength of the
structural and conductor casing must be designed to exceed the expected loads that will
be encountered during the life of the well.
Note: Most subsea wellhead manufacturers now offer an improved method to reduce
bending fatigue whereby the low and high pressure wellhead housings are rigidly locked
together. The rigid lockdown feature causes the two wellheads to act as one
component, preventing cyclic movement which could cause fatigue failure in the
conductor casing below the wellhead. Rigid lockdown should be considered for
production wells or any well drilled in a high current environment. Wellhead
manufacturers should be consulted for exact ratings, options and recommendations. For
critical and/or deepwater wells, it is also recommended that EM URC conduct a bending
analysis which includes both the wellhead and the structural and conductor casing
strings.

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

8.1.3 OVERVIEW OF WELLHEAD COMPONENTS

Subsea wellhead equipment consists of a few major components: Low pressure

wellhead housing, high pressure wellhead housing, various sizes of mandrel-type casing
hangers and seal assemblies. Auxiliary equipment consisting of Temporary Guidebase
(TGB) or mudmat (both optional) and Permanent Guidebase (PGB) are used in
conjunction with the subsea wellhead equipment. The decision to use a temporary
guidebase or mud mat depends on many factors: water depth, rig type, seafloor
conditions, high current, etc. Permanent guidebases are used on most wells drilled from
a floating rig. The type of permanent guidebase is dictated by several factors: rig type
(DP or moored), is the rig equipped with guidelines, etc.
Note: a P G B is n o t re q u ire d if th e rig s B O P sta ck is e q u ip p e d w ith a fu n n e l d o w n . F o r
more information on guide bases and guidance systems, refer to Section 7, Open Water
Operations.
Low Pressure Wellhead Housing is run
on top of the last joint of 30 in. or 36 in.
structural casing and is locked into the
permanent guidebase. The structural
casing can be set either by being
cemented into a pre-drilled hole or jetted
into place. The low pressure housing
(Figures 8.1 and 8.4) is designed to
transfer the combined loads of all
subsequent casing strings, BOP stack and
riser to the surrounding formation and must
resist bending moments from the BOP
stack and riser. It also provides the
landing area for the high pressure
wellhead housing to lock into and has
cementing ports for the conductor casing
Figure 8.4 Low Pressure Wellhead cement job. The low pressure housing has
Housing an internal profile that accepts a cam-
actuated running tool. Optional features include but are not limited to rigid lockdown to
high pressure wellhead housing, hydrate seals/deflectors and ROV actuated ball valves
to close cementing ports. For deepwater applications, a supplemental low pressure
hanger profile sub can be run below the low pressure wellhead housing that allows
running an additional string of 24 in. or 26 in. casing.

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

HIGH PRESSURE WELLHEAD HOUSING

High Pressure Wellhead Housing is typically run on top of the last joint of conductor
casing and is latched or locked into the low
pressure housing. The high pressure housing
(Figures 8.1 and 8.5) provides the main pressure
vessel interface between the BOP equipment and
the well casing. The majority of high pressure
wellheads currently being run are 18-3/4 in. to
match the size of the rig s su b se a B O P sta cks.
The size of the high pressure housing refers to
the nominal bore through which the casing
hangers and seal assemblies must pass. The
bore of the high pressure housing is limited by the
landing shoulder for the lowermost casing
hanger, which is generally large enough to drift a
17-1/2 in. bit. Note there is still a very limited
number of MODUs (mostly older drillships) that
are still equipped with 16-3/4 in. BOP stacks,
which requires the use of 16-3/4 in. high pressure
wellhead housings.
There is also a very limited use of 16-3/4 in.
wellheads on rigs equipped with 18-3/4 in. BOP
stacks (requires the use of a crossover wellhead
connector on the bottom of the BOP). The 16-3/4
in. high pressure wellheads will not be discussed
further, but the student should be aware that
Figure 8.5 18-3 /4 H igh Pressure
they exist.
Wellhead Housing
Pressure ratings for high pressure wellhead
housings are either 10 or 15k psi and generally provide casing hanger and seal
assembly landing areas for three casing strings ranging from 13-3/8 in. to 7 in. diameter.
Note: There are several wellhead systems that allow running a fourth casing string
(16 in.) in the high pressure wellhead, although these are becoming less popular. If the
additional string of casing is needed, the current trend is to run a three-hanger high
pressure housing with a 16 in. low pressure hanger profile sub welded in the 20 in.
casing. Note that the drift of the 16 in. low pressure hanger profile subs is generally in
the range of 17 in. to 17-3/8 in. and may not allow the use of a standard 17-1/2 in. bit.
The top of the wellhead is cut with a profile to match the wellhead connector on the BOP
stack, typically a Vetco H-4 or Cameron hub connector. The bottom of the high pressure
wellhead is welded onto a joint of 20 in. casing. The bottom of the 20 in. extension joint
should have a weld-on quick stab threaded or squinch joint connector to facilitate easy
make-up to the remainder of the 20 in. casing string. Note that there has been some
concern with squinch joint connectors, which do not require rotation for make-up, but rely
solely on o-rings for sealing.

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

The high pressure housing will have a running profile for either threaded or cam-
actuated running tools. In addition to size, pressure rating and number of hanger
positions, the high pressure wellhead system must be specified for the expected service
conditions. Additional specifications include sweet or sour service (per NACE MR-01-
75), standard latch or rigid lockdown, bending moments and combined load ratings.
Subsea wellhead systems are available with up to 7.0M ft-lb bending moment and
7.1 M lb combined load ratings.
Note: The combined load consists of casing weight plus test pressure (e.g., MS-700
combined load rating of 7.1 M lb corresponds to 3.0 M lb casing weight + 15k psi full
bore test pressure). Also note that the higher bending moment ratings generally
required the use of 36 in. (or larger) structural casing. Refer back to Table 8.1 for
additional info on ratings for various subsea wellhead systems.

CASING HANGERS
Casing Hangers are used to run and land additional
strings of casing in the high pressure housing. All casing
hangers used with subsea wellhead equipment are
mandrel-type as compared to slip-type hangers that are
common with surface wellhead equipment). The hangers
are supported either by a shoulder in the high pressure
housing or by the seal assembly and casing hanger for
the previous set casing string. Space-out is extremely
critical for mandrel-type casing hangers. The remedial
procedure for casing stuck off bottom is to use a casing
patch tool, which is discussed under Special Situations at
the end of this section. In addition to providing support to
hang casing and reacting to pressure test loads, the
casing hanger also allows return flow from the annulus
during cementing, provides external seal surfaces for an
annulus pack-off and internal seal surfaces for tools,
tubing hanger and tieback sealing. Casing hangers have
an internal profile for either threaded or cam-actuated
running tools. The bottom of the hanger is threaded with
a casing box connection and has a tong neck to facilitate
thread make-up. A pin x pin casing handling pup is
generally bucked onto the bottom of casing hanger prior
to sending it out to the rig.
The standard casing program for a three-hanger
wellhead system includes 13-3/8 in., 9-5/8 in. and 7 in.
Figure 8.6 13-
casing hangers (Figure 8.6), but other sizes are also
3 /8 , 9 -5 /8 and 7
available. The hangers stack on top of each other as
Casing Hangers
subsequent casing strings are run.

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

Because of the large diameter and high working pressures, large downward loads are
imposed on the wellhead landing shoulder where the 13-3/8 in. casing hanger lands.
This shoulder must support the weight of all casings strings set in the wellhead plus the
force caused by test or wellbore pressure. Wellhead manufacturers use various
methods of dealing with this problem. As an example, Vetco uses a high strength insert
load ring in the 18-3/4 in. MS-700 high pressure housing and an integral passive (no
moving parts) load ring permanently attached to the 13-3/8 in. casing hanger to provide
7.1 M lb combined load rating.

SEAL ASSEMBLIES
Seal Assemblies, also referred to as casing pack-offs
(Figure 8.7), are used to seal the annulus between the
casing hanger and the wellhead housing and must
provide a pressure tight seal up to the rated working
pressure of the system. The seal is formed by an
elastomer and/or metal-to-metal seal. Seal assemblies
are further categorized by the method by which they
Figure 8.7 MS-1
are set: weight set or torque set. Most wellhead
Seal Assembly
syste m s u se a u n ive rsa l size se a l a sse m b ly th a t w ill
(Casing Pack-off)
work with any of the casing hangers that are run in the
high pressure wellhead housing.
Seal assemblies are installed around the upper portion of the casing hanger and are
generally run via sin g le trip w h e re th e y a re ru n w ith th e ca sin g h a n g e r a n d e n e rg ize d
after the cement job is completed. The single trip method has gained much favor due to
rig time and cost savings. Seal assemblies can also be run and set on a separate trip
after the casing has been cemented. This option generally allows more flow-by area
during cementing, which may be desirable if Equivalent Circulating Density (ECD) is a
problem and cement placement is critical. Because seal assemblies are such a critical
component of the subsea wellhead system, they will be discussed in more detail later in
this section.

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CASING/CEMENTING OPERATIONS

8.1.4 OVERVIEW OF TOOLS

Because of the remoteness of the seafloor and

the harsh environment where it is run, subsea
wellhead equipment requires many specialized
running tools and accessory equipment. The
ru n n in g to o ls u se d w ith V e tco s M S -700
wellhead system are described and shown below
along with brief procedures on how they are run.
Detailed running procedures and tool
specifications for the selected wellhead system
must be provided by the wellhead manufacturer.
Sufficient quantities of spare/expendable parts,
service manuals, running procedures and a
qualified wellhead manufacturer service
representative should be onboard the rig when
running this equipment.

LOW PRESSURE WELLHEAD CAM

ACTUATED RUNNING TOOL (CART)
Low Pressure Wellhead Cam Actuated
Running Tool (CART) is used to run the 30 in.
(or larger) structural casing and low pressure Figure 8.8 3 0 C am -Actuated
wellhead housing. The tool typically has a 6-5/8 Running Tool (CART)
in. Reg box up With Drill Ahead Capability
with either a 4-1/2
in. IF or 6-5/8 in.
Reg pin down. A typical CART is actuated with five LH
turns to engage the dogs on the tool into the mating
profile in the wellhead housing and five RH turns to
release the tool from the wellhead.
Procedures for running the structural casing were
included under Section 7, Open Water Operations. If the
structural casing is being jetted-in, the CART with Drill
Ahead Capability (Figure 8.8) allows drilling ahead with a
26 in. bit without having to trip the casing running string.
18-3/4 in. Cam Actuated Running Tool (CART) is used
to run the 20 in. conductor casing and the 18-3/4 in. high
pressure wellhead housing (Figure 8.9).
The typical 18-3/4 in. CART tool has a 6-5/8 in. Reg box
up x 4-1/2 in. IF pin down (other connections may be
available) and requires five LH turns to engage the dogs
Figure 8.9 18-3 /4 on the tool into the mating profile in the wellhead housing
Cam-Actuated Running and five RH turns to release the tool from the wellhead.
Tool (CART) Procedures for running the conductor casing were
included under Section 7, Open Water Operations.

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If high bending loads or fatigue are anticipated, the 18-3/4 in. wellhead housing can be
rigidly locked down using the Bootstrap Tool (Figure 8.10). The Bootstrap Tool is run as
an integral part of the 18-3/4 in. CART and allows preloading of the high pressure
wellhead to the low pressure housing with up to 1.0 M lbs. The Bootstrap Tool uses 12
hydraulic cylinders to multiply 80 kips of drill string overpull into 1.0 M lb setting force.
Other variations of this tool use mechanical levers(vs. hydraulic pistons) to achieve
similar preload forces.

Figure 8.10 Bootstrap Tool and

18-3/4 in. CART

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

CASING HANGER DRILL PIPE RUNNING TOOL (DPRT)

Casing Hanger Drill Pipe Running Tool (DPRT) is designed for multipurpose use to
minimize the equipment required on the rig (Figure 8.11). The primary function is to
install casing hangers and
seal assemblies. The DPRT
can be used to install the
casing hanger and seal
assembly in a single trip or
either component in separate
trips. The same tool is used to
run casing hangers from 13-
3/8 in. to 7 in.. The tool can
also be used to install
emergency seal assemblies
that will be discussed later in
this section. The tool is
designed to fully energize the
seal assembly without
pressure assist from the
landing string. The tool has a
6-5/8 in. Reg or 4-1/2 in. IF
box up x 4 in. 8rd box down
(for cement plug launch
assembly).
Note: Be sure you have the
correct crossover to go from
the bottom of the DPRT to the
SSR cement plug launch
assembly. The DPRT
consists of three basic
systems: camming, detent
and hydraulic intensifier.
These systems work in
conjunction to minimize
operations required remotely
at the rig.
For example, to accomplish Figure 8.11 Casing Hanger Running Tool (DPRT)
casing hanger lockdown, seal
assembly energizing and tool
retrieval requires only four actions: four turns RH rotation, slack off 20 kips landing string
weight, four more turns RH, and 50 kips overpull. The DPRT is equipped with lead
impression blocks to determine whether or not the seal has been properly energized.
Operational Summary for running casing with the DPRT and setting/testing the seal
a sse m b ly is in clu d e d la te r in th is se ctio n . D o n o t e xce e d th e m a n u fa ctu re rs te n sio n
rating for the running tool or that for the landing string.

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CASING/CEMENTING OPERATIONS

CASING HANGER RUNNING TOOL WITH PRESSURE ASSIST (PADPRT)

Casing Hanger Running Tool with Pressure Assist (PADPRT) is used to run the
various sizes of casing hangers and also run, set and test seal assemblies in a single or
dual trip (Figure 8.12). The tool has a 6-5/8 in. Reg or 4-1/2 in. IF box up x 4-1/2 in. IF
pin down or 4 in. 8rd box down (for cement plug launch assembly).
Note: Be sure you have the correct crossover to go
from the bottom of the PADPRT to the SSR cement
plug launch assembly. The tool uses a camming
system to lock and release the tool to the casing
hanger. The tool has a Smart Ring system that
ensures the seal assembly is in the correct position
prior to setting. The Pressure Assist feature energizes
the seal assembly with the assistance of 15 kips of
landing string weight. The BOP pipe rams or annular
are closed, and the pressure on the outside of the
landing string is increased to 3,000 psi to fully set the
seal assembly. Operationally the PADPRT is similar
to the DPRT, except the seal assembly is energized
with 3,000 psi pressure and only 15 kips landing string
w e ig h t. D o n o t e xce e d th e m a n u fa ctu re rs te n sio n
rating for the running tool or that for the landing string.
After testing the seal assembly, the BOP stack can be
pressure tested with the PADPRT in place by applying
70 kips of overpull to isolate the intensifier burst disk.
To release the running tool from the hanger, additional
right hand rotation is required. The PADPRT is also
equipped with lead impression blocks to determine
whether or not the seal has been properly energized.
The PADPRT is preferred over the DPRT due to the
tool being more user friendly to service in the field and
capable of properly energizing the seal assembly if
debris is present in the wellhead area.

Figure 8.12 Casing Hanger

Running Tool with Pressure Assist
(PADPRT)

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CASING/CEMENTING OPERATIONS

FULL BORE CASING HANGER RUNNING TOOLS

Full Bore Casing Hanger Running Tools are used to
run heavy casing strings that exceed the tension
rating of the DPRT, PADPRT or landing string
(Figure 8.13). The tools are specific to the size of
casing that is being run (e.g., 13-3/8 in. tool required
for 13-3/8 in. casing, 9-5/8 in. tool required for 9-5/8
in. casing). The tools allow casing to be used as the
landing string and will generally have a tension rating
of 1.0 M lb or higher. The tools provide full bore
access to casing and allow the use of conventional
surface release cementing wiper plugs. Operationally
the tools are much simpler than the DPRT and
PADPRT, but do not allow the seal assembly to be
run, set or tested on the same trip (i.e., the tool lands
the casing hanger only). The tool is released from
the casing hanger by turning the casing running string
two (2) RH turns. Figure 8.13 Full Bore
Casing Hanger Running Tool

SEAL RETRIEVAL TOOL

Seal Retrieval Tool is used to de-energize and
retrieve seal assemblies and can also be used to
test and re-energize the seal (refer to Figure 12).
The tool has a 4-1/2 in. IF box up x 3-1/2 in. IF box
down. The tool incorporates a closed hydraulic
section which intensifies upward forces by an 8:1
ratio. The tool latches onto the seal assembly with
a straight vertical stab. The seal assembly is then
retrieved by a progressive upward pull: 12 kips de-
energizes the seal, 25 kips releases the seal from
the wellhead housing and 35 kips pulls the seal free.
If needed, the tool can be released by setting weight
down and two to three RH turns.

Figure 8.14 - Seal Retrieval

Tool
Figure 8.14
Seal Retrieval Tool

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SUBSEA WELLHEADS &
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NOMINAL SEAT PROTECTOR (NSP), WEAR BUSHINGS AND

RETRIEVAL TOOL
NSP or bore protector and wear bushings are used to protect the high pressure
wellhead housing internal seal areas and casing hanger internal bores from key-seating
and other damage (Figure 8.15). Individual wear bushings are provided for their
re sp e ctive ca sin g h a n g e rs. T h e N S P is u se d to p re ve n t d a m a g e to th e h o u sin g s b o re
and load shoulder prior to running the first (typically 13-3/8 in.) casing hanger. Most
wellhead systems allow the NSP to be installed at the surface prior to running the high
pressure wellhead housings, which saves rig time (and money) by not requiring a
separate trip. Wear bushings generally have a seal on the lower external diameter to
provide a non-isolation BOP test and a trash seal on the upper outside diameter. Wear
bushings will have a retention device, typically a lock ring, that locks the wear bushing to
the casing hanger. The NSP/Wear Bushing Retrieval tool is used to run and retrieve
both the NSP and wear bushings and has a 4-1/2 in. IF box up x 4-1/2 in. IF box down.
The tool is dressed with 17-1/2 in. slips for the NSP and 15 in. slips for the wear
bushings. The tool
is stabbed into the
wear bushings with
drill string weight.
Upward pull sets the
slips to engage and
retrieve the wear
bushing. The NSP
requires 20 kips
overpull for retrieval,
whereas the wear
bushings require 60
kips overpull.
During BOP tests,
most wear bushings
are designed to
support the full load
of the test pressure
against the test plug
or isolation test plug.
If the NSP is in
place, the isolation
test plug must be
used to isolate the
test pressure and
prevent collapse
failure of the NSP.

Figure 8.15 Nominal Seat Protector, Wear Bushings and Retrieving Tool

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CASING/CEMENTING OPERATIONS

ISOLATION BOP TEST TOOL (ISOT)

Isolation BOP Test Tool (ISOT) is used to test the BOP stack (Figure 8.16). The tool
seals in the wellhead housing bore and isolates (hence its name) the annulus seal from
the BOP test pressure. The tool can seat on the housing shoulder, casing hanger, wear
bushing or NSP, thus providing maximum test options. The tool can be
locked into the high pressure wellhead housing running profile to allow
testing to 15k psi with the NSP in place. The isolation tool is J-type
which lands on a predetermined shoulder in the wellhead. The tool is
weight-set energized and has a 4-1/2 in. IF box up x 4-1/2 in. IF pin
down.
T h e to o l h a s tw o ru n n in g p o sitio n s. T h e first p o sitio n e xp a n d s th e "C
ring and engages the housing running cam profile, which protects the
NSP by transferring the test pressure load to the wellhead. The
se co n d p o sitio n d o e s n o t e xp a n d th e C rin g a n d is u se d w h e n la n d in g
on hangers and wear bushings. After landing on the desired shoulder,
the tool is rotated less than 1 turn RH to energize the large weight-set
lip seal. Approximately 10 kips drill string weight is required to
e n e rg ize th e to o ls b u lk ru b b e r se a l. T h e C rin g re q u ire s 2 0 kip s to
Figure 8.16 Isolation
expand, if that option is selected. All seals are re-usable and field
BOP Test Tool (ISOT)
replaceable.

PLUG TEST TOOL

Plug Test Tool is used also to test the BOP
stack (Figure 8.17). The tool seals in the wellhead
housing bore and isolates the open casing from BOP
test pressure. The tool can seat on the wellhead
housing load shoulder, casing hanger or wear bushing.
Unlike the Isolation BOP Test Tool, the Plug Test Tool
is not designed to land on the NSP nor does it isolate
the annulus seal from the BOP test pressure. The tool
is very simple in design (no moving parts) and has 3
seal surfaces on the outside diameter. The tool uses
O-ring and lip-type seals and is rated for 15k psi. The
tool has interchangeable stems that allow for either 4-
1/2 in. IF box up x 4-1/2 in. IF or 3-1/2 in. IF pin down.
The tool is reversed (i.e., run bottom side up) to test
the wellhead or wear bushings All seals are re-usable
Figure 8.17 - Plug Test Tool and field replaceable.
(shown in position to test casing)

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

CLEAN & FLUSH TOOL

Clean & Flush Tool is used to remove debris and flush the annulus
area between the casing hanger and wellhead housing (Figure 8.18).
The tool is typically run prior to initially setting a seal assembly that is
to be run on a separate trip or prior to re-running a seal assembly if
problems were encountered when attempting to set it via single trip.
The tool has four blades and four nozzles which pump jets of fluid
down the drill pipe into the annulus area. The nozzles are located at
the top of the milling slots to allow flushing of the debris. The tool has
a 4-1/2 in. IF box up connection. The tool has brass bearings to
protect the casing hanger body during rotation. Lead indicators can
be loaded into receptacles in the brass bearings to record
the distance the tool has engaged into the annulus. It is also
Lead
recommended the tool be painted white prior to running to indicators
provide visual indication.

DIVERLESS WELLHEAD CAP Figure 8.18 - Clean &

Flush Tool
Diverless Wellhead Cap is used to protect the interior seal surfaces
and exterior profile of the high pressure wellhead housing during periods of temporary
abandonment (Figure 8.19). It has four spring-locks that latch into the wellhead BOP
connector profile when the cap is lowered into place. The weight of the cap is sufficient
to expand the locking mechanism. This allows the cap to be installed on drill pipe or via
tugger line and ROV. The Vetco cap uses the SG-Style Seat Protector Running and
Retrieving tool. Approximately three kips overpull is required to remove the cap from the
wellhead. Preservative fluid may be pumped through
the soft hose and check valve assembly on the top cap,
displacing the drilling fluid or seawater under the cap.
This provides a corrosion-resistant bath to the upper
seal area of the wellhead housing and also to the
exterior profile of
the housing.

8.1.5 SEAL ASSEMBLIES

TYPES OF SEAL ASSEMBLIES

As stated earlier in this section, seal assemblies (also
referred to as casing pack-offs) are used to seal the
Figure 8.19 annulus between the casing the hanger and wellhead
Diverless Wellhead Cap housing and are a critical component of the subsea
wellhead system. The seal is formed by an elastomer or
metal-to-metal seal (or combination of the two). The current trend is to use elastomer
seals rated for 5,000 psi or less for supplemental casing hangers for 16 in. and larger
casing and metal-to-metal seals rated for up to 15,000 psi for 13-3/8 in. and smaller

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

casing that lands in the high pressure housing. Seal assemblies are further categorized
by the method by which they are energized: weight set or torque set.

WEIGHT SET
Weight set is the preferred method for all deepwater applications, with systems available
fro m a ll five o f th e le a d in g w e llh e a d m a n u fa ctu re rs. V e tco s MS-700 and DrilQuip SS-15
are the most common examples of weight set seal assemblies. Operational procedure
for running a weight set seal assembly is included later in this section.

TORQUE SET
Torque set is mostly limited to older design equipment, but still has its place in shallower
w a te r w h e re a va ila b le w e ig h t is lim ite d b y th e le n g th o f th e ru n n in g strin g . V e tco s S G -5
wellhead system is the most common example of torque set seal assemblies. Torque is
delivered to drive nut of the seal assembly via the running tool, which is rotated to the
right by the landing string.
Seal assemblies are installed around the upper portion of the casing hanger and are
g e n e ra lly ru n via sin g le trip w h e re th e y a re ru n w ith th e ca sin g h a n g e r a n d e n e rg ize d
after the cement job is completed or they can be run on a separate trip (generally less
desirable due to additional rig time and cost, unless more flow-by area during cementing
is re q u ire d ). M o st w e llh e a d syste m s u se a u n ive rsa l size se a l a sse m b ly fo r th e 1 3 -3/8
in. and smaller casing hangers. Refer to Figure 8.7 for a weight set, metal-to-metal seal
MS-1 seal assembly that is used with the Vetco MS-700 wellhead system. The MS-1
seal is an all metal-to-metal (no elastomer components or back-up seal) and is rated for
sour service up to 15,000 psi.
The seal is relatively simple and consists of four main parts:
1) A n e n e rg izin g rin g o r E rin g .
2) th e U se a l.
3) a lower support ring.
4) an assembly nut.

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SUBSEA WELLHEADS &
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The mating surfaces for the seal are wicker profiles cut into the circumference of the
w e llh e a d h o u sin g a n d ca sin g h a n g e rs. T h e w icke rs a re o f a h a rd e r m a te ria l th a n th e U
seal. The MS-1 se a l is a tta in e d b y e n g a g in g th e E rin g in to th e U se a l, w h ich sp re a d s
a n d d e fo rm s th e so fte r U in to th e p a ra lle l w icke rs (Figure 8.20). Each wicker seal
interface provides an effective seal. The five to seven wickers engaged provide five to
seven separate seals.
In addition to sealing, the Before Setting After Setting
b itin g o f th e U se a l b y th e
wickers provides a
mechanical lock between the
casing hanger, MS-1 seal
assembly and wellhead
housing. The angle of the
wickers was designed to
provide an optimum balance
between sealing and locking.
Note: Many of the other Wickers
wellhead manufacturers use a
lock ring (as compared to
V e tco s w icke rs) to lo ckd o w n
the seal assembly and casing
hanger to the wellhead
housing. On expendable
wells, the common practice is
to leave the lock rings off Figure 8.20 MS-1 Seal Engagement
seal assemblies (if so
equipped) to allow easier removal of the casing hangers during well abandonment.
If the primary seal assembly cannot be correctly set or fails to pressure test, subsea
wellhead manufacturers provide an Emergency seal assembly that can often be used
to correct the problem.

EMERGENCY SEALS
The two primary types of emergency seals are:
1) Elastomer only.
2) A combination of metal-lip seals and elastomer pack-off.
The elastomer only seal is generally limited to a maximum pressure of 10,000 psi
whereas the combination of metal-lip seal and elastomer pack-off are rated to a full
15,000 psi. Other variations of emergency seal assemblies use a lead seal or
combination of lead and elastomer, but these are much less common today. Most
emergency seal assemblies are generally shorter (by 1 to 2 inches) and may have more
taper or relief on the nose area than the standard seal assemblies they replace. These
features allow them to set slightly higher and still not interfere with the next casing
hanger and also to be more junk tolerant. Most wellhead manufacturers have
emergency seal assemblies available for sour service up to the rated working pressure

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

of the wellhead system. Refer to Figure 8.21 for

V e tco s S G -TPR emergency seal assembly for use
with the Vetco MS-700 wellhead system. The seal
uses a combination of metal-lip seals and
elastomer pack-off and is rated for sour service up
to 1 5 ,0 0 0 p si. S im ila r to V e tco s sta n d a rd M S -1
seal assembly, the SG-TPR uses wickers to lock
the seal assembly to both the casing hanger and
wellhead housing (Figure 8.22). The SG-TPR
Figure 8.21 SG-TPR
tolerates cuttings, gumbo, hanger offsets up to
Emergency Seal Assembly
0.35 and junk marks up to 0.100 inch depth. The
(Pack-off Assembly)
SG-TPR uses the same running tools as the MS-1.
Additional information on the use and setting of
emergency seal assemblies is included under Special Situations, Section 8.4.1, Leaking
Seal Assemblies. It is recommended that a sufficient quantity of emergency seal
assemblies be kept on the rig (one minimum, two for remote locations).

Wellhead Housing

Wickers

Metal-lip Seals
Casing Hanger

Elastomer pack-off

Figure 8.22 SG-TPR Emergency Seal Assembly Engagement

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

RUNNING TOOL OPTIONS FOR SEAL ASSEMBLIES

Most subsea wellhead systems allow seal assemblies
to b e ru n via sin g le trip w h e re they are run with the
casing hanger and energized after the cement job is
completed; or they can be run on a separate trip
(generally less desirable due to additional rig time and
cost, unless more flow-by area during cementing is
required). For the Vetco MS-700 system, seal
assemblies can be run, set and tested with either the
DPRT or the PADPRT. Information on these tools is
included under Section 8.1.4, Overview of Tools. The
running tools are equipped with a Smart Ring system
that ensures the seal assembly is in the correct position
prior to energizing. If the seal is not in the correct
position, it will remain on the running tool and can be
retrieved. The area between the casing hanger and
wellhead housing can then be cleaned with the Clean &
Flush Tool. Both running tools are equipped with lead
Figure 8.23 Installing Seal impression blocks to determine whether or not the seal
Assembly Onto DPRT has been properly energized. Refer to Figure 8.23 for
the installation of a seal assembly onto the DPRT. If
the seal fails to test, the Seal Retrieval Tool is used to de-energize and retrieve either
type of seal assembly. The Seal Retrieval Tool can also be used to test and re-energize
seals, but is not used to run seal assemblies.

SETTING AND TESTING THE SEAL

Regardless of the type of wellhead equipment employed, a most important step in its
use is the determination, prior to drilling out of the casing shoe, that an adequate seal
has been obtained within the wellhead. The pressure needs to be sufficient to contain
any pressure that might be applied to the blowout preventers in subsequent operations.
While the test procedures are relatively simple, executing them in a manner that will
provide valid and meaningful data requires forethought and planning. The first step to
testing the seal assembly is to ensure that it has been set and energized properly per
th e w e llh e a d m a n u fa ctu re rs g u id e lin e s a n d p ro ce d u re s. It is re co m m e n d e d th a t a
qualified wellhead manufacturer service representative be onboard the rig when running
this equipment.
The seal test procedure is similar for most wellhead manufacturers. Some form of test
plug or pack-off is used to seal in the wellhead below the seal being tested. Most
equipment allows testing the seal assembly with the running tool, but on others a
separate test is run (requires a separate trip). For the Vetco MS-700 system, the DPRT
or PADPRT can be used to run the casing hanger and run, set and test the seal
assembly all in one trip. This is especially important on higher cost, deepwater drilling
operations. Operational Procedure for testing seal assemblies with the DPRT is
included in Section 8.2, Casing Operations. The seal assembly can also be pressure
tested using the Plug-type Test Tool and Seal Retrieval Tool.

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CASING/CEMENTING OPERATIONS

Note: if it is required to test the blind/shear rams (BSR) after drilling out casing, a means
must be provided for backing off of the test plug so that the BSR can be closed.
Although this was once an MMS requirement, most current regulations do not require
re-testing the BSR until after the next string of casing has been set. If BSR testing is
required after drill out, special tools must be obtained from the wellhead manufacturer
(e.g., DrilQuip Drill Pipe Release and Test Sub).
Note: a leaking casing hanger seal assembly can pose a very serious problem on a well
drilled from a floating rig. If the annulus below the seal assembly is closed, a leak could
result in either a burst outer casing string or collapse of the inner casing string. Because
of this, it is often desirable to leave the annulus between the inner and outer string open
(i.e., leave TOC below previous casing shoe) to act as a relief valve. However, if
hydrocarbon bearing zones are present below the previous shoe, regulations may
require sealing the annulus by bringing TOC a sufficient distance above the shoe.
If the annulus is closed, extreme caution should be taken during testing of the seal
assembly. The recommended method is to pump at a low, controlled rate and maintain
a pressure-volume plot. A leak can often be identified sooner from the plot than from a
pressure drop on a gauge. Early identification can prevent bursting or collapsing a
casing string. Additional information on leaking seal assemblies is included under
Special Situations, Section 8.4.1, Leaking Seal Assemblies.

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CASING/CEMENTING OPERATIONS

8.2 CASING OPERATIONS

8.2.1 INTRODUCTION

Casing running from floating rigs requires additional procedures and precautions
compared to land and platform drilling operations due to vessel motion and use of
subsea wellhead equipment. General guidelines and precautions for running casing
from a floating rig are discussed in this section. Checklists for casing equipment and
running operations should be completed prior to the start any job. Refer to ExxonMobil
Standard Operations Manual Floating Drilling, Section 9 for a copy of the checklists.
Note: casing must be designed per basic standard specified in EMDC Drilling OIMS
Manual, Element 3. At the time of this writing, the basic standard is the ExxonMobil
Bridging Document for Interim Well Casing and Tubing Design (EMLRFD).

8.2.2 GUIDELINES AND PRECAUTIONS

DRILLING REQUIREMENTS
Include pre-job, during-job and post-job guidelines and precautions that are specific to or
of special importance for casing operations on floating rigs.

Casing Preparation (pre-job)

Ensure pipe rack area is clean and cleared of debris, tripping hazard and slick
areas.
Unload casing using proper slings and rack on pipe rack.
Verify weight and grade of each joint.
Remove thread protectors (helps to ensure an accurate strap measurement);
clean threads and visually check threads for damage.
Number and measure (strap) the length of each joint, taking into account pin-end
make-up loss. Paint the casing number and strap measurement legibly on the
pipe.
Drift casing with an API drift.
Check for internal debris and remove if any found.
Prepare a casing tally report that includes the joint number, type, weight, length,
depth in well and location of components or accessories. Two (2) qualified
personnel must verify the tally.
Float equipment should be thread locked and bucked-on prior to being sent to
rig. The made up float joints and two joints with loose collars should be shipped
to the rig.

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Hole preparation (pre-job)

Drill to casing point based on the casing tally, plus 20 to 40 ft (6 to 12 meters) of
rat hole. The extra hole allows for fill on bottom and is extremely important for
mandrel-type casing hangers that are used with subsea wellhead equipment.
Prior practice was to drill 50 ft (15 meters) of rat hole, which was sufficient to
allow for an extra joint if it were inadvertently added to the string.
Make-up the casing hanger running tool (DPRT or PADPRT), seal assembly,
casing hanger and SSR wiper plug set and stand back in derrick (out of critical
path, if possible).
Make-up the SSR Cement Head and load the proper size drill pipe dart(s) and/or
setting ball.
Make certain the landing string has been strapped, drifted to manufacturer
recommendations for SSR system and stood back in the derrick. Ensure space
out allows the casing hanger to be run through the BOP stack without making a
connection.
Make a wiper trip to TD, circulate and condition mud to the desired properties.
Circulate out the riser through the boost line and/or choke & kill lines at maximum
rate possible.
Pull out of hole, checking for tight spots and excessive drag. Back ream through
tight spots. Jet wellhead area on the way out of the hole to facilitate pulling the
wear pushing.
Pull the diverter element.
Ensure the wear bushing retrieving tool is dressed with the correct slips. Using
the casing landing string (for space-out measurement), run in the hole with the
wear bushing retrieving tool and wash sub and jet the wellhead area clean. For
the Vetco MS-700 system, 10 kips of drill pipe weight will latch the retrieving tool
to the wear bushing and 60 to 80 kips overpull will pull it free. Thoroughly jet the
wellhead and BOP clean and POOH.

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Preparing the rig floor (pre-job)

Ensure that the casing spider, elevators and links have sufficient rating to handle
total casing load plus 200 kips (per EM Standard Operations Manual Floating
Drilling, Section 9).
Ensure that the casing running tools are in good shape, correct number of
sections are installed in the slips, clamp segments are for the size casing being
run and all dies in good condition.
Take time to clean up rig floor before rigging up casing tools: pick-up and stow
equipment, remove all rubbish and wash down entire work area.
Inspect the stabbing board for proper operation and ensure all safety devices are
in place.
Rig up casing running tools.
Check the position of the rig over the hole and align as accurately as possible
before running casing. To reduce the possibility of the casing hanger being
damaged or hung up in the BOP stack or wellhead, the vessel offset should be
maintained at 2% of water depth or less.
Check weather forecast to determine if sufficient time is available to complete the
operation before storms or bad weather are due at location. Excessive vessel
motion during casing running operations is hazardous to the casing running crew
and can result in casing fatigue failure if pipe is left on the slips too long while
waiting for weather to improve.

Well Control (pre-job and during-job)

The primary means of well control while running casing is the drilling fluid.
Proper mud properties and effective hole cleaning will allow the casing to be run
to bottom with less problems, and will reduce the surge pressure as the pipe is
run and during circulation.
The secondary means of well control are the annular preventers. Casing rams
are not installed on floating rigs. The closing pressure on the annular preventers
should be reduced to avoid crushing the casing.
BSR can shear casing up to 7 a n d still se a l (n o se a l fo r la rg e r size s). N e w e r
build rigs with casing shear rams can shear up to 1 3 3 /8 (se a l p ro vid e d b y
BSR).
A drill pipe x casing crossover with full opening safety valve on top (kept in open
position) to be kept on rig floor. A second full opening drill pipe safety valve and
an inside BOP must also be available on the rig floor.
Install the diverter element and lock it down once casing running operations are
underway and any centralizers have been run.

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Running the casing (during-job)

Hold pre-job safety meeting and review Job Safety Analysis (JSA)
Check float equipment for debris. Make-up the float joints using thread locking
compound. Do not thread lock more pipe than can be stood back in the derrick.
Check the float equipment by filling with mud and picking up and slacking back
off to rotary table.
Install the diverter element and lock it down once casing running operations are
underway and any centralizers have been run.
Fill the casing completely on a regular basis, typically at least every five (5) joints.
In most cases it can be filled or partially filled while picking up the next joint, but it
is recommended that it be completely filled on a regular basis to ensure it is full
and all mud accounted for. Consideration should be given to having a top drive
fill-up device to save rig time and reduce potential for injury to fill-up hose
operator.
Tie slip handles with soft line until there is no buoyancy effect to dislodge casing
from slips. Safety clamps (dog collar) should be used until string has sufficient
weight or for flush joint pipe.
Monitor mud returns. Adjust running speed to minimize mud losses to the
formation.
Run casing with minimum connection time after entering open hole.
Make-up casing hanger running tool/casing hanger assembly (previously made-
up and stood back in the derrick). Run casing to bottom on landing string. Land
the casing in the wellhead using the motion compensator. Do not unseat casing
after it lands.
Check the measurement of the landing string against the tide tables, tide gauge
and reference line (to be discussed in further detail in this section).

EQUIPMENT MAKE-UP
Make-up torque will be specified in the drilling program or supplemental procedure and
is based on connection type, grade and weight of pipe, plating on the threads and type
of thread compound to be used. Refer to ExxonMobil Bridging Document for Interim
Well Casing and Tubing Design (EMLRFD), Section 7.6 for information on connection
make-up requirements and recommended thread compounds. Unless specified
otherwise, consideration should be given to using an environmentally friendly thread
compound such as Bestolife 2000. Float equipment is to be made-up with thread
locking compound.
A standard torque gauge can be used to make-up most casing connections. However,
critical strings such as production casing or tubing should be monitored with a torque-
tu rn syste m su ch a s W e a th e rfo rd s JA M o r e q u iva le n t.

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LANDING STRING
For floating drilling operations, all casing is landed using drill pipe as the landing string.
If the casing weight exceeds the tensile rating of normal drill pipe, heavier weight and/or
higher strength drill pipe is typically used (e.g., for 5 in. drill pipe landing string, use 25.6
ppf S-135 versus 19.5 ppf X-95 or G-105). Hevi-Wate drill pipe (HWDP) could also be
substituted, but is seldom used. Casing can also be used as the landing string using a
full bore casing hanger running tool (refer to Figure 8.13), but this takes significantly
longer to run and the casing landing string must be laid down at the end of the job.
There is also a higher potential for sticking the casing off bottom.
Deeper well depths and deepwater operations have driven the Industry to develop high
tensile strength landing strings. The use of special heavy wall (0.75 in), high strength
(S-135 and higher) drill pipe landing strings with high strength connections is becoming
common on ultra-deepwater new generation rigs. Tensile ratings for the special heavy
wall 5 in. OD landing strings is in excess of 1,300 kips and for 6-5/8 in. OD is in excess
of 1,600 kips (without safety factors). Grant Prideco has recently manufactured integral
joint (no welding) 5-1/2 in. and 6-5/8 in. with extra heavy wall (1.338 in.) and 125 ksi
grade (including tool joints) that are rated at 2,000 kips (without safety factor).
Because slip crushing is a serious limitation above about 1,500 kips, these landing
strings require a second tool joint knot below the box end to allow using bottle-neck
elevators in lieu of slips (LAST Landing and Slipless Technology). At the time of this
writing, the integral joint slipless landing string has not been used. Note that due to the
high cost of any of the special landing strings, this equipment is not used for drilling (i.e.,
use is dedicated to landing casing).
To reduce th e la n d in g strin g te n sile ra tin g , it is a lso p o ssib le to flo a t in a p o rtio n th e
string. The upper portion of the casing string is not filled with mud, which increases the
buoyancy and reduces the load. This technique has been used successfully in the past,
but is limited by casing collapse and differential pressure across the float equipment. If
the float equipment fails, the full casing load will be placed on the landing string. Due to
the availability of higher strength landing strings and the risks involved, this method is
seldom used.

SPACEOUT
A standard precaution is to spaceout the landing string so that a connection does not
have to be made while the casing hanger or seal assembly is in the BOP stack. This is
to reduce the possibility of damage due to vessel heave. The spaceout is accomplished
by using drill pipe pup joints of the appropriate length. Another precaution is to spaceout
the landing string at the surface to avoid interference with the cement head due to vessel
heave or tidal fluctuations. In some areas, tidal variations as much as 30 ft exist. The
same effect can also be caused by vessel offset in deepwater.

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LANDOUT MEASUREMENT (REFERENCE LINE)

All casing depths are referenced to the rotary kelly bushing (RKB) or drill floor elevation
(DFE), adjusted for tide. This reference point can change due to tide variations, storm
surges, etc. After running the BOP stack and riser, the lower half of the slip joint
remains at a fixed distance from the wellhead. A cable (reference line) is tied to the
bottom of the slip joint and is extended back to the rig. The cable is marked at the
original reference point. Reported setting depths for all future casing strings can be
adjusted for tide variations as determined from the original mark on the reference line.
This step is very important because a casing hanger that is set too high in the wellhead
will cause problems with the seal assembly and subsequent casing hangers.
The above method will work with all floating rigs. For moored floating rigs, an alternative
method uses the guidelines that are fixed to the permanent guidebase (PGB). The
guidelines are marked at the original reference point. The landing string is strapped out
of the hole to get the exact distance to the wellhead. Reported setting depths for all
future casing strings can be adjusted for tide variations as determined from the original
reference mark on the guideline.

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8.2.3 SETTING AND TESTING THE SEAL ASSEMBLY

PROCEDURE
(example is for a Vetco MS-700 system which uses weight set seal assemblies)
Ensure the Nominal Seat Protector (NSP) or wear bushing has been removed and
that the wellhead and BOP have been jetted clean.
Make-up DPRT (or PADPRT) with the cement wiper plug launching assembly (out of
critical path if possible).
Thread the seal assembly onto the DPRT (out of critical path if possible).
Lower the DPRT and stab it into the casing
hanger until it shoulders out
(Figure 8.24). Rotate the stem on the tool
four RH turns to lock the tool to the
casing hanger (out of critical path if
possible).
Run the casing to the last joint.
Make-up the DPRT to the last joint
suspended in the casing slips. Lift the
assembly and run the casing hanger to the
subsea wellhead on the landing string.
Check measurements to ensure hanger is
at the proper depth in the wellhead. Set
down all casing weight and 15 - 20 kips
landing string weight. The weight indicator
reading should be the same as when the
wear bushing was retrieved. Do not move
or pick-up the casing after it has landed out.
Circulate and cement the casing as per
program. Do not reciprocate the casing.
Figure 8.24 Installing DPRT
Rotate the landing string four RH turns to into Casing hanger
release the DPRT/PADPRT stem from the
lower body (tool remains locked to the
casing hanger).
Begin lowering the landing string, allowing
the stem to move downward approximately 48 in..
Slack off 20 kips landing string weight to fully energize the seal assembly.

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Line up to circulate down the choke or kill line and break circulation. A good method
to ensure you are lined up properly is to leave the failsafe choke of kill line valve
closed and apply 50 100 psi, then open the valve and check to see if the
pressure drops.
Note: In deepwater, the volume in a choke or kill line can exceed 100 bbls. This will
result in having to pump several bbls of the fluid to build pressure. It is
recommended that a volume versus pressure plot be used to determine the minimum
volume required to achieve the desired pressure.
Close pipe ram or annular and pressure up through a choke or kill outlet to test the
casing hanger to wellhead seal. Pump at a low, controlled rate and carefully monitor
the volume pumped. Generally to bbl above the volume required to pressure up
the line is the maximum volume necessary to achieve a successful test if the seal is
not leaking. Use extreme caution as a leaking seal assembly can result in casing
failure during testing. After a successful test, vent off pressure and open preventer.
Measure the volume of fluid bled back.
Lift the landing string approximately 35 in. until the stem piston shoulders out.
Rotate landing string four (4) RH turns to release the tool from the casing hanger.
Retrieve tool. Approximately 50 kips of overpull is required to release the seal
assembly from the DPRT setting sleeve.
Pull the tool back to the surface and inspect the lead impression blocks to determine
whether or not the seal has been properly energized.
Run in the hole and set the wear bushing. For the Vetco MS-700 system, overpull
about 30 kips to ensure the wear bushing is latched to the casing hanger. With
neutral weight on the running tool, use RH rotation to un-jay and release the running
tool. POOH with running tool.

POTENTIAL FOR CASING FAILURE

A leaking casing hanger seal assembly can pose a very serious problem on a well drilled
from a floating rig. If the annulus below the seal assembly is closed, a leak could result
in either a burst outer casing string or collapse of the inner casing string. Because of
this, it is often desirable to leave the annulus between the inner and outer string open
(i.e., leave TOC below previous casing shoe) to act as a relief valve. However, if
hydrocarbon bearing zones are present below the previous shoe, regulations may
require sealing the annulus by bringing TOC a sufficient distance above the shoe. If the
annulus is closed, extreme caution should be taken during testing of the seal assembly.
Generally to bbl above the volume to pressure up the line is the maximum volume
necessary to achieve a successful test if the seal is not leaking. The recommended
method is to pump at a low, controlled rate (~ BPM) and maintain a pressure-volume
plot. A leak can often be identified sooner from the plot than from a pressure drop on a
gauge. Early identification can prevent bursting or collapsing a casing string. Additional
information on leaking seal assemblies is included under Special Situations at the end of
this section.

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TOOL JOINT SPACEOUT LIMITATION WHEN TESTING BOP

WITH CASING RUNNING TOOL
The DPRT or PADPRT can be used to test the BOP stack after running casing and
setting the seal assembly. Due to the height of these tools, tool joint spaceout may
prohibit closing the lower pipe rams. If this occurs, the lower pipe ram can be tested to
the casing test pressure while tripping in the hole prior to drilling out. This is generally
an acceptable practice. If the bottom pipe rams must be tested to a higher pressure, a
trip to run the Isolation BOP Test Tool or Plug Test Tool is required. With the Vetco MS-
700 system, this test can be made with the wear bushing running tool when the wear
bushing is run, thus eliminating the need for an additional trip with a test plug.
Irregardless of the wellhead system or test to be performed, spaceout should always be
calculated for the land-out of all test plugs in relation to the tool joints and ram/annular
preventers.

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CASING/CEMENTING OPERATIONS

8.3 CEMENT EQUIPMENT/HEAD MAKEUP AND

OPERATIONS

8.3.1 INTRODUCTION

Cementing operations on floating drilling rigs are similar in most aspects to land or
platform rig operations. However, there are several significant differences: 1) type of
cement head that is used, 2) wiper plug releasing system and 3) lack of casing
movement while cementing. The casing is not rotated or reciprocated for the following
reasons:

Possibility of sticking the casing hanger above the desired setting point in the
wellhead housing.
Possibility of detaching the casing running tool from the casing string prematurely.
Possibility of damaging the seal assembly or the sealing surfaces in the wellhead
housing.
Casing movement during cementing is known to improve mud displacement and the
integrity of the cement job, but it is not done on floating rigs. Because of this, other
methods and precautions must be taken to improve cementing success. These include,
but are not limited to, using an inhibitive mud system to minimize hole washout,
conditioning the mud and hole properly, using a pre-flush spacer, mixing cement
uniformly, and pumping at maximum possible rates. A cementing checklist should be
completed and all equipment thoroughly checked out prior to starting any job. Refer to
ExxonMobil Standard Operations Manual Floating Drilling, Section 10 for a copy of a
cementing checklist.
Note: The top of cement (TOC) for casing strings other than structural and conductor
should be well thought out.

The current trend is to leave as many of the annuli open as possible and not to bring
cement back into the previous casing shoe, thereby creating a downhole relief valve.
This avoids pressure build-up and potential for casing failure due to a leaking seal
assembly and a phenomena known as Annular Pressure Build-up (APB). Problems with
casing failures during seal assembly testing is relevant to all wells whereas APB pertains
to HP/HT (high pressure/high temperature) subsea production wells or subsea wells that
are tied-back and produced from a surface structure. APB has resulted in the failure of
several non-EM operated wells in the US GOM. At high production rates, heat from the
produced fluids can increase the pressure in trapped annuli and can result in burst outer
casing strings and/or collapsed inner strings.

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Note: There are circumstances where the annuli cannot be left open. If hydrocarbon
bearing zones are present below the previous shoe, regulations generally require
sealing the annulus by bringing TOC a sufficient distance above the shoe. Also, annuli
that were initially left open may become sealed at a later time due to barite settling of the
mud.

Because of this, the following mitigation measures should be considered for wells that
have the potential for APB:

Installation of burst disks in casing couplings of outer casing strings (not applicable to
production casing).
Foam modules applied to the outer surface of the inner casing string (requires
sufficient annular clearance).
Foamed spacers pumped during cement job that are trapped below the seal
assembly (questionable value).
Consideration to run more casing strings as liners, thereby eliminating an annulus
(typically requires higher strength/grade/weight for casing string liner is hung from).
High pressure wellhead housing with side outlets for active B & C annuli bleed and
monitoring (conceptual design exists, but no equipment has been built at the time of
this writing).

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8.3.2 SPECIAL EQUIPMENT

CEMENT HEAD
Special cement heads similar to those
used for liner cementing jobs are
required for floating drilling casing
PICK UP SUB WITH
cement jobs. This is due to the casing NC50 (4-1/2" IF) BOX

and casing hanger being conveyed to

the subsea wellhead located on the
seafloor via a landing string, much the
same way as a liner is run. The cement
head needs to have provisions to SWIVEL SIDE
safely/accurately/reliably release a PORT INLET

setting ball and dart(s) that are required

for launching subsea release wiper plugs SET SCREW AND
ANTI-ROTATION KEY
and are commonly known as Subsea
DIVERTOR
Release (SSR) Cementing Heads TOP DART SPOOL
(Figure 8.25). TOP DART
PLUNGER
Most equipment can accommodate up to SUB ASSEM BLY
2 darts and a setting ball and eliminates
the need to break a connection when
dropping a ball or releasing a dart. An BOTTOM DART
SPOOL
internal bypass allows circulation
BOTTOM DART
through the top connection that can be
connected to the top drive or through the
cementing line side outlet even when
fully loaded with darts and ball. This SET SCREW AND
ANTI-ROTATION KEY
eliminates the need for an external
bypass manifold found on most
PIN ADAPTER
cementing heads. Typical ratings for
this equipment are 1,750 kips tensile,
NC50 (4-1/2" IF) PIN
7,500 psi and 25,000 ft-lb torque. Actual OR
ratings are generally lower due to (6-5/8" FH) PIN

connection limitations. Weatherford also

offers a heavier duty version called a Figure 8.25 Subsea Release
Top Drive Cementing Head that has (SSR) Cementing Head
similar features and tensile and pressure
ratings, but is rated for 40,000 ft-lb
torque.

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SUBSEA RELEASE (SSR) WIPER PLUGS AND BALL/DART

For floating operations, casing wiper plugs are launched remotely from the bottom of the
casing hanger running tool (DPRT or PADPRT) that has been run to the seafloor with
the landing string. Two plug SSR wiper plugs (Figure 8.26) are generally run on 13-3/8
in. and smaller casing strings and allow wiping the casing ahead of and behind the
cement slurry. A weighted ball dropped from the cementing head releases the bottom
plug ahead of the cement.

Plug Mandrel

Top SSR Plug

Releasing Dart

SSR Top Plug

Bottom SSR Plug

SSR Bottom Plug Releasing Ball

Figure 8.26 Subsea Release (SSR) Wiper Plugs And Ball/Dart

A drill pipe dart is released from the cement head behind the cement. The drill pipe dart
wipes the cement from the landing string and latches into and releases the top plug.
SSR wiper plugs larger than 13-3/8 in. are also available in double plug sets, but
generally only a top plug is run. Most cementing service companies have SSR wiper
plugs that are PDC bit drillable and some have a non-rotating feature that is designed to
reduce the amount of time to drill out the wiper plugs. Normal practice is to make-up the
SSR wiper plug set, casing hanger running tool (DPRT or PADPRT) and casing hanger
and stand it back in the derrick prior to running casing. Of utmost importance, the
landing string must be drifted to ensure there is sufficient clearance for the ball and dart.
It is also recommended that no component of the landing string have sharp internal
shoulders that may damage or cause the dart to become hung up.

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OPERATIONAL SUMMARY
Operational Summary for running and releasing SSR wiper plugs is as follows.
Pressures listed are approximate and vary depending on wiper plug size. Consult
manufacturer for pressure range for the equipment that is used.

Ensure SSR wiper plug set and mandrel with equalizing sub (Figure 8.27) are
made-up to the bottom of the casing hanger running tool.
Ensure proper size releasing ball and dart are loaded in the SSR cementing head.
Landing string, casing hanger running tool, equalizing sub, etc. must be drifted to
ensure there is sufficient clearance for the ball and dart.
Run casing and land hanger in subsea wellhead housing as per program. The
casing string is normally landed with the SSR cementing head stand.
Install SSR cementing head and break circulation. Circulate at least one casing
volume or annulus volume (whichever is greater). Pump preflush spacer as per
program.
When ready to cement, drop the setting ball and pump at low rates until the ball
lands in the ball seat of the bottom wiper plug and the pressure starts to build up.
Application of 1,200 to 1,600 psi differential pressure is required to release the
bottom wiper plug.
Note: The pressure increase to release the bottom plug is often difficult to see. The
bottom plug will move down the casing wiping ahead of the cement until it hits the
float collar. Approximately 300 psi is required to shear the pins on the bottom plug
ball seat, which moves downward to expose circulating ports. This allows cement to
be pumped through the bottom plug.
Mix and pump cement as per program.
After pumping the cement, a drill pipe dart is released from the SSR cementing head
and is followed with the postflush spacer (if required). The drill pipe dart should be
pumped at a slow rate until it lands and latches in the top wiper plug and pressure
starts to build up. Application of 1,700 to 3,100 psi differential pressure is required to
release the top wiper plug. The drill pipe dart and top wiper plug then move down
the casing together and wipe cement until they land out on top of the bottom plug
and shut off circulation.
After launching the top wiper plug, the rig pumps are generally used to displace
cement on floating rigs. It is recommended not to over-displace the cement.
However, it is common practice to over-displace by as much as 50% of the volume of
the float joints if a clear indication of the top wiper plug shear release was seen.
Note: It is generally easier to drill cement than to repair a wet shoe.
Bleed casing pressure to zero and check to ensure floats are holding.
Procedure for setting and testing the seal assembly was covered under casing
operations.

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PLUG MANDREL/EQUALIZING SUB

If high pump pressure is required to break circulation, pressure can travel upwards past
the SSR wiper plug fins and become trapped. The trapped pressure adds to and assists
the pressure applied to release either of the plugs and can cause them to release
prematurely (usually with detrimental results if the top plug is released while cement is
still in the landing string). To minimize the possibility of trapped pressure, it is
recommended the SSR plug mandrel be equipped with an equalizing sub.
The equalizing sub can either be an integral part of the plug mandrel to which the wiper
plugs are shear-pinned, or a separate equalizing sub may be run directly above the plug
mandrel (refer to Figure 8.27). The equalizing sub has one-way poppet-type check
valves that allow the trapped pressure to bleed-off back into the landing string. As with
the landing string, it is very important that the plug mandrel and equalizing sub be drifted
to ensure there is sufficient clearance for the ball and dart.

Figure 8.27 SSR Equalizing Sub (run above SSR wiper)

)plugs)

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

SCHLUMBERGER SUBSEA CEMENTING HEAD

A s a n a lte rn a te to co n ve n tio n a l S S R w ip e r p lu g s, S ch lu m b e rg e rs D e e p se a E X P R E S
Subsea Cementing Head (refer to Figure 26) uses wiper plugs that are loaded in a plug
basket that is connected to the bottom of the casing hanger running tool (DPRT or
PADPRT). The wiper plugs are a simpler design than SSR plugs and are identical to
those used on their Surface EXPRES system. Unlike SSR plugs, fluids are not pumped
through the inside of the plugs and no latching
mechanism is required for plug sealing. The
wiper plugs are loaded into the plug basket with
2000 lb. and are retained by friction. A
separate equalizing sub is not required with this
system as there are no concerns with trapped
pressure. All plugs are launched by releasing
darts (ball is not used for bottom plug) from the
Surface Dart Launcher (SDL) cement head that
is similar to a Top Drive cementing head.
Unlike conventional cementing heads, the SDL
allows the darts to be released remotely from
the rig floor (enhanced safety feature). The dart
travels down the landing string to the subsea
cementing head, where it pushes the wiper plug
out of the basket. Shear pins in the subsea
head provide a positive indication of plug
launch via increase in pumping pressure: 1,500
psi for the bottom plug and 3,000 psi for the top
plug. The darts are retained in a dart holder in
the subsea cement head and are retrieved
when the casing hanger running tool is pulled
from the well. Similar to SSR wiper plug
operations, it is very important that the landing
string be drifted to ensure there is sufficient
clearance for the darts. It is also recommended
that no component of the landing string have
sharp internal shoulders that may damage or Figure 8.28 Schlumberger
cause the darts to hang up. Subsea Cementing Head

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CASING/CEMENTING OPERATIONS

8.4 SPECIAL SITUATIONS

8.4.1 LEAKING SEAL ASSEMBLY

A leaking casing hanger seal assembly can pose a very serious problem on a well drilled
from a floating rig. If the annulus below the seal assembly is closed, a leak could result
in either a burst outer casing string or collapse of the inner casing string. Because of
this, it is often desirable to leave the annulus between the outer string open (i.e., leave
TOC below previous casing shoe) to act as a relief valve. However, if hydrocarbon
bearing zones are present below the previous shoe, regulations may require sealing the
annulus by bringing TOC a sufficient distance above the shoe. If the annulus is closed,
extreme caution should be taken during testing of the seal assembly. Generally to
bbl is the maximum volume necessary to achieve a successful test if the seal is not
leaking. The recommended method is to pump at a low, controlled rate (~ BPM) and
maintain a pressure-volume plot. A leak can often be identified sooner from the plot
than from a pressure drop on a gauge. Early identification can prevent bursting or
collapsing a casing string.
If a leaking seal assembly is suspected during initial pressure testing, it recommended
that the test be stopped and efforts made to determine the source of the leak. Other
possible locations of the leak besides the seal assembly are:
1) Surface equipment leak.
2) BOP pipe rams.
3) choke or kill line.
4) test plug.
5) BOP stack to wellhead connector.
Some leaks may be simple to diagnose: a leak past the BOP rams may be detected
by returns up the riser; a leaking wellhead connector may be detected with the subsea
TV or ROV and a leaking test plug is indicated by returns up the drill pipe. However,
even simple diagnostics can be very difficult on a floating rig: heave can cause bbl or
more fluctuation when monitoring returns up the riser, and it is often difficult to see leaks
with subsea TV or ROV without adding dye to the fluid. Other leaks may only be found
by trial and error. If no other leaks can be found, it is probable that the seal assembly is
leaking. Sometimes repeating the seal assembly setting procedure will solve the
problem. Increased weight, pressure or torque may be effective depending on the type
o f se a l th a t is u se d . W e llh e a d m a n u fa ctu re rs re co m m e n d a tio n sh o u ld b e fo llo w e d .

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

If these attempts fail to correct the leak, the seal assembly should be pulled and carefully
inspected to determine the cause of the problem. Junk, trash or shale may have lodged
under the seal assembly and prevented it from being properly set and energized. The
Seal Retrieval Tool (refer to Figure 8.14) is used to retrieve the seal assembly. Before
rerunning the seal assembly, the Clean & Flush Tool (refer to Figure 8.18) should be
run to remove debris and flush the area between the casing hanger and wellhead
housing. The Clean & Flush Tool should be painted white prior to running. Lead
indicators on the tool and marks on the paint can be used to determine the distance the
tool has engaged into the annulus. The condition of the seal assembly that was pulled
and any other available indicators will be used to decide what type of seal assembly to
run. If junk marks are present, it may be desirable to run an emergency seal assembly
(refer to Figure 8.29) that has metal lip seal with an elastomer pack-off.
The Vetco SG-TPR emergency seal assembly is designed to set and seal with hanger
offsets up to 0.35 and junk marks up to 0.100 inch depth and still provides 15k psi
pressure integrity. If no indication of junk, a new MS-1 seal assembly may be run. Used
seal assemblies are generally not re-run or refurbished. The DPRT (refer to Figure
8.12) or the PADPRT (refer to Figure 8.12) can be used to run, set and test either type
of seal assembly.
If these efforts fail to correct
the leak, the well may require a
Bridging Seal (refer to Figure
8.29). The bridging seal is
designed to land and seal in
previous casing hanger and
lock and seal in the wellhead
housing bore. Implied by its
name, bridging seals allow
bridging above damage in the
wellhead housing up to an area
that is not damaged. They are
available for 13-3/8 and 9-5/8
in. casing hangers and are run
with either an MS-1 or SG-TPR
emergency seal assembly.
The bridging seal stack up Figure 8.29 Bridging Seal (shown without seal assembly)
height is identical to that of a
casing hanger and assumes the next available hanger position in the wellhead housing.
The DPRT (refer to Figure 8.11) is used to run, set and test the bridging seal.
Note: This option may preclude running and landing the remaining casing strings in the
wellhead. Depending on the situation, subsequent casing may have to be run as a liner
if there are no slots left in the wellhead after running a bridging seal.

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

8.4.2 STUCK CASING/CASING PATCH INSTALLATION

Stuck casing can be a very serious problem for wells drilled from floating drilling rigs.
Standard precautions (such as providing sufficient rat hole to allow for fill on bottom and
having the hole in as good of shape as possible) sometimes are not enough. Since
subsea wellhead systems require the use of mandrel casing hangers, casing stuck off
bottom generally results in the casing extending above the subsea wellhead and into or
above the BOP stack. If efforts to run the
casing to bottom or pull it from the well are
unsuccessful, the solution requires the use
of an overshot-type casing patch (Figure
8.30). Special casing patches for this
application are available from various service
companies (Bowen, A-Z, etc.) and have an
internal slip assembly and packer (elastomer
and/or lead seals) that provide a pressure
tight assembly. The Operational Summary
for installing the casing patch is as follows:
Cement the casing as per procedure.
Consider reducing amount of cement
pumped to ensure TOC is safely below
wellhead and BOP (typically not a
problem as casing annuli are either left
open or cement only brought 200 ft
inside previous casing shoe on floater
wells). Release casing hanger running
tool and POOH with landing string.
Using a casing cutter, cut the casing one
or more joints below the wellhead.
Retrieve the cut end. To ensure a
precision cut, it is often recommended
that a second cut be made with the
assistance of a marine swivel landed out
in the wellhead housing. Retrieve the cut
end.
Dress off the top of the cut with a mill to
Figure 8.28 Overshot-type Casing Patch prevent damaging the seals on the inside
of the casing patch.
Run the casing patch and casing hanger spaced out with casing and/or pup joints to
provide the desired space-out. Slight rotation should allow the casing patch to
swallow the casing stub in the wellbore. The casing patch has an extension sub that
allows sufficient swallow to allow the casing hanger to be landed in the wellhead
housing.
Set and energize the seal assembly to lock the casing hanger to the wellhead.
POOH with casing hanger running tool.

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To put the casing string in tension, a releasing spear is run into the casing below the
casing patch and used to pull the casing stub further into the extension sub of the
casing patch. Slips inside the casing patch hold the casing in tension. Release
spear and POOH.
Pressure test casing string and resume operations.

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

8.4.3 LARGE BORE WELLHEADS

OVERVIEW
Special situations, mostly related to deepwater drilling, have driven the Industry to
develop large bore subsea wellhead systems. Large Bore systems are somewhat more
complicated than standard subsea wellhead equipment and their use is
warranted/required only if one or more of the following conditions is present:

Shallow water flow environment

Deepwater/Deep TVD (low fracture gradient and pore pressure margin)
Pressurized sands present in the top hole section
The large bore systems allow an additional string of casing (typically 18 in.), hanger and
seal assembly to pass through the 18-3/4 in. high pressure wellhead housing with the
BOP stack and riser in place. This allows the interval to be drilled with complete BOP
pressure control and with all returns taken back to the drilling rig. The 18 in. casing
string is run as a liner and is landed in a low pressure hanger profile sub welded into the
conductor casing, much the same way as 16 in. casing with standard subsea wellhead
equipment. However, in the case of the Large Bore system, the conductor casing size is
increased to 22 in. (compared to 20 in.) and the structural casing must be increased to
36 in. (or larger). This effectively increases the total number of available casing strings
to nine: 36 in. x 26 in. x 22 in. x 18 in. liner x 16 in. liner x 13-3/8 in. x 11-3/4 in. liner x 9-
5/8 in. x 7 in..
Currently two wellhead manufacturers offer large bore wellhead systems: DrilQuip SS-
15 BigBore and Vetco MS-700 Full Bore . Both systems are similar and offer a rigid
lock feature that rigidly locks the high and low pressure wellhead housings together to
reduce bending fatigue. The large bore 18-3/4 in. high pressure housings have positions
for three (3) casing hangers, 13-3/8 in., 9-5/8 in. and 7 in. and share some of the same
components and running tools as the standard systems. However, specialized running
tools are required to run, set and energize the 18 and 16 in. hangers and seal
assemblies. Elastomers are used on the 18 in. seal assemblies and generally limited to
3,500 psi. These are similar to the 16 in. seal assemblies, which also use elastomers
and are limited to 5,000 psi.

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SUBSEA WELLHEADS &
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ANNULAR TOLERANCES
The concern with large bore wellhead systems is the extremely tight tolerances between
the wellhead equipment and the casing strings that are run. As an example, the
clearance between the 18-3/4 in. high pressure wellhead housing and the 18 in. casing
hanger is only 0.0620 in., less than one tenth of an inch! The 18 in. casing hanger is
only about 3 ft tall, but this is no small feat considering the harsh environment and
remoteness on the bottom of the seafloor where the equipment is run. Use of flush joint
18 in. and 16 in. is mandatory, but this still affords very little annular clearance over the
entire length of the casing strings. Based on a pure flush (no external upset) 18 in.
casing connection, the total clearance between the 18-3/4 in. wellhead and the casing is
only 0.437 in., which equates to less than one quarter of an inch radial clearance over
the entire length of the 18 in. casing string. In addition to the close tolerances in and
below the wellhead, standard 21 in. OD drilling risers have IDs of approximately 19 in..
This results in about 0.5 in. radial clearance between the 18 in. casing and the riser.
Proper rig stationkeeping and riser tension must be maintained while the 18 in. casing is
run. Weather conditions should also be considered and may result in WOW downtime
until sea states are calmer.
Although tight annular tolerances are a major concern with large bore wellhead systems,
note that they have been successfully run in the US GOM and Caspian Sea. Without
this specialized equipment, it is probable that some of these wells may not have been
able to reach TD. Additional planning and extra precautions are recommended when
large bore subsea wellhead equipment is used. It is essential that all casing and
wellhead equipment be drifted, calipered and checked for damage.

SPECIAL TOOLS FOR RUNNING TIGHT TOLERANCE CASING

To minimize mud losses while running the 18 in. and 16 in. casing strings, it is
recommended that special auto-fill float equipment be used that allows returns to be
taken back up through the landing string be run. A quick connect adapter is available
that connects to the top of the landing string and allows returns to routed back through
the top drive circulating hose without having to make-up the top drive into each stand as
it is run. This helps to reduce the time required to run the casing and minimizes mud
losses to the formation.

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8.4.4 DRILQUIP THIRTY INCH TOP UP SYSTEM (TITUS)

DrilQuip has developed a system that will perform a cement top job outside of the 30 in.
structural casing without having to trip the landing string. The TITUS system has
become fairly popular in the North Sea where structural casing typically must be drilled
and cemented in place. Due to strong environmental forces in the North Sea (wind,
waves and current), the structural casing on many wells drilled from floating rigs will lose
its bond with the formation near the mudline. When this occurs, the wellhead and
subsea BOP stack generally develop cyclical movements that form a crater around the
wellbore.
Prior to the advent of TITUS, the typical remedial action was to run a bent joint of tubing
on drill pipe down one of the guidelines and pump a cement top job or puddle job to fill
the crater. This was difficult and often required the assistance of a ROV to guide the
tubing around the BOP stack and into the crater. After pumping the remedial cement
job, additional riser tension would be pulled in an effort to minimize wellhead movement
until the cement had set. The remedial action was not always successful and often
required more than one attempt.
TITUS equipment consists of a two inch (2 in.) steel pipe that is connected to the outside
of the 30 in. low pressure wellhead housing extension joint that terminates into a cement
distribution ring located above the bottom connector (Figure 8.31). Flexible lines with
quick connects are used to connect the 2 in. steel pipe to the permanent guidebase
(PGB) and on up to a swivel sub that is run on top of the Cam Actuated Running Tool
(CART). A special drill pipe dart is launched behind the primary cement job and seals
off the main bore of the swivel sub. The landing string is pressured up to about 500 psi
to shear out and open the side-outlet on the swivel sub. The cement top job is then
pumped down the landing string to a depth of approximately 33 ft (10 meters) below the
mud line and is distributed around the outside of the structural casing. A ROV is
required to disconnect the flexible line from the PGB prior to releasing the CART and
POOH with the landing string. TITUS equipment has been used successfully on
ExxonMobil operated wells in the North Sea and should be considered for future wells
drilled in this area or where similar problems exist.

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SUBSEA WELLHEADS &
CASING/CEMENTING OPERATIONS

2 flexible hose Swivel Sub w/

side-outlet
(500 psi to open)

ROV operated 30 CA RT
Grout Latch

PGB

Low Pressure
Wellhead Housing and
3 0 E xtension J t.
seafloor

2 steel pipe

Cement Distribution Ring

Figure 8.31 DrilQuip Thirty Inch Top Up System (TITUS)

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 9
BLOWOUT PREVENTER EQUIPMENT Section

9.0 BLOWOUT PREVENTER EQUIPMENT

OBJECTIVES

The intent of the material in this section is to only cover the differences in BOP
equipment used either in a subsea BOP stack or on a floating drilling rig. This section
provides a brief summary on the equipment and is intended only as reference material
for the Floating Drilling School. A basic understanding of BOP and well control
equipment is required. Additional detailed information on Subsea BOP Equipment can
b e fo u n d in th e F lo a tin g D rillin g B lo w o u t P re ve n tio n a n d W e ll C o n tro l E q u ip m e n t
manual.
On completion of this lesson, you will be able to:

Identify the major components in a subsea blowout preventer system.

Describe the operations of a subsea wellhead connector.

List subsea wellhead system options for external hydrate prevention.

List the differences between the rams, annulars, and choke/kill valves used in
subsea BOPs and surface stack BOPs.

List the major components of a subsea hydraulic control system.

Describe the basic sequence required to operate a function (e.g. open a ram
preventer) when using a subsea hydraulic control system.

List the major components of a multiplex BOP control system.

Describe how a multiplex BOP control provides redundancy for the electronics.

Describe the basic sequence required to operate a function (e.g. closing an annular
preventer) when using a multiplex BOP control system.

List the minimum requirements for surface accumulators.

List the available backups for the control systems and describe the major functions
of each.

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BLOWOUT PREVENTER EQUIPMENT

CONTENTS Page

9.0 BLOWOUT PREVENTER EQUIPMENT ............................................................................................................. 1

OBJECTIVES ...................................................................................................................................................... 1
CONTENTS ......................................................................................................................................................... 2
9.1 INTRODUCTION .................................................................................................................................................. 4
9.2 WELLHEAD & LMRP CONNECTORS................................................................................................................ 6
9.2.1 VETCO H-4 ............................................................................................................................................ 6
9.2.2 CAMERON COLLET CONNECTOR ..................................................................................................... 8
9.2.3 CONNECTOR RING GASKETS .......................................................................................................... 10
9.2.4 WELLHEAD CONNECTOR GAS HYDRATE PREVENTION ............................................................. 11
9.3 RAM PREVENTERS .......................................................................................................................................... 12
9.3.1 DRILL PIPE HANG-OFF...................................................................................................................... 13
9.3.2 RAM LOCKS ....................................................................................................................................... 14
9.3.3 SHEAR RAM ....................................................................................................................................... 16
9.4 ANNULAR PREVENTERS ................................................................................................................................ 18
9.4.1 ANNULAR CLOSING PRESSURE ..................................................................................................... 19
9.4.2 ADDITIONAL CLOSING PRESSURE REQUIREMENTS ................................................................... 19
9.4.3 TRAPPED GAS WITH ANNULAR PREVENTERS ............................................................................. 20
9.4.4 SURGE DAMPENERS FOR STRIPPING WITH ANNULAR PREVENTERS ..................................... 21
9.4.5 ANNULAR ELASTOMERS ................................................................................................................. 21
9.5 CHOKE AND KILL LINE VALVES .................................................................................................................... 22
9.5.1 GENERAL ............................................................................................................................................ 22
9.6 FLEXIBLE CHOKE & KILL LINES .................................................................................................................... 24
9.7 LOWER MARINE RISER PACKAGE (LMRP) .................................................................................................. 26
9.8 CONTROL SYSTEMS ....................................................................................................................................... 28
9.8.1 OVERVIEW .......................................................................................................................................... 28
9.8.2 HYDRAULIC CONTROL SYSTEM...................................................................................................... 28
9.8.3 HYDRAULIC POWER UNIT ................................................................................................................ 28
9.8.4 REMOTE PANELS (RIGFLOOR AND AUXILIARY) ........................................................................... 30
9.9 HOSE BUNDLE, HOSE REEL & RIGID CONDUIT .......................................................................................... 31
9.9.1 HOSE BUNDLE ................................................................................................................................... 31
9.9.2 HOSE REEL ........................................................................................................................................ 32
9.9.3 RIGID CONDUIT .................................................................................................................................. 32
9.10 BOP CONTROL POD ........................................................................................................................................ 33
9.10.1 POD VALVE (TYPICAL) ...................................................................................................................... 34
9.10.2 SHUTTLE VALVES ............................................................................................................................. 35
9.10.3 OPERATING A FUNCTION ................................................................................................................. 36

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BLOWOUT PREVENTER EQUIPMENT

9.11 MULTIPLEX CONTROL SYSTEM .................................................................................................................... 37

9.11.1 INTRODUCTION .................................................................................................................................. 37
9.11.2 GENERAL OVERVIEW OF A MULTIPLEX SYSTEM......................................................................... 38
9.11.3 HYDRAULIC POWER UNIT ................................................................................................................ 39
9.11.4 DRILLER'S CONTROL PANEL .......................................................................................................... 40
9.11.5 TOOLPUSHER'S CONTROL PANEL ................................................................................................. 41
9.11.6 HPU INTERFACE PANEL ................................................................................................................... 41
9.11.7 SYSTEM REDUNDANCY .................................................................................................................... 42
9.11.8 MUX CABLES ..................................................................................................................................... 42
9.11.9 RIGID CONDUIT LINE AND HOT LINE .............................................................................................. 43
9.11.10 MULTIPLEX CONTROL PODS ........................................................................................................... 44
9.11.11 RISER CONTROL BOX ....................................................................................................................... 45
9.11.12 OPERATING A FUNCTION ................................................................................................................. 46
9.12 CLOSING SYSTEM REQUIREMENTS ............................................................................................................. 47
9.12.1 SURFACE ACCUMULATORS ............................................................................................................ 47
9.12.2 SUBSEA ACCUMULATORS............................................................................................................... 47
9.13 BACKUP SYSTEMS .......................................................................................................................................... 49
9.13.1 ACOUSTIC .......................................................................................................................................... 49
9.13.2 DEADMAN ........................................................................................................................................... 50
9.13.3 ROV HOT STABS ................................................................................................................................ 51
9.13.4 ELECTRO-HYDRAULIC ...................................................................................................................... 51
9.14 BOP STACK TESTING ..................................................................................................................................... 52
9.14.1 FUNCTION TESTING .......................................................................................................................... 52
9.14.2 PRESSURE TESTING ......................................................................................................................... 53
9.15 DIVERTER SYSTEMS ....................................................................................................................................... 54
9.15.1 INTRODUCTION .................................................................................................................................. 54
9.15.2 HANDLING SHALLOW GAS .............................................................................................................. 55
9.15.3 MAJOR COMPONENTS OF A DIVERTER SYSTEM ON A FLOATING RIG .................................... 57
9.15.4 WORKING PRESSURE OF THE DIVERTER SYSTEM...................................................................... 58
9.15.5 DIVERTER UNITS ............................................................................................................................... 59
9.15.6 DIVERTER LINES ............................................................................................................................... 61
9.15.7 DIVERTER VALVES............................................................................................................................ 62
9.15.8 UPPER BALL JOINT OR FLEX JOINT............................................................................................... 64
9.15.9 RISER SLIP JOINT.............................................................................................................................. 64
9.15.10 RISERS ................................................................................................................................................ 65
9.15.11 DIVERTER CONTROL SYSTEM ........................................................................................................ 65
9.15.12 DIVERTER ACTUATION ..................................................................................................................... 66
9.15.13 AUXILIARY EQUIPMENT ASSOCIATED WITH DIVERTER OPERATIONS ..................................... 67
9.16 REFERENCES ................................................................................................................................................... 68

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BLOWOUT PREVENTER EQUIPMENT

9.1 INTRODUCTION
This chapter provides information on well control equipment used on a floating drilling
units focusing on the differences between that equipment and the equipment used on
land, platform or jack-up rigs. The "subsea" system places the BOP equipment and
wellhead on the seabed and is tied back to the surface by the marine riser, similar to a
long "bell nipple". The primary purpose of the system is to close in the well and to
provide flexible and redundant methods for safely removing an influx. In addition, the
system must also allow for rig motion, temporary suspension of the drill string, and
temporary abandonment of the location. Deepwater operations may also impose
additional requirements such as fast response times for the closing system
and high
bending
loads.

Flex Joint
LMRP
Connector

Annulars

Choke/Kill
Vales Ram

Wellhead
Connector

Figure 9.1 Typical BOP Stack and Control System

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BLOWOUT PREVENTER EQUIPMENT

The typical subsea BOP stack (Figure 9.1) consists of two annular preventers, four ram
preventers, and three or four choke and kill line outlets. S in ce a flo a tin g rig s B O P s a re
located just above the mudline, replacing a damaged ram or installing casing rams
requires that the entire BOP stack must be brought to the surface. This is one of the
main reasons why two annular-type preventers are common for floating rigs. A general
subsea stack arrangement is shown in Figure 9.2 with a sequence of arrangements that
provide a
progressive
amount of well
control capability.
For DP
operations, it is
absolutely
necessary that
the BOP be
capable of
supporting each
main size of pipe
for hang-off and
that the stack has
shearing and
Figure 9.2 Various Subsea Stack Arrangements sealing capability.

New rigs designed for ultra-

Flex Joint
deepwater have been built with
Choke Line
BOP stacks equipped with five
Outlet Below
and six ram preventers, and in
Upper Annular
some cases, up to six choke/kill
side outlets. The configuration
for these new ultra-deepwater LMRP Connector
stacks typically include three
pipe rams, two sets of blind
shear rams and a set of casing
Lower Annular
shear rams. In some cases, the
lower most ram may also be
designed for use as a test ram Blind Shear
whereas it will hold pressure
from the top thus allowing the
ram to be closed and the stack Casing Shear
tested against this ram instead
of tripping to set a test plug in
the wellhead. This has been Pipe Rams
accomplished by installing the
test ram upside down, but new
rams are being designed to hold
pressure from either side.
Figure 9.3 Ultra Deepwater BOP Stack Components

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BLOWOUT PREVENTER EQUIPMENT

9.2 WELLHEAD & LMRP CONNECTORS

Hydraulically actuated connectors are used to connect the BOP stack to the high
pressure wellhead, and to connect the lower marine riser package (LMRP) to the BOP
stack. The two connectors that are found most often are the Vetco H-4 and the Cameron
Collet connectors.
9.2.1 VETCO H-4
Many styles of the H-4 are available and have similar mechanical designs (Figure 9.4).
The H-4 connector is operated by several hydraulically actuated pistons, which drive a
cam ring upward and downward. A shallow taper on the ID of the cam ring in turn drives
a segmented ring of dogs radially inward into a grooved profile on the wellhead housing.
This provides a large axial locking force, which energizes the ring gasket and preloads
the connector to the wellhead. The hydraulic system configuration features a primary
and secondary lock system where part of the cylinders are ported to the primary lock
port, with the balance ported to the secondary lock. The same arrangement is included
on the unlock side of the cylinders. When hydraulic fluid is applied to either of the lock
ports, fluid enters those operating cylinders (rod side) from above. The pistons pull the
cam ring downward, driving the dogs radially inward (lock position). The primary and
secondary unlock ports should be connected to separate control lines to give redundant
ability to unlock a connector if one line fails while in service. Greater unlock force is
provided since the unlock area of the pistons is greater than the lock area since the
unlock area does not include the piston rod area.

Cam Ring

Lock Dogs
LOCK

Hydraulic
Piston
UNLOCK

Figure 9.4 Vetco Super HD H-4 Connector

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When pressure is applied to the unlock ports, fluid enters the cylinders below the
pistons. The pistons and the cam ring are forced upward, thus allowing the dog-segment
to move radially outward through the action of the springs located between the dog
segments. There is a 45o taper on the wellhead grooves and the dog segments. When
the connector is picked up, the dog segments are forced radially outward by this taper.
The connector utilizes a VX gasket and is equipped with an indicator rod, which makes it
possible to monitor the locking and releasing function either on the surface or subsea
(with the aid of a ROV).
Vetco H-4 Connector Types
DHD H-4 E H-4 ExF H-4 HD H-4 SHD H-4 ExF HAR
H-4
Bending Load 2.5 MM 2 MM 3.1 MM 4.0 MM 7.0 MM 3.1 MM
Capacity @ 2/3
Yield (ft/lbs)
Preload (lbs) 5.0 MM 2.10 MM 2.51 MM 6.25 MM 7.5 MM 2.51 MM
Hydraulic Circuits 10 10 12 10 10 12
Max. Service 15,000 10,000 15,000 15,000 15,000 15,000
Pressure (psi)
Hydraulic Pressure 1,500 1500 1500 3,000 3,000 3,000
(psi)

Table 9.1 - H-4 Connector Data

The available H-4 connector styles are summarized in Table 9.1. The HD-H4 and SHD-
H4 are heavy-duty high preload connectors, suitable for high bending loads at 15,000 psi
service pressure. The HAR-
H4 (Figure 9.5) is a high
angle release connector used
primarily on LMRPs. The
connector has a much
reduced swallow over the
mandrel and allows release at
higher rig offsets.

Generally, the BOPs are

landed on the subsea
wellhead with 1500 psi
pressure on the unlock port of
the wellhead connector. After
landing the unlock ports are
vented and locking pressure
is applied to the primary and Figure 9.5 Vetco High Angle Release (HAR) Connector
secondary lock ports. After
locking at the required pressure (3000 psi required to obtain the maximum preload), the
locking pressure may be reduced to 1500 psi and maintained at that level. Vetco
recommends that a locking pressure of 1500 psi be maintained on all LMRP connectors
at all times (while running and during routine operations).

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9.2.2 CAMERON COLLET CONNECTOR

The Cameron Collet Connector has been used on floating drilling rigs since the 1960s.
The two types of the collet connectors are the Model 70 and HC/DWHC Collet. The
Collet connector locks onto a hub on the subsea wellhead which has the same profile as
used on manually installed clamps.

Indicator Rod
Gasket
Retainer Pins

Primary
Actuator Unlock
Ring

Secondary
Unlock
Locking
Segment
Lock

Figure 9.6 Cameron Model 70 Connector Figure 9.7 Cameron HC Connector

MODEL 70 CONNECTOR
The Model 70-collet connector normally has six to nine cylinders with all cylinders being
used for unlocking and 4-6 cylinders used for locking. Hydraulic closing fluid pulls an
actuator ring down which, by leverage and tapered surfaces, forces pivoted locking
segments under the hub. Opening pressure causes the actuator ring to push upward
and the locking segments rock open to release the connector. All the cylinders are
attached to the actuator ring to unlock the connector, but only four to six of the cylinders
are attached to the bottom plate of the connector to provide locking force. When
unlocking, all cylinders will push upward on the actuator ring to unlock the connector. To
monitor the actuation of the connector, indicating rods can be monitored by subsea TV
or ROV to verify the locked or unlocked position of the actuator ring. Due to the short
swallow of the connector over the wellhead, Cameron advertises that the connection can
be released and pulled away from the wellhead hub at angles
up to 30 o.
An AX type ring gasket is used on the collet connector with spring loaded gasket
retainers to simplify ring gasket replacement. The Model 70 connector (Figure 9.6) is
available in 10 ksi and less working pressure.

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CAMERON HC COLLET CONNECTOR

For larger sizes and higher working pressures, Cameron Model HC connectors (Figure
9.6).are available. These connectors are similar to Model 70 connectors except there are
no individual operating pistons. A single piece-operating piston (similar to an annular
preventer operating piston) is used to lock the clamp segment open and close with
hydraulic pressure. The connector is available
with a secondary unlock piston and uses the AX
ring gasket. The secondary unlatch piston on the
HC Collet Connector is used only as a backup to
the primary hydraulic circuit since it does not
provide additional unlock force.
CAMERON DWHC COLLET CONNECTOR
For ultra-deepwater where high tension, bending
and bore pressures are required, Cameron
provides the Deep-Water High Capacity collet
connector (DWHC) (Figure 9.8). This connector
utilizes the same type annular hydraulic piston as
used in the HC connector and seals with an AX
gasket. Bending loads are 9,300,000 fl/lb at
15,000 psi and 2,000,000 lbs tension. The
DWHC can lock onto the DWHC wellhead hub or
the standard Cameron hub with no modifications. Figure 9.8 - CIW DWHC Connector

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9.2.3
CONNECTOR RING GASKETS
Connector manufacturers use different varieties of type AX, NX, CX, DX, or VX ring
gaskets (non-API) to provide a metal-to-metal seal against the wellhead or connected
component. These gaskets are made from a variety of materials including low yield
carbon steel and a variety of resilient materials used as a backup for the metal-to-metal
seal.
If the BOP-to-wellhead ring gasket fails to test or develops a leak when the stack is
subsea, the gasket can usually be replaced with a ROV. With the connector on the
wellhead, retainer screws/hydraulic pins can be retracted allowing the release of the ring
gasket. After picking up the connector the seal ring will remain on the wellhead where it
can be retrieved by the ROV. A new seal ring can then be placed on the wellhead and
the connector lowered onto the wellhead.
For the Vetco VX gasket (Figure 9.9), cadmium plated carbon steel or stainless steel
ring gaskets can be used in 10,000-psi equipment. Only stainless steel ring gaskets
should be used for 15,000-psi service.

VX Gasket Standard VGX Gasket. Rated for VT Profile Gasket A ABB Vetco Gray H-4
carbon steel, cadmium 15,000 psi at temperatures
plated metal-to-metal seal
secondary metal-to-metal connectors, MS-700 and
up to 350 F. seal. The secondary VT SG subsea wellhead
for 10,000 psi MWP. Geometrically
Stainless steel rated for sealing surface is used systems are
interchangeable with the
15,000 psi MWP. VX gasket. Ideally suited
when impact, corrosion or manufactured with the
for high-pressure, high- washout has damaged the dual taper VXNT gasket
temperature applications primary VX sealing profile with two
and critical service surface in the wellhead or independent sealing
applications connector. surfaces

Figure 9.9 - Vetco Wellhead Ring Gaskets

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9.2.1. WELLHEAD CONNECTOR GAS HYDRATE PREVENTION

Small gas seepage that may occur from the seafloor or between the conductor and
structural casing can cause gas hydrates to form in deepwater (Figure 9.10) due to the
pressures and temperatures that are present. Hydrates generally form when the gas
contacts the bottom side of the BOP stack components and/or frame. Though this
formation will not prevent circulation, it can prevent the wellhead connector from
hydraulically unlatching. The failure of the wellhead connector to unlatch is caused by
the formation of gas hydrates in the wellhead by wellhead connector annulus. The
formation of hydrates in this area prevent the wellhead connector locking segments from
retracting during the unlatch sequence.

Gas Hydrate

Figure 9.10 Hydrates at Wellhead Connector Down Funnel

Several modifications to the wellhead system by the manufacturer can be made to

reduce the potential flow path of the gas into the wellhead by wellhead connector
annulus. These modifications include:
Installation of ROV actuated ball valves on the cement ports of the 30/36 in.
wellhead housing (closed by the ROV after cementing).
Placement of an external o-ring on the 18-3/4 in. wellhead housing to seal the
18-3/4 in. by 30/36 in. annulus.
O-rings to seal between the 30/36 in. and the mud mat.
Connect wellhead by connector annulus to BOP control system, ROV
intervention panel, or dedicated injection hose run from the surface.
Pump glycol via BOP control system or ROV into wellhead by connector annulus
to prevent hydrate formation.
Displace wellhead by connector annulus via the BOP control system, ROV or
dedicated injection with methanol to dissipate hydrates.
In areas were there is a high potential for gas seepage after cementing, a mud mat
should be considered to divert the gas horizontally away from the connector.

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9.3 RAM PREVENTERS

Ram preventers utilized in subsea BOP stacks have the same operating features and
requirements as ram preventers used with surface BOP stacks except for a few
exceptions described below (Figure 9.11). The main differences are:
Larger bore size.
Utilization of side outlets for choke and kill lines.
Hydraulically actuated locking mechanism.
Capabilities to hang-off the drill pipe.
Use of shear blind rams.
High bending loads.
Since only one size BOP stack is used and all casing installed after the BOP stack is in
place must be run through the bore of the rams and annulars, subsea stacks typically
have a bore of 18 in. with pressure ratings of either 10,000 or 15,000 psi. To minimize
the amount of connections and to reduce the overall height of the stack, side outlets on
the ram preventers are utilized for choke and kill outlets instead of a dedicated spool as
required for surface BOP stacks. The need to reduce the overall height is due to height
limitations when storing the BOP stack on the rig and to reduce the bending moment
seen during extreme rig offsets.

Large Bore High Bending Capacity Flanges

Hydraulically
Actuated Ram Locks

Side Outlet Used

for Choke/Kill
Valves

Figure 9.11 Typical Subsea Stack Ram Preventer

C am eron T L R am Preventer w ith S T Locks

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For deepwater applications and DP vessels it is extremely important that the bending
strength of the body and flanges throughout the BOP stack be considered and the
bending moments calculated to ensure that the integrity remains sound during high
offsets. When high strength bolts are used to provide for the increased bending loads,
hydrogen embrittlement of the bolts has been observed in the bolts due to the subsea
environment and the sacrificial anodes on the BOP stack. To reduce the potential for
hydrogen embrittlement, a hardness check should be performed prior to installing the
b o lts to e n su re th a t th e R o ckw e ll C va lu e is in a ra n g e o f 3 4 -35.
In addition, for DP vessels that rotate to weather vane into the environment, the torque
that is generated from the rigs rotation must be dissipated through the tensioner ring on
the riser to prevent damage to the BOP stack and or wellhead.

9.3.1 DRILL PIPE HANG-OFF

In floating well control operations, it is more likely that drill pipe will be hung-off on a pipe
ram due to one of the following situations:
Gas is known or suspected of being above the shut-in annular.
The drill pipe is starting to stick.
Weather conditions are deteriorating and rig heave is excessive.
High riser angle at the LMRP.
Unable to establish full returns and underground flows may exist.
Gas is trapped in the BOP stack after well control operations.
Operating from a DP rig requires tool joint to be positioned for emergency
disconnect.
Although the need to hang-off and shear is a rare event, especially on moored rigs, the
shear and seal action will typically be successful only against the tube of the drill pipe
and if the pipe is stationary (hung-off). The specific preventer in the BOP stack that is to
be used to hang-off the drill string is selected in conjunction with the position of the shear
ram. This is to ensure that adequate clearance for the tool joint is provided between the
hang-off ram and shear ram and choke/kill outlets are available below the hang-off ram.
Since most subsea BOP stacks consist of two double ram preventers, the shear ram will
typically be located as the top most ram (No. 4) preventer in the BOP stack with the
hang-off ram located as the top ram (No. 2) of the bottom double. This is needed since
spacing between the rams on a typical double ram does not provide sufficient clearance
to shear the pipe when it is hung off directly below the shear ram (No. 3). A specially
built double ram preventer is available with extra spacing (10 14 in.) between the rams to
provide room for the tool joint when the pipe is hung-off. Exact measurement of the drill
pipe tool joints should always be taken and compared to the stack measurement to
determine if adequate clearance is available.

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When drill pipe is hung off on a subsea stack, the pipe ram blocks typically support the
weight of the drill string with the tool joint supported on the contoured edge of the ram
block face. To support the weight of the drill string without damaging the ram block, ram
blocks used in subsea BOP stacks should have a hardened area around the lip of the
ram block. If Variable Bore Rams (VBR) are used, the amount of pipe that can be hung-
off should be determined by the largest size of the VBR range (i.e. 5 pipe for 3 - 5
VBR) so that the weight will be supported by the ram block and not the VBR packer. If
a smaller size pipe must be hung off in the VBR, the hang-off weight should be limited to
prevent damage to the ram packer.
The limiting or maximum hang-off weights will vary according to the preventer
type/manufacturer and should be verified from the manufacturer's catalog.
9.3.2 RAM LOCKS
To maintain wellbore integrity when hydraulic closing pressure is removed from a
preventer, all ram preventers are required to have a locking mechanism to lock the ram
closed and maintain a seal against full rated wellbore pressure. The two basic types of
locking mechanisms that are incorporated by the manufacturers are:
automatic locking mechanisms that are integral to the ram operating system
independent lock that functions independently of the ram operating system

Lock Nut and

Clutch
Assembly

Figure 9.12 - Hydril Ram and MPL Lock

On the Hydril MPL lock (Figure 9.12), a mechanical lock is set each time the ram is
closed. A unidirectional clutch mechanism and a lock nut control locking and unlocking
of the MPL. The unidirectional clutch mechanism maintains the nut and ram in a locked
position until the clutch is disengaged by applying opening pressure to the ram.

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T h e C a m e ro n S T lo ck (Figure 9.13) is independent of the ram close function. When

close pressure is applied to the ram, the gray tail rod travels in (as shown) with the ram
clo se p isto n . T h e ra m ca n b e o p e ra te d w ith o u t th e S T lo ck.
T o lo ck th e ra m , co n tro l flu id is a p p lie d to th e S T lo ck p isto n , fo rcin g th e w e d g e (b lu e )
behind the tail rod. The wedge is held in place by a lock nut and clutch mechanism. To
o p e n th e ra m , u n lo ck p re ssu re is first a p p lie d to th e S T lo ck a n d a fte r th e S T lo ck
reaches full open position, a poppet valve allows open pressure to be applied to the ram.
The automatic system is used in the Shaffer Poslock, Ultralock or Ultralock II and the
Hydril MPL locks. Both systems are integral to the ram close function and secure the
ram in the final close position. The independent lock system is utilized by Cameron as a
We d g e L o ck o n th e m o d e l U a n d U II ra m s a n d th e R a m L o ck o r S T lo ck o n th e T
a n d T L p re ve n te rs. T h e se lo cks a re in d e p e n d e n t o f th e ra m clo se fu n ctio n (i.e .
hardware) and are actuated by their own hydraulic circuit independent of the ram close
function.

Locking
Wedge

Tail Rod

ST Lock Port
and Piston

Figure 9.13 - C am eron S T Lock

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9.3.3 SHEAR RAM

An integral blind/shear ram BOP is a required component of the subsea stack (Figure
9.14). It provides the capability to shear drill pipe, wireline, and some limited ranges of
casing and/or to seal off the open hole and maintain full pressure integrity. The
placement of the shear ram in the BOP stack is always located above the hang-off rams
in the BOP stack and are
almost always located in
the uppermost ram
preventer.
The force to shear a
given pipe is affected by
the design of the shear
blade, the shearing
mechanism, the pipe wall
thickness, and the pipe
material strength. Due to
the variation in the pipe
properties for a particular
string of the same size
and weight, shear
pressures during shear
tests have been found to Figure 9.14 - Cameron Blind Shearing Rams
vary 25% to 30%.
Table 9.2 lists some shear pressure data that is available from shear ram manufacturers
for a variety of pipe sizes. Data from these tests provide an estimate of the required
shear pressure obtained from shear tests without hydrostatic or wellbore pressure acting
on the ram. Actual shear pressures can require an additional 100 to 300 psi, depending
on the mud weight, water depth and wellbore pressure. Tables with shear test results for
the preventer to be used should be obtained from the manufacturer to determine if the
tubulars to be used can be sheared by the preventer. To provide the greatest chance for
a clean shear and seal, it is recommended that the shear rams be closed with the full
3000-psi available hydraulic control pressure when shearing pipe.

Shear Ram Type 5 S-135 (19.5 lb/ft) 5 S-135 (24.7 9 5/ 8 K -55 (47
lb/ft) lb/ft)
C IW 18 15k T o r T L - SBR
C IW 18 15k T o r T L DVS 2480 1990 N/A
C IW 18 15k T o r T L - SSR 1650 1320 980
H yd ril 18 15k L W (19 o p erato r) <2800 <2800 <2800
Shaffer T-72 (14 o p erato rs) 3100 3850 N/A
Shaffer V-SH R (14 o p erato r) 2100 2600 N/A

Table 9.2 Shear Data for Various Rams

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To provide the necessary shear force, shear rams are sometimes equipped with bonnets
that provide either a larger piston (19 in. versus 15 in. for Hydril rams) or a tandem
piston that provides a second piston on tail rod to the close side of the shear rams.
This additional closing area will reduce the required closing pressure for a given tubular
size and weight by 40 50% (i.e. Shaffer 18 in., 15k ram with 14 in. by 16 in.
tandem piston shear pressure for 5 in., 32.7 lb/ft drill pipe is reduced from 2600 psi
to 1175 psi).
DP rigs are subject to drift/drive off from the well site, and consequently, there is a higher
probability of shear-ram usage. To provide greater assurance that the well will be
isolated on a disconnect, some DP rigs are equipped with two sets of shear rams. The
lower shear ram is functioned first to provide the initial shear and seal and the upper
shear ram is actuated afterwards as a backup shear/seal or to provide a seal should the
lower shear be damaged and unable to provide a seal after shearing the pipe. BOP
stacks on DP rigs will typically either be equipped with two sets of shear rams or shear
rams with larger or tandem pistons as described above.
Several new ultra-d e e p w a te r rig s h a ve a lso a d d e d a S u p e r S h e a r ra m th a t h a s th e
capability to shear some drill collars and larger sizes/weights of drill pipe and casing.
These rams are designed to shear only and do not provide a seal, thus requiring the
blind shear ram to be closed afterwards to secure the wellbore.

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9.4 ANNULAR PREVENTERS

Annular preventers used for subsea BOP stacks are the same preventers found on
surface BOP stacks. The three most common annular preventers used for subsea
sta cks a re th e S h a ffe r S p h e rica l, C a m e ro n D a n d th e H yd ril G X . S in ce th e a n n u la r
provides the only close-in option with drill collars or casing in the stack, a majority of the
subsea stacks have two annulars to provide redundancy for this close-in capability. The
to p a n n u la r is typ ica lly u se d a s th e w o rkin g a n n u la r to h a n d le th e rig m o tio n a n d is th e
primary stripping preventer, if needed.
The two annulars are normally separated with the LMRP stack connector so that the top
annular can be tripped for repair without retrieving the entire stack. When the BOP stack
is only equipped with a single annular, the annular should be located above the LMRP
connector so it can be retrieved with the LMRP.
One unique feature found in annular preventers
used for subsea stacks is the dual body annular
(Figure 9.15). The dual body annular has one
large preventer body with two elements and two Flex Joint
operating pistons. This preventer, when used, is
installed on the LMRP making both annulars
retrievable with the LMRP. Upper Annular

The working pressure of the annular preventers

utilized in subsea stacks is typically one pressure
rating lower than the working pressure of the ram
preventers; i.e. 5000 psi annulars with 10,000 psi
Lower Annular
rams and 10 ksi annulars with 15 ksi rams. Since
well control with pressures in excess of 1500 psi
will normally be transferred to ram preventers,
the lower required pressure rating for the
annulars allows smaller overall stack size and
weight. The location of the annulars at the top of
the BOP stack also provides flexibility to use
either the choke or kill lines for circulating out
and/or to monitor, bleed, bullhead or lubricate Figure 9.15 - Hydril
the wellbore in the event circulation is not G X D ual B ody A nnular
possible during a well control incident. with Flex Joint Included

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9.4.1 ANNULAR CLOSING PRESSURE

During drilling operations, the annular and ram pressure regulators are typically set at
1500 psi on the hydraulic closing system. This pressure is necessary to:
close the preventer reasonably fast in the event of a kick.
positively create a seal with the drill pipe if the packer element is worn or has low
elasticity due to age or cold environment.

9.4.2 ADDITIONAL CLOSING PRESSURE REQUIREMENTS

When operating annular preventers subsea, the hydrostatic pressure of the drilling fluid
in the riser exerts an opening force on most annular preventers. To provide the same
desired closing performance subsea, the required closing pressure is equal to the
surface installation closing pressure plus a compensating pressure to account for the
opening force exerted by the drilling fluid column. The amount of closing pressure
adjustment required for the riser hydrostatic effect depends on the annular BOP design,
(the unbalanced feature of the opening and closing piston areas), the water depth, and
the mud weight in the riser (Figure 9.16). Closing Pressure Increase

Shaffer Spherical
18 5 K

Figure 9.16 Annular Closing Pressure for Various Water Depths & Mud Weights

C lo sin g p re ssu re a d ju stm e n ts fo r a n n u la r p re ve n te rs a re in clu d e d in th e m a n u fa ctu re rs

catalog and should posted on the rig floor for the particular annular preventer included in
the BOP stack. For water depths less than 1500 feet, the closing pressure compensation
for the Cameron and Shaffer annulars is small (100 to 200 psi) and the adjustments are
not needed. The piston on the Hydril GX annular is balanced and does not require
adjustment for hydrostatic pressure.

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Another circumstance where additional closing pressure may be required for an annular
preventer is when closing the annular against wellbore pressure. The wellbore pressure
effect is generally of no consequence when closing a single annular or the upper annular
since the wellbore pressure is typically low when the annular is actuated. However,
when a lower annular is exposed to high wellbore pressure before being closed, the
normal closing pressure to the lower preventer may not be sufficient to close it and
establish a seal. This closing pressure limitation occurs where the closing ratio of the
annular preventer is relatively small. Although closing the lower annular against high
wellbore pressure may be an infrequent event; the possible wellbore pressure effect on
the lower annular should be considered. An alternative to using the lower annular could
be to close a lower pipe ram and hang off.

9.4.3 TRAPPED GAS WITH ANNULAR PREVENTERS

A major consideration after controlling a well with the annular in deepwater is the
removal of gas trapped in the top of the BOP stack between the closed BOP and the top
choke outlet line. This upper stack space can be 8 to 12 feet high and contain several
barrels of free gas under pressure. Release of the pressured gas into the riser can result
in rapid unloading of the riser and a potentially hazardous surface situation. Options for
handling the trapped gas include:
minimizing the trap space by closing in with the lower annular or by hanging off
on a pipe ram before circulating out,
installing an additional outlet directly beneath the upper annular to allow
circulating most of the trapped volume, or
purging the upper stack after the well is dead.
An outlet directly beneath the upper annular allows for continued well control with the top
annular and provides the most positive procedure to remove trapped gas. On older rigs,
the outlets are not normally standard arrangements, and the most common industry
control procedure for trapped gas has been to shut in and hang-off the drill pipe on a
pipe ram, thus eliminating the potential for accumulating trapped gas in the space
between the annular and the uppermost side outlet. When circulating out an influx on the
pipe ram with the choke/kill outlet directly beneath the ram, trapped gas should not be a
concern since the outlet is generally within 6 in. of the ram block and does not provide
sufficient volume to accumulate trapped gas.
H a n d lin g a n d re m o vin g tra p p e d g a s fro m a su b se a B O P sta ck is in clu d e d in W e ll
C o n tro l O p e ra tio n s se ctio n o f th is m a n u a l.

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9.4.4 SURGE DAMPENERS FOR STRIPPING WITH ANNULAR

PREVENTERS
To minimize closing pressure surges and reduce wear on the annular element when
large diameter tool joints are stripped through the annular, an accumulator is installed at
the annular preventer as a surge dampener. Typically a 5 to 10 gallon subsea
accumulator bottle is placed immediately adjacent to the closing port on the preventer.
To dampen the closing pressure fluctuations and to compensate for the slow response
(and possible 100 to 150 psi dead-band-range) of typical subsea regulators.
The recommended surface precharge pressure for this surge bottle is generally 500 psi,
plus the necessary correction for water depth and temperature. The surge bottle
precharge pressure needs to be less than the annular closing pressure used during
strip p in g o p e ra tio n s so th a t th e b o ttle p ro vid e s a cu sh io n fo r th e clo sin g syste m .
One disadvantage of the surge bottle is additional closing fluid is required to pressure
the surge bottle when routinely functioning the preventer or closing in on a kick. The
additional required closing fluid to charge the surge bottle will increase the closing time
for the annular.
9.4.5 ANNULAR ELASTOMERS
Elastomers used in annulars on subsea stacks are subject to greater fatigue than
surface BOP stack annulars. The elastomers in subsea annulars fatigue much quicker
due to the subsea environment, operating range and number of times the annular is
functioned.
The subsea environment (typically around 42F subsea) and drilling fluid are factors that
cause the annular p a ckin g e le m e n ts to lo se e la sticity w h ich d e cre a se s th e e le m e n ts
ability to return to full bore after actuation. Loss of memory in the element to return to
full-bore will obstruct full-bore tools from passing through the BOP stack and may require
the BOP stack to be retrieved for element replacement. In addition, the cold temperature
can also cause higher than normal closing pressures to obtain a pressure seal.
The elastomer also receives additional fatigue since the subsea annular is functioned
much more often than a surface BOP annular since it is needed to located the tool joint
in the BOP stack before closing a pipe ram. The travel required to close large bore
subsea annulars also accelerates the element wear since it must operate though a large
range each time it is closed on standard size tubulars (drill pipe - 5in. or 5 in.). As the
packer element ID wears away, metal-to-metal interference between the packer insert
segments and the drill pipe tool joint may ultimately occur and hamper stripping
operations. This problem has been especially evident when using 5 in. or 6 5/8in. drill
pipe with the larger 7in. or 7 in. tool joints.
Although to a lesser extent, the performance of elastomers used in ram preventers are
also affected by the colder temperatures found in the subsea environment. On some
occasions, rams may require functioning several times to obtain the initial seal.
All BOP elastomer products and wellbore pressure containing components should be
supplied by the original m a n u fa ctu re r a n d sh o u ld m e e t th e m a n u fa ctu re rs sp e cifica tio n s
for the intended service environments.

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9.5 CHOKE AND KILL LINE VALVES

9.5.1 GENERAL
Choke and kill valves required on surface BOP stacks must also be installed on subsea
stacks. Since the stack is subsea, the valves must be hydraulically operated rather than
manually operated. Two valves with hydraulic operators are required on each choke and
kill line outlet from the BOPs, and the valves should be positioned as close to the BOP
stack as possible with a minimum of connections between the stack and the valves.
The type of choke and kill valves used on floating rigs differs by manufacturer, gate/fluid
flow sealing design and actuation design. The selection of a particular valve/actuation
combination will depend on
peculiarities of the installation
geometry, water depth application and
other considerations including cost,
working pressure, maintenance costs,
repair part availability, and closing
pressure requirements, etc.
When opening a gate valve,
movement of the gate causes a hole in
the gate to line up with the flow
passage through the valve body
(Figure 9.17). The flow passage
through the gate is located near the
stem end for fail closed valves.
Retracting the gate toward the
operator causes the valve to close.
The gate seals against the
downstream seat assembly with a
metal-to-metal seal. Most choke and
kill valves are bi-directional in that they
will hold pressure from either direction. Figure 9.17 Typical Subsea Choke/Kill Gate Valve

To operate the valve, a stem is used to connect the valve gate to the valve actuator. On
some valves, the bottom side of the gate will also have a stem that is exposed to
seawater hydrostatic to balance forces across the gate. Seawater hydrostatic pressure
on the exposed end area of the lower stem will translate into a force to close the valve
offsetting force to open the valve. When forces across the gate are balanced by a lower
stem causing the valve to be almost water-depth insensitive, the valve is known as a
balanced valve (Figure 9.18).
Actuators typically use combinations of spring force, hydrostatic force of the column of
co n tro l flu id o r se a w a te r h yd ro sta tic a ctin g o n th e o p e n sid e o f th e a ctu a to r, a n d
se a w a te r h yd ro sta tic o r co n tro l flu id h yd ro sta tic a ctin g o n th e clo se sid e o f th e a ctu a to r.
Some actuators have a single opening fluid inlet. When this type actuation is used, force
to close the valve is generated by a spring in the actuator, and seawater hydrostatic
acting on the actuator. Pressure inside the valve (in-line) is used to assist closing on

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some unbalanced valves. Other actuators have a pressure-assist close port. Valves
used for deepwater (>2000 ft) typically have a pressure assist circuit.
F o r m a n y ye a rs, ch o ke a n d kill va lve s w e re a d ve rtise d a s b e in g F a il-sa fe w h ich w a s
sometimes abbrevia te d F S . T h is te rm is g e n e ra lly d e fin e d a s th e a b ility o f a va lve to
close in the absence of any hydraulic control pressure from the surface control system, a
pre-loaded spring forces the gate to close whenever the opening control pressure is
zero. At high in-line differential pressure across the gate, seat friction may prevent fail-
safe closure. High in-line differential pressure across the gate could occur if a valve were
closed on a high-pressure flowing stream. Beginning in the late 1980s most
manufacturers would not guarantee fail-safe closure of their valves in all service
conditions. To provide for fail-safe operations, a pressure-assist close circuit was added
to the choke and kill valves subsea to provide this feature. This circuit is placed subsea
at the valve to ensure pressure assist close is available should hydraulics not be
available from the surface.

Figure 9.18 Principle of Balanced and Non Balanced Valves

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9.6 FLEXIBLE CHOKE & KILL LINES

Flexible choke and kill lines are used for two sections of the choke/kill system. At the
surface, high-pressure hoses are used to connect the choke/kill lines from the riser to
the choke manifold via hard piping on the rig. These hoses allow for rig heave motions
and the resulting stroke of the slip joint. Hoses used in the moonpool are typically 60 to
90 ft long.
Subsea, flexible choke/kill lines can either be high-pressure hoses or steel flexible pipe
fle x lo o p co ile d a ro u n d th e fle x jo in t to a llo w fle xib ility (Figure 9.19). The subsea lines
are used to make the transition on the LMRP from the riser around the flex joint to the
choke/kill outlets on the BOP stack. This transition allows for the angular motions of the
riser caused by rig offset and surge/sway of the vessel at the surface. Flexible hoses
used on the LMRP are typically 15 to 20 feet in length.
Flexible choke/kill hoses
are either bonded or non-
bonded construction with
stainless steel outer
sheaths. Bonded hoses
are typically vulcanized
(one piece) and made
from rubber elastomers
and steel strands. Non-
bonded hoses are usually
made from several
individual layers of
thermo-plastics that have
no adhesion between
them and steel strips.

Figure 9.19 Typical Configuration of Choke/Kill Lines

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Typical problem with flexible hoses are;

damage to the outer protective sheath causing damage to the inner layers
overbending or over-torqueing the hose causing separation at the end
connections
degradation caused by exposure to gases liquids or solids that leads to blistering,
swelling, accelerated aging, collapse or erosion of the inner liner.
Flexible hoses should be pressure tested and inspected both internally and externally
before use. Most manufactures require pressure testing to 1-1/2 times the working
pressure rating on a annual basis.
The other type of choke/kill line
used on the LMRP is a steel pipe
(fle x lo o p ) (Figure 9.20) coiled
around the flex joint to form a
spiral so that the pipe can flex
when angle is generated at the
flex joint. Although the steel pipe
is low maintenance and extremely
durable, it is seldom used since
each line on each rig has to be
specially built requiring long lead-
time. When rig s w ith fle x lo o p
lines are used, the lines should
be checked for fatigue cracks and
wall thickness before use.
The connections for choke/kill
lines between the LMRP and the
BOP stack are exposed to high
end loading during pressure
testing. To prevent separation of
the lines, mini- hydraulic
connectors similar to the wellhead
connectors are installed at the
LMRP connector to secure this
Figure 9.20 Flex Loop Choke/Kill Lines
connection.

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9.7 LOWER MARINE RISER PACKAGE (LMRP)

The Lower Marine Riser Package (LMRP) (Figure 9.21) typically consists of a frame,
connector, annular preventer (typically 2 annulars), flex joint, control pods, and choke/kill
lines connecting the stack to the riser. Additional items that may be located on the LMRP
are test valves at the termination of the choke/kill line before it mates up with the BOP
stack, accumulator bottles, and ROV intervention panel.
The purpose of the LMRP is to allow the BOP control pods and annular preventer to be
disconnected and retrieved to the surface for repair while allowing the BOP stack to
remain on the wellbore. The BOP stack is left on the wellbore to supply a well control
barrier and facilitate well control operations on re-entering the wellbore.

Flexible Choke,
Kill, and Rigid
Conduit Jumper
Hoses

Flex
Joint

ROV
Intervention
Panel
Choke/Kill
Test Valve

Figure 9.21 - Glomar Jack Ryan Lower Marine Riser Package

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On DP rigs, the connection between the LMRP and the BOP stack will have a guide
funnel, either up (on BOP) or down funnel (on LMRP), and orientation pins to stab and
realign the LMRP onto the BOP stack. The alignment system is needed to land and latch
the LMRP onto the BOP stack subsea after a disconnect. Figure 9.22 shows the up
funnel alignment system used on the Discoverer Seven Seas and a generic down funnel
system is show in Figure 9.23.

Helical cam to mate with

Funnel to receive alignment pin on LMRP
LMRP connector

Final alignment hole to

mate up with pins on
bottom of LMRP

Figure 9.22 - UP Funnel System on BOP Stack for

Discoverer Seven Seas LMRP not Shown

Helical Slot and Alignment

Pin Require for Orientation
Final Alignment Pins

Figure 9.23 - Generic Down Funnel Alignment System with

Stack and LMRP Shown

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9.8 CONTROL SYSTEMS

9.8.1 OVERVIEW
The function of a BOP control system is to direct hydraulic fluid to the appropriate side of
the operating piston and to provide the means for the fluid on the other side of the piston
to be vented. There are two basic classifications of control systems used in floating
drilling operations, the hydraulic and the Electro-hydraulic multiplex-control system.
The most common is the hydraulic control system, which is primarily found on moored
floating rigs. The E/H multiplex control system is primarily used on DP and ultra-
deepwater moored floating drilling vessels. The multiplex design provides the necessary
response times required on DP rigs for an emergency disconnect during a possible drive
off or drift off. Some of the manufacturers of control systems are Cameron Iron Works
(now a part of Cooper Oil Tools), Shaffer, ABB, and the Valvcon Division of Hydril.
9.8.2 HYDRAULIC CONTROL SYSTEM
Fluid used to operate the functions on the BOP stack is delivered from the hydraulic
control manifold (closing unit) through the hose reel, hydraulic hose bundle to the
subsea control pods. The pods contain control valves, which direct power fluid to the
various BOP stack functions on command from the surface. The control valves are
operated by pilot fluid supplied through small, individual pilot hoses, which connect the
valves to the hydraulic control manifold located at the surface. These small hoses are
contained in the hose bundle with the power fluid hose. The surface hydraulic control
manifold contains the panel valves, which direct pilot fluid pressure to the pod valves.
These panel valves are generally equipped with solenoid actuated cylinders which allow
co n tro l o f th e p a n e l va lve s fro m th e D rille rs p a n e l a n d m in i re m o te p a n e l. T o p ro vid e
complete redundancy for the subsea portion of the control system, two independent
hose reels, hose bundles, and pods are used.
The preceding discussion oversimplifies the hydraulic control system to a great extent.
To provide more detail, the following system description begins at the surface control
system and concludes with the subsea BOP pod. Keep in mind that the primary function
of each item on the system is to get fluid to the selected equipment at the desired
pressure in the minimum amount of time.

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9.8.3 HYDRAULIC POWER UNIT

The Hydraulic Power Unit (HPU closing unit) contains the fluid reservoir, pumps,
gauges, and equipment necessary to control the valves and regulators on the subsea
pods. Actuation of the valves at the control manifold can be accomplished locally or from
any of the remote panels. The control manifold also contains the pod selector valve.
The control manifold is equipped with two independent pump systems; electrically driven
triplex pumps are generally used as the primary system with air-operated pumps as the
secondary system. The combination of all pumps must be capable of charging the entire
accumulator system from the established accumulator system precharge pressure to the
maximum-rated system pressure in 15 minutes or less.
Hydraulic fluid is stored in a reservoir and is made up by automatically mixing soluble
BOP fluid and potable water. The fluid reservoir is necessary because control fluid is
vented subsea when the equipment is functioning. This fluid is then pumped by electric
and/or air pumps from the reservoir to the accumulators. The fluid is stored in the
accumulators, which are precharged to 1200 psi (minimum) with nitrogen to the system
working pressure.
Fluid from the accumulators flows through filters (usually 40 micron), a flow meter and
then through a pod select valve that directs the fluid through the pod hose to the active
pod. Pressure from the accumulators is read via a pressure gauge at the panel or at the
remote panel via pressure transducer. Pressure switches are also used to automatically
start and stop the pump(s) at the design working pressures of the control system. To
prevent overpressuring the system, relief valves are installed to relieve the pressure at
10% over the normal working pressure. Also located at the HPU are control boxes with
solenoid valves used to actuate the panel valves from the remote panels and pressure
switches that provide signals to the indicator lights and the remote pressure indicators
(gauges).

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9.8.4 REMOTE PANELS (RIGFLOOR AND AUXILIARY)

A typ ica l syste m co n ta in s tw o p a n e ls, th e D rille rs p a n e l (Figure 9.24), which is located
on the rig floor, and a mini-panel,
which is usually located in the
T o o lp u sh e rs o ffice . T h e re m o te
panels are powered electrically with
either an uninterrupted power
supply (UPS) or the emergency
generator. Remote panels have
capabilities to control all of the BOP
stack functions including pressure
regulation and monitoring of all
system pressures including the
surface diverter equipment. The
controls on the remote panels are
generally configured to graphically
display the BOP stack.
The operation of a function using Figure 9.24 - NL Shaffer Control System
the remote panel is accomplished D rillers Panel
through electro-pneumatic controls.
To operate a function, the button on the remote panel is depressed, thus allowing
current to actuate an electric solenoid valve at the closing unit. When the solenoid valve
is actuated, air pressure is allowed to shift the panel valve allowing pilot fluid to flow
through the pod hose to the appropriate pod valve. Because rig air is required to actuate
the BOPs from the remote panel, the backup air supply must be connected to the
solenoid valves on the closing unit to ensure remote actuation is available.
The controls for all critical functions (shear rams, connectors, LMRP) on these panels
should be equipped with covers to prevent accidental operation.

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9.9 HOSE BUNDLE, HOSE REEL & RIGID CONDUIT

9.9.1 HOSE BUNDLE

In standard hydraulic systems, the subsea power fluid supply and all pilot signals for the
pod valves are transmitted through a hydraulic umbilical, commonly called a hose
bundle.
The hose bundle is
generally composed of a
one-inch power fluid hose
surrounded by 3/16-inch
pilot and readback lines
(Figure 9.25). The outer
covering on the hose
bundle is made from
several materials, the
most common being Figure 9.25 Typical BOP Control
polyethylene and Hose
polyurethane. The
polyurethane is the preferred covering material because of its better physical properties.
For the individual hoses included in the hose bundle, hose manufacturers have been
required to provide a hose with less volumetric expansion to shorten the control system
response times. The majority of the response time required when a function is actuated
is the time and volume of fluid required to initially pressure the hose to 300 to 500 psi.
The volumetric expansion (V.E.) characteristic of the 3/16 in. pilot hose is a key factor
affecting response times for the BOP hydraulic control system.
For hydraulic systems that have been converted to operate in deepwater, a system
ca lle d p re ssu re -b ia s w a s d e ve lo p e d a n d u tilize d to m a in ta in lo w p re ssu re (+ /- 300 psi)
on the hose (pilot lines) at all times thus eliminating the time/volume required to initially
expand the hose when the function is actuated.
The hydraulic umbilical is routed to the pod by attaching a hose to the pod retrieving
wireline run from the rig to the top of the control pod. With this configuration the hose
leaves the reel and runs over roller sheaves before being attached to the top of the pod.
As the stack is lowered the hose bundle is attached to a dedicated wireline with hose
clamps. If necessary, the control pod can be retrieved independently using this wireline.

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9.9.2 HOSE REEL

The hose reel (Figure 9.26) is used to
store the hydraulic umbilical and provides
the means for easy running and retrieval
of the pod. Each hose reel, blue and
yellow, contains a motor drive assembly,
brake assembly, a hose reel manifold
and a junction box. When the pod is run
or retrieved, the junction plate at the
jumper hose is disconnected from the
hose reel. However, to keep selected
functions live while running or retrieving
the stack, a few controls are mounted on
Figure 9.26 Typical Hose Reel
the side of the reel (Figure 9.27). These
controls normally included such functions
as stack and riser connector and pod
latch. Power fluid from the surface
hydraulic control manifold is piped to the
hose reel through a swivel and used to
provide control fluid to the functions
during the operation
of the reel.

Figure 9.27- Hose Reel Running Controls

9.9.3 RIGID CONDUIT
When a function is actuated, the pressure
drop in the one-inch power hose included in the hose bundle can be substantial,
particularly for long hose lengths. One way to compensate for this pressure loss and
assure faster actuation times is to place accumulators subsea on the BOP stack. Since
the advantages of subsea accumulators diminishes with increasing water depth due to
the decreasing volume of usable fluid stored in a given accumulator, a large (two to
three inch ID) rigid conduit line attached to the riser is used. This line can be used
independently or in conjunction with either of the power fluid lines located in the hose
bundle. Another advantage to the rigid conduit line besides the smaller friction losses
from the larger internal diameter, is the shorter length. The rigid conduit line is only as
long as the riser for a particular water depth. On the other hand, the entire length of the
hose bundle must be used, regardless of water depth, requiring the power fluid to travel
through spare hose left on the hose reel.
To allow the fluid from the rigid conduit line to be supplied to only one pod at time, a
conduit valve manifold is located on the lower marine riser package. A typical manifold
consists of three, two-position three-way valves. One valve is used to supply power fluid
to the active pod, the second valve is used to isolate power fluid from the inactive pod,
and the third valve is used to dump the conduit line when the riser is retrieved. A one-
way check valve is used between the pod and valve manifold to isolate power fluid in
the one-inch power line located in the hose bundle from the rigid conduit line (if it is
not in use).

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9.10 BOP CONTROL POD

The Subsea Control Pod (Figure 9.28) provides the means to transfer fluid from the
surface equipment to the equipment at the blowout preventer stack without having
individual piping from the surface to each preventer. The hydraulic control system is
equipped with two control pods, designated as the blue or yellow pod. To maintain a fully
redundant control system, both pods must be operational at all times. If a control pod
should become inoperable,
drilling operations are
suspended and the BOP
stack is controlled with the
working pod until repairs are
completed and tested. The
control of the BOP stack
should be alternated between
pods weekly.
Power fluid is supplied to the
pod at the full rated working
pressure of the system, which LMRP Stinger Stack Stinger
- Extended Retracted
is normally 3000 psi. Since
the BOP equipment is
operated at a pressure lower Stack Female
Receptacle
than 3000 psi, the power fluid
flows through subsea
regulators (annular and
LMRP
manifold) in each pod. Female
Regulators serve two Receptacle
purposes. First, they reduce a Figure 9.28 - Cameron Modular Pod
higher pressure to a selected
pressure, normally 1500 psi. Secondly, they maintain or regulate the preset pressure
should external forces attempt to increase or decrease the pressure, such as during an
annular stripping operation. Pods usually have two 1 1/2-inch regulators. One regulator
is used to supply the pod valves controlling the annular preventers and is labeled as the
A n n u la r P re ssu re re g u la to r o n th e su rfa ce . T h e o th e r re g u la to r su p p lie s th e p o d va lve s
for the rams, choke and kill valves, connectors, and any remaining functions. This
pressure is illustrated a s M a n ifo ld P re ssu re o n th e su rfa ce co n tro l p a n e ls.
The downstream side of each regulator in the subsea control pod is connected through a
h o se in th e h o se b u n d le to a g a u g e a t th e su rfa ce la b e le d A n n u la r o r M a n ifo ld
R e a d b a ck P re ssu re . T h is g a u g e is used to monitor output pressure from the blue and
yellow pod regulators. A small shuttle valve attached to the back of the readback
pressure gauge is used to isolate the inactive pod regulator. When a BOP is operated,
the readback pressure is used along with the flow meter to indicate when full closure of
the BOP occurs. Located downstream of the subsea regulator are the pod valves. These
valves direct the regulated power fluid to the desired side (open or close function) of the
selected preventer while venting the fluid from the opposite side of the preventer to the
sea. All pod valves are operated hydraulically from the surface through small pilot hoses
in the umbilical.

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To allow the pods to be retrieved subsea from the LMRP, retractable stingers with
elastomers seals are used to provide fluid passage from the pods to the control hose for
each function. Each pod is equipped with a stack stinger and a LMRP stinger. The
stingers extend and retract into female receptacles on the stack and LMRP respectively
and are hydraulically energized to provide a pressure seal. Fluid ports in the stingers
align with ports in the female receptacles where control hoses attach the female
receptacle to the shuttle valve at the preventer.

9.10.1 POD VALVE (TYPICAL)

The pod valve shown is a two-position, three-way valve commonly called a SPM (Sub
Plate Mounted) valve (Figure 9.29). SPM valves are located in each pod with one valve
being required for each function (i.e. one valve to open and one valve for close).
The SPM pod valve is a poppet
type with a sliding piston that
seals on a nylon seat. In the
normally closed position (with no
pilot pressure applied), the spring
seats the piston onto the lower
seat and power fluid from the
subsea regulator is blocked at the
SPM valve. With the inlet
pressure from the subsea
regulator blocked, operating fluid
from the preventer is allowed to
flow back through the SPM valve
and vent subsea.
In the open position, with pilot
pressure applied to the SPM
valve, the piston shifts upward
and seals against the upper seat.
In this position, the vent port is
isolated by the upward position of Figure 9.29 Sub Plate Mounted (SPM) Pod Valve
the piston. Also with the piston
shifted in the upward position, power fluid is allowed to flow through the SPM valve and
operate the function. Two SPM valves are required to operate most functions.

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9.10.2 SHUTTLE VALVES

Shuttle valves provide redundancy and allow a preventer to be operated independently
from two separate sources (pods) while isolating the inactive pod. Shuttle valves are
typically installed directly into the control fluid outlet of the preventer with hoses from
each pod attached. Shuttle valves are an inherently simple piece of equipment and
therefore are very reliable (Figure 9.30).
To provide the capability of operating a preventer from more than two sources (i.e. ROV
hot stab and blue and yellow pod) while isolating the inactive sources, multiport shuttle
valves are used or standard shuttle valves are used in series.

Connected to
Function
Connected to
Connected to Yellow Pod
Blue Pod

Figure 9.30 - Typical Shuttle Valve

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9.10.3 OPERATING A FUNCTION

To open a ram, as shown in the illustration (Figure 9.31):
1. The open button at the
Driller's panel is depressed
sending an electrical signal
to the solenoid valve at the
HPU.
2. On actuation of the solenoid
valve, air pressure is applied
Solenoid Valves
to the air cylinder and shifts
the panel valve at the HPU
3. When the panel valve is
shifted, pilot pressure
(typically 3000 psi) is sent
through pilot lines in both
umbilicals to the open SPM
valves in both pods and Air Cylinder & Panel Valve
shifts the SPM valves open.
Due to the design of the
Pilot Lines to Inactive Pod
panel valve, pressure to the Manifold Regulator
close side of the SPM valve
is simultaneously vented
back through the pilot line to
the surface reservoir. Inactive

4. When the open SPM is

shifted, power fluid travels
through the HPU pod select
valve (not shown), through
the hose bundle or rigid
conduit line to the active
pod, through the pod
regulator (typically reducing
3000 psi to 1500 psi) and Shuttle Valves

through the SPM pod valve.

From the pod the fluid
travels through the control
hose, through the shuttle
valve and operates the ram
open. As the ram opens,
fluid from the close chamber
of the ram travels back
through the close shuttle
valve, through the hose and
vents to the sea through the Figure 9.31 Operating an open function
close SPM pod valve. with a hydraulic BOP Control System

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9.11 MULTIPLEX CONTROL SYSTEM

9.11.1 INTRODUCTION
The intent of a multiplex (MUX) system is the same as the hydraulic control system, to
provide for the remote operation of subsea blowout preventers and/or other well control
va lve (s). T h e te rm m u ltip le x sim p ly m e a n s th a t th e co m m u n ica tio n s syste m fro m th e
su rfa ce to th e se a flo o r ca rrie s co m m a n d s a n d /o r d a ta fro m th e su rfa ce to th e su b se a
electronic components via a single medium (cable) using a method for continuously
sharing the transmission medium.
Multiplexed communications links and electrical power links are provided to decrease
the time required to function a BOP or subsea valve. Experience has proved that an
a ll h yd ra u lic co n tro l syste m ca n n o t p ro d u ce e ffe ctive re sp o n se tim e s in u ltra -
deepwater. Time is a particularly significant factor in the operation of a system on a
dynamically positioned (DP) vessel when an emergency disconnect is required. Total
actuation times must be measured in seconds or a disconnect from the seafloor may
become impossible before the vessel drags the BOP over, causing damage to subsea
equipment, wellhead and BOP, possibly leaving the well unprotected.
In the early 1980s with the introduction of computer control devices, the basic format of a
m u ltip le x co n tro l syste m b e g a n to m ig ra te to th e co n ce p t o f a "C e n tra l C o n tro l U n it.
Probably this format was suggested by the basic "Hub" design where a computer can
accept both input signals and at the same time generate output signals. Since a single
computer negates the concept of redundancy, it wasn't long before two computers were
employed running parallel communication paths.
Current Multiplex systems are also driven by the convenience of modern computers to
the extent that many of the independent and redundant features of the original dedicated
and separate control panels and pods are now unobtainable. Instead, triple-redundant
computers and multiple parallel communications paths are offered as security against
electrical and communications failure.

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9.11.2 GENERAL OVERVIEW OF A MULTIPLEX SYSTEM

The system has both surface and subsea components. The primary surface components
in clu d e a D rille rs co n tro l u n it, T o o lp u sh e rs control unit, HPU control unit,
communication/distribution units (two) and two uninterruptable power supplies.
Also located on the surface are two MUX cable reels (one for each subsea pod), and a
high-pressure closing unit, which is the source of energized hydraulic power fluid.
Subsea components include the two identical and redundant subsea pods and two
multiplex cables connecting the respective pods with the communications/distribution
units. Hydraulic fluid is normally supplied to the pods via rigid conduit line(s) that direct
the fluid to the active pod via the rigid conduit manifold on the LMRP. In addition to the
rig id co n d u it lin e , m a n y rig s a lso in clu d e a h o t lin e (typ ica lly a o n e in . h o se ) th a t
supplies hydraulic fluid for emergencies and while running and retrieving the BOP stack.
Multiplexed data communications are based on computer technology, to include
computer network protocols and the use of modems. Two-way communications are
supported and utilized to ensure all surface generated commands are received and
processed. The communications and control network contains several industrial
(embedded) computers, sensors, software, control panels, interface panels, and
interconnecting cables. The MUX system receives, transmits, processes, and records
the operator commands system activity and sensor readings. Selected automatic
processes are also programmed to operate and monitor the system. The processed
inputs and outputs are sent to the control and interface panels. The control panels
display the status and analog signal readings from the system sensors.
Surface-to-seafloor communications and electrical power links are provided to actuate
subsea solenoid valves. These solenoid valves then actuate piloted, SPM hydraulic
valves that control the flow of power fluid, thereby initiating hydraulic actuation of a
blowout preventer actuator (piston), stack mounted choke/kill valve, or other major stack
mounted control valve.

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9.11.3 HYDRAULIC POWER UNIT

The Hydraulic Power Unit (HPU) used with a multiplex system is very similar to the
system used for a standard hydraulic BOP control system. The multiplex hydraulic differs
in that it does not include air driven pumps and surface mounted panel valves that
hydraulically control the individual pod valves since control of the pod valves is
accomplished via the electrical signal to the solenoid valves.
The HPU consists of an electric powered pumping system, a BOP fluid (lubricant) and
glycol mixing unit, surface accumulator system, and pressure supply manifold and
control skid with a panel for Diverter System and Telescoping Joint Seal Controls. The
HPU will also typically include an electronic Programmable Logic Controller (PLC) unit to
monitor the HPU fluid mixing system, air and hydraulic pressures, surface flow meter
output, pump running status, and fluid level alarms. Data from the HPU is transmitted to
the other remote panels via serial link cables.
The working pressure of the HPU ranges from 3000 to 5000 psi with pumping provided
by up to four electric powered triplex pumps. Pumps are powered directly from the main
rig electrical supply with at least one pump connected to the rig's emergency
generator(s). Pumps are set to automatically start/stop within operating pressures
of the system.
The control fluid is a mixture of potable water and a 1% to 3% concentration of BOP
control fluid concentrate with glycol added, as needed depending on the environment.
The BOP control fluid concentrate and ethylene glycol are stored in individual reservoirs
and mixed automatically as control fluid in the main HPU reservoir.
From the system pumps the energized BOP control fluid is stored in an accumulator
system that is typically manifolded into separate banks with one bank dedicated for the
diverter. From the accumulators, the fluid is filtered through 20 to 40 micron filters and
metered via the surface flow meter. Output from the flow meter is displayed at all
remote panels.
The controls for the diverter system are also located at the HPU. These controls are
similar to those used on a straight hydraulic BOP control system. Hydraulic panel valves
a re in sta lle d a t th e u n it w ith a ir a ctu a te d cylin d e r fo r re m o te a ctu a tio n fo r th e D rille rs a n d
T o o lp u sh e rs p a n e l. R e g u la to rs fo r d ive rte r p a cke r, flo w lin e a n d slip jo in t p a cke r se a ls
are also included at the HPU and controlled locally by manual operation or remotely from
the electric panels.

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9.11.4 DRILLER'S CONTROL PANEL

The Driller's Control Panel (Figure 9.32) is one of two primary means to initiate the
actuation of functions of the BOP stack or diverter system. The panel includes
illuminated push button controls complete with
nametags for the BOP stack, Diverter and HPU
functions. The BOP stack functions and the LMRP
functions are configured graphically on the panel to
ensure easy identification. Functions typically require
two-handed operation via a "press and hold" button to
enable and a "function button" (which must be
simultaneously pushed) for each function. The panel
will also include buttons for adjustment of pressure
regulators in each subsea pod (i.e. annular regulator,
BOP manifold regulator). The panels are also equipped
with warning lamps and audible alarms to signal
abnormal system conditions. Warning lamps normally
Plastic
included are: low accumulator pressure, low air
Covers
pressure, low BOP control fluid level, low glycol level,
low BOP control lubricant level, low blue pod solenoid
pilot pressure, low yellow pod solenoid pilot pressure, Plastic
and reduced redundancy (pod mismatch). Covers
To prevent inadvertent
actuation of a function,
protective guards are placed
over the shear ram and
connector unlatch function
buttons. In addition, some
Figure 9.32 Multiplex BOP Control Panel
systems are equipped so that
buttons to actuate a function
Disarm
can be disabled or locked out via software commands. This
switch feature may be used to disable or lock out functions for the
inside of following:
panels
Wellhead connector unlatch while drilling.
LMRP connector unlatch while a running or retrieving the
stack or while drilling (except for Emergency Disconnect
Figure 9.33 Critical circuitry).
function lockouts
Pipe rams close function during a well test when the non
sealable part of the subsea test tree is across the ram.
Inside the panel, two PLC (programmable logic controller) units made up of analog
output, digital output, digital input, Central Processing Unit (CPU), and other hardware
are mounted in an explosion proof junction box. The junction box is connected via
redundant fiber optics cables routed separately to redundant communications controllers
located elsewhere on the vessel. The PLC processor is used to control and monitor all
input/output (I/O) commands or signals. By way of the redundant communications
controllers, the panel can communicate with the PLCs in the Toolpusher's Panel, the
HPU and the two Subsea Pods.

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T h e P L C s in th e D rille rs p a n e l co n sta n tly sca n s th e syste m lo o kin g fo r a m e ssa g e fro m

a pushbutton or another PLC. When a message from a pushbutton is received, the PLC
issues a message that is sent to all other PLC, that either update their status
(T o o lp u sh e rs p a n e l m a y ch a n g e in d ica to r lig h ts) o r p e rfo rm a fu n ctio n (su b se a p o d fire s
a solenoid valve).
Electrical power to the MUX system including the subsea pods is provided by redundant
uninterruptable power supplies (UPS). The only electrical parts excluded are the pumps
on the HPU.

9.11.5 TOOLPUSHER'S CONTROL PANEL

The Toolpusher's control panel is the second redundant control station in the MUX
control system. Therefore it is functionally identical to the Driller's Control Panel, except
the panel is usually designed for installation in a safe area and is not explosion proof.

9.11.6 HPU INTERFACE PANEL

The Hydraulic Power Unit (HPU) panel interfaces with the system to provide control and
status of the control fluid pumps, accumulator system, and other surface equipment.
This panel includes the same PLC hardware for communicating with the other panels,
but does not have switches to function the BOPs.

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9.11.7 SYSTEM REDUNDANCY

As illustrated in the Figure 9.34, a typical multiplex BOP control system has redundancy
for just about all items except the push buttons on the panels. The location of the control
panels, distribution panels, UPSs, and routing of the conductors between the panels are
also separated to provide backup and prevent damage/failure of any single item from
causing the entire system to fail. The redundancy within the panels also allows for failure
of PLC components within the panel while still allowing the system to function.
In addition, some systems also have an Electro Hydraulic Backup System which
consists of select TYPICAL MUX SYSTEM ELECTRONIC SCHEMATIC PRINCIPLE OF REDUNDANCY
TYPICAL MUX SYSTEM ELECTRONIC SCHEMATIC - PRINCIPAL OF REDUNDANCY
functions that are hard- Screen Screen Screen
wired (individual power Light Light Light
wire to the selected
DRILLER CONTROL PANEL TOOLPUSHER CONTROL PANEL HYDRAULIC POWER UNIT
solenoid valve) through Analog Output Analog Output Analog Output Analog Output Analog Output Analog Output
the umbilical cable to
Digital Input Digital Input Digital Input Digital Input Digital Input Digital Input
the solenoids. The
purpose of this back-up Digital Output Digital Output Digital Output Digital Output Digital Output Digital Output

system is to provide a CPU CPU CPU CPU CPU CPU

means for emergency
disconnect that is PROFIBUS
Interface
PROFIBUS
Interface
PROFIBUS
Interface
PROFIBUS
Interface
PROFIBUS
Interface
PROFIBUS
Interface
independent of the MUX
Power Supply Power Supply Power Supply Power Supply Power Supply Power Supply
system. Solenoid valves
that control the critical
functions of an
emergency disconnect DISTRIBUTION DISTRIBUTION
UPS "A' UPS "B'
are directly wired to the PANEL EVENT LOGGER PANEL
Power Supply Power Supply Power Supply Power Supply
surface via the umbilical CPU CPU YELLOW CPU CPU YELLOW
to each pod. Activation BLUE A A BLUE B B

is achieved from an PROFIBUS

Interface
A Interface
PROFIBUS PROFIBUS
Interface
B Interface
PROFIBUS

independent remote Modem Modem Modem Modem

p a n e l a t th e D rille rs
station or a similar
panel with the
SURFACE
uninterruptable power SUBSEA
supplies. The functions BLUE MUX CABLE YELLOW MUX CABLE

typically activated with BLUE POD YELLOW POD

the Electro-hydraulic
Solenoid Power Solenoid Power Solenoid Power Solenoid Power
Backup System are: Power Supply Power Supply Power Supply Power Supply
CPU CPU CPU CPU
1. Pod Stabs Extend Modem Modem Modem Modem
Solenoid Drive Solenoid Drive Solenoid Drive Solenoid Drive
2. Shear Rams Close Analog Input Analog Input Analog Input Analog Input
RS 485 Interface RS 485 Interface RS 485 Interface RS 485 Interface
3. All Stabs Retract
RISER
4. Riser Connector CONTROL
BOX
Unlock Pressure Pressure
Transducer Transducer
9.11.8 MUX Solenoid Valve Solenoid Valve

CABLES Figure 9.34 Mux System Electronic Principle of Redundancy

Each multiplex BOP

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control system is equipped with a minimum of two mux cables, a blue and yellow system
cable. The cables are stored on storage reels that are equipped with air or hydraulic
motors, a level winding system, and a slip ring to allow circuitry to be maintained while to
the reel rotates.
The mux cable is an armor-covered cable that typically has four power supply wires and
six to ten communication conductors. The power conductors are typically 8 AWG size
conductors and provide 440 volts for the solenoid supply. The wires used for
communications are typically 20 AWG and can be either single or multi conductors.
The overall cable is usually around 1.5 in. in diameter with a breaking strength of
30,000 pounds.

9.11.9 RIGID CONDUIT LINE AND HOT LINE

The hydraulic control fluid is supplied subsea via a 2.5 to 4 in. diameter conduit line
attached to the riser. The line has a rated working pressure of 3000 to 5000 psi,
depending on the working pressure of the BOP control system. The line is built integral
to the riser and connections made up as each riser joint connection is made.
A Conduit Valve Module is located at the LMRP and is used to direct control fluid to the
active subsea pod.
The conduit module is used to:
Isolate the associated rigid conduit line; e.g., open or close supply from the rigid
conduit line.
Select the pod to which power fluid is supplied.
Provide control fluid to the solenoid supply systems in the Subsea Pods.
Filter the control fluid.
Supply control fluid to pods from the 1 in. hot line if necessary.
S o m e rig s a re a lso e q u ip p e d w ith a h o t lin e co n sistin g o f a o n e -inch diameter hydraulic
hose with a rated working pressure of 5000 psi. The hose is stored on a reel in the
moonpool area and is attached to the riser as it is deployed. The hot line terminates at
the Conduit Valve Module on the LMRP. The hot line may be selected as the supply
conduit from the surface, or may be isolated (deselected) by valves in the Conduit Valve
Module. The hot line can be used as a backup for the rigid conduit line, but is primarily
used to supply fluid to the control pods as they are being deployed and to secure the
well should the rigid conduit line become inoperable.

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9.11.10 MULTIPLEX CONTROL PODS

The multiplex subsea control pod comprises two sections, an electronic module and a
hydraulic section. The hydraulic section of a multiplex subsea pod is very similar to the
pods used on a straight hydraulic control system, and in some cases, the same
equipment. The electronic section
of the pod is typically mounted
above the hydraulic section with
control lines from the solenoid
valves connecting each pod
valve. Since the two sections are
h a rd co n nected, the pod is
handled as one unit. Subsea Pod Electronics
retrieval of the multiplex pod
differs from the straight hydraulic
Solenoid Valves
pod in that it typically cannot be
retrieved independently of the
LMRP. Independent retrieval is
limited by the fact that the mux
cables are attached to the riser
and the mux cable is usually hard
connected to the pod. The weight
and size of these pods also make
it difficult for subsea retrieval on
guideline tuggers. Pod Hydraulic
Section
A multiplex pod designed by
Cameron and installed on the
Marine 700 (Figure 9.35) is
e q u ip p e d w ith w e t co n n e cts fo r
connecting the MUX cable so that
it can be retrieved independently
of the LMRP. The retrieval and
redeployment of the pods on the Stack Stinger
Marine 700 has been completed
successfully several times. LMRP Stinger
Although this feature can save
considerable rig time should a
Figure 9.35 - Marine 700 - Cameron
pod need to be retrieved for
Pod Hanging in Moonpool
repair, it has not been widely
used to date.
Operation of the pod is accomplished through a redundant subsea electronic module
(SEM) installed in a one-atmosphere vessel. The vessel containing the electronic units,
power supply and power conditioning equipment is typically purged with dry nitrogen to
ensure that it remains moisture free. Connections between this module and the solenoid
valves and Riser Control Box is accomplished using subsea connectors.

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Solenoid valves are equipped with dual coils powered from each pod for redundancy
with the status continuously monitored providing an alarm to the surface panel for any
open circuits. To minimize leaks at the low volume sliding sleeve solenoid valves, 20-
micron filters are installed in each pod to maintain a clean solenoid supply fluid.
Another important part of a multiplex control pod is the accumulators in the pod used to
store and maintain solenoid supply (pilot) pressure. Solenoid supply pressure is required
to be available at all times so that pod startup can be accomplished.
During operations, one pod is always "active" (pressurized) and the second or redundant
pod is updated and actuated electrically so that on selection, it assumes the status of the
active pod.

9.11.11 RISER CONTROL BOX

The Riser Control Box (RCB) provides a means to connect external sensors/devices to
the electronic packages in the pods for signal transmission to the surface. The items
typically connected to the RCB are the Electronic Riser Angle (ERA) sensors, and BOP
sta ck P re ssu re a n d T e m p e ra tu re p ro b e . T h e se d e vice s a re co n n e cte d to p ro ce sso rs in
each pod by means of RS-485 communications through the riser control box mounted
on the LMRP. In addition, communication and power is provided between the two pods
via the RCB to allow the pods to be operated from the mux cable of the other pod should
one mux cable become inoperable.
T h e E R A is u se d to p ro vid e rise r a n g le fro m th e se n so r a t th e fle x jo in t o n x & y a xe s
that can be connected to the D/P system to determine rig offset.
The pressure and temperature probes are installed at choke/kill outlets either on the
BOP stack or at the upper annular outlet to record the stack temperature and pressure.
If sensors are mounted on the BOP stack, wet connects are required to mate the
sensors to the RCB on the LMRP. The pressure sensor records the actual pressure and
temperature at the stack/LMRP (including hydrostatic) and can be used to
measure/record choke line friction pressure (CLFP). During well kill operations, the
sensor can be used to compensate for CLFP during circulation and to provide an early
indicator of gas entering the choke/kill lines.

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9.11.12 OPERATING A FUNCTION

1. T h e b u tto n to clo se th e a n n u la r is d e p re sse d o n th e D rille rs panel. The PLC in the
panel receives the signal and issues a message over the network to close the
annular preventer. The message is transmitted to all panels and both pods
(Figure 9.36).
2. The message
(electrical signal) is
sent via the blue and
yellow mux cable to
each pod. On receipt
of the message, the
pods remove power to
the open solenoid
valve and apply power
to the close solenoid
valve. A message is
sent back over the
network so that all
panels can update
their displays.
3. Power is applied to the
close solenoid valve;
the coil actuates the
solenoid valve and
allows pilot supply
pressure from a pod-
mounted accumulator
fed by the rigid conduit
line to shift the annular
close SPM valve. At
the same time, the
annular open solenoid
valves are de-
energized allowing
open pilot fluid to vent
subsea at the pod.
4. When the annular
close SPM valve shifts Figure 9.36 Basic Circuit to Operate a CLOSE Function
open, power fluid from
the surface accumulators is allowed to flow though the rigid conduit line to the active
pod. The power fluid then flows through the pod regulator where the pressure is
reduced (typically to 1500 psi), through the open SPM valve and out the bottom of
the pod and into the hose, through the shuttle valve and to the close port on the
annular preventer and closes the annular. As the annular closes, the open fluid exits
the annular, flows through the open shuttle valve and hose to the pod where it is
vented subsea through the annular open SPM valve.

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9.12 CLOSING SYSTEM REQUIREMENTS

9.12.1 SURFACE ACCUMULATORS

For floating rig operations, it is recommended that the surface volume of the hydraulic
control system for a subsea stack have a minimum usable hydraulic fluid volume to
satisfy these requirements (with the pumps inoperative):
1. Adequate volume to comply with regulatory requirements of the operating
area.
2. Open and close all the ram-type BOPs and one annular BOP in the subsea
stack with the resulting accumulator status the greater of:
a. 50% volume reserve.
b. the pressure of the remaining accumulator volume exceeds the calculated
minimum operating pressure (using the ram BOP closing ratio) to close any ram
BOP (excluding the shear ram) and open any choke at the required shut-in
pressure.
9.12.2 SUBSEA ACCUMULATORS
Subsea accumulators are typically installed to reduce the closing times or to provide fluid
for a backup system (i.e. acoustic, deadman). Subsea accumulators must have an
additional precharge pressure equivalent to the hydrostatic head in the control system at
the accumulator. Subsea accumulator bottles used for normal BOP actuation functions
should be precharged to a selected precharge plus the pressure gradient at a rate of
.445 psi per foot (seawater gradient). For example, an accumulator precharged to 1200
psi and deployed in 2000 feet of water should be precharged at the surface to 2090 psi.
SS Bottles Precharged = 1200 psi + (.445 psi x 2000)
Before Running = 1200 psi + 890 psi
= 2090 psi

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The additional volume of nitrogen to provide the 890 psi precharge pressure in the
example above is necessary to overcome the hydrostatic pressure acting on the
opposing side of the operating piston that is vented to the sea when a function is
actuated. Since the accumulator is filled with an additional volume of nitrogen to
counteract the equivalent hydrostatic pressure, the available volume remaining in the
accumulator for fluid will be less. The example below using Boyles Law of gases
illustrates that the available fluid in a 10 gallon accumulator decreases from 6.0 gallons
on the surface to 3.76 gallons when used at 4000ft water depth.
System Operating Pressure = 3000 psi
Surface Precharge Pressure = 1200 psi
Total fluid in a 10 gal accumulator on surface = 60% or 6.0 gals
Subsea Precharge pressure for 2000ft WD = 2090 psi
Total fluid in a 10 gal accumulator subsea = 51.2% or 5.12 gals
Subsea Precharge for 4000ft WD = 2980 psi
Total fluid in a 10 gal accumulator subsea = 37.6% or 3.76 gals
When the temperature change from surface to subsea and the compressibility of
nitrogen is added to the equation, the available fluid from a subsea accumulator
becomes even less, making them impractical for use as a way to decrease closing times
due to the number of bottles that would be required. For this reason, large diameter
conduit lines are the preferred means to reduce closing times as water depth increases.
On some ultra-deepwater rigs, helium has been substituted for nitrogen for subsea
bottles (primarily used for the deadman system). The smaller molecule of helium makes
it more compressible at the higher pressure needed for pre-charging deepwater subsea
accumulators. The higher compressability of the helium provides more usable fluid per
accumulator than nitrogen, thus requiring fewer bottles to be mounted on the BOP stack.
A disadvantage to using helium as a precharge gas for accumulators bottles is that it
tends to leak at a higher rate than nitrogen, is less readily available and costs about
400% more than nitrogen. Accumulator bottles equipped with a piston type float have
proven less resistant to helium loss than conventional bladder or float accumulator
bottles used with nitrogen.
Subsea accumulator bottles used as surge bottles with annular preventers should
typically be pre-charged to 500 psi, plus the hydrostatic pressure gradient for the given
seawater depth. Subsea accumulator bottles used in conjunction with emergency
backup subsea acoustic systems should be precharged, and adjusted for water depth in
the same manner as other subsea bottles to ram preventers.

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9.13 BACKUP SYSTEMS

9.13.1 ACOUSTIC
An acoustic system can be installed on the blowout preventer stack to actuate selected
functions when the primary control system is lost. An acoustic control system can
operate in water depths down to 6000 feet and up to a one mile offset from the wellbore
depending on the model. Acoustic systems manufactured by Raytheon Company and
Cameron Iron Works are the most common. Acoustic signals may be emitted on location
from the rig or off location from the deck of a boat. Acoustic signals are sent through the
water to hydrophones located on the blowout preventer stack. Through a subsea battery
powered electronics system mounted on the stack, the acoustic signals are converted to
electrical signals, which in turn actuate solenoid pilot valves located in a dedicated mini
pod dedicated to the acoustic system. The solenoid pilot valves send a hydraulic signal
to actuate a control valve in the acoustic mini-pod. This allows fluid from a stack
mounted acoustic accumulator bank to function the selected preventer. The acoustic
system hydraulics are connected to the preventer through a second shuttle valve
mounted at the function. Selected functions may include shear rams close, hangoff pipe
ram close, wedgelock (if equipped), and connector unlatch.
Typically, the capacity of the subsea acoustic bottle is 1.5 times the volume required to
function the selected components. The subsea accumulator bottles for the acoustic
system are the same as surface bottles plus an adjustment for seawater hydrostatic
pressure at the given location. The subsea acoustic bottle pressure is not regulated
down and the full 3000-psi bottle pressure is delivered to the selected function.
If installed, the acoustic system should be tested by actuation of a BOP function
1. when the BOP stack is initially run to verify competence of the system.
2. before retrieving the stack at the completion of the well to provide data for
possible maintenance.

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9.13.2 DEADMAN
T h e M U X syste m m a y in clu d e a fe a tu re ca lle d D e a d m a n w h ich ca n b e tu rn e d on
(armed) or off (disarmed) as desired by the operator. When armed, the shear rams will
be closed and other selected functions will actuate should there be a loss of all
hydraulic power, communications, and all electrical power subsea. The energy provided
to activate the shear rams and other functions is in the form of hydraulic energy stored
in subsea accumulators attached to the BOP stack. A combination of the following
conditions must simultaneously exist for the deadman function to trigger. They are:
1. loss of electrical power to the Yellow pod.
2. loss of electrical power to the blue pod.
3. loss of hydraulic pressure from the hot-line(s).
4. loss of hydraulic pressure in the rigid conduit line(s) coming down the riser.
T h e d e a d m a n se q u e n ce is u se r d e fin e d . O n th e Glomar Jack Ryan, the sequence is
programmed to rapidly increase the BOP manifold pressure, shear pipe, lock the ST-
Locks on the shear ram, close all choke and kill line valves, and unlatch the choke and
kill line connectors on each pod. Lithium batteries in each pod provide the necessary
electrical power to fire the solenoids and run the PLC processor that controls the
sequence. Fluid power is from four (4) dedicated 175-gallon accumulator bottles on the
lower BOP stack. These bottles are independent and isolated from the surface
accumulators except when being charged.

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9.13.3 ROV HOT STABS

Hot-stab connectors are typically used as a means of emergency actuation of select
stack and LMRP functions. The ROV hot-stab connector consists of a stab-type device
that can be inserted by an ROV into a pressure receiver coupling. Hot-Stabs are used to
hydraulically operate pre-selected functions. Typically, the blind/shear rams and the
LMRP connector are selected. Hydraulic pressure is provided by the ROV from an
alternate hydraulically powered pump using BOP control from a bladder attached to the
ROV or by using seawater as the emergency hydraulic fluid. Because this method does
not provide for maintaining hydraulic pressure on the function after actuation, it will be
necessary to lock the preventers when they are actuated. Hot-stab connectors are
designed with single, dual, or triple port configurations. The dual port configuration would
be used to operate the ram and lock simultaneously.
ROV intervention is used to provide backup to a limited number of functions. The most
critical functions are equipped with a means to operate via ROV intervention in the event
the control system does not function.
Functions that may be included on the ROV intervention Panel on the LMRP are:
LMRP Connector Unlock.
LMRP Connector Secondary Unlock.
LMRP Connector Glycol Injection.
LMRP Gasket Release.
ROV intervention functions that may be included on the BOP stack Panel is:
Wellhead Connector Unlock.
Wellhead Connector Secondary Unlock.
Wellhead Connector Glycol Injection.
Blind Shearing Rams Close.
Casing Shear Rams Close.
Wellhead Gasket Release.

9.13.4 ELECTRO-HYDRAULIC
An electro-hydraulic system is sometimes used for a backup to the multiplex BOP
control system. The electro-hydraulic system provides a direct electric signal to the
solenoid valves bypassing the multiplex logic. The system uses dedicated wires in the
MUX cable connected directly to the solenoid valves. This system requires the normal
hydraulic circuit to be operational and is setup to only operate dedicated emergency
functions.

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BOP STACK TESTING

To confirm the integrity of the Subsea BOP stack, a function and pressure test is
required much the same as a surface BOP stack. Since the stack is subsea, this process
is more difficult and time consuming since long trips are required to install the test plug,
larger volumes are required while testing making leaks harder to detect and test
monitoring is via gauges/meters and television cameras.
9.14.1 FUNCTION TESTING
One of the most important operations to confirm the integrity of the control system is
function testing the BOPs. The function test is used to verify that the preventer will open
and close as required and that the control system does not leak. The closing times for
subsea preventers per API 16E are 60 seconds for annulars and 45 seconds for ram
preventers.
The function test is performed by closing and opening each preventer and choke/kill
valve from each subsea pod and each surface panel. Each time the preventer is
functioned, the volume of fluid to operate the function is recorded from the flow meter
and the time from when the button is depressed until the preventer is fully actuated is
recorded. The time required for preventer to function is usually determined by monitoring
for recovery of the read-back pressure gauge and/or the completion of flow from the flow
meter. On straight hydraulic control systems with subsea accumulator bottles, the
closing time should be recorded by use of the read-back pressure gauge since the
surface flow meter will continually count after the preventer is fully closed due to the
recharging of the subsea accumulator bottles.
Multiplex BOP control systems will typically have a surface flow meter and subsea flow
meters mounted in each pod. The subsea flow meters can be a good indicator that the
preventer has completed actuation since it does not measure recharging the subsea
bottles.
Function tests should be performed:
1. On surface before deploying the BOP stack.
2. Initially on bottom after the BOP stack is landed and latched.
3. While pressure testing the BOP stack.
4. Every 7 days.
Measuring and tracking actuation (closing and opening) times and volumes for the
subsea preventers is important for detecting impending problems with the preventers
and trouble shooting any problems. Slower response times and higher than normal
operating pressure have been early indicators of mechanical problems in ram locks,
connectors and annular preventers. To properly troubleshoot control system problems, a
log should be maintained recording each operation while troubleshooting.

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9.14.2 PRESSURE TESTING

Pressure testing is the second step necessary to confirm the integrity of a BOP stack. A
pressure test is required to confirm the pressure integrity of the preventer and system
and to confirm that the preventer has fully actuated on a function test when surface
indicators are not positive.
One major difference between surface and subsea BOP stack testing is that on initial
installation, only one pressure test to confirm the integrity between the connector and
wellhead may be performed since the stack was completely tested prior to being
deployed subsea. Pressure testing of subsea BOP stacks is typically performed at the
following intervals:
On surface prior to running the BOP stack.
After setting each casing string.
Every 14 days.
Any additional time required by regulatory agency.
Subsea stacks are typically tested with water on the surface and with the current mud
that is in the hole after the stack is subsea. The use of mud subsea is necessary due to
the complications of spotting water in the BOP stack while testing and the potential loss
of hydrostatic. During testing, a test plug is set in the top of the wellhead and the test
fluid is usually pumped via one of the choke or kill lines during the test. This method
allows the drill pipe to be open back to the surface for monitoring the wellbore and for
potential leaks past the test plug. During BOP testing, well control is maintained by the
hydrostatic pressure of the fluid column in the drill pipe since the hydrostatic of the mud
in the riser is isolated from the wellbore by the test plug.
In ultra-deepwater, consideration must be give to the differential pressure of the mud
versus seawater when selecting the BOP test pressure. For example, while drilling in
8000 feet of water with 15.0-ppg mud, the BOP body is subjected to a differential
pressure of 2700 psi. For a BOP rated to 15000 psi, the maximum test pressure for
these conditions would be 12300 psi.

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9.15 DIVERTER SYSTEMS

9.15.1 INTRODUCTION
The basic function of the diverter system on a floating rig is similar to that for rigs with a
surface BOP stack, to allow uncontrolled flow to be safely directed away from the drilling
rig. Figure 9.37 shows a typical diverter system.
The general purpose associated with diverter systems is to divert shallow flow from the
wellbore when insufficient integrity is available at the casing shoe to allow the well to be
shut-in and the influx circulated out with the BOPs. In floating drilling, the industry has
moved away from using the diverter system to handle a shallow gas kick at the surface
due to the higher peak pressures seen during riser unloading, and the reliability of the
diverter equipment. The dynamic peak pressure condition is not solely a floating drilling
condition but takes on added significance with floating rigs because of the larger
hole/riser volumes, equivalent higher formation pressures, more diverter equipment seal
arrangements, and the tortuous diverter flow path.

Figure 9.37 Typical Diverter System

The primary use of the diverter systems today on floating rigs is to handle gas in
the riser. In this event, the diverter system is not exposed to as prolonged a pressure
situation because the source of uncontrolled flow has been shut off by the closed BOP.
The trapped energy of the gas migrating in the riser, however, will still have to be
handled by the surface diverter but for a shorter duration than a non-shut-in situation.

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9.15.2 HANDLING SHALLOW GAS

When operating from a floating rig, shallow gas is typically handled by one of the
following methods:
Obtaining a shallow hazard survey and if a high potential for shallow gas exists,
the well location is moved, if possible.
If the location cannot be moved, a pilot hole is drilled without the riser in place
allowing the well to be diverted at the seafloor if required. This method provides
the best chance to dynamically kill the well since the hole volume is less, the
ECD is higher from the smaller annulus clearance, and there is a continuous
hydrostatic head provided by the seawater.
Drill the hole for the conductor casing with weighted mud taking returns at the
seafloor. This method allows the shallow gas formation to be drilled riserless
while still maintaining an overbalance on the formation. If the shallow formation
does flow, the well can still be diverted subsea and dynamically killed. This
p u m p & d u m p m e th o d ca n require 20,000+ barrels of mud and is a logistics
challenge.
Shutting in the BOP on all influxes after the BOPs are set on the conductor
casing. This is possible since the conductor casing today is typically set +/- 2000
ft BML as opposed to 1000 to 1200 ft BML depth that was standard in the early
1980s. The additional depth minimizes the possibility of broaching at the
conductor casing shoe.

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In areas where the water depth is less than 500 feet, a pin connector (Figure 9.38) may
be used if a zone with a high potential for shallow gas must be drilled in the conductor
hole section. The need for the pin connector is based on the fact that diverting subsea
could allow the gas to surface directly beneath the rig. The shorter riser length in this
water depth also provides less gas expansion/storage volume before it reaches the
surface making the diverter system a more reliable option. Pin connectors are very rarely
used in floating drilling operations today.
The best well control practice for shallow gas is prevention practices, i.e., controlled
penetration rates, seawater hydrostatic and dynamic kill procedures.

Figure 9.38 Typical Pin Connector Configuration

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9.15.3 MAJOR COMPONENTS OF A DIVERTER SYSTEM

ON A FLOATING RIG
Components of a general diverter system on a floating rig are shown in Figure 9.39:
Diverter retrievable unit that includes the sealing element, flowline seals, and
hydraulic system for actuating the diverter packer.
Diverter packer provides an annular seal and stops the upward flow path of
well fluids. Can have a restricted internal diameter or full opening and may have
capabilities to close and seal on open hole.

Optional Riser Mud

Gas Separator
System

Figure 9.39 Components of a Typical Diverter

System

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Diverter housing - anchors the diverter system and provides side outlets for
return flowline, diverter lines.and trip tank/fill-up lines. Diverter housing is
permanently mounted to the rig floor substructure.
Discharge lines and valves - routes fluids overboard or to the shale shaker.
Valves are also included to isolate all auxiliary lines for the trip tank and fill up
lines. Valves and lines are permanent installations on floating rigs.
Upper ball/flex joint provides angular movement of the riser/slip joint caused
by rig motion on floating rigs.
Slip joint - provides a dynamic seal between the riser and the rig while
permitting vertical motion of the rig.
Riser provides a conduit from the seafloor to the surface.
Diverter control system provides control to sequentially function the
necessary diverter components so the well is not shut in at the surface.
Riser Mud Gas Separator System (optional) provides a means to circulate
the mud from the riser through a mud gas separator before returning to the
shakers/mud pits.

9.15.4 WORKING PRESSURE OF THE DIVERTER SYSTEM

The diverter system should have a working pressure of at least 150-psi when the subsea
stack is to be used as the primary response method in a well control situation. This
minimum pressure level provides some degree of diverter pressure integrity for gas that
may enter the riser before the subsea BOP stack is closed. Typically the diverter line
valves would be the limiting low-pressure components in the diverter system
If the diverter system is used to handle shallow gas, the working pressure should be at
least 300 psi. This minimum pressure level provides a degree of working pressure
allowance for normal equipment wear and for design safety tolerance against possible
peak pressures and dynamic fluid surges.
Conversely, a diverter system designed and/or used to handle gas from the riser above
a shut-in BOP may not be capable of sustained pressure and flow from a formation kick.
Even if the top hole is drilled without a riser, a diverter system must be operational for
the remainder of the drilling operations when a riser is in use.

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9.15.5 DIVERTER UNITS

Diverter units typically include:
1. A packer arrangement to effect an annulus seal around the drill pipe.
2. Side outlet(s) for the flow to exit or enter the diverter.
3. A structural housing to anchor the diverter and to provide flowline connections.
Diverter units are typically permanent installations on floating rigs.
One common type of diverter unit found on most third generation and earlier rigs is the
Regan KFDS diverter. The KFDS diverter is equipped with a retrievable packer insert
that typically has an internal diameter (10.625 in.) less than the riser and is not capable
of closing and sealing on open hole. The reduced ID of the insert requires that the
packer be removed and stripped over the drill string whenever a tool larger than 10.625
in. is used.
Operation of the KFDS is accomplished by applying hydraulic pressure to a bladder in
the diverter housing that expands and squeezes the packer around the pipe. KFDS type
diverters (Figure 9.40) are low volume functions and can typically be closed in ten
seconds or less. Opening is accomplished by venting the closing pressure and allowing
the elasticity of the element to open the packer.

Removable diverter packer typical

packers h ave 10 .6 2 5 internal
diameters

Bladder

Diverter housing
lockdown dogs

Flowline Outlets

Diverter Housing
welded to substructure

Figure 9.40 KFDS Diverter

On the KFDS diverter system it is important to ensure that the diverter close function is
never actuated unless the diverter packer is installed. Actuating the diverter packer

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without the packer installed could cause the bladder to rupture causing injury to
personnel. To ensure that the diverter close function cannot be actuated unless the
packer is installed, an interlock is typically installed to block packer close fluid unless the
diverter lock down dogs are energized. A review of this system is typically required
during rig acceptance to ensure that an interlock system is included.
A CSO (Complete Shut-Off) diverter unit (Figure 9.41), that incorporates an annular-
type packing element is also used and found on rigs built or upgraded since the mid
1990s. This system has a full through-bore internal diameter equal to the riser and is
typically rated for 1000-psi wellbore pressure on 5-inch pipe and 500 psi wellbore
pressure on open hole. The full bore internal diameter allows the diverter packer to
remain installed while handling large OD tools thus reducing handling time for BHAs and
large downhole tools.

Annular style element

with full capabilities

Diverter lockdown dogs Diverter housing

connected to substructure

Opening Chamber

Closing Chamber

Flowline, diverter line, trip

tank line connections

Figure 9.41 Complete Shut-off Diverter

Closing the CSO type diverter is accomplished by applying pressure below the piston
that forces the element up and in around the pipe. The CSO diverter is opened by
venting closing pressure and applying opening pressure to the top of the piston. As the
piston moves down, the elasticity of the element forces the element to the open position.
The volume to close the CSO type diverter is substantially greater than the KFDS
diverter and can require up to 20 seconds to operate.

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9.15.6 DIVERTER LINES

The typical diverter line found on floating rigs is a 12-inch nominal size (12.75-inch OD)
with a 0.406-inch wall thickness. Since the diverter system is a permanent installation on
a floating rig and used throughout the entire well, the diverter lines are permanently
installed and typically have welded connections. On semisubmersible rigs, the overboard
diverter lines are typically installed below the main deck so the lines do not provide an
obstruction while moving material on the main deck. The process of routing these lines
below the main deck requires installation of numerous turns and bends in the lines. On
some semisubmersible rigs, diverter systems have been installed with 10+ ninety-degree
turns in each line.
This tortuous diverter line routing and valve arrangement common to floating rig
installations has been a contributing factor to plugging and erosion problems during
diverter operation. Since the lines are prone to erosion, it is important to verify the wall
thickness at potential erosion and corrosion points in the diverter lines prior to accepting
the rig or if the wall thickness is suspect.
Diverter lines on drillships typically have fewer turns than semisubmersible rigs since the
design of the ship allows the lines to be routed straight overboard (port/starboard)
beneath the rig floor.
In addition to the large diverter and flowline(s) attached to the diverter housing, the
housing also has connections for the trip tank and fill-up lines. During a diverting
operation, either a check valve or a remotely actuated valve that closes when the
diverter is actuated is used to prevent back flow into the trip tank and fill-up lines. The
auxiliary lines for the trip tank and fill-up are also permanent lines.
Another line that is tied into the piping from the diverter housing is the mud bucket return
line. To simplify the system and prevent the need for another isolation valve, the mud
bucket return line is typically connected to the flowline downstream of the flowline
(shaker) valve.

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9.15.7 DIVERTER VALVES

There are two basic types of valves used for diverter systems on floating rigs, a guillotine
knife valve and a ball valve (Figure 9.41).

Ball Valve

Guillotine Knife
Valve

Figure 9.41 Ball and Guillotine Knife Type Diverter Valves

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Ball valves are preferred in the flowline, and the diverter lines and are typically found on
floating rigs built or upgrades after the mid 1990s. The ball valve is preferred because it
provides a full open, non-restricted flow path with a quarter-turn actuation and can easily
be fitted with failsafe hydraulic actuators. Hydraulic actuators for ball valves are typically
designed for 1500 psi operating pressure and are preferred due to their reliability and
quick response. The hydraulic valve actuator for the ball valve is also generally smaller
than the pneumatic actuator on knife valves since it operates at a higher supply pressure
and does not require the piston travel. The BOP accumulator system is normally used to
provide the hydraulics to the actuators via independent pressure regulators for the
diverter system.
The guillotine knife-type valve was installed quite extensively on third generation and
earlier rigs and is still common on floating rigs today. The working pressure of the
guillotine knife-type valves is typically 150 psi and is acceptable for use, but not
preferred because of the low-pressure seal mechanism, the exposed gate feature and
the split-body design.
The split-body design may allow the fluid to leak external to the valve body. The knife
valve is also generally equipped with a low-pressure pneumatic actuator that may not
provide the force required to actuate the valves with high differential pressure. Air
actuators are normally designed for 80 to 120 psi operating pressure and are generally
much larger and require more maintenance than hydraulic actuators. If rig air pressure
drops below the minimum air pressure requirement to the actuator, the actuator torque
could be reduced and the valve may be slow opening or not fully opened. Pneumatic
actuators for guillotine knife valves typically do not have a failsafe feature to ensure that
the valve fails to the correct position should control pressure be lost.
Actuators should be sized to operate the ball and knife valves with the minimum rated
working pressure of the system applied across the valve. For example, if the diverter
system is rated as a 300-psi system, the actuators should be capable of operating the
valves against 300-psi pressure.
Butterfly valves are not acceptable in diverter installations since they are not full
opening. API gate valves are acceptable but are seldom used because of their costs,
large size and the large space necessary for installation and repair.
The shaker (flowline) valve should be installed upstream of all low-pressure equipment
such as flo sho, in-line gas sensor, mud bucket return line, and mudlog equipment to
protect the equipment during a diverting operation.

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9.15.8 UPPER BALL JOINT OR FLEX JOINT

The Regan DR ball joint is commonly used and provides pressure integrity by a grease
seal between two o-rings in the close-tolerance metal-to-metal area between the ball
joint. The DR ball joints are normally 500 psi rated working pressure.
A low-pressure flex joint is also commonly used as an alternative to the
mechanical/grease seal type ball joint. The enclosed flexible coupling typically consists
of four nitrile rubber elements, molded around spherical shaped steel segments that
react to the alternating tension and compression forces from the slip joint. The flex joints
are available in various tensile capacities with pressure ratings up to 2000 psi.
S e e S e ctio n 1 0 o n R ise rs fo r a d d itio n a l in fo rm a tio n o n B a ll/F le x Jo in ts.
9.15.9 RISER SLIP JOINT
The riser slip joint packers are a critical component of the floating rig diverter system.
The packers provide a dynamic seal between the inner telescoping riser joint below the
diverter and the outer telescoping top joint of the riser. Slip joint packers are generally
designed for 500-psi pressure in a static mode (i.e. no vessel heave). The packer
working pressure limit will be less in a dynamic operating mode due to packer age, slip
joint pipe conditions, and riser service. To provide for redundancy and allow backup
during diverter operations, riser slip joints are typically equipped with dual packers.
Actuating the lower slip joint packer may be sequenced with the Close-Divert control
logic or it may be an independent regulator control operation on the control panel.

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9.15.10 RISERS
The drilling riser acts as the primary conduit between the drilling vessel and the well,
with the diameter of the riser sized to be compatible with the desired BOP/wellhead
system. The most common drilling riser size contains a nominal tube OD of 21 in. and a
0.625 in. wall. Riser sizes vary with in size and yield from wall thickness of 0.50 to 1.125
in. with pipe outside diameter from 20 in. to 22 in. and yield up 80 ksi.
For additional information on Risers and Slip Joints, see Section 10.

9.15.11 DIVERTER CONTROL SYSTEM

The diverter control system may be a self-contained system or may be a separate, but
dedicated part of the BOP control system. The most common method is to have
dedicated controls and accumulator bottles supplied by the same reservoir and pumps
from the BOP control system. When a combined BOP/Diverter control system is used,
the diverter accumulator capacity is typically isolated with a check valve to prevent loss
of the BOP capacity if the diverter system becomes depleted or inoperative. The diverter
control system is sized to actuate the diverter line valves, the flowline valve, the auxiliary
line fill-up valve (if controlled) and the diverter packer in less than 30 seconds.
Diverter control panels are typically located at each BOP control station (Drill floor,
Toolpusher office and main accumulator unit) with the remote panels electrically
operated.

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9.15.12 DIVERTER ACTUATION

The diverter packer should not be closed until:
1. The diverter lock down dogs are in the lock position.
2. The insert lock down dogs are in the lock position (KFDS diverter).
3. The flow line seals are energized.
Since diverter control systems vary depending on manufacturer, contractor, rig design,
and era in which they were built, the controls for diverters vary from a fully-automated
system that sequences the operations of all diverter components to a fully-manual
system where the operator must actuate each item in the correct sequence. The
primary goal, in either case, is to ensure that the system is never fully shut-in when the
diverter is actuated.
The diverter control system must be sequenced to normally operate so that the well will
not be shut in by the diverter. A typical diverter sequence is as follows:
1. Open diverter line valve direction of flow is pre-selected.
2. Close shaker (flowline) valve and trip tank return line valve if equipped.
3. Close trip tank/fill-up line valve, if included.
4. Close riser mud gas separator line valve, if included.
5. Close diverter packer, increased pressure to slip joint packer.
6. Change direction of flow if required (manual function not part of a sequenced
function).
If an automated system is used to sequence and close all of the functions, it is important
that feedback is included to verify the actuation of each function before the next function
is actuated. Systems that use a timed sequence between each actuation may allow the
system to be fully closed-in should a function not actuate or actuate slower than the
sequenced time.
Regardless of the control method used, a diverter function and flow test should be made
with the system immediately after installation to verify correct actuation of all
components and that all lines are free of obstructions.

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9.15.13 AUXILIARY EQUIPMENT ASSOCIATED WITH DIVERTER

OPERATIONS
On some newer or upgraded rigs, the mud returns from the riser has been connected to
a mud gas separator to allow mud with high gas or small gas bubbles that may be in the
mud to be routed through the degasser. On some rigs, this connection is made to the
regular mud/gas separator, and other rigs have installed a separator mud/gas separator
dedicated to the riser. The riser mud gas separator has been used for the following:
Circulate out high drill gas to prevent dangerous levels of gas on the rig floor or in the
shaker room.
Circulate returns after opening the BOPs following a well kill operation to prevent any
trapped gas that may been released off of the rig floor without having to divert the
mud overboard.
Handle high levels of gas in oil base mud without having to divert any of the mud
overboard. As oil base mud is circulated to the surface, gas in solution may be
released when it reaches its bubble point causing a rapid expansion.
Note: If the riser mud/gas separator is used to circulate out high drill gas with the BOPs
open, then the returns from the mud/gas separator typically bypass the flo-sho and may
also bypass the gas trap at the shakers. Kick detection and rapid gas expansion while
circulating in this configuration will be difficult with these sensors bypassed.

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REFERENCES
1. IADC Deepwater Well Control Guidelines: First Edition, October 1998
2. E xxo n C o m p a n y In te rn a tio n a l F lo a tin g D rillin g B lo w o u t P re ve n tio n a n d W e ll C o n tro l
E q u ip m e n t M a n u a l; R e visio n 1 , 1 9 9 7
3. W e st D e e p w a te r C h a lle n g e s S e m in a r M a n u a l; Ju ly 2 7 -28, 2000
4. C a m e ro n C o n tro ls B a sic O p e ra tio n M a n u a l fo r th e M a rin e 7 0 0 D rillin g R ig ;
Volumes 1, 2 and 6, Revision B01, July 2001

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RISER SYSTEMS

10
Section

RISER SYSTEMS

OBJECTIVES
On completion of this lesson, you will be able to:

Given a diagram, identify the principal components of the riser system

State the maximum allowable ball/flex joint angles for drilling and
non-drilling conditions

Identify conditions when the riser should be disconnected

Identify the most important parameter in normal riser operation

Identify the major components of the diverter system and describe how it
operates

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CONTENTS Page

10.0 RISER SYSTEMS ................................................................................................................................. 1

OBJECTIVES ....................................................................................................................................... 1
CONTENTS .......................................................................................................................................... 2
10.1 GENERAL DESCRIPTION ................................................................................................................... 3
10.2 RISER SYSTEM COMPONENTS......................................................................................................... 3
10.3 LOWER FLEX/BALL JOINT ................................................................................................................ 6
10.4 DRILLING RISER ................................................................................................................................. 7
10.5 RISER CONNECTORS ........................................................................................................................ 8
10.6 BUOYANCY ....................................................................................................................................... 11
10.6.1 SYNTACTIC FOAM MODULES ........................................................................................ 111
10.6.2 AIR CANS ............................................................................................................................ 13
10.7 CHOKE AND KILL LINES, AUXILIARY LINES ................................................................................. 14
10.7.1 CHOKE AND KILL LINES ..................................................................................................... 14
10.7.2 RIGID HYDRAULIC CONDUIT LINE ..................................................................................... 14
10.7.3 MUD BOOST LINE ................................................................................................................ 14
10.7.4 RISER BOOST LINE TERMINATION JOINT ........................................................................ 15
10.7.5 RISER FILL-UP VALVE ........................................................................................................ 16
10.8 TELESCOPING (SLIP) JOINT ........................................................................................................... 18
10.9 RISER TENSIONERS ......................................................................................................................... 19
10.10 UPPER BALL/FLEX JOINT/DIVERTER ASSEMBLY ....................................................................... 20
10.10.1 UPPER FLEX/BALL JOINT ................................................................................................ 20
10.10.2 DIVERTER ASSEMBLY ...................................................................................................... 21
10.11 RISER ANALYSIS .............................................................................................................................. 23
10.11.1 GENERAL ........................................................................................................................... 23
10.12 RISER TENSIONING CRITERIA ........................................................................................................ 27
10.12.1 STABILITY CRITERION ...................................................................................................... 27
10.12.2 LOWER RISER ANGLE CRITERION .................................................................................. 28
10.12.3 UPPER RISER ANGLE CRITERION ................................................................................... 28
10.12.4 STRESS CRITERION .......................................................................................................... 28
10.12.5 OTHER CONSIDERATIONS & ANALYSIS......................................................................... 29
10.12.6 TYPICAL GOVERNING CRITERIA ..................................................................................... 30
10.13 EXAMPLE RESULTS FROM ANALYSIS ....................................................................................... 31
10.13.1 MINIMUM TENSION MANUAL CALCULATION ................................................................. 32
10.14 RISER OPERATIONS ........................................................................................................................ 34
10.14.1 RISER SPACE-OUT ............................................................................................................ 34
10.14.2 RUNNING THE BOP, LMRP & RISER ................................................................................ 35
10.14.3 LANDING THE BOP STACK ............................................................................................... 39
10.14.4 INSTALLED RISER OPERATIONS & MONITORING ......................................................... 41
10.15 EMERGENCY DISCONNECT & HANG-OFF ..................................................................................... 42
10.15.1 RISER RECOIL ................................................................................................................... 42
10.15.2 RISER HANG-OFF .............................................................................................................. 42
10.16 HIGH CURRENT OPERATIONS ........................................................................................................ 44
10.17 REFERENCES ................................................................................................................................... 46

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10.1 GENERAL DESCRIPTION

In offshore drilling operations, the drilling riser system forms a large diameter conduit
between the BOP at the seafloor, and the drilling vessel. It extends the wellbore and acts
somewhat like a long bell nipple, permitting the use of relatively conventional drilling
methods from a floating rig. Attached to the riser are the high pressure choke and kill
lines that provide a conduit from the BOPs to the choke manifold on the surface.

10.2 RISER SYSTEM COMPONENTS

Figure 10.1 is a schematic of a typical drilling riser system with the major components
(from bottom to top):

Figure 10.1 Riser System Overview

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RISER SYSTEMS

LOWER MARINE RISER PACKAGE (LMRP)

The LMRP provides a means of disconnecting the drilling riser from the BOP using a
hydraulically actuated connector. When the riser is disconnected, the BOP remains in
place to ensure the well remains secure. The LMRP includes one or two annular
preventers, as well as the BOP control pods and the lower flex joint. Information on the
L M R P e q u ip m e n t is in clu d e d in th e W e ll C o n tro l E q u ip m e n t S e ctio n o f th is m a n u a l.

LOWER FLEX/BALL JOINT

This is a hinge mechanism that allows the riser to deflect from vertical. Either a flex joint
or a ball joint may be used, but a flex joint is more common. The flex joint accommodates
lateral movement of the drilling vessel, as well as movement of the riser caused by
environmental loading. Surrounding the Lower Flex Joint are flexible choke, kill, and
hydraulic lines.

AUXILIARY LINES AND HOSES

To accommodate for the movement of the riser and the vessel heave and offset, flexible
hoses and/or flexible steel piping is used to connect the auxiliary lines on the riser to the
LMRP and the rig. High pressure hoses will always be used for the connect from the riser
to the rig at the surface with hoses or flexible steel piping used to make the transition
around the flex/ball joint at the LMRP.

RISER TERMINATION JOINT

The riser termination joint is a short riser joint that provides a transition from the mud
boost line to the bore of the riser joint. Typically installed directly above the LMRP to
allow additional circulation and flow through the riser.

RISER JOINTS
Individual riser joints are run from the lower flex joint through the water column. Riser
joints are equipped with choke and kill lines and may also be equipped with a hydraulic
conduit and/or mud boost line. Some riser joints may be equipped with buoyancy to
reduce the overall in-water weight of the riser.

PUP JOINTS
Shorter versions of the riser joints, pup joints allow the riser to be precisely spaced out for
the water depth at the well location. Pup joints are not equipped with buoyancy.

FILL-UP VALVE
The fill-up valve allows the riser to be rapidly filled with seawater to prevent riser collapse
if the drilling fluid begins to evacuate the riser (generally not recommended for use in
ExxonMobil operations).

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INTERMEDIATE FLEX JOINT

The Intermediate Flex Joint, when used, is installed between the slip joint and the first
joint of riser below the slip joint. Intermediate flex joints are used on drill ships where slip
contact with the moonpool/ship is a concern during a drive off/drift off. When an
intermediate flex joint is used, the hoses to the auxiliary lines will connect to the
termination joint below the middle flex joint instead of the slip joint.

TELESCOPIC JOINT
Often referred to as a Slip Joint, it attaches the upper-most riser joint to the rig. The
Telescopic Joint compensates for riser length variation due to vessel heave and offset.
The Telescopic Joint is composed of an inner barrel (upper section) and an outer barrel
(lower section). Riser tensioners on the rig are attached to the outer barrel and allow the
riser to be supported in tension to prevent buckling. The inner barrel is attached directly
to the rig at the upper flex/ball joint, and strokes in and out of the outer barrel as the rig
moves.

TENSIONER RING
A solid circumferential support ring called the Tensioner Ring has all of the tensioner
cables pre-attached and is stored beneath the diverter. The riser is run through the
support ring, and the ring is latched to the slip joint prior to landing the BOP stack.
The tensioner ring can be nonrotating or rotating for use with a D/P rig.

RISER TENSIONERS
Riser tensioners allow constant tension to be applied to the riser while allowing for rig
heave.

UPPER FLEX/BALL JOINT

The inner barrel of the Telescopic Joint is usually attached to the diverter housing using a
ball joint/flex joint, which allows angular rotation at the top of the riser.

DIVERTER
The diverter housing allows the drilling fluid returns to be directed to the mud pits. It also
has an element that allows the top of the riser to be closed so that gas/mud returns can be
safely diverted overboard through large diameter vent lines in the event gas is allowed to
enter the riser.

Each of the components above the BOP is an integral part of the drilling riser system.
The various drilling riser system components are described in more detail below.
Sketches of major components or subassemblies are provided.

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RISER SYSTEMS

10.3 LOWER FLEX/BALL JOINT

Since the subsea wellhead and BOP are fixed while the drilling vessel is continually
moving, a lower flex/ball joint is required to allow movement of the riser from vertical, and
reduce the bending moment on the lower end of the riser. The lower flex/ball joint is
usually an integral part of the LMRP.
Industry initially favored a ball joint, which is a sealing ball and socket arrangement that
allows the riser up to 15o of angular rotation at that point. Because there is relative
movement between the ball and socket, routine maintenance is required to ensure
pressure integrity and low rotational torque.
Ball joints work satisfactorily in shallow water. However, in greater water depths,
increased pressure differential across the ball joint (due to the difference in density
between the mud in the riser and the surrounding seawater) results in increased torque to
cause rotation. This results in additional loading of the dynamic seals and increased
bending loads. Some ball joint designs utilize a pressure balance system to equalize
internal and external pressure in order to maintain a moment-free connection and reduce
bearing forces between ball joint faces. A pressure balance system increases the
pressure on the seawater side of the seals to that created by the hydrostatic head of the
mud column within the riser. This equalizes the pressure across the ball joint seals, which
reduces the load necessary to cause rotation. The ball joint pressure balance system
must be adjusted with changes in
mud weight.
To eliminate problems with ball
joints (i.e. leaking seals, adjusting
balance pressure whenever mud
weight is changed), the flex joint
is currently the preferred
approach used for deepwater
drilling riser systems. Figure
10.2 shows a cross-section of a Flex Joint
flex joint assembly. Flex joints Housing
are passive units that use rubber Elastomer
and steel composites to allow Element
rotation. Flex joints do not
provide a moment-free
connection, but moments are
small and the resistance to
change in angle can actually be
beneficial for minimizing the flex
joint angle. Most flex joints have Figure 10.2 Oil States Flex Joint
a mechanical stop at 10 of bend.

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RISER SYSTEMS

10.4 DRILLING RISER

The drilling riser acts as the primary conduit between the drilling vessel and the well, with
the diameter of the riser sized to be compatible with the desired BOP/wellhead system.
The most common drilling riser size contains a nominal tube OD of 21 in. and a 0.625 in.
wall. Riser sizes vary with in size and yield from wall thickness of 0.50 in. to 1.125 in.,
pipe outside diameter from 20 in. to 22 in. and yield up 80 ksi. Decreasing OD and/or wall
thickness will reduce submerged system weight and reduce tensioner requirements.
Thicker wall and higher yield strength riser pipe is found in deepwater applications where
collapse and tensile loading is greater.
Standard riser joints range between 50-7 5 fe e t in le n g th , d e p e n d in g o n th e rig s h a n d lin g
capabilities. Longer riser joints minimize the number of connections within the riser string.
Reducing the number of connectors enhances pressure integrity, reduces the overall
weight and tensioner requirements, reduces riser deployment time, and reduces the
overall cost. Pup joints allow appropriate riser space-out for the water depth. Pup joints
are generally supplied in lengths from 10-40 ft, in 5-ft increments.

Figure 10.3 Typical Riser Joint without Buoyancy

A typical drilling riser joint consists of the following components (Figure 10.3):
riser main tube
connectors
auxiliary lines (choke, kill, mud boost, hydraulic conduit)
buoyancy
Since the BOP isolates wellbore pressure, the riser is not generally considered as a high-
pressure containment component. However, pressure integrity is important since the
hydrostatic pressure of the mud in the riser is greater than the seawater pressure outside
the riser. This pressure differential becomes pronounced as illustrated in the Table 10.1
for varying water depth and mud weight increases.

Differential Pressure Between Seawater and Mud Weights

Listed for Various Water Depths
Water Depth
(feet) 10.0 ppg 12.0 ppg 14.0 ppg 16.0 ppg
2000 156 364 572 780
4000 312 728 1144 1560
6000 468 1092 1716 2340
8000 624 1456 2288 3120

Table 10.1 Differential Pressure exerted on Riser

Loss of pressure integrity in the riser can cause the wellbore to be underbalanced since
the riser may contain a significant amount of the total hydrostatic pressure.

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RISER SYSTEMS

10.5 RISER CONNECTORS

Riser joints are connected using specialized mechanical connectors. Figure 10.4 shows
two typical designs flange and dog types. Design configurations vary according to the
supplier, but the designs share common features. The connector forms a structural and
pressure tight connection with sufficient strength to handle tension, bending, shear,
and pressure separating loads. To facilitate riser deployment and retrieval, the riser
connectors are designed for rapid makeup and breakout and to simultaneously
makeup the auxiliary lines.

Figure 10.4 Flanged and

Dog Type Riser Connectors

The lower half of the connector also forms a landing shoulder for hang-off of the drilling
riser system during installation and retrieval of the BOP stack. This hang-off provision is
im p o rta n t in d e e p w a te r w ith la rg e B O P s sin ce th e rise rs h a n g in g w e ig h t a n d th e re su ltin g
dynamic loading can be significant, and the support shoulder must be able to handle
such conditions.

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RISER SYSTEMS

Generally, riser end connections are preloaded designs. Methods to achieve preloaded
conditions vary between different suppliers. A preloaded connection is one in which the
co n n e ctio n s m e ch a n ica l fo rce s, o n p ro p e r m a ke -up, exceed the range of anticipated
bending, tension, and pressure separating loads. Proper preload prevents large cyclic
stresses in the connection and its premature fatigue failure.
Tensile capacity for riser coupling is defined by API Spec 16R in Table 10.2:

API Class Tensile API Class Tensile Capacity

Capacity millon/lbs
millon/lbs
A 0.5 D 1.5
B 1.0 E 2.0
C 1.25 F 2.5

Table 10.2 Riser Coupling Tensile Capacity

A seal subassembly or seal sub located between the flanges provides pressure integrity.
By using a separate seal sub, rather than an integral seal, change-out of a leaking riser
joint is quick and easy during running operations without having to replace an entire joint.
This is usually a field-replaceable insert equipped with elastomeric seals, however metal-
to-metal seals are also available. In addition, if a seal pocket within a flange is damaged,
then special seal subs are usually on-hand utilizing elastomeric seals in different locations
to bridge the damaged area(s) within the seal pocket.
The most common connector for a deepwater application is a flange connection like that
shown in Figure 10.6. Makeup of flange connections typically requires the use of large
bolts to ensure proper connection preload. Preloading ensures pressure and structural
integrity, and fatigue resistance. Most designs of this type have replaceable bolts and
nuts so that damage to threads can be quickly and easily handled at the rig floor.

Seal Sub

Auxiliary Line Seal Subs

Figure 10.6 CIW Flanged Riser Connector

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RISER SYSTEMS

Another common type of riser connector is the dog type, shown in Figure 10.7. Bolts or
screws are used to drive dogs on the box end of the coupling into a profile on the pin end.
Within this design, individual segments are radially preloaded into a mandrel profile on the
other half of the connection. Angled faces on the segments and the mandrel profile
convert this radial loading into axial preloading forces within the connection. Proper
torque applied to each segment actuating screw creates the desired preloaded condition.
As with the flange connectors, this preloaded mechanical connector also creates sufficient
force to resist the separating force of the radial positioned auxiliary lines around the
circumference of the riser string tubular. In some designs, the actuating section of the
connector can be readily removed and replaced at the rig floor should the actuating
mechanism become damaged, thereby allowing running or retrieval operations to
continue.

Figure 10.17 Dog Type Riser Connector

Vetco MR-6

During makeup of the riser joints, all auxiliary lines (choke, kill, mud boost, rigid conduit)
are configured on the riser joints to align and stab when each riser connection is made up.
Auxiliary lines are typically secured to the joint at the riser flange and do not have their
own locking connection. Since the lines do not lock together, all loads from the riser and
BOP stack are supported by the riser flange. In addition, the load that is generated while
pressure testing the auxiliary lines (Table 10.3) is also transmitted to the flange and can
be substantial for large bore choke/kill line systems

Additional Loads from Pressure Testing Choke/Kill

Auxiliary Lines
Line System
Internal Pressure Load For
Diameter Rating Two Lines
Ocean Valiant,
George Richardson 3.0 '' 15000 psi 211,950 lbs
Marine 700, Glomar
Jack Ryan 4.5 '' 15000 psi 476,888 lbs
Table 10.3 Pressure Loads on Choke/Kill Lines

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RISER SYSTEMS

10.6 BUOYANCY
Riser joints may also be equipped with buoyancy to help offset the riser system's
submerged weight. The closer the riser is to neutral buoyancy, the less top-tension is
needed to maintain a vertical position. There are two methods of providing buoyancy,
syntactic foam and air cans.

10.6.1 SYNTACTIC FOAM MODULES

The more common buoyancy option is syntactic foam (Figures 10.8 and 10.9). Syntactic
foam is a fiberglass-jacketed polymer matrix of hollow spheroids. Because the foam has
a lower density than seawater, it creates a positive buoyant force when submerged and
o ffse ts a p o rtio n o f th e rise rs su b m e rg e d w e ig h t. S yn ta ctic fo a m b u o ya n cy m o d u le s a re
attached to the outside of the bare riser, and contain contours to fit around the auxiliary
lines.

Figure 10.8 Riser Joint with Syntactic Foam

Syntactic foam has an in-air weight of 24-to-32-lb/cu ft, is simple, rugged, and finding
wider use for both drilling and permanent production riser installations. Syntactic foam
can be used in deeper applications and does not require air compression equipment that
air cans require. However, the density of the foam to withstand the increased hydrostatic
pressure increases overall weight and deck load.
Syntactic foam is more reliable than air cans and does not require air compression
equipment that air cans require. However, since it provides less buoyancy than the same
volume of air, foam usually results in greater outside diameters and longer coverage
lengths versus the air can approach. The buoyant force generated by the foam must not
exceed the submerged weight of the riser system since the riser string must remain
negatively buoyant to prevent compression when the LMRP is disconnected from the
BOP stack.

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RISER SYSTEMS

Other disadvantages of syntactic foam systems are potential implosion/crushing of the

foam as water depth/hydrostatic pressure increases, water saturation over long periods of
time, and the inability to vary the magnitude of buoyancy supplied to the riser system. To
withstand the hydrostatic pressure of the deeper water depths, the density of the syntactic
foam must increase with increasing water depth. Since the foam is denser, it will provide
less buoyancy and the joint of riser will have more in-water weight than a comparable joint
rated for shallower water. To compensate for this, the outside diameter of the foam may
be increased for the foam with the deeper water depth rating if adequate running
clearance is available at the diverter.
Syntactic foam is typically manufactured with water depth rating from 2000 to 10,000 ft in
1000 ft increments. Water depth rating for the foam is usually denoted by color coding the
modules as illustrated in Figure 10.9.

Color marking indicates water

depth rating for buoyancy

F igure 1 0 .9 S yntactic F oam w ith D ifferent W ater D epth R ating

Generally the foam should be run in the corresponding water depth range to minimize the
top tension required and to prevent water ingress into the foam if it is run too deep.
During the riser analysis, it is essential that amount and location of each type of foam
buoyancy is known so that the correct riser tension curves can be calculated.

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RISER SYSTEMS

10.6.2 AIR CANS

The air can, an external thin-walled cylinder
(Figure 10.10), can be integral or non-
integral to the slick (non-buoyant) riser
system. The air-can, usually open bottomed,
is filled with air after the riser is run. The filled
air cans create a positive buoyant force,
o ffse ttin g a p o rtio n o f th e rise rs su b m e rged
weight. These systems require large volume
air-su p p ly syste m s fo r a ir-u p o p e ra tio n s. In
addition, each can must contain an air-dump
valve to purge the air before riser retrieval.
Compared to buoyancy modules, air systems
are a more weight efficient means of creating
a positive buoyant force. In addition, the
magnitude of buoyancy provided to the
system can be varied if necessary. This can
be an important feature during riser hang-off
when additional weight may be needed at the
bottom of the riser to prevent the riser from
going into compression. Riser buckling may
result from simultaneous down-heave vessel
motion and upward riser motion due their
different natural frequencies. Increasing the
rise rs h a n g in g w e ig h t w ill h e lp p re ve n t th is
situation.
Air cans are very rarely used today for
riser buoyancy.

Figure 10.10 Air Can Riser Joint

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RISER SYSTEMS

10.7 CHOKE AND KILL LINES, AUXILIARY LINES

10.7.1 CHOKE AND KILL LINES

The high-pressure choke and kill lines are attached to each riser joint to allow fluid
circulation in and out of the wellbore when it is isolated by the BOP, and well intervention
and control procedures are required. Choke and kill lines must have the same or higher
pressure rating as the BOP and typically have an internal diameter of three to four inches.
These lines have stab connectors that make-up along with each riser joint and can
experience extreme well-control pressures and separating loads at the connection.
The riser connector must provide the force necessary to resist the pressure-induced
separating forces within the lines.

10.7.2 RIGID HYDRAULIC CONDUIT LINE

The rigid hydraulic conduit is used on some shallow water rigs and all deepwater rigs to
supply hydraulic fluid to the BOP control pods to reduce the BOP closing times. The rigid
conduit line is typically a 2.5 to 3.5 inch internal diameter line constructed of stainless
steel with a working pressure rating of 3000 or 5000 psi depending on the BOP control
system rating. The rigid conduit line is mounted to the riser joint the same as the
choke/kill lines with stab type connectors. During riser deployment, the rigid conduit line
would typically be pressure tested via the BOP control system to prevent over-pressuring
the line.

10.7.3 MUD BOOST LINE

The mud boost line allows mud to be circulated down to the LMRP and into the riser to
increase the annular velocity of the mud returning up the riser. The mud boost line usually
terminates just above the lower flex joint, and includes a check valve or hydraulically
operated valve to prevent the loss of mud should the line develop a leak. A hydraulically
operated valve also allows the line to be tested while running the riser, while a check
valve does not. The internal diameter of the mud boost line is typically three to five inches
with a working pressure of 3000 to 5000 psi.

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RISER SYSTEMS

10.7.4 RISER BOOST LINE TERMINATION JOINT

One method of terminating the riser boost line

into the riser is via a riser termination joint
(Figure 10.11). The riser termination joint is a
short riser joint (typically five ft.) that is run
directly above the LMRP with an outlet from the
boost line into the bore of the riser. The outlet
Check Valve from the boost line to the riser has a removable
target end cap that provides access to a check
valve. The check valve used for the Cameron
termination joint in the illustration to the right is a
standard drill pipe float valve. The termination
joint allows for easier maintenance and repair
since the joint is removed and placed on the
deck each time the riser is retrieved.

Figure 10.11 CIW Termination Joint

Electronic Riser Angle

Indicator Instruments
Another method for
terminating the boost line is
through the riser adapter that
is integral to the flex joint
(Figure 10.12). When the
boost line is terminated on the
riser adapter, it allows for
installation of a gate valve
since it can be used to prevent
u-tubing of mud between the
line and the riser, and it Riser Mud Boost Line Valve
provides a method to test the
line while it is deployed. If a
gate valve is installed on the Connection to Flex Joint
mud boost line, it should be a
failsafe open valve to prevent
the valve from failing to the
Figure 10.12 Integral Riser Adapter with
close position while
Auxiliary Line Terminations
circulating.

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RISER SYSTEMS

10.7.5 RISER FILL-UP VALVE

Situations can occur where partial loss of the mud column creates an external differential
pressure on the riser, leading to potential riser string collapse. The loss of the mud
column can occur for the following reasons:
Lost (returns) circulation.
Emergency disconnect of riser.
Riser evacuation.
Hole in the riser.
The situation most likely to occur is lost circulation. When this happens, the height of the
mud column within the wellbore and riser drops, leaving a section of the riser empty. If
this level reaches a critical depth, the hydrostatic head of the external seawater can cause
riser collapse.
A second situation involves an emergency disconnect on a D/P vessel. During an
emergency disconnect with heavy mud in deepwater, the mud in the riser will drop out and
equalize with the seawater hydrostatic pressure, leaving the upper end of the riser void of
drilling mud. Again, if the drilling mud reaches a critical depth, the hydrostatic head of the
external seawater could cause the drilling riser string to collapse.
A third situation involves a gas kick that causes a displacement of the drilling mud and
temporary loss of the mud hydrostatic head within the riser, and again the external
seawater hydrostatic head could cause the riser to collapse. This is most likely to occur if
gas were released from the BOP stack after a well control circulation or an influx were
allowed to get above the BOP stack before the well was shut-in.
A fourth situation involves riser wear (keyseating). If riser curvature reaches a critical
magnitude, then the rotating drillpipe can wear a hole in the riser. As a result, the
weighted drilling fluid will leak out of the riser, leaving the upper section of the riser empty.
This is most likely to occur at the lower most riser joint(s) or in the flex joint since a
discrete angle occurs at the flex joint. Again, if the mud level drops to a critical depth,
hydrostatic head of the seawater can cause riser collapse.

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RISER SYSTEMS

In an attempt to prevent collapse, a

riser fill-up valve (Figure 10.13)
can be placed within the riser
length. The fill-up valve is
essentially a riser joint with a
sliding sleeve valve that allows
rapid filling of the riser with
surrounding seawater to minimize
the potential pressure differences
between the O.D. and I.D. of the
riser. This sliding sleeve is
normally closed and senses
pressures both inside and outside
the riser. When the external
pressure exceeds the inner
pressure by a predetermined
magnitude, the valve rapidly opens
allowing the surrounding seawater
to fill the riser. The valve is
generally located near the upper
end of the riser. This location is
useful in preventing collapse
caused by lost circulation,
emergency disconnect or riser
Figure 10.13 Cameron Riser Fill-up
wear. However, collapse
Valve/Joint
conditions caused by gas
evacuation require a fill-up valve
close to the location of the interface between the gas bubble and the drilling mud. This
can occur at any point within the riser. The further the fill-up valve is from the point of
instability, the less likely the valve is to sense the pressure differential and open.
Note: ExxonMobil discourages the use of riser fill-up valves because of potential for
leaking and accidental actuation. According to the EMDC Drilling OIMS Manual, an
automatic fill-up valve is required if the riser collapse strength does not meet the riser
collapse criteria listed in Section 10.12.5.

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RISER SYSTEMS

10.8 TELESCOPING (SLIP) JOINT

The telescoping joint (Figure 10.14) permits the
riser to change length to accommodate vessel
motion and rig offsets. The telescopic joint
consists of an inner barrel that is attached to the
drilling vessel at the diverter, and an outer barrel Inner/Outer
that is attached to the top drilling riser joint. The Barrel Lock
outer barrel is supported axially by the riser
tensioning system.
Slip Joint Packers
As the vessel laterally offsets and heaves in
response to environmental conditions, the
telescopic joint extends and retracts. Seals
between the inner and outer barrel ensure fluid
containment as the telescopic joint extends and
retracts. Most slip joints are typically equipped with Tensioner Ring
two sets of seals that can be energized by either
air or hydraulic pressure applied through a hose in
the moonpool. Slip joint packer pressure is usually
kept just above the leak point to minimize the wear
on the packers. To provide for replacement, at
least one packer is split so that it can be installed Gooseneck Connections
with the slip joint in place. Telescopic joints for Choke/Kill Lines
typically have a forty to sixty ft stroke. If vessel
motions are anticipated to exceed this range, then
operations are suspended, the drilling riser is
disconnected at the LMRP, and the riser is hung-
off or pulled to the surface.
Tensioner lines from the riser tensioners are
attached to pad eyes or a landing ring on the outer
barrel of the telescopic joint. On dynamically
positioned rigs, the tension ring is designed to
rotate around the outer barrel so that the vessel
heading can be changed without rotating the riser.
In deeper water applications, the tension ring may
include a large thrust bearing to allow easier
rotation.
Surrounding the outer barrel of the telescopic are
attachment points for flexible jumpers that connect
the auxiliary lines on the riser to their respective
attachment points on the drilling vessel. The
flexible lines are allowed to hang in a catenary
configuration, free to accommodate telescopic joint
length changes and various rig and riser motions.

Figure 10.14 Vetco Slip Joint

Closed Position

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RISER SYSTEMS

10.9 RISER TENSIONERS

Riser tensioners (Figure 10.15) are used to provide a constant tension to the top of the
riser during floating drilling operations. The tension is required to provide structural
integrity and keep the riser from buckling.
Tensioners consist
of hydraulic pistons
pressurized with
compressed air
supplied by air over Air Pressure Vessel
oil accumulators.
Low Pressure Seal
To maintain the
tension as constant Fixed Orifice

as possible, large Accumulator

Air Pressure Air-Oil Reservoir
Vessels (APVs) are 25-40 psi
used to provide the
necessary air
volume during the
travel of the
tensioner while High Pressure Seals
maintaining a
Cylinder
relative constant air
pressure to the
accumulator. Air
acts against the Turn Down Sheave
hydraulic fluid with
Low Pressure Air
relatively constant High Pressure Air
Low Pressure Oil
pressure over the High Pressure Oil
stroke of the
tensioner. The Figure 10.15 Typical Riser Tensioner System
pistons engage
sheaves with wire
ropes that attach to the outer barrel of the telescopic joint. Tensioners typically have a
12.5-ft stroke, and the wire rope is sheaved to accommodate 50 ft of slip-joint travel.
Large turndown sheaves underneath the substructure are used to route the tensioner line
down toward the outer barrel of the telescopic joint. The turn down sheave is positioned
as close as possible to the riser to minimize the angle from vertical. This angle is referred
to as the fleet angle and increases as the rig heaves downward. As the fleet angle
increases, the vertical component of tension applied to the riser decreases.
The wire rope must be slipped or replaced on a regular basis due to fatigue as it passes
over the sheaves. The frequency will depend on the severity of the seastate and the riser
tension required.

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RISER SYSTEMS

10.10 UPPER BALL/FLEX JOINT/DIVERTER ASSEMBLY

The diverter and the upper ball/flex joint are usually an integral part of the upper end of
th e te le sco p ic jo in ts in n e r b a rre l. T h e d ive rte r/u p p e r jo in t a sse m b ly lands and locks into a
diverter housing located below the rig floor. The diverter housing, a structural section of
the drilling rig, is attached to mud tank return lines and the flare vent lines. Figure 10.17
illustrates a diverter and upper ball joint assembly.

10.10.1 UPPER FLEX/BALL JOINT

An upper flex/ball joint, like the lower one, accommodates lateral movement of the drilling
vessel and prevents bending failure at the upper end of the riser. Like the lower flex/ball
joint, the upper one provides rotational motion while maintaining wellbore access and mud
column containment. These are also usually ball or flex joints providing up to 10-degrees
of freedom. The functional requirements and design features of this joint are similar to
those mentioned for the lower flex/ball joint, but the upper joint is not required to
withstand a large pressure differential, therefore pressure compensation is not
necessary. Figure 10.16 shows an upper ball joint.

Figure 10.16 Typical Upper Ball Joint

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RISER SYSTEMS

10.10 DIVERTER ASSEMBLY

The diverter assembly is located at the top of the riser, attached to the top of the upper
flex/ball joint. The diverter housing is rigidly attached to floor beams on the underside of
the rotary table and supports the weight of the diverter package and the inner barrel. The
diverter package consists of a hydraulically actuated element that seals around drill pipe.
When actuated, the diverter causes gas & mud flows to be diverted overboard. The riser
is not designed as a pressure containment device, and to prevent significant over
pressuring, the diverter system is designed so that on activation, the flowlines lines are
opened before the bag element is closed.

Figure 10.17 Typical Diverter System

Regan KFDS Type

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RISER SYSTEMS

During normal drilling operations, the diverter, shown in Figure 10.17 and 10.18, directs
drilling fluid from the telescop in g jo in t to th e m u d p its. In th e ve rtica l b o re s o p e n p o sitio n ,
the fluid exits through lateral ports (flowline) that are piped to the mud pits. If there is an
unexpected abrupt mud or gas flow into the drilling riser, the diverter system [diverter,
flowline valve(s), and overboard diverter line valve(s)] redirects the flow to the overboard
line and closing in around the drill pipe. The diverter usually contains multiple large
diameter (12 to 16 in.) lines for handling large volumes of mud flowing up the drilling riser.
If an unexpected flow takes place, these lines are isolated and other lines that lead to
overboard are opened.
During a well control situation, an annular-like element closes the vertical opening in the
diverter, thereby isolating the rig floor and protecting rig personnel. This annular element
allows the diverter to close on a wide range of tubular sizes. The diverter is not intended
to a ct a s a b lo w o u t p re ve n te r, b u t a s a m e a n s o f re d ire ctin g th e flu id s ve rtica l flo w fo r sa fe
discharge. To prevent significant pressurization, diverter systems are designed such that
activation causes the vent lines to open. At the same time, the bag element and flowline
are closed. The diverter sits in a diverter housing that is a structural part of the drilling rig
directly beneath the rotary table.

Locking dog to secure

diverter into housing

Diverter Seals
Trip Tank Pump Inlet

Upper ball/flex joint attached

Flowline Outlet

Figure 10.18 Full Opening Diverter System

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RISER SYSTEMS

10.11 RISER ANALYSIS

10.11.1 GENERAL
The riser is subjected to various forces that cause it to deviate from vertical and since it
essentially gains all of its structural integrity from tension, the single most important
parameter in operation of the system is top tension. Insufficient top tension can result in
operational problems associated with riser curvature, large flex joint angles, or even
buckling. Tensioning the riser will reduce the curvature and flex joint angle, however too
much tension produces high stresses in the riser that can result in reduced fatigue life and
increased maintenance to the riser and the tensioning system.
To determine the proper tension for the various mud weights during the well, a riser
analysis is performed based on the following parameters:
Water depth.
Mud weight.
Wave and current environment.
Riser properties.
Vessel Offset.
Prior to the riser analysis, detailed specifications of the riser components should be
obtained from the Contractor or Manufacturer to provide buoyancy and in-water weights.
Table 10.4 low is an example of riser specifications for the Glomar Jack Ryan riser.

Unit Weight in Air Unit Weight in Seawater

Outside Buoyancy Buoyancy
Description Diameter Steel lbs lbs Total Steel lbs lbs Total
Riser Jt. 75 ft,
1 .1 2 5 w a ll 3 0 0 0
ft buoyancy 55.5 35975 22000 57925 31150 -30330 820
5000 ft buoyancy 56.5 35975 24525 60500 31150 -30565 585
7500 ft buoyancy 59.0 35975 31025 67000 31150 -30335 815
10000 ft buoyancy 60.0 35975 34825 70800 31150 -27920 3230
Riser Slick Jt, 7 5 ,
1 .1 2 5 w a ll 35.0 36025 36025 31340 31340
Riser Slick Jt, 5 0 ,
1 .1 2 5 w a ll 35.0 25775 25775 22245 22425
Riser Slick Jt., 4 0 ,
1 .1 2 5 w a ll 35.0 25125 25125 21860 24860
Riser Slick Jt., 2 0 ,
1 .1 2 5 w a ll 35.0 15175 15175 13200 13200
Riser Slick Jt., 1 5 ,
1 .1 2 5 w a ll 35.0 12693 12693 11041 11041
Riser Slick Jt., 1 0 ,
1 .1 2 5 w a ll 35.0 10210 10210 8881 8881
Slip Joint Outer
Barrel 35.0 76760 76760 66704 66704
Tension Ring 35.0 39895 39895 39895 38895
LMRP 35.0 225600 225600 196046 196046
BOP Stack 35.0 500700 500700 435108 435108

Table 10.4 Glomar Jack Ryan BOP & Riser Weights

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RISER SYSTEMS

With the riser information listed above and the water depth at the location, a riser joint
arrangement can be prepared to establish the weights for the required riser configuration.
A number of comprehensive computer programs have been developed to model riser
behavior and determine the riser angles and stresses associated with a prescribed set of
parameters or operating conditions. These angles and stresses are compared to a set of
empirically based limits, or criteria on the stresses and angles, and are used to establish
the recommended riser tension using an iterative analysis that requires vessel offset as an
input. A mooring analysis or station-keeping analysis is required to determine the
appropriate vessel offsets to input to the riser analysis.
In areas with a severe environment, deepwater, or when operating with a D/P rig, a
co u p le d a n a lysis may be performed to include bending loads throughout the entire riser
system including the BOP stack, wellhead, and structural/conductor casing. This analysis
accounts for bending from the BOP stack down through the conductor casing taking into
account soil strengths, whereas the normal riser analysis assumes the BOP stack is a
fixed point.

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RISER SYSTEMS

RISER LOADS DURING FLOATING DRILLING OPERATION

WI
N
D

WAVE
FORCES

C
BOUYANCY TENSION PULLED
U F
R O ON RISER BY VESSEL
R R
E C VESSEL OFFSET
NTES

WEIGHT OF MUD,
RISER AND DRILLSTRING
IN RISER (IF ANY)

API RP 16Q Buckling (Stability) Criterion:

Tmin = TSRmin N / [Rf (N-n)]
where:
TSRmin = minimum slip ring tension
N = numbers of tensioners supporting the riser
n = number of tensioners subject to sudden failure
Rf = Fleet angle and mechanical efficiency factor (0.9
0.95)
Tmin = minimum tension to avoid effective compression at
the lower flex joint.
Tsrmin = Minimum slip ring tension
Tsrmin = Ws*Fwt Bn*Fbt+Ai[Dm*Hm-Dw*Hw]
where:
Ws = submerged riser weight
Fwt = submerged weight tolerance factor (API
recommends 1.05 unless accurately weighed)
Riser Loads (Tension & Axial forces) Bn = net lift of buoyancy material
applied at lower ball joint Fbt = buoyancy loss and tolerance factor (API
recommends 0.06 unless accurately known)
Ai = internal cross section area of riser including choke,
kill, and auxillary lines.
Dm = mud density
Rig BOP Stack and LMRP
Hm = mud column height (from flowline to lower flex joint)
Dw = seawater density
Hw = seawater column height (to lower flex joint)
Horizontal Subsea X-mas Tree

Wellhead stick-up above visible mudline WELLHEAD/STRUCTURAL

CASING ANGLE

Depth of Soil with zero/min. strength

Figure
Figure 10.18
10.19 RiserLoads
Riser Loads During
During Drilling
DrillingOperations
Operations

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RISER SYSTEMS

It is essential that upper and lower joint angles remain below specified values to prevent
damage to the riser, LMRP, BOP and casing strings. Damage to these items can result in
loss of pressure integrity and subsequently well control. To maintain riser integrity and
ensure safe operations, API recommends maximum design and operating guidelines
including a calculation for Minimum Required Top Tension as represented in Table 10.5.

Design Criteria or Operating Riser Connected Riser

Limit Drilling Non-Drilling Disconnected
Mean Flex/Ball Joint Angle 2.0 deg N/A N/A
Maximum Flex/Ball Joint Angle (upper 4.0 deg 90% of 90% of
and/or lower) available available
maximum maximum
Stress Criteria (static + maximum
dynamic stress amplitude):
Allowable Stress (method A)
40% y 67% y 67% y
Allowable Stress (method B)
Significant Dynamic 67% y 67% y 67% y
Stress Range:
@ S A F 1 .5
@ SAF > 1.5 10 ksi N/A N/A
15/SAF N/A N/A
Minimum Top Tension Tmin Tmin N/A
Dynamic Tension Limit DTL DTL N/A
Maximum Tension Setting 90% DTL 90% DTL N/A

Table 10.5 Riser Operating and Design Guidelines

y is the riser pipe yield stress

SAF is the Stress Amplification Factor, defined as the ration of the local peak
alternating stresses to the nominal alternating stress in the pipe wall.
DTL is the Dynamic Tension Limit, defined as the vessels maximum tensioning
capability

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RISER SYSTEMS

10.12 RISER TENSIONING CRITERIA

Four basic tensioning criteria have been developed, largely based on operational
experience, as a basis for selecting the minimum riser top tension. Checks with all four
criteria are made to determine the minimum riser top tension. These general criteria are
used throughout industry with some variation in the values chosen.
The four criteria are:
Stability or buckling
Upper riser angle
Lower riser angle
Stress

10.12.1 STABILITY CRITERION

The stability (or buckling) criterion is based on a simple concept: having a large length-to-
diameter ratio, the riser will be susceptible to buckling if the entire riser is not kept in
tension. The tension necessary to prevent buckling depends on the total in-water weight
of the riser, including mud, therefore the tension requirements increase with both longer
risers and higher mud weights. Additional tension over the minimum to prevent buckling
is applied to compensate for fluctuation due to vessel motions, and to provide reserve in
case a tensioner line fails.
The tension setting to meet the stability requirement ( Tmin ) is computed as
Tmin TSR min N /[ R f ( N n)]

where TSR min is the minimum slip ring tension; N the number of tensioners; n the number
of tensioners subject to sudden failure; and R f the fleet angle and mechanical efficiency
factor. For a typical rig with 8 tensioners N = 8, two of which are subject to sudden
failure n = 2, and a fleet angle and mechanical efficiency factor R f = 0.90 then:

Tmin 1.481 TSR min

Note: If the tensioners are connected and operated in pairs, then two tensioners should
be considered for sudden failure. If the tensioners have individual controls and separate
piping, then one tensioner can be considered for sudden failure.

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RISER SYSTEMS

10.12.2 LOWER RISER ANGLE CRITERION

The mean lower riser angle should be kept under 2 and the maximum angle should be
kept under 4 to prevent excessive wear due to pipe movement and rotation in the lower
flex joint and BOP stack. Large angles also make it more difficult to run large diameter
tools such as casing hangers. The 2 limit does not reflect a hard barrier, but a reliable
guide, and every effort should be taken to minimize the angle. Wear is more of a concern
when the drill string weight is high and the sideloading of the drillpipe at the flex joint is
greatest. In operations, the rig position is usually adjusted, if necessary, to keep the angle
less than 1 degree. Rigs are typically equipped with subsea sensors to monitor this angle
continuously.
When drilling is suspended, it is important to keep the peak lower riser angle to less than
90% of the maximum allowable. Most lower ball joints or flex joints have a mechanical
stop at 10, so the allowable angle is 9. When the mechanical stop is reached, high-
bending moments can be transmitted into both the riser and the LMRP.

10.12.3 UPPER RISER ANGLE CRITERION

Riser analysis tensions are selected to keep the mean upper riser angle less than 2 and
the maximum angle should be kept under 4 for the same reasons outlined for the lower
flex joint. In addition, drill pipe and casing makeup becomes more difficult as the upper
ball joint angle increases. The tensioner-induced side loading at the tensioner ring will
increase with the upper riser angle, and will increase wear on the slip joint packing
element. Measurement of the upper angle is difficult since rigs are usually not equipped
with angle instruments at the slip joint to measure the upper ball/flex joint angle and visual
observations cannot detect less than a few degrees.
When drilling is suspended, the maximum upper riser angle limit depends on the
configuration of the rig. At large angles, impact of the riser, choke and kill hoses, or
tensioners with the moonpool is a concern. Significant damage can occur, particularly if
the vessel is heaving when contact is made.

10.12.4 STRESS CRITERION

Stress criteria are well below the yield strength of the riser. Two calculation methods can
be used, but at least one of these criteria must be satisfied.
Method A is suitable for most water depths and is the one typically used by URC. The
allowable stress in the drilling mode is 40% of the yield strength of the riser, and when
drilling is suspended the allowable stress is 67% of the yield strength. In deeper water
depths it may be difficult to satisfy the criteria of Method A due to the high riser tensions.
Method B can be used for deepwater where the riser tensions are high, but the
alternating or dynamic stress may be fairly low. Using Method B, the allowable stress is
67% of the yield strength of the riser for both the drilling and drilling suspended conditions.

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RISER SYSTEMS

10.12.5 OTHER CONSIDERATIONS & ANALYSIS

In addition to the four criteria above, there are several other general considerations for
riser analysis. These considerations include collapse and burst of the riser pipe,
tensioning capacity, Vortex Induced Vibration (VIV) and hang-off analysis.

COLLAPSE
The riser is not generally designed to resist hydrostatic collapse, but this situation can
occur if the riser is evacuated by a large gas influx or by a severe loss of mud (either to
the ocean or downhole). Riser can withstand from 1000 to 4000 ft of evacuation
depending on the wall thickness, diameter and yield strength. The DRILLRISER program
in the standard PC load can be used to determine the void depth at which collapse occurs
for a specific riser and top tension. The OIMS manual requires that riser collapse be
checked against the following criteria:
Unloaded by gas: 50% evacuated (but maximum evacuation of 1500 ft)
with 9 ppg mud below
Hole in riser at bottom: the heavy mud in riser equalizes with seawater
and leaves the upper section of the riser void,
void depth = water depth x (1.0 8.5/max. mud density)

BURST
The riser is subject to burst loads imposed by the pressure differential between the
internal mud and external seawater. Although burst should be checked, particularly in
deepwater, these loads are usually well within the burst capacity of the riser pipe.

TENSIONER CAPACITY CRITERION

The minimum required tension should not exceed 90% of the total available tension
capacity.

VIV ANALYSIS
In high current situations, analysis for VIV should be performed by URC. This analysis will
determine if VIV is likely to occur and what the expected fatigue life of the riser will be. If
VIV damage potential is too high, it is possible to run VIV suppression devices. See
Section 10.16 for VIV suppression devices.

HANG-OFF ANALYSIS
The particular hang-off configuration for a rig should be modeled to determine if the rig
and riser motion could cause significant dynamic effects, or bucking at the top of the riser.
If problems are indicated, there may be preventive measures available such as altering
the suspended weight of the riser (e.g. trapping mud in the riser on disconnect).

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RISER SYSTEMS

10.12.6 TYPICAL GOVERNING CRITERIA

SHALLOW WATER DRILLING

In shallow water (<1000 ft) the ability of the mooring system to hold the rig on location
usually dominates the riser analysis. For typical drilling operations, predicted vessel offset
must be limited to achieve the required limit on the lower riser angle.

DEEPWATER DRILLING
In d e e p w a te r, th e rise r w ill n e e d b u o ya n cy a n d th e rig s te n sio n in g ca p a city w ill h a ve to b e
high, especially with high mud weights. The high tension may result in high stress and
necessitate the use of the Method B for the stress evaluation. Riser collapse is also more
of a concern in deepwater.

HIGH MUD WEIGHT MUD

In deepwater, high mud weights will increase the riser sag and require additional top
tension to limit the lower riser angle.

HIGH CURRENTS
High currents increase the upper and lower riser angles and vessel offset must be more
carefully controlled. Higher riser tension is required to keep the riser angles low.

SEVERE ENVIRONMENTS
Severe wind and wave conditions increase vessel offsets and usually cause the lower
riser angle to be the governing criterion. In some cases the static and dynamic stresses
will cause the stress limit to be exceeded. The stress criterion rarely governs except in
severe seas or situations where the riser is not suitable for the water depth, mud weight,
and environment.

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RISER SYSTEMS

10.13 EXAMPLE RESULTS FROM ANALYSIS

Figure 10.20 shows the recommended riser top tension for the D/P Drillship Glomar
Jack Ryan for a well in 3019 ft water depth. In the example below, a minimum API
tension was calculated along with a minimum top tension based on the 95% current
e n viro n m e n t. S in ce th e lo ca tio n w a s im p a cte d b y a stro n g lo o p cu rre n t, th is a d d itio n a l
calculation was performed using actual current data accumulated over an 18-month
pe rio d . T h e M a xim u m A P I T e n sio n is 9 0 % o f th e rig s m a xim u m te n sio n in g ca p a city.

Recommended Vertical Tensions

Glomar Jack Ryan - GOM - 3019 feet
3000

2500
Riser Vertical Tension (kips)

2000

1500

1000

500 Max. API Tension

Rec. Tension - 95% Current
Min. API Tension
0
8 9 10 11 12 13 14 15 16

Mud Weight (ppg)

Figure 10.20 Example - Recommended Riser Tension Graph

Since the Glomar Jack Ryan is a D/P vessel and subject to an emergency disconnect of
the LMRP, the minimum riser tension in the example above is constant for mud weights
from 8.55 ppg (seawater) to 11.5 ppg. The governing factor for the tension from 8.55 ppg
to 11.5 ppg is minimum tension to ensure lift off of the LMRP from the BOP stack, not riser
stability. For mud weights over 11.5 ppg, tension increases to offset the additional mud
density in the riser.

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RISER SYSTEMS

10.13.1 MINIMUM TENSION MANUAL CALCULATION

Manual calculation of the minimum riser tension to prevent buckling can be performed by
hand. This is often useful to determine if a prospective rig tensioning capacity is suitable
prior to running a detailed riser analysis. This calculation can also prove useful for
determining minimum tension requirements in the field. Once the minimum tension to
prevent buckling is known, consideration should be given to the range of anticipated
vessel offsets and the severity of the environment. In mild environments, the buckling
tensioner setting is usually adequate. In severe environments or in high current, a higher
tension may be necessary to minimize the lower riser angle.

Required Data:
A 12.0 ppg Mud Weight
B 50 feet Height of mud column above mean water line
C 75 feet Length of standard riser joints
D 6 each Number of standard riser joints without buoyancy
E 10/21 each Number of standard riser joints with buoyancy each type 1 and 2
F 30975 lbs In-water weight of a standard riser joint without buoyancy (0.87 x air weight)
G 3975/645 In-water weight of a standard buoyed riser joint weight for each type 1 & 2
lbs/each jt.
H 60 feet Total length of riser pup joint(s)
I 35000 lbs Total in-water weight of riser pup joints
J 105544 lbs Total weight of outer barrel (of the telescopic joint) above water, tensioner ring,
and middle flex joint
K 75 feet Length of outer barrel below water
L 3.0 in. C&K line ID
M 60750 lbs In-water weight of outer barrel (air wgt. X .87)
N 19.75 inches Inside diameter of standard riser joint
P 2959 feet Distance from mean water line to bottom of lowest riser joint
Q 8 Number of tensioners
TWW Total weight of the riser string in water (w/o mud), KIPS (1000 pounds)
DMW Differential mud weight (riser and C&K lines) , KIPS (1000 pounds)
MTT Minimum Top Tension, KIPS (1000 pounds)
MTS Minimum Tensioner Setting, KIPS (1000 pounds)

The objective of the calculation is to estimate the suspended weight of the riser and the
differential mud weight. The buoyed weight of the various riser joints and the telescopic
joint can be obtained from the rig contractor. These weights are usually recorded when
the riser is run and the contractor will have data from previous installations that will allow
the weights to be verified.

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RISER SYSTEMS

CALCULATION
1. TWW = [(D x F) + (E x G for type 1) + ( E X G for type 2) + I + J + M]/1000
= [(6 x 30975) + (10 x 3975) + (21 x 645) + 35000 + 105544 + 60750]/1000
= [185850 + 39750 + 13545 + 35000 + 105544 + 60750]/1000
= 440 KIPS
2. DMW = {0.052 x x [(A-8.55) x N2 x P + A x N2 x B + (A-8.55) x L2 x P]}/1000
4
= 0.052 x .785 x [(12.0 8.55) x 19.52 x 2959) + 12.0 x 19.52 x 50 + (12.0 8.55) x 32 x 2959
1000
= {0.052 x .785 x [(3.45 X 390.0 X 2959) + (12.0 x 390.0 x 50)]}/1000
= {0.052 x .785 x [3981334 + 234000]}/1000
= 172 KIPS
3. MTT = TWW + DMW
= 440 + 172 = 612 KIPS
4. MTS = MTT x [ Q/( Q tensioner pair failed ) ]/(efficiency due to fleet angle and mechanical)
= 612 x [ 8/(8 2) ]/0.9
= 612 x 1.48
= 906 KIPS

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RISER SYSTEMS

10.14 RISER OPERATIONS

10.14.1 RISER SPACE-OUT

The BOP/LMRP and riser are landed on a high-pressure wellhead housing that is welded
to the top of the conductor casing. One of the first steps in planning a well from a floating
drilling vessel is to determine the water depth and the amount of riser that will be needed.
To calculate the amount of riser needed, a space-out calculation is run using the following
information:
water depth
wellhead stick-up above the mudline
height of the rig floor above the waterline
height of the BOP & LMRP
length of all riser string components, including the telescopic joint and pup joints

The goal of the space out calculation is to determine the number of riser joints and pup
joints that will be required (Table 10.7). Consideration is given to the possible tidal
variations, maximum heave motions and lengthening of the slip joint due to vessel offset.
A desired mean slip joint stroke position is established based on these factors. Generally,
a rig will space out so that the slip joint is one-half to two-thirds closed. This allows for rig
heave and tidal variation to further collapse the slip joint, and maximizes the length
available slip joint to stroke out as the vessel offsets from the location.

GLOMAR Jack Ryan

BOP & Riser Running Worksheet
Operator: EEPTL Location: Trinidad Block 26
Water Depth: 3022 ft RKB to Wellhead: 3092.4 ft
Qty Qty Length Total Cumm
Required onboard Equipment Run (each) Length Length RKB to Top
1 1 BOP & LMRP 50.40 ft 50.40 ft 50.40 ft 3042.00 ft
6 10 75' Slick Joints 75.00 ft 450.00 ft 500.40 ft 2592.00 ft
0 23 75' Red 10000 ft jts 75.00 ft 0.00 ft 500.40 ft 2592.00 ft
0 13 75' Black 7500 ft jts 75.00 ft 0.00 ft 500.40 ft 2592.00 ft
0 27 75' Orange 5000 ft jts 75.00 ft 0.00 ft 500.40 ft 2592.00 ft
31 39 75' Blue 3000 ft jts 75.00 ft 2325.00 ft 2825.40 ft 267.00 ft
0 1 10' Pup joint 10.00 ft 0.00 ft 2825.40 ft 267.00 ft
0 1 15' Pup joint 15.00 ft 0.00 ft 2825.40 ft 267.00 ft
1 1 20' Pup joint 20.00 ft 20.00 ft 2845.40 ft 247.00 ft
0 1 40' Pup joint 40.00 ft 0.00 ft 2845.40 ft 247.00 ft
1 1 50' Pup joint 50.00 ft 50.00 ft 2895.40 ft 197.00 ft
1 2 Termination Joint 75.00 ft 75.00 ft 2970.40 ft 122.00 ft
1 2 Slip joint (Closed) 79.00 ft 79.00 ft 3049.40 ft 43.00 ft
1 1 Diverter, Upper Flex jt & RT 17.60 ft 17.60 ft 3067.00 ft 25.40 ft
Slip Joint Stroke Out 25.40 ft
Slip Joint Stroke Remaining 39.60 ft

Table 10.7 Example of Riser Spaceout Worksheet

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RISER SYSTEMS

10.14.2 RUNNING THE BOP, LMRP & RISER

A riser-handling spider is used during running and retrieving of the riser. The spider sits
on the rotary table, or on a false rotary, and provides a landing surface for the riser string
during makeup of riser couplings. The spider supports the entire weight of the string using
dogs that extend out to contact the landing shoulder or flange of the riser. Spiders are
custom made by the riser manufacturers to fit their specific riser. Vetco spiders are
typically one-piece units, while Cameron spiders can be split in the middle. The riser dogs
can be either manual or hydraulic.
On rigs where vessel motion can cause excessive bending moments on the riser landing
shoulder, a shock-absorbing gimbal is used in conjunction with the riser spider.
Significant bending loads can occur due to the vessel motion or due to offsets of the riser
caused by current loads. The gimbal allows the riser to deflect up to 3 degrees, largely
eliminating bending loads on the riser at the spider. Deflection of the gimbal and riser
offset angles can restrict riser
running operations due to contact
between the riser and diverter
housing.
Several designs are available for
riser gimbals. The gimbal in Figure
10.21 utilizes elastomer cushions
similar to a flex joint. Other riser
gimbals use a ball and socket that
allows the spider to swivel up to 5
degrees. The ball and socket are
keyed together by a single key in the
ball riding in a slot in the socket.
When the spider is not loaded,
hydraulically actuated cylinders are
used to level the gimbal. Due to the
available clearance between the
riser and diverter housing, the riser
may not be able to swivel the full
Figure 10.21 Riser Spider and Gimbal
travel of the gimbal.

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RISER SYSTEMS

A riser running tool (see Figure 10.22) is used to lift individual riser joints into the derrick
and to raise or lower the entire riser string. The lower end of the riser running tool
engages the riser connector on the top of the riser joint. The make-up of the riser running
tool can be manual or hydraulic. The upper end of the riser running tool will directly fit into
the bails suspended from the hook, or it will have a sub that fits into large elevators in the
bails.

Dog Type Riser Running Tool Flange Type Riser Hydraulic Flange Type Riser Mechanical
Vetco MR-6D Running Tool Vetco HMF Type Running Tool Vetco HMF

Figure 10.22 Riser Running Tools

The BOP and LMRP are the first components of the riser system that are run. The BOP
and LMRP should be thoroughly inspected and function tested on the rig prior to being
deployed. This preparation can be completed out of the critical path if the LMRP and BOP
are stored together as a single unit and the pod hoses can be installed. On some rigs, the
BOP and LMRP must be mated in the moonpool as they are run, which necessitates
function testing of the stack in the critical path to ensure that the control pods are correctly
configured and engaged.

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RISER SYSTEMS

The following points should be considered when reviewing the contractors procedure for
running the BOP, LMRP, and riser:
Ensure that a new steel ring gasket is installed in the wellhead connector.
If the stack was split from the LMRP prior to being mated in the moonpool,
then a function test should be performed to test all pod seals between the
LMRP and BOP.
Pull off the location 75 ft or more prior to running the riser. Move the rig back over
the well when preparing to run the telescopic joint.
Minimize the time that the BOP and LMRP spend in the wave zone. This can be
accomplished by making up two joints of riser together before connecting them to
the LMRP.
Test the choke and kill lines every five to ten joints to the maximum test pressure
that will be required throughout the well. Ensure that sufficient spare riser seals
are available at the rig.
Ensure that the riser running tools and handling equipment have current inspection
certification.
Ensure that there is proper equipment and a reliable procedure for checking the
torque and make-up position of the riser connections.
Record the weight of the riser every joint as it is deployed. An accurate
measurement of the buoyed weight is required to ensure that sufficient tension is
applied to the top of the riser. The final hanging weight should be compared to the
value used in the riser analysis.
Verify that the riser buoyancy rating is sufficient for the planned deployment depth.
After lowering the BOP and LMRP below the splash zone, all auxiliary lines are typically
pressures tested to ensure pressure integrity in each line. Auxiliary lines should be tested
to the maximum BOP test pressure that will be encountered during the well and at regular
interval while running the remaining riser. The control umbilicals or mux cables are
spooled out and run with the riser.
When running the BOP stack in a high current environment, the current may cause the
BOP stack and riser to deflect and be offset from the rig (Figure 10.23). This offset can
cause high bending loads at the riser flange, restrict operations due to contact between
the riser and the diverter housing, and require the rig to be offset from the location to
position the BOP stack over the wellhead before landing the stack. On a D/P rig, the rig
may even be placed up current and allowed to drift with the current to minimize the angle
in the rotary while deploying the riser.

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RISER SYSTEMS

On deepwater riser deployment operations, relatively small vessel heave can cause high
loads on the riser and surface equipment due to the different frequencies of the riser and
vessel motions. Due to the large mass of the riser, the motion of the riser can get out of
sync with the vessel as it heaves up and down. This difference in frequency may cause
extremely high loads if the riser is still traveling down and rig starts an upwards motion.
Hookloads of 2 to 2.5 million pounds have been reported during these episodes. During
the opposite cycle, the riser may go into compression if the rig heaves down while the
riser is still on the up stroke, which may cause the riser to buckle, then develops high
sn a p a n d je rk lo a d in g a s to re tu rn s to te n sio n .

Figure 10.23 BOP & Riser Offset during Deployment

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RISER SYSTEMS

10.14.3 LANDING THE BOP STACK

There are a variety of procedures used to land a BOP stack and riser. Generally these
are specific to each rig. It is important to review the specific landing procedure used on
each rig to understand how the loads are shared between the riser tensioners and the
main block as the BOP is landed.
A common method of landing the BOP is described as follows:
The fully collapsed and locked telescopic joint is made up to the top of the riser, and a
slick riser joint is run between the telescopic joint and the block. At this point, the
entire weight of the assembly is on the block so the compensator is not used.
The riser tensioners are rigged up and pressured to support about 100 kips less than
the total buoyed BOP, LMRP and riser weight. This results in the riser tensioners and
the block sharing the weight. The compensator is activated, but is underpressured
and fully extended. The compensator and block will support the weight not carried by
the riser tensioners.
The block is lowered to position the BOP stack just above the wellhead. As the BOP
is lowered, the riser tensioners stroke and the pressure in the tensioners will increase,
supporting more of the riser load. The load carried by the block will decrease as the
riser tensioners take more weight. Manual adjustment of the pressure in the
tensioners and compensator may be required at this time.
When the wellhead starts to support some of the weight of the BOP, the load carried
by the block decreases and the compensator will begin to stroke, leaving the load
shared by the riser tensioners, the block, and the wellhead. Again, manual adjustment
of the pressure in the tensioners and compensator may be required, and the
compensator is positioned to about mid-stroke.
After hydraulically latching the wellhead connector, the compensator can be pressured
up to apply an overpull to test and verify that the wellhead connector has properly
engaged the wellhead.
Once the riser is fully supported by the riser tensioners, the telescopic joint can be
unlocked and the inner barrel stroked out. The diverter insert can then be installed
and the inner barrel is landed with the diverter insert in the diverter housing.

CONSIDERATIONS
The telescopic joint is more commonly landed fully collapsed and locked as described
above. Some rigs land the stack with the telescopic joint fully extended like a bumper
sub. The disadvantage to this procedure is that the landing shoulder on the bottom of
the inner barrel is rarely inspected and several BOP stacks have been dropped from
this failure.
The riser tensioners are usually rigged up prior to landing the stack. This allows a
large portion of the load to be carried by the tensioners as the stack is landed. At
least enough tension to prevent buckling of the riser is usually transferred to the
tensioners, with the remaining load carried by the block.

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RISER SYSTEMS

The BOP stack should be directly over the wellhead before it is lowered. This
prevents damage to the wellhead or the guidelines (if used). Guidelines can easily be
severed as the stack swallows the guideposts. Landing of the stack is monitored with
a Remotely Operated Vehicle (ROV) or a stack mounted camera.
Once the stack is positioned over the well it should be lowered firmly to swallow the
wellhead connector.

Figure 10.24 Guidelineless landing of Figure 10.25 Guidelineless landing of BOP

BOP stack with GRA stack with down funnel on BOP stack

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RISER SYSTEMS

10.14.4 INSTALLED RISER OPERATIONS & MONITORING

The well plan will contain a table or graph (Figure 10.20) that outlines the minimum riser
tension required for combinations of anticipated mud weight, vessel offset and wave and
current environments. The criteria that determine the minimum tensioning requirements
for each condition should also be provided so that adjustments can be made if the
situation warrants. For instance, whenever the mud weight is increased it is usually
necessary to compensate by increasing the tension.
Throughout the operations the following should be monitored and recorded:
Riser tension.
Lower flex joint angle (using level indicators above and below the flex joint).
Vessel offset.
Mooring line tensions.
The lower flex joint angle is the most useful indicator since it will increase as a result of
vessel offset, loss of tension or buoyancy, or an uncompensated increase in the mud
weight. This angle should be maintained less than 1.5o to minimize riser and BOP wear.
Vessel offset and mooring line tensions are useful parameters since severe weather or
currents will move the rig off station and increase the lower flex joint angle.
To monitor the riser, flex joint and BOP angles and offsets, several indicators and sensors
are used depending on the rig type and BOP control system. The most common type of
in d ica to r is a b u lls-e ye slo p e in d ica to r. S lo p e in d ica to rs a re u su a lly m o u n te d o n th e
BOP stack, LMRP, and immediately above the lower flex joint. The slope indicator uses a
ball with .5 to 1o indicator circles inside a glass/plastic covered case that is viewed by an
ROV to provide the angle of the indicator. Slope indicators are good at providing a rough
estimate of the angle, but exact angles are difficult to determine, due to the poor visibility,
angle distortion when viewing with the ROV camera, and inaccurate measurements from
in d ica to rs n o t ze ro e d a t th e su rfa ce p rio r to ru n n in g th e B O P sta ck.
Another type of indicator used to provide vessel offset and riser angle is an acoustic
system. The acoustic system provides vessel offset using a short baseline signal from
the hydrophone located on the vessel. Riser inclination is transmitted acoustically from an
inclinometer mounted on the riser just above the lower flex joint to hydrophone receivers
on the rig.
If a D/P rig is used with a multiplex BOP control system, riser and BOP inclination are
transmitted via the multiplex BOP control system from inclinometers mounted in the BOP
control pods.

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RISER SYSTEMS

10.15 EMERGENCY DISCONNECT & HANG-OFF

In severe weather, it may be necessary to bring a semisubmersible to a shallower draft to
prevent wave slamming of the decks. There is also increased risk that the mooring
system may be unable to hold the vessel on location, possibly due to anchor slipping.
The LMRP must be disconnected before deballasting the rig, or before the lower angle
exceeds the maximum, for reliable release of the connector. The well plan should contain
vessel offset and lower riser angle limits where it is necessary to disconnect the riser. In
an emergency disconnect of this type, vessel motions may preclude riser retrieval and it
may be necessary to hang off the riser. Continued worsening of the weather may lead to
motion conditions that could result in the loss of the riser and LMRP. Contingency plans
should be prepared in anticipation of this situation. As an example, the contingency plans
can be written so that the riser is pulled in advance of a forecast severe storm.
Dynamically positioned rigs may be unable to hold the vessel on location due to problems
with the dynamic positioning system. Loss of stationkeeping is often referred to as drive-
off (vessel powers off location), or drift off (vessel loses power and drifts off location).
Various offset limits are established for DP operations so that the well can be secured and
the riser disconnected quickly before the riser or wellhead are damaged.

10.15.1 RISER RECOIL

In deepwater, the riser tension may significantly exceed the wet weight of the riser and
LMRP. During an emergency disconnect on a DP rig, high tension could cause the
telescopic joint to collapse and impact the diverter housing. The disconnect sequence on
a DP rig is largely automated once it is activated, and there must be a provision in the
sequence to reduce the high riser tension for a controlled release. To accomplish this, a
riser recoil system is used.
A riser recoil system can be set up in a variety of ways. One way is to use valves to
isolate the pressure in the tensioners from the majority of large volume air supply. This
allows the pressure in the tensioner system to decrease as the tensioners stroke and the
riser comes up. Another method to accomplish this is to use isolation valves to switch the
tensioners to a separate lower pressure air supply as part of the disconnect sequence.
Whichever method is used, it is important to make sure that the contractor has correctly
configured it for the specific well location and operating parameters.

10.15.2 RISER HANG-OFF

If the riser is disconnected intentionally prior to an advancing storm, or unintentionally as a
result of a dynamic positioning failure, it is important to properly hang off the riser to
prevent damage to the riser or rig.
Each rig will have its own procedure for hanging off the riser. It can be hung off on the
tensioners, riser spider, riser running tool, or some combination. During riser hang-off, the
tensioners may be closed to hold the riser firm or adjusted to a mid stroke position to allow
the riser to stroke. In deepwater where the riser has a large mass, it is critical that the
motion of the riser has the same frequency as the rig or the motion of the riser is
dampened/compensated.

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RISER SYSTEMS

When reviewing the rig procedure for hanging off the riser, some issues to consider are as
follows:
The riser must be pulled up far enough to ensure that the LMRP remains clear of the
BOP stack.
If the riser is hung off in the spider, rig movement may cause the riser to rock within
the spider, or rock the entire spider. Gimbaled spiders may help prevent this.
If the riser is suspended on the riser running tool and/or tensioners, the dynamic load
caused by relative motion between the riser and the rig can be very large. The reason
that the loads can be very large is that they depend on the acceleration and
deceleration of the total mass of the riser, not just the relatively low buoyed weight.
An indicator of this dynamic effect is a fluctuating load.
Interference between the riser and the diverter housing, moonpool or hull should be
considered. If the riser is left suspended through the diverter housing it is probably
better to position a bare joint in the diverter.
If the rig is abandoned with the riser suspended from the tensioners, it is important to
overpressure the tensioners so that they remain stroked out and the riser load is
evenly distributed among the tensioners even if some of the air bleeds off. If the
tensioners stroke in and bottom out the load will be unevenly distributed among the
tensioners, possibly overloading some of the lines.

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RISER SYSTEMS

10.16 HIGH CURRENT OPERATIONS

High currents can cause problems with riser operations. The most common problem is
large deflections due to the drag on the riser. This usually results in high angles at the
lower flex joint and upper ball joint, and can also result in high bending stresses in the
riser, BOP, wellhead and casing. To reduce the effect of the high current on riser angle,
additional tension can be pulled. The rig can also be offset into the current to minimize
the lower flex joint angle, but the upper ball joint angle may tend to increase when this is
done.
As the current increases, there is a potential for vortex induced vibrations (VIV). This
results from flow separation as the water passes the riser, resulting in vortices shedding
from the riser on alternate sides. These vortices induce alternating forces on the riser
perpendicular to the current direction, and can cause the riser to vibrate perpendicular to
the current flow. This can result in significant fatigue of the riser. In addition, the drag on
the riser is greater if fully developed VIV is occurring, which will increase the riser angles
and bending stress.
Various techniques and operating practices can be used to prevent VIV. A common
method of preventing VIV from developing is to alternate bare and buoyant joints. The
flow regime will be different around the bare and buoyant joints and may prevent the
d e ve lo p m e n t o f V IV . T h is m e th o d p ro b a b ly isn t e ffe ctive in h ig h cu rre n t e n viro n m e n ts
where the current speed can be sufficient to excite the staggered configuration.
Strakes may be installed on the riser to prevent VIV. A strake is a helical rib on the
outside of the riser. Generally the strake height must be a minimum of 10% of the
diameter of the riser to prevent VIV from developing and the performance improves as the
stra ke h e ig h t in cre a se s. S tra ke s ca n b e co n fig u re d w ith 1 , 2 o r 3 sta rts w h ich w ill re su lt
in single, double or triple helixes. A triple helix is generally more effective, and each
individual strake should make a complete wrap around the riser in the equivalent length of
15 riser diameters.
The disadvantage of strakes is that they increase the drag of the riser and tend to
increase the riser angles. It is also difficult to install strakes on risers.

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RISER SYSTEMS

Fairings have been successfully installed on risers

(Figure 10.26) to prevent VIV in extreme current
environments. A fairing is a wing-like foil that is installed
around the riser as it is run through the moonpool. The
fairing allows the water to flow past the riser smoothly
and prevents the formation of vortices. Fairings have the
advantage of reducing the drag force on the riser as well
as suppressing VIV.
Installation of fairings is time consuming and may slow
the riser running to about a joint per hour. Special
platforms and lifting equipment should be placed in the
moonpool to facilitate installation of the fairings. Fairings
are typically custom built for a riser and supplied in 6-8 ft
lengths to facilitate handling. The fairing clam-shell
around the riser buoyancy as the riser is run through the
moonpool.
Thrust collars are installed around the riser buoyancy to
axially confine the fairings. Generally a thrust collar must
be placed above and below a set of three fairings. The
thrust collars allow the fairings to weathervane so they
remain effective as the current direction changes. It is
generally easier to design a fairing for installation around
a buoyed riser joint since the buoyancy provides a
relatively smooth cylindrical surface. Auxiliary lines must
be contained within the buoyancy circumference to allow
the fairings to fit.
Figure 10.26 Riser Fairing
An indicator of VIV is riser movement or oscillation of the Installed On Riser Pup Joint
riser perpendicular to the current, often in a figure eight In Yard
pattern, visible in the moonpool. The frequency of the
oscillation will depend on the length of the riser and the tension. Steps that can be taken
to minimize VIV once it initiates include pulling additional tension, and/or securing the well
and displacing the riser to seawater. If VIV has fully developed, disconnecting the LMRP
is not recommended since this will generally result in greater vibration of the riser (less
tension).
If left unchecked, VIV can cause riser failure. A rig operating in Brazil in the 1970s
reported currents in excess of 6 knots and strong vibration of both the riser and the
auxiliary lines, ultimately leading to riser failure in a few days. In deeper water with uniform
high currents, the fatigue life may be a matter of hours.

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RISER SYSTEMS

10.17 REFERENCES
IADC Deepwater Well Control Guidelines: First Edition October 1998
E xxo n C o m p a n y In te rn a tio n a l F lo a tin g D rillin g B lo w o u t P re ve n tio n a n d W e ll C o n tro l
E q u ip m e n t M a n u a l; R e visio n 1 , 1 9 9 7
API Recommended Practice 16Q First Edition, November 1, 1993
Atlantic Margin Joint Industry Group, Deepwater Drilling Riser Integrity Management
Guidelines, Revision 2, March 2000

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WELL CONTROL OPERATIONS

11
Section

11.0 FLOATER WELL CONTROL

OBJECTIVES
The intent of the material in this section is to only cover the differences in well control
operations conducted from a floating rig and the same operations conducted from a rig
with a surface BOP stack. A basic understanding of well control operations and
principles is required.
On completion of this section, you will be able to:

Describe the complications in abnormal pressure detection and kick detection when
drilling from a floating rig.

Develop a procedure for recording choke line friction pressure.

Develop a shut-in procedure for subsea BOP stack

List the considerations for selecting a pump rate when circulating out an influx with a
subsea stack.

Describe a method to compensate for choke line friction when initiating circulation
when circulating out an influx on a floating vessel.

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WELL CONTROL OPERATIONS

CONTENTS Page

11.0 FLOATER WELL CONTROL .................................................................................................................... 1

OBJECTIVES ............................................................................................................................................ 1
CONTENTS .............................................................................................................................................. 2
11.1 GENERAL ................................................................................................................................................. 3
11.2 FORMATION INTEGRITY AND MUD DENSITY ....................................................................................... 4
11.3 ABNORMAL PRESSURE AND KICK DETECTION ................................................................................. 7
11.4 CHOKE LINE FRICTION PRESSURE .................................................................................................... 10
11.5 GAS IN RISER......................................................................................................................................... 12
11.6 SHUT-IN PROCEDURES ........................................................................................................................ 14
11.6.1 SHUT-IN GUIDELINES .............................................................................................................. 15
11.6.2 HANG-OFF GUIDELINES .......................................................................................................... 17
11.6.3 VESSEL OFFSET CONSIDERATIONS ..................................................................................... 18
11.7 DECISIONS PRIOR TO KILLING THE WELL ........................................................................................ 19
11.7.1 GENERAL .................................................................................................................................. 19
11.7.2 ONE LINE CIRCULATION VS TWO LINE CIRCULATION ....................................................... 20
11.7.3 RECORDING SHUT-IN PRESSURES ....................................................................................... 22
11.7.4 FACTORS INFLUENCING MAXIMUM CASING PRESSURE ................................................... 23
11.7.5 SELECTION OF PUMP RATE ................................................................................................... 24
11.7.6 EFFECTS OF MUD/GAS SWAPOUT IN THE CHOKE LINE .................................................... 25
11.7.7 PRESSURE LIMITATIONS ........................................................................................................ 25
11.8 WELL KILL OPERATIONS ..................................................................................................................... 27
11.8.1 MUD WEIGHT CHOICES ........................................................................................................... 27
11.9 CIRCULATING OUT AN INFLUX............................................................................................................ 29
11.9.1 ESTABLISHING CIRCULATION - USING INACTIVE LINE PRESSURE GAUGE ................... 30
11.9.2 ESTABLISHING CIRCULATION - WITHOUT USING INACTIVE LINE
PRESSURE GAUGE .................................................................................................................. 32
11.9.3 DISPLACING THE WELL WITH BALANCE WEIGHT M U D (D R IL L E R S M E T H O D) .............. 34
11.10 GAS HYDRATES .................................................................................................................................... 37
11.11 TRAPPED GAS REMOVAL .................................................................................................................... 38
11.11.2 CIRCULATE MUD BETWEEN LINES ....................................................................................... 40
11.11.3 CIRCULATE WATER BETWEEN LINES .................................................................................. 41
11.11.4 TAKE GAS RETURNS UP CHOKE LINE .................................................................................. 41
11.11.5 REMOVE REMAINING GAS FROM STACK ............................................................................. 42
11.11.6 CIRCULATE RISER ................................................................................................................... 42
11.11.7 CIRCULATE MUD BETWEEN LINES ....................................................................................... 43
11.11.8 CIRCULATE WELL THROUGH CHOKE ................................................................................... 43
11.12 REFERENCES ........................................................................................................................................ 46

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WELL CONTROL OPERATIONS

11.1 GENERAL
The major difference in floating well control is the location of the BOP stack on the ocean
floor. The well control complications resulting from the BOP stack being located on the
seafloor include:

Lower formation integrity due to increasing water depth.

Kick detection masked by vessel motion.

Effects of long large risers, and long small diameter choke/kill lines.
As the water depth increases, the BOPs are moved further from the rig and can actually
be closer to the bit than to the rig for most of the well. This, along with the large volume
of the drilling riser, complicates early detection of kicks and makes quick reliable shut-in
methods more complex. The long choke and kill lines also complicate and hinder
successful well control operations due to their high friction losses.
Unlike surface BOP well control operations, the BOPs are installed on the conductor
casing, and the diverter system remains ready for use anytime the BOP stack is run.
Diverter systems on floating rigs are also subject to more frequent and rigorous service
conditions than those encountered with surface BOP operations since they remain in
place throughout the well.
Causes of kicks and the equipment/procedures for kick detection are not necessarily all
unique in a floating drilling operation.

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11.2 FORMATION INTEGRITY AND MUD DENSITY

Inland and offshore formation fracture pressures are dependent primarily on over-burden
pressure and formation pore pressure. Overburden pressure is the stress on the
formation due to the weight of the formation and fluid above it. Offshore, overburden
pressure at a given submudline depth will be composed of the seawater weight plus the
weight of formation from the mudline to the depth. At a given RKB depth, increasing
water depth will cause overburden (and resulting formation fracture stress) to decline.
This occurs since seawater (8.6 lb/gal) replaces more of the dense soil (approx. 18.7
lbs/gal and higher) in the overburden calculation.
When overburden pressure and resulting Formation Fracture Stress (FFS) decline due
to an increasing %age of seawater in the total overburden calculation, the spread
between expected PIT and a constant 8.5 ppg pore pressure declines. For example
(Figure 11.1), a PIT about 4 ppg greater than 8.5 ppg pore pressure can be expected at
1400 ft BML for a well in 1000 ft water depth. This will allow increasing mud weight at
least 3 ppg before the next casing string is required. The spread between pore pressure
and FFS declines to just 1.7 ppg at the same 1400 ft BML depth for a well in 4000 ft of
water. A casing string at this depth would permit raising mud weight only about 1.0 ppg
before the next casing string is required. The drilling margin between pore pressure and
FFS will require additional shallow casing strings as water depth increases.

Figure 11.1 Overburden Pressure/Seawater

Depth

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WELL CONTROL OPERATIONS

In floating drilling operations, the integrity of the formation should be tested after setting
each casing string. Prior to the PIT, the mud should be circulated to ensure that it is
clean and that there is a uniform mud density throughout the wellbore. If there is
sufficient heave to cause movement of the pipe through the annular preventer, the pipe
should be hung off on the pipe ram to prevent surges and fluctuations in the pressure
during the test. Since the surface pressures are typically low, especially for shallow
casing string, a low pressure gauge or digital gauge should be used to record the test
pressures. Pump rates during the test may vary from to 1 bpm depending on the open
hole size and hole volume. To provide sufficient data points, pressures during the test
should be recorded and plotted every bbl regardless of the pump rate. To determine
the fracture closure pressure, the final shut-in pressure should be held a minimum of 10
minutes. The results of the PIT should be calculated and posted on the rig floor to assist
in planning for well control operations.
When conducting PITs with non-aqueous fluids (NAF), the operation is much more
critical since fractures caused by an NAF are much more difficult to close and less likely
to regain their original fracture resistance strength. For this reason, caution should be
taken when performing the PIT with an NAF to ensure that initial leakoff is detected
before excessive fracturing occurs.
If a computerized cement unit is used, the pressures should be recorded by the
computer at the unit so that additional data points can be provided. The real time plotting
feature of this system can be beneficial in identifying the initial leakoff to the formation.
When using a Pressure While Drilling (PWD) sub, the pressures recorded by the PWD
during the PIT should be downloaded and compared to the surface test pressures to
confirm the results.
The mud density to control the well is distributed throughout the open hole, casing and
riser. In deepwater locations, the hydrostatic in the riser may be providing anywhere
from 25 to 50% of the overall hydrostatic pressure for the wellbore. When operating in
shallow water (<1000 ft), a common practice was to maintain a mud weight that would
provide an overbalance on the wellbore during the loss of hydrostatic from the riser. In
deepwater locations where sufficient mud weight to provide an overbalance for loss of
hydrostatic in the riser cannot be maintained while drilling, procedures must be in place
and equipment must be tested to ensure that the well can be secured prior to the loss of
the riser.
The compressibility effects associated with NAF are a function of both pressure and
temperature. The density at the bottom of the wellbore can be 0.3 to 0.5 ppg heavier
than measured at the surface due to the hydrostatic pressures exerted on the fluid.
Conversely, the density at the bottom of the wellbore on a high temperature well can be
0.3 to 0.5 ppg lighter than measured at the surface due to the expansion of the fluid. On
most deepwater wells, the bottom hole temperatures will be low, therefore the pressure
effects will dominate. Even if a NAF is used during the PIT, it typically will not cause a
problem since the relative difference between the mud weight and the PIT pressure is
the same.

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WELL CONTROL OPERATIONS

Another characteristic of the NAF is a higher friction loss while circulating resulting in a
high Equivalent Circulating Density (ECD). ECDs from NAF will typically run between 0.3
and 0.6 ppg and are especially high when drilling 8 in. hole below 9 5/8 in. casing due
to the smaller annular clearance. When drilling with NAF, the use of a PWD tool can be
especially useful in determining the actual downhole pressure.
Due to the thin margin between the pore pressure and the overburden pressure, mud
losses on deepwater wells are common and difficult to prevent. Once the fracture is
opened, it can be difficult to stop. Since shallow formations in deepwater do not develop
matrix strength, fracture propagation may also be difficult to stop. The use of an NAF will
also compound this problem due to the heavier density from the compressibility of the
mud. The higher ECD pressures while circulating and the increased difficulty for the
formation to heal since the NAF penetrates the fracture tip more readily is also a
problem. The following drilling practices are commonly used to prevent exceeding the
fracture gradient:
Control drilling to limit cutting loading and increasing the ECD.
Limiting tripping speeds and pipe movement to prevent surges.
Use of PWD tools to measure downhole ECDs while drilling.
Better training and kick detection by rig crew and monitoring equipment.

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11.3 ABNORMAL PRESSURE AND KICK DETECTION

Abnormal pressure indicators and kick detection indicators are the same for surface
and subsea drilling operations. The major difference in subsea drilling is that the
indicators are much more difficult to detect due to the vessel motion and subsea
environment.
The most common method for detecting abnormal pressure is by monitoring for changes
in the mud, gas and cuttings circulated back to the surface. Since the well is connected
to the rig with a large volume riser, the lag time required for the indicators to reach the
surface is substantially longer than on wells with surface stacks. In deepwater, this
additional volume may increase the time to circulate out a drilling break to 2 to 3 hours.
In addition to the increased circulating time, the large internal diameter of the riser also
decreases the velocity of the mud, which in turn causes the mud temperature to be more
greatly affected by the seawater temperature. Due to the large heat transfer that takes
place as the mud travels up the riser, the return temperature of the mud in deepwater
can actually be cooler (60o to 65o) coming out of the hole than when it is pumped from
the pits. This cooler/constant temperature of the return mud can mask gas readings and
make indicators such as mud temperature useless for pressure detection.

RISER BOOST LINE

To compensate for the large volume of mud in the riser, most rigs are equipped with a
riser boost line installed on the riser. Mud is circulated through the riser boost line and
added to the return mud at the bottom of the riser. The purpose of the riser boost line is
to increase the annular velocity in the riser, decrease the bottoms-up time and assist
with riser (hole) cleaning. Since fresh mud is added to the return mud at the seafloor,
abnormal pressure indicators such as return gas are diluted when the boost line is used.
To allow pressure trends to be tracked when the boost line is used, the flow rate with the
boost line should be consistent while drilling.
One type of tool that is beneficial for abnormal pressure detection in deepwater is the
PWD/LWD tools. These tools provide real time resistivity/gamma ray logs, circulating
densities and relative downhole temperatures at the tools. The resistive/gamma ray logs
can be used to indicate sand/shale lithology and formation pressure changes through
resistive changes. These indicators can be recorded within one to two ft of the bit
depending on the tool manufacturer. The PWD tool temperature sensor provides
real-time downhole temperature eliminating the lag and cooling effect of the mud when
it is circulated through the riser.
The most common method for detecting a kick on any rig is increasing pit volume and a
return flow higher than the circulation rate recorded at the flowline. These two
parameters can be difficult to measure on a floating rig when substantial rig motion is
occurring. Rig heave, the me a su re o f th e rig s rise a n d fa ll in re sp o n se to th e se a sta te ,
is the greatest contributor to this measurement problem.

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WELL CONTROL OPERATIONS

With substantial heave, the flowline rate will change in response to this vertical motion,
making it difficult to detect a small influx. Other rig motions, such as substantial roll and
pitch, will affect the liquid level of the mud pits and make it difficult to accurately measure
the active pit volumes and the changes in their levels. During heavy sea conditions,
PVTs can fluctuate +/-20 bbls and the flo-sho can deviate 10 to 15%. This problem can
be even greater when operating from a drillship due to increased motion.
As water depth increases, the importance of detecting a kick early also increases in
response to the rapid increase in gas volume allowed to expand freely as the influx is
moving up the hole. For very shallow water locations, the rapid volume increase is
detected by increasing flow or pit volume, and the BOPs are closed well before the gas
reaches the BOPs or the surface. For deepwater wells, an influx may be above the BOP
stack before a significant change in pit volume and increased flow is noticeable at the
surface.
A second reason for early influx detection is the limited differential between mud weight
and fracture pressure typically found in deepwater wells. The likelihood of a kick causing
lost returns is significantly increased when the mud weight fracture pressure tolerance is
small.

PVT SENSORS
When a rig is experiencing substantial motion, kick detection can be improved in a
number of ways. Frequent flow checks by the driller is the simplest method. The well can
also be flow checked to the trip tank to determine if a small flow is occurring. Pit Volume
Totalizer (PVT) sensors can be installed to minimize pit volume deviations due to the
rig s p itch a n d ro ll. L o ca tin g th e P V T se n so rs in o p p o site co rn e rs o f a n a ctive p it a n d
a ve ra g in g re su lts w ill n e u tra lize th e rig s m o tio n .
Another factor that increases the difficulty in detecting an influx is the use of synthetic
base mud (NAF). While drilling, the flow properties of NAF can add up to 0.6 ppg of
ECD and provide sufficient overbalance to prevent a formation from flowing until the
interval has been drilled and the pumps are shut down. The disadvantage to this
situation is that since a larger amount of the high permeability, high porosity formation
has been drilled, larger influxes can be taken in a shorter time period. The highly
compressible nature of the fluid also makes it more difficult to flow check the well since
the natural expansion of the mud will cause the well to flow longer on connections and
flow checks.
D u rin g d rillin g , a p h e n o m e n o n ca lle d b a llo o n in g ca n o ccu r w h e re flu id is lo st w h ile
circulating and flows back into the wellbore when the pumps are turned off. This
phenomenon is caused by the opening and closing of induced or in-situ micro fractures.
When the bottom hole pressure (ECD) exceeds or equals the fracture propagation
pressure, a stable radial fracture is propagated. When the pumps are turned off and the
ECD falls below the fracture propagation pressure, the fracture closes and pushes the
mud back into the wellbore. Flow back from a ballooning formation can be 50 to 75 bbls
and take up to 30 minutes to stop flowing on connections.

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WELL CONTROL OPERATIONS

To provide for kick detection, the well is flow checked to the trip tank with the flow rate
recorded (e.g. volume recorded each minute) and compared to previous flow checks. A
decreasing flow rate while flow checking would typically indicate a ballooning formation,
whereas a constant or increasing flow rate would indicate an influx from the formation.
Trending successive flow checks is key to identifying ballooning
When the ECD exceeds the fracture propagation pressure significantly, the fracture
propagation becomes unstable and results in massive mud losses.

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WELL CONTROL OPERATIONS

11.4 CHOKE LINE FRICTION PRESSURE

Since the BOP stack is located on the seafloor, long small-diameter (usually about 3.0
inch ID) choke and kill lines are used to connect the BOPs on the ocean floor to the rig
choke manifold. As water depth and the length of these lines increase, pressure losses
in these lines increase due to the increasing friction between the moving fluid and the
pipe ID. This can become significant and must be considered when circulating out a kick.
The addition of choke line friction pressure to the hydrostatic mud pressure and surface
pressure can easily be enough to exceed the FFS. This is especially critical for
deepwater wells where choke line friction pressure is high and mud column's hydrostatic
is generally only slightly under the FFS.
While circulating out a kick, it is important to prevent the addition of this choke line
friction pressure from being imposed on the casing shoe. This is accomplished by
subtracting all or part of the choke line friction from original stabilized shut-in annulus
pressures while circulating out the influx.
There are two methods used to estimate choke line friction pressure drop while
circulating out a kick. The pressure loss can be calculated using standard fluid dynamics
equations, or the pressure drop can be measured prior to a kick. Generally, actual field
measurements are the most accurate and widely used. The recommended field
measurement method to obtain choke line friction pressure drop with drill pipe in the
BOPs is:
1. Circulate down the DP and up the riser with each mud pump at rates ranging
from one to four BPM for the current mud weight. Record circulating pressures.
2. Close the annular on the drill pipe, and circulate down the drill pipe with each
mud pump, and up the choke/kill line at previous rates (be sure the choke is fully
open).
3. Record surface drillpipe pressure.
4. Subtract the two values at each pump rate to obtain the choke line friction
pressure drop.
An alternate method to measuring the choke line friction pressure is to circulate down
the choke/kill line and up the riser. This method provides the total friction pressure
required to circulate the mud down the choke/kill line and up the riser. This method can
be used with open hole exposed and is very comparable to the method listed above.
Since either the choke or kill lines are subject to use as a choke line, the measurement
should be run on each line independently. If both choke and kill lines will be used
simultaneously, the measurement should be run with both lines open. The measurement
should be run before drilling out the casing cement float equipment. This will prevent
placing pressure on the open-hole after drilling out.

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WELL CONTROL OPERATIONS

Whenever the mud weight is changed substantially, the choke line friction can be
corrected by use of this equation:

Corrected chokeline friction = Initial Friction x New MW

Initial MW
Several numerical methods are available to calculate flowing fluid pressure losses in
choke or kill lines. A method developed by EURC is included in the well control program
K IK in clu d e d o n th e E M D C D rillin g co m p u te rs.
When using synthetic based muds or highly viscous water-based muds, the fluid in the
choke and kill lines can become very viscous as it sits stagnant for long periods of time
at the colder subsea temperatures. This viscous fluid coupled with the small diameter
lines may make it difficult to obtain accurate CLFPs, to read initial shut-in casing
pressure or to initiate circulation during well control operations. It may be necessary to
reduce the viscosity of this mud while drilling it, in order to break circulation in the lines,
two to three times every 12 hours. During well control operations, it may be necessary to
close a preventer below the choke and kill lines to isolate the wellbore and to circulate
down one line and up the other before recording pressure and attempting to break
circulation.

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WELL CONTROL OPERATIONS

11.5 GAS IN RISER

The possibility of getting free gas in the riser is quite high when operating in deepwater.
In areas of the world where shallow geo-pressured formations are common, it will be
quite possible to get gas in the riser if a geo-pressured zone is encountered at 2000 ft
(or even shallower) below the mud line.
Free gas in the riser can be one of the most dangerous situations on a rig from a
personnel safety standpoint as well as the possibility of riser collapse or a fire on the rig
floor.
At depth, the gas slips through the mud in the riser. Near the surface, it is possible for
the gas to reach a critical depth (bubble size and pressure) where rapid subsequent gas
expansion pushes the balance of the mud out the riser. This expansion is very rapid and
can generate a significant pressure surge as mud flow overcomes the flowing friction in
the system.
Gas in a drilling riser can occur from:
Circulation of drill gas.
Formation influx gas above the BOPs before detection.
Gas trapped in the BOPs at the end of a well control operation released to
the riser.
Gas in a riser is a very important concern due to the volatility of gas and its high
compressibility. Drill gas is the formation gas that is brought to the surface with the
cuttings and can be significant when drilling at high ROPs. A riser circulation line (boost
line) is effective in increasing the flow rate in the riser and diluting drill gas in the mud
return flow
Gas trapped in the BOP stack at the end of a well control operation requires careful
handling to ensure the gas is safely removed. When a gas kick is circulated out of a well,
gravity effect usually results in the gas being trapped in the stack above the uppermost
choke or kill line. Rather than release this trapped gas to migrate up the riser, special
handling methods should be used to release the gas from the stack through a choke line
to the surface.
For handling riser gas on floating rigs, the diverter system is utilized. Floating rigs are
unique in that the riser and diverter system is utilized from spud to total depth. The
diverter system for floating rigs was originally designed as low-pressure well-control
equipment for shallow gas on shallow water depth floating wells. The primary use of the
diverter system today is for handling of a gas influx once it is in the riser.

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WELL CONTROL OPERATIONS

In addition to the typical diverter system used to divert the fluid overboard, some rigs
are now equipped to allow returns from the riser to be routed through a gas separator
where the gas can be vented and mud returned to the active system. This system is
beneficial in keeping the gas off the rig floor and out of the mud processing room, but
they are not designed to handle a riser unload should the gas reach its critical expansion
point. In addition, the riser degasser systems may not allow indicators such as flo-sho
and return gas to be monitored since they could be bypassed.
If trapped gas is released into the riser (above the BOPs), field-testing has shown that it
is important to allow the gas to migrate to the surface without pumping. This will tend to
strin g -o u t a n d ke e p th e g a s in sm a ll b u b b le s w h ile in th e rise r. S m a lle r g a s b u b b le s ca n
be handled safely because they surface slowly and do not displace mud from the riser
(small bubbles slip by mud in the riser). After given adequate time for gas to migrate to
the surface, the riser must be circulated to remove any residual gas. As a precaution,
this circulation should be performed at a very slow rate.

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WELL CONTROL OPERATIONS

11.6 SHUT-IN PROCEDURES

Because of the location and complexity of the blowout preventer equipment and controls
used on floating drilling rigs, required shut-in procedures become more complex. In
deepwater drilling, the need to
perform these procedures with EXAMPLE
greater efficiency is critical due to SHUT-IN PROCEDURE
the need to limit influx volume and DRILLING
the resulting surface pressure
imposed on the formation. Vessel IF ANY OF THE FOLLOWING OCCURS:
motion and rig offset also add to 1. Increase in rate of pentration.
2. Increase in flow.
the problems associated with 3. Gain in pits.
detecting and shutting-in the well 4. Decrease in pump pressure, gain in strokes.

from a floating drilling rig.

FLOW CHECK WELL

SPACEOUT AND SHUT-IN 1. Pick-up and position tool joint to shut-in the well.
2. Shut down pumps.
For this reason, precise instruc- 3. Check for flow.

tions and drills on tool joint

spaceout and shut-in procedures
Notify Company Man Is
must be established with the rig and NO the well
flowing?
personnel (Figure 11.2). On DP Toolpusher

rigs, the need to properly space

YES
out the tool joint and shut-in the
BOP stack is also required to SHUT IN THE WELL
secure the well for an emergency 1. Close the upper annular.
disconnect caused by a loss of 2. Open the lower choke line valve.
stationkeeping. During a drive- 3.
4.
Record the pit gain, shut-in D/P & casing pressure in 1 minute intervals.
Check for back flow through the mud pumps.
off/drift-off, the Driller may have 5. Check the riser for flow.

less than one minute to position

the pipe and secure the well
before actuating the ESD to Is
Riser
disconnect the LMRP connector. flowing?

For this reason, the tool joint

location/spaceout on a DP rig YES
should be determined and known NO
1. Activate the diverter.
at all times by the Driller so that 2. Monitor the slip joint & adjust pressure if required.
3. Divert riser flow overboard to lee side of rig.
the pipe ram can be closed prior 4. Monitor overboard lines and fill riser as required.
to hanging off the drill pipe without
first locating the tool joint with the
HANG-OFF THE DRILL PIPE
annular preventer.
1. Notify Company Man, Toolpusher & ASK.
During shut-in for well control 2.
3.
Locate Tool Joint with Upper Annular.
Close Middle Pipe Rams & Hang-off D/P.
operations, the tool joint should be 4. Adjust compensator to set 30 kips on ram.
5. Control Well as directed.
located with the annular preventer
before closing a pipe ram to Note: 1. The upper annular should remain closed until after the well kill process is complete.
2. Kill line will be used to compensate for CLFP when initiating circulation.
prevent inadvertently closing the
ram on a tool joint. Figure 11.2 Example Shut-in Procedure

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WELL CONTROL OPERATIONS

11.6.1 SHUT-IN GUIDELINES

After installation of the BOP stack, the well will almost always be shut-in subsea and
controlled with the BOP stack. Even though formation integrity may be marginal at
conductor setting depths of 1,500 to 2,000 ft below the mud line, the alternative of using
the diverter equipment to control the influx at the surface is even less appealing. Even
under these marginal conditions with shallow casing shoe depths, controlling the well
with the BOP stack has proven to provide less overall risk to people, well and
equipment.
The well will typically always be initially shut-in using an annular preventer. The annular
preventer provides a means to effectively shut-in the well while still allowing for
movement of the drill pipe and locating the tool joint without damage to the preventer.
The need to initially close-in the well using the annular preventer becomes even more
important in deepwater where vessel offset increases the difficulty in calculating tool joint
location in the BOP stack.
Due to the differences in floating rigs and the available BOP equipment, rig and well
specific shut-in and well control procedures should always be developed. Shut-in
procedures should be developed for drilling, tripping, and casing operations.
Shut-in procedures should take into account the following considerations:
Is there an outlet directly beneath the annular?
Will the influx be circulated out using an annular for hung off on a pipe ram?
Is the rig moored or a DP rig?
Which ram will be used to hang off the drill pipe?
Is there sufficient room between the hang-off ram and shear ram for the
tool joint?
Is there a choke and kill line beneath the preventer to be used for the well
kill operation?
Shut-in procedures for floating rigs should always include steps to monitor and/or divert
any flow from the riser. In deepwater, the potential for gas to be above the BOP stack
and in the riser also adds to the complexity of shutting-in and killing the well. Should
there be any flow from the riser after the well has been shut-in, it will be difficult to
differentiate between riser flow and a leaking preventer. If the preventer is leaking and
hydrostatic pressure is being lost, an additional influx could enter the well and ultimately
cause significantly higher casing pressure and lost returns. Should the gas in the riser
begin to expand and flow during a well kill operation, a simultaneous diverter/kick pump
out operation would be required. Therefore, equal emphasis should be placed on
monitoring the riser along with the well as the influx is circulated from the wellbore. In
doing so, surface equipment must be aligned so that returns from the gas separator and
riser can be monitored independently.

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 WELL CONTROL OPERATIONS

To allow for a fast sh u t-in , the first valve downstream of the choke should be in
the closed position with the choke half open during drilling and tripping operations
(Figure 11.3).

First Valve
Downstream of Choke

Open Valve
Closed Valve

Figure 11.3 Shut-in Arrangement for Typical Choke Manifold for Subsea BOPs

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WELL CONTROL OPERATIONS

11.6.2 HANG-OFF GUIDELINES

The drill string will typically be hung-off if any of the following conditions exist
during well control operations:
Weather and sea conditions (either current or forecast) are creating excessive
heave that can result in wear damage to the annular BOP element.
Riser angle at the Lower Marine Riser Package is greater than established limit.
Drill string is attempting to stick. An early decision will be required to ensure that
hang off of the drill pipe can be accomplished while the string is still free.
Casing pressure increases above 1500 psi.
Unable to establish full returns, or evidence of an underground flow exists.
Surface flow from the riser indicating that the annular preventer may be leaking
formation fluid or gas above the BOP stack.
Using a DP rig or operating with high mooring loads where there is a high potential for a
mooring failure.
Except for an emergency disconnect situation on a DP rig, the location of the tool joint
should always be verified before closing any pipe ram.
Because of the conditions that normally exist when the use of a pipe ram is required (i.e.
high casing pressures, unacceptable rig heave, drill pipe trying to stick or rig offset
beyond acceptable tolerance), the drill pipe will almost always be hung-off.

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WELL CONTROL OPERATIONS

11.6.3 VESSEL OFFSET CONSIDERATIONS

An important consideration in the shut-in procedure on a floating rig is the location of
the drill pipe tool joints in the BOP stack. Since the BOPs are fixed to the mudline
and the rig is in motion, this is a dynamic problem. In shallow water locations, it is
common practice to position a tool joint in the BOPs based on the pipe tally and
positioning tool joints a specific distance above the drill floor. In shallow water this
has been an acceptable method to position a tool joint within the BOPs.
As water depth increases, the possible error increases, and this procedure becomes
unacceptable. A change in vessel offset can cause the distance from the rig floor to
the BOPs to change significantly. For deepwater wells, it is common practice to
close an annular preventer and pick-up the drill pipe until a tool joint contacts the
bottom of the annular. With this data, and knowing the distance from the annular to
the ram-type BOPs, the position of a tool joint within the BOPs can be determined
with relative accuracy.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

11.7 DECISIONS PRIOR TO KILLING THE WELL

11.7.1 GENERAL
T h e D rille rs co n so le sh o u ld b e e q u ip p e d w ith an accurate gauge to monitor the drill pipe
pressure and a display showing the pump rate in strokes per minute and the cumulative
number of pump strokes. The display should also provide a control to zero the
cumulative stroke counter.
The control panel for the remotely adjustable chokes should provide gauges to register
drillpipe pressure and casing pressure immediately upstream from the choke that is used
to control the well. The panel also contains the choke controls, a gauge indicating choke
position, meters to read pump rate in strokes per minute and cumulative pump strokes,
and a control to zero the cumulative pump stroke counter.
In addition to the previously described equipment, an additional gauge should be
provided at the choke console to monitor the casing pressure on the circulating line that
will not be used (inactive line) to circulate the influx from the wellbore. This inactive
circulating line gauge is used:
To simplify the measurement of choke line friction pressures.
To allow the choke operator to automatically exclude most, if not all of the choke
line friction from drill pipe pressure when the initial drill pipe circulating pressure
is established.
To signal the invasion of the active choke line by gas.
In addition, some rigs with multiplex BOP control systems have pressure and
temperature sensors installed on the BOP and/or LMRP for monitoring the pressure and
temperature at subsea. If the BOP is equipped with a pressure sensor, it can be used to
compensate for CLFP when initiating circulation and to signal when the influx enters the
BOP stack. The use of the sensor is especially useful since it:
Provides a gauge to compensate for CLFP when using both lines to circulate.
Allows the inactive line to remain closed for use as a backup line.
Provides a subsea sensor to measure the annulus pressure when the fluid in the
choke/kill line is too viscous to transmit a pressure to the surface.

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WELL CONTROL OPERATIONS

11.7.2 ONE LINE CIRCULATION VS. TWO LINE CIRCULATION

The two choke and kill lines on floating rigs provide the following purposes and uses:
Backup for first line.
Provides an inactive line to monitor shut-in casing while compensating for CLFP.
Allow circulation across the BOP.
Allows circulation of the wellbore after the pipe is hung-off and sheared.
Dual circulation to reduce friction losses.
In normal practice, an influx should be circulated out using a single choke line. The
alternate (inactive) line will generally be used to monitor casing pressure when the pump
is brought on line.

Single line circulation is common practice due to:

Uncertainty of choke line friction during initiation of circulation,
BOP stack and outlet arrangements may not permit the use of two circulating
lines when pipe is hung off,
Consistent well control practices with most industry experience and training.

The use of two lines should be considered when:

The choke line friction pressure is greater than the shut-in casing pressure, two
lines reduce the friction by 50% to 75% for the same circulation rate.
The choke line friction pressure would cause casing shoe pressure to be greater
than leak-off pressure.
Gas is causing the surface casing pressure to fluctuate excessively, impacting
the ability to maintain constant drill pipe pressure.

Advantages of using two lines:

Circulating through two lines instead of one reduces choke line friction pressure
losses by as much as 50%.
Alternately, a kick can be circulated through two lines at twice the rate with the
same choke line friction losses.
As the gas bubble comes up two lines instead of one, surface choke line
pressure increases less rapidly, resulting in less rapid adjustments of the choke
to keep the drill pipe pressure constant.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

Disadvantages of using two lines:

If the well kill operation is to performed with the drill pipe hung-off on the hang-off
ram, most BOP stack arrangements would require the use of the outlet below the
master ram for access to the second circulating line. As always, the use of the
outlet below the master should be limited to emergency procedures and non-well
control operations.
When both lines are used for circulation, the ability to monitor the well on the
inactive line during pump start-up and during the well kill operation is lost.

When using two lines for circulation, the BOP stack may act as a gas/mud separator
assuming the mud and gas are in two phases. The effect of this is that the majority of the
gas will exit through the upper choke/kill line, causing the friction to be less, thus
allowing a greater proportion of the total influx flow through the upper line. The net effect
is that there is less of a chance for mud/gas swap over in the choke/kill line and less
fluctuation in surface pressures.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

11.7.3 RECORDING SHUT-IN PRESSURES

After the pumps have been stopped and the well shut-in, the shut-in drill pipe and casing
pressures should be recorded every minute until shut-in pressures have stabilized.
Thereafter, pressures should be recorded every five minutes until well kill operations
begin. It is extremely important that the pressures be recorded continuously after initial
shut-in to assist in identifying possible lost returns. It is also likely that due to the short
open hole intervals in deepwater wells that the maximum shoe pressure may occur on
initial shut-in.
If a non-ported drill pipe float is in use, the pressure required to pump open the float
valve should be used as the initial shut-in drill pipe pressure. The method to determine
when the float valve has opened is the same as determining formation leakoff for the
pressure integrity test.
In deepwater, the viscosity of the mud in the choke/kill line can sometimes prevent
pressure response to the casing pressure gauge at the surface. To reduce the viscosity
of the mud in the choke/kill lines prior to a well control incident, the mud should be
circulated periodically each tour to reduce the mud gel strength. If the viscosity of the
mud does not allow pressures to be transmitted to the surface after the well has been
shut-in, a preventer to isolate the wellbore should be closed and the choke and kill lines
circulated to reduce the viscosity. Caution should be taken during the alignment of the
valves for this exercise to prevent the wellbore from being open during circulation.

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WELL CONTROL OPERATIONS

11.7.4 FACTORS INFLUENCING MAXIMUM CASING PRESSURE

The maximum casing pressure resulting from maintaining a constant bottom-hole
pressure while circulating out a kick depends on a number of factors. The most
important of these factors are volume and type of influx. Other factors include the
annulus size, kick intensity, and weighting-up schedule.

VOLUME OF KICK INFLUX

The maximum casing pressure seen while circulating out a kick increases as the volume
of feed-in increases. Of all the variables involved, the volume of the influx is the only
parameter that we can control that affects the surface pressure.
For this reason, the well should be shut-in as quickly as possible.

TYPE OF INFLUX
A gas influx produces a higher casing pressure than any other type of influx of the same
volume. This is due to the ability of gas to expand as it nears the surface and force mud
from the annulus, thereby further reducing the hydrostatic pressure. Any influx should be
assumed to be gas as it represents the worse condition. Even a water or oil kick will
contain associated gas.

KICK INTENSITY
Kick intensity refers to the additional mud weight in pounds per gallon required to kill the
kick, i.e. a one-pound kick, a two-pound kick, etc. It is equal to shut-in drill pipe pressure
divided by the depth of the kicking formation and the 0.052 conversion factor. Kick
intensity primarily affects the rate of influx feed-in rather than the maximum surface
pressure reached during circulation. That is, a two-pound kick will feed in at a faster rate
than a one pound kick. The pressure levels of kicks of different intensity are appreciably
different throughout a large portion of the circulation. However, when the gas reaches
the surface, these pressures differ by very little. Therefore, for the same volume of
feed-in, the maximum casing pressure is relatively insensitive to the kick intensity;
however, since the rate of feed-in is governed by the pressure differential into the
wellbore (as well as other factors such as formation permeability), a 1.5 pound per gallon
kick would have to be detected much quicker than a 0.4 pound per gallon kick for the
volume of feed-in to be the same. If the same time elapses in both cases before the
kicks are detected and the well shut-in, the volume of feed-in would be much greater
with the 1.5 pound per gallon kick.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

11.7.5 SELECTION OF PUMP RATE

The selection of the circulation rate is based on several factors including, choke line
friction pressure, formation integrity at the casing shoe and rig equipment. This rate will
normally be in the range of one to three barrels per minute.
The low pump rates are desirable to:
Allow more time for the choke operator to react to changing pressures.
Accommodate handling gas volumes at the surface.
Reduce CLFP and the possibility of lost returns.
Care should be exercised in selecting the pump rate, since excessive choke line friction
pressure from high pump rates can cause formation breakdown.
To minimize the maximum pressure seen by the shoe, a pump rate should be chosen
such that:
The choke line friction losses will not exceed the shut-in casing pressure, or
The sum of the choke line friction pressure and the shut-in casing pressure will
not exceed the formation integrity.
When gas reaches the surface, the mud gas separator may be the limiting factor as to
how fast the kick can be circulated. As the gas reaches the surface, a reduced pump
rate may be necessary to prevent the loss of the liquid leg in the separator. If this is
necessary, the pump rate should be reduced before the influx enters the line, since
choke adjustments are much more difficult afterwards.
If additional circulation cycles are needed, the considerations listed above should be
looked at before an increased pump rate is selected. If most or all of the gas is out of the
hole (i.e. the casing pressure is less than the choke line friction pressure), it may not be
possible to adequately compensate for the choke line friction pressure.

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WELL CONTROL OPERATIONS

11.7.6 EFFECTS OF MUD/GAS SWAPOUT IN THE CHOKE LINE

During the pump out of a high volume, non-dispersed gas influx, the invasion of the
choke line by the gas influx will cause a sudden loss in hydrostatic pressure.
The rapid pressure change may not provide sufficient time for the choke operator
to adjust the choke, especially when circulating at normal kill pump rates of two to
three bbls per minute.
The rapid reduction in bottom hole pressure and the failure to compensate adequately
can be minimized by early detection of gas entry into the choke line. Pressure on the
inactive choke line gauge or BOP sensor will begin to decrease rapidly shortly after gas
enters the active choke line. This signal should be seen several seconds before the drill
pipe pressure reacts and should alert the choke operator of the need to begin closing the
choke. When gas reaches the surface and gas starts through the choke, casing pressure
should begin to decrease rapidly signaling a need to further close the choke.
Since it may be difficult for the choke operator to maintain the correct bottom hole
pressure at the normal kill rate, a reduced pump rate may be required. If the pump rate
is to be reduced, it should be changed before the influx reaches the choke line since
initiating circulation with gas in the choke line or at the surface might prove to be very
challenging due to the constantly changing casing pressures.
Note: This reduction in pump rate may also be required if the surface equipment (gas
buster) is unable to safely handle the volume of gas.
As gas continues to leave the well and mud invades the choke line, the rate of
hydrostatic pressure increase will be appreciable, thus requiring a rapid opening of the
choke. Failure to keep the drill pipe pressure from increasing at this point will result in
excess casing shoe pressure, possibly causing lost returns.
The other thing that can happen when a non-dispersed gas influx enters the choke line
is that a comparatively higher casing pressure may be noted since the entire length of
the line may be filled with the influx. This is caused by the volume of the choke line being
much smaller than the casing by drill pipe annulus that the influx occupies when it
reaches the surface on a well with a surface BOP stack.
For a 0.3 ppg kick with a 10.0 bbl gas influx, the maximum pressure when using a
surface BOP stack is 1013 psi where the maximum pressure would 2780 psi when
operating 5000 ft water depth. This increased surface pressure causes the flow (due to
the gas expansion) downstream of the choke to be higher for the subsea well. This
increased flow rate can cause overloading of the surface degasser and increased wear
on the on the choke manifold and piping.
It should be noted however, that an influx is normally dispersed during circulation and
that a discreet gas bubble may seldom occur while circulating an influx from the
wellbore.

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WELL CONTROL OPERATIONS

11.7.7 PRESSURE LIMITATIONS

The pressure limitations in a well control operation that must be considered are the
casing and the formation at the casing shoe. In offshore wells, the integrity of the
formation will normally be the downhole failure point. An exception to this could be if lost
returns with underground flow occurred after taking a kick and the hole was allowed to fill
with gas. This could allow the casing or BOPs to be exposed to formation pressure.

CASING SHOE INTEGRITY

The equivalent mud weight that the casing shoe can withstand is determined from the
Casing Seat Pressure Integrity Test (PIT). This test is extremely important while drilling
the well because many critical operational decisions such as casing setting depths and
alternatives during well control operations are based on this value. The calculation for
determining the maximum allowable surface pressure to avoid formation fracturing is
based on that value.
For Example:
Maximum Allowable = (PIT - Current MW) (Csg. Shoe TVD) (0.052)
Surface Pressure (psi) = (13.2 - 12.2) (8100) (0.052)
= 425 psi

CASING BURST
The maximum allowable surface pressure on the casing should be calculated for each
change in casing type in a casing string with different weights and grades, and the
lowest value used. The weak point in the casing is usually at the bottom of the lowest
grade and weight of pipe in the string. The lower of the two values for the casing or the
casing shoe will determine the estimated surface pressure for downhole failure. Usually
the casing shoe will govern.
For casing strings with extensive drilling or tripping hours, additional consideration
for casing wear should be considered in the burst calculation. Misalignment in
particular may be a problem on deepwater wells due to the possible wellhead
angle or rig offset. Casing wear is also caused from deviated holes, doglegs,
coarse hardbanding, and corrosion.

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WELL CONTROL OPERATIONS

11.8 WELL KILL OPERATIONS

Well killing techniques using a subsea blowout preventer stack have several unique and
different operations. The mechanical hookup of the subsea blowout preventer stack
causes a problem that is unique to floating operations. Namely, the equivalent circulating
density of the system with the preventers closed (even with the choke wide open) is
radically different than during normal circulation.
The primary cause of the problem is the friction pressure losses associated with
circulating through small diameter subsea lines from the blowout preventers to the choke
manifold. This additional friction pressure, if not compensated for, could exceed the
formation integrity at the ca sin g sh o e a n d ca u se lo st re tu rn s. T h e m e th o d s (i.e ., D rille rs,
Weight and Wait, Bullhead, etc.) used to kill a well from a floating drilling rig are the
same as used for land, platform or jackup rigs. Even though the methods are the same,
each method requires special considerations and procedures when used from a floating
drilling rig.

11.8.1 MUD WEIGHT CHOICES

When pre-planning for potential well control problems, a kill procedure should be
selected based on choke line(s) friction pressures at selected kill rates, and the fracture
tolerance of the wellbore. It may be desirable to use both choke and kill lines for
circulation. Whichever method is selected, it should ensure the following:
Minimum back-pressure is added to the system during well control to prevent
wellbore fluid entry and lost returns.
Kill well at selected circulation rate, recognizing that radical changes in surface
pressure may occur when gas enters the choke line(s).
Minimize shut-in periods to reduce the possibility of increased casing pressure
from bubble migration and the possibility of hydrates forming.
Surface equipment may impose limitations on the kill rate.
Normally there are three choices for a mud weight to use when circulating out an influx:
Original (Drillers) Mud Weight.
Balance Mud Weight.
Overbalance Mud Weight.
T h e D rille rs m e th o d fa cto rs a ffe ctin g th e m u d w e ig h t ch o ice a re th e ca p a city o f th e rig s
mud mixing equipment, the strength of the casing seat, weight material on hand and
time required to weight up the mud. Any one of these may be the controlling factor for a
particular condition.

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WELL CONTROL OPERATIONS

ORIGINAL MUD WEIGHT (D R IL L E R S M E T H O D )

The kick can be circulated out using the original mud weight, and then kill weight mud
circulated around to complete the killing operation. This approach offers the advantages
of relative speed and simplicity, but will result in a higher maximum surface pressure
than other methods.

BALANCE MUD WEIGHT (WEIGHT AND WAIT METHOD)

Pumping balance weight mud from the beginning of the operation will result in the lowest
surface pressures
(Figure 11.4)
possible. This
method has the
advantage of
balancing the
formation pressure
and removing the
influx from the well in
the least amount of
time. Any excess
mud weight (i.e.,
safety factor, trip
margin, etc.) above
the balance weight
mud will increase the
casing pressure
during the killing
operation, due to the
U-tube effect, and is
not recommended. Figure 11.4 Annulus Pressures for Various Mud Weight Choices

OVERBALANCE
MUD WEIGHT
In some circumstances, where sufficient integrity at the casing shoe is available, the well
may be circulated by adding a couple of additional points of mud weight to provide the
overbalance kill mud weight. This method would remove the influx and add the
overbalance pressure needed to trip and operate during the first circulation. Caution
should be taken if this method is selected, the additional u-tube pressure added could
cause formation breakdown. This method should not be selected solely on the fact that a
quicker well kill will occur. Field experience has proved that more than one circulation is
generally necessary to remove all of the gas from the annulus.

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WELL CONTROL OPERATIONS

11.9 CIRCULATING OUT AN INFLUX

Although the concepts are the same when circulating out an influx on a floating rig as on
a rig with a surface BOP stack, the friction from the choke line requires a different
technique to initiate circulation. The technique to initiate circulation and compensate for
C L F P is d e scrib e d b e lo w fo r th e first a n d se co n d circu la tio n o f th e D rille rs m e th o d . T h e
technique for the Weight and Wait method would be the same as the second circulation
fo r th e D rille rs m e th o d .
The same as surface stack well control techniques, the casing pressure is used to
establish circulation, but the pressure relationships in the annulus (casing pressure) are
not predictable during continued circulation because of the presence of formation fluid.
The casing pressure required to maintain a constant bottom-hole pressure depends on
the type of formation fluid and a changing vertical length of formation fluid in the annulus.
Under actual conditions, neither the exact type or height of the formation fluid is
known. Therefore, drill pipe pressure control should always be used to keep constant
bottom-hole pressure when circulating the kick out of the annulus. In the drill pipe, mud
weight is known and the drill pipe pressure can be read on the gauge. These factors,
when properly used determine bottom-hole pressure with certainty.
During circulation of the kick, gas expansion and the resulting increase in pit volume
must be allowed. As drilling fluid volume in the annulus decreases from gas expansion,
higher casing pressures are necessary to keep a constant bottom-hole pressure. The
necessary pit volume and casing pressure increases will result automatically at all times
if the correct drill pipe pressure is held.
When a kick occurs while drilling, gas flows into the circulating drilling fluid and a mixture
occurs. While circulating the kick out of the well, the gas generally rises faster than the
drilling fluid. Because the drilling fluid flow rate outside the drill string is not the same at
all points across the hole, some gas will be pushed ahead during the circulation and
some will lag. As a result of this distribution of influx gas, casing pressures predictions
are not exact since in most cases a single bubble is not really going to happen.
Fortunately, the peak casing pressure that can be expected will be some-what less than
predicted. Due to unknown hole geometries and slow annular velocities, some additional
volume of drilling fluid must be pumped before the well will be completely free of the
influx.
T h e D rille rs M e th o d is th e sim p le st te ch n iq u e fo r co n tro llin g kicks. A s th e a n n u lu s ch o ke
is adjusted to maintain a constant drill pipe pressure, gas, if present, will expand in the
proper manner. The correct wellbore pressure relationships are maintained at all times
by this method of control and the procedure is readily adaptable to field operations in all
cases where the bit is near the bottom of the well.

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WELL CONTROL OPERATIONS

1. ESTABLISHING CIRCULATION - USING INACTIVE LINE

PRESSURE GAUGE
To establish a steady circulating rate while keeping a constant bottom-hole pressure, the
pump should be brought up to the pre-selected kill rate while holding a constant casing
pressure on the inactive circulating line pressure gauge equal to the shut-in pressure
(Figure 11.5).

Figure 11.5 Wellbore at Figure 11.6 Wellbore Press.

Shut-in Condition Circulating at Kill Speed

The recommended procedure is as follows:

Concurrently open the annulus choke on the active circulating line and slowly bring the
pump up to selected speed (kill rate).
While bringing the pump up to speed, adjust the choke on the active line to hold the
casing pressure constant on the inactive line pressure gauge (Figure 11.6). Holding the
casing pressure constant on the inactive line pressure gauge for the short time required
to bring the pump up to speed, will essentially maintain a constant bottom-hole pressure.

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WELL CONTROL OPERATIONS

With the pump running at the desired constant speed and the casing pressure
stabilized on the inactive line pressure gauge at the desired value, read the drill pipe
pressure.

Note: The drill pipe pressure read at this point is that pressure necessary to
maintain a constant bottom-hole pressure.

The difference between the shut-in and pumping drill pipe pressure is the pressure
required to circulate the drilling fluid at the desired rate. While maintaining the casing
pressure constant on the inactive line pressure gauge, the casing pressure on the active
line pressure gauge will decrease by an amount equal to the choke line friction pressure.
Note: Changes in pressure due to choke manipulation require approximately two
seconds per 1,000 ft of drill string to register on the stand pipe gauge; however, this lag
in response time can be longer if a large gas kick is present.
Keep the stabilized drill pipe pumping pressure constant by manipulating the annulus
choke while continuing to maintain the same CONSTANT pump rate.
Any change in bottom-hole pressure will be seen as a change in drill pipe pressure and
can be corrected by manipulating the annulus choke, since the mud density remains
constant in the drill pipe.

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WELL CONTROL OPERATIONS

2. ESTABLISHING CIRCULATION - WITHOUT USING INACTIVE

LINE PRESSURE GAUGE
This method would be used when the inactive line is not available or when both lines are
used for circulation during a well kill operation. To establish a steady circulating rate
while keeping a constant bottom-hole pressure, the pump should be brought up to the
pre-selected kill rate while decreasing the shut-in casing pressure on the active
circulating line by the amount equal to the choke line friction pressure. This pressure
would then be held until the pump kill speed is reached. The initial drill pipe circulating
pressure would then be determined.
Example (Refer to Figure 11.7):
Initial Shut-in Casing Pressure (SICP) = 425 psi
Initial Shut-in Drill Pipe Pressure (SIDPP) = 210 psi
Slow Pump Pressure at 3 bpm, Kill Rate (SPP) = 120 psi
Choke Line Friction Pressure with Current Mud Weight (CLFP) = 140 psi.
Initial Circulating Casing Pressure = SICP - CLFP = 425 -140 = 285 psi
Choke line friction pressures were recorded before drilling below the current casing shoe
and corrected for any mud weight changes.
Estimated Initial Drill Pipe Circulating Pressure = SPP + SIDPP = 120 + 210 = 330 psi

Figure 11.7 Wellbore Pressures at Figure 11.8 Wellbore Pressures Circulating at

Shut-in Condition without Inactive Line Kill Speed without Inactive Line

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

Concurrently open the annulus choke on the active circulating line and slowly bring the
pump up to selected speed (kill rate).
1. While bringing the pump up to speed, adjust choke to hold the casing pressure at
285-psi (SICP - CLFP) on the active line pressure gauge (Figure 11.8). This will
essentially maintain a constant bottom-hole pressure.
2. With the pump running at the desired contact speed and the casing pressure
stabilized at 285 psi on the active line pressure gauge, read the drill pipe pressure.
The drill pipe pressure read at this point is that pressure necessary to maintain
a constant bottom-hole pressure. The difference between the shut-in and pumping
drill pipe pressure is the pressure required to circulate the drilling fluid at the desired
rate, the initial drill pipe circulating pressure.

Note: Changes in pressure due to choke manipulation require approximately 2

seconds per 1,000 ft of drill string to register on the drill pipe gauge. This lag
response time can be longer if a large gas kick is present.
3. Keep the stabilized drill pipe pumping pressure constant by manipulating the annulus
choke while continuing to maintain the same CONSTANT pump rate. Any change in
bottom-hole pressure will be seen as a change in drill pipe pressure and can be
corrected by manipulating the annulus choke, since the mud density remains
constant in the drill pipe.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
 WELL CONTROL OPERATIONS

4. DISPLACING THE WELL WITH BALANCE WEIGHT MUD

(D R IL L E R S M E T H O D )
After circulating out the kick without increasing drilling fluid density as described, the well
should be shut-in and the drilling fluid density increased in the pits to the kill weight
(Figure 11.9). Circulation of the kill weight fluid down the drill pipe at a constant rate will
change both the circulating pressure and the hydrostatic pressure (Figure 11.10). A
pressure reduction schedule is generated for the strokes required to displace the drill
pipe as a result of the change in hydrostatic as the balance weight fluid is pumped down
the drill pipe.

Figure 11.10 - Original Mud Weight in Hole

Figure 11.9 - Influx Removed Well Shut-in
Influx Out, Circulating at Kill Speed

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WELL CONTROL OPERATIONS

Calculations
1) IFP = IDPCP - SIDPP = 330 - 210 = 120 psi
2) FDPCP = IFP X (KMW/OMW) = (120)(11.0/10.0) = 132 psi
3) FDPFP = IDPCP - FDPCP = 330 - 132 = 200 psi
4) PSI decrease per increment = FDPFP/10 = 20 psi
IDPCP = Initial Drill Pipe Circulating Pressure
SIDPP = Shut-in Drill Pipe Pressure
IFP = Initial Friction Pressure
KMW = Kill Mud Weight
OMW = Original Mud Weight
FDPCP = Final Drill Pipe Circulating Pressure
FDPFP = Final Drill Pipe Friction Pressure

Next the stroke per increment is calculated for the pressure reduction.
Drill String Capacity = 171 bbls
Pump Output = 0.120 bbls/stk
Strokes to Displace Drill Pipe = 171/0.120 = 1425 stks
Strokes per Division = 1425/10 = 142

A schedule is then prepared showing a 20 psi decrease in the drill pipe circulating
pressure every 142 strokes.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

As the kill weight mud is pumped from the surface to the bit, downward adjustments are
made to the drill pipe pressure based on the schedule above. When the balance weight
mud reaches the bit, the final pressure of 132 psi will be held until the annulus is
displaced with balance weight fluid (Figure 11.11).
As the annulus is displaced with balance weight fluid, the casing pressure will decrease
to zero psi. As the casing pressure becomes less than the CLFP, the choke will be
completely open and the choke operator will not be able to compensate for the CLFP
(Figure 11.12). The drill pipe and bottom hole pressure will increase by 154 psi, an
amount equal to the CLFP adjusted for the new mud weight.

Figure 11.12 - Balance Weight Mud at

F igure 1 1 .1 1 B alance W eight M ud Figure 11.12 Balance Weight Mud at
Choke Circulating at Kill Speed, Unable to Choke
at Bit Circulating at Kill Speed
Circulating at Kill Speed, Unable to
Compensate for CLFP

Compensate for CLFP

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

11.10 GAS HYDRATES

During deepwater well control operations, hydrates can form in the choke/kill lines or in
the BOP stack when natural gas and water in the drilling mud combine under certain
combinations of low temperature, high pressure, and a sufficiently long shut-in period.
The hydrates develop into solids that are capable of blocking choke and kill lines,
jamming BOP equipment, and sticking drill pipe. Although incidents of hydrate formation
have not been frequent, they have been very costly. The problem is more likely in
deeper water operations due to the increasing pressure and decreasing temperature.
For a water depth of 2,000 ft with a 10.0-ppg hydrostatic pressure, the hydrate
equilibrium temperature for methane is 48 degrees, 2 degrees over the typical seafloor
temperature at that depth. In 4,000 ft of water the equilibrium temperature is 61 degrees,
20 degrees over the typical seafloor temperature of 41 degrees for that water depth.
The formation of hydrates is also dependant on time since chemically it takes a certain
amount of time for the hydrate to form and the circulating temperature of the mud is
greater than the seafloor temperature. For mud systems that have a high potential for
hydrate formation, it is best to initiate circulation as soon as possible during a well
control incident to minimize the cooling of the drilling fluid. For prevention of hydrates
d u rin g w e ll co n tro l o p e ra tio n s, th e D rille rs m e th o d sh o u ld b e se le cte d to m in im ize th e
time for hydrate formation.
Pictured below are hydrates recovered from tubing used during a well test on an
exploration well. The hydrates formed in the tubing at about 3,000 ft below sealevel and
plugged the tubing. The tubing had to be retrieved to the surface where the reduced
pressure and increased temperature caused the hydrates to disassociate allowing them
to be removed. Under similar conditions, hydrates have plugged choke/kill lines and
required the LMRP to the retrieved to remove the hydrates. Caution should always be
taken when retrieving choke and kill lines plugged with hydrates since the pressure
released by the gas from the hydrates can cause the plug to be blown from the lines and
possibly cause injury to personnel.

Figure 11.13 Hydrates Recovered from Tubing during Production

Test

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

11.11 TRAPPED GAS REMOVAL

Gas trapped in a subsea blowout preventer can be a serious problem in floating drilling.
Depending on BOP outlet placement, as much as eight bbls of gas can be trapped at kill
fluid hydrostatic pressure beneath a closed BOP and above the BOP outlet used to
circulate out an influx. After a kick has been successfully controlled, improper handling of
this trapped gas can have serious implications.
The key to preventing a trapped gas problem is removal of the gas through a choke or
kill line rather than allowing the high-pressure gas to migrate up the riser. The trapped
gas problem can also be minimized by reducing the trapped gas volume that must be
removed after a kick by either circulating out the influx using a pipe ram or through an
outlet directly beneath the annular preventer.
In order to use the trapped gas removal procedure, the subsea stack must be arranged
with outlets for both the choke and kill lines above the lowest set of rams. This will
isolate the open hole and provide a method to circulate across the stack through the
choke and kill lines.
The recommended procedure for removal of trapped gas is to reduce the hydrostatic
pressure in the choke/kill line to allow the gas to expand and vent through the choke/kill
line.
Note: If the hydrostatic pressure in the choke/kill line is reduced to less than the
seawater hydrostatic pressure on the outside of the ram preventer, the differential
pressure may cause the BOP bonnet gasket to leak since they have a very low
external pressure rating.
This is accomplished by circulating a lightweight fluid under kill weight equivalent
pressure down both choke and kill lines. The fluid must be circulated under
backpressure to keep the bubble from expanding. Bleeding the choke line pressure off
after displacing the line with lighter weight fluid allows the gas bubble to expand,
unloading the majority of fluid from the choke line. Pressure of the trapped gas is thus
reduced to the hydrostatic head of the residual fluid remaining in the choke line.
If backpressure had not been held, the bubble would have expanded during circulation,
resulting in a bubble that was pressure equivalent to the full column of water in the
choke line. It would have been impossible to reduce the pressure of the gas from the
water hydrostatic to near atmospheric pressure. After the trapped gas has been reduced
to near atmospheric pressure, the choke and kill lines can be filled with mud. The
remaining small volume of low pressure trapped gas can be removed from the well by
opening the BOP (diverter closed), allowing mud in the riser to U-tube and displace the
remaining gas and water in the choke line to the choke manifold.
The diverter should remain closed in the event some gas enters the riser when the BOP
is opened, and a ram should be closed below the choke line outlet to prevent a possible
well influx.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

Field studies indicate that a 300-psi differential from the mud filled riser to the fluid in the
choke line would cause displacement of the remaining trapped gas into the choke line.
Displacement of the gas at lower differential pressure is untested, however displacement
efficiency will probably decline with declining pressure differential. With shallow water or
low mud weight, obtaining a large pressure difference may not be possible especially if
the rig does not have a riser boost line to displace the riser with kill fluid before opening
the annular.
Since the potential for forming hydrates when displacing trapped gas with freshwater is
likely, a hydrate-inhibited fluid should be used. If gas does enter the riser above the
BOPs, field-testing has shown that it is important to allow the gas to migrate to the
surface without pump in g . T h is w ill te n d to strin g o u t th e g a s a n d ke e p it in sm a ll
bubbles in the riser. Small bubbles can be handled safely because they surface slowly
and do not displace mud from the riser (mud slips by small bubbles in the riser).
After allowing adequate time for gas to migrate to the surface, the riser must be
circulated to remove any residual gas. This circulation should be performed at a very
slow rate. The time required for gas bubbles to migrate to the surface will depend on
several factors including mud properties, water depth, and gas bubble characteristics
(number, size, and initial pressure). Field testing in equivalent 1350-ft. water depth
indicated gas bubbles would require at least 30 minutes to migrate to the surface.
A minimum of a 30-minute waiting period should be used for comparable water depths.
In general, a longer waiting time should be used for deeper water depth.
Included at the end of this section is an example of a rig specific (choke/kill line
configuration specific) procedure to remove trapped gas.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

11.11.1 TRAPPED GAS REMOVAL PROCEDURE

The following is an example procedure designed to remove gas trapped in a subsea
BOP stack between an annular preventer and choke outlet, after circulation of a kick. A
rig specific trapped gas removal procedure should be generated and performed after
every deepwater well control occurrence.
This procedure is designed for one particular BOP stack arrangement. Other stack
arrangements would require slight modifications to the procedure, but the basic
technique and order of steps should not change.
1. Calculate required back pressure (BP) with the following equation:
BP = (KM - DF) x 0.052 x WD
KM = Kill Mud in PPG
WD = Water depth, ft.
DF = Displacement Fluid in PPG
2. Make sure all subsea choke-and-kill valves (inner and outer) are closed except
for upper choke valves, which should both be open (Figure 11.14).
Note: Gas should be removed from stack via uppermost stack outlet. Using a
lower outlet will reduce the effectiveness of the procedure.

9.11.12 CIRCULATE MUD BETWEEN LINES

3. Space out drill pipe. Close #3 rams and hang-off the drill pipe (Figure 11.15). Monitor
closing fluid volume to verify ram closure.

Note: Choice of rams is dictated by need to circulate between choke and kill lines,
above closed rams.
4. Open both upper kill-line valves. At this point, both valves on each of the upper
choke-and kill lines (above the closed rams) are open. Rig up to take choke line
returns through choke manifold and mud gas separator.
5. Rig up cement pump to kill line.
6. With cement pump, circulate unweighted mud at 2 bpm down kill line, across stack,
and up choke line (Figure 11.16). Hold backpressure on choke line as calculated in
Step 1. Continue to circulate until both choke-and-kill lines are filled with unweighted
mud.

Note: Unweighted mud or a gel pill should be used to displace weighted kill mud
from lines to avoid barite settling when water is pumped. This step also ensures a
clear flow path across the stack.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

11.11.3 CIRCULATE WATER BETWEEN LINES

7. With the cement pump, circulate reduced weight fluid at 1 bpm down kill line, across
stack, and up choke line (Figure 11.17). (Note: If freshwater is not available, use
seawater.) Hold backpressure on choke line as calculated in Step 1. Continue to
pump until both choke and kill lines are displaced. After displacing lines, shut-in
choke and kill lines at surface.

Note: If the cement unit has been previously targeted to pump down the choke line,
the procedure can be varied as follows: pump water down choke line to stack taking
mud returns out kill line. Hold backpressure on kill line. Do not overdisplace choke
line. After displacement, shut-in choke and kill lines at surface.

Note: In deepwater application, a hydrate-inhibited fluid rather than freshwater

should be used.

Note: If a riser boost line is available, raise riser mud weight to kill mud weight.
8. Close both upper kill line subsea valves. All valves should now be closed except for
upper choke line valves, which should be open. Bleed off pressure on kill line.

11.11.4 TAKE GAS RETURNS UP CHOKE LINE

9. Route choke line returns directly overboard.
10. Open choke line at surface (Figure 11.18). If possible, observe returns through
overboard line. Returns should consist of water, gas, and possibly some of the mud
in the stack. The maximum amount of mud returns would be the volume between the
annular BOP and the choke line. Greater mud returns would indicate leaking rams.
11. Leave choke line open and continue to monitor returns. It may take 15-30 minutes
before gas reaches the surface. Return flow may start and stop several times during
this process. After a minimum 30 minutes waiting period, but not before all flow has
died, proceed with remaining steps.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

11.11.5 REMOVE REMAINING GAS FROM STACK

12. Ensure that riser is full of mud. Make sure diverter is lined up overboard. Choke line
should remain routed overboard.
13. Close diverter.
14. Open #1 (upper) annular (Figure 11.20). Gas remaining below annular may begin
rising, or it may be pushed into open choke line. Choke line returns should consist of
water, gas and mud.
15. Observe diverter outlet and choke line return flow for 15-30 minutes. If both are
dead, go to next step. If either is flowing, allow it to continue to flow until all gas has
surfaced and riser and choke line are both static. Flow out choke line will cease
when mud levels in choke line and riser are equal and all gas has been removed
from choke line. Gas in the riser may require several hours to migrate to the surface,
depending on mud properties and water depth.
16. Function #3 ram to ensure there is no gas in the ram cavity.

11.11.6 CIRCULATE RISER

Note: The order of circulating riser and choke/kill lines is unimportant and may even
be done in tandem. Regardless of the order, the safety precautions given in this
procedure should be followed.
17. Rig up mud pump to kill line.
18. Close both upper choke line valves (Figure 11.21).
19. Open both upper kill line valves.
20. Open diverter and rig up to take riser returns through separator to shakers.
21. With rig pump, circulate kill-weight mud down kill line and up riser. Be prepared to
divert riser returns overboard. Watch for increased return flow as a signal of gas
expansion in the riser. If flow becomes excessive, or if any gas reaches surface, stop
pumping, close diverter, and divert returns overboard. Do not resume pumping until
riser is static. Stop pumping and check for flow several times during riser
displacement.
22. After displacing kill line and riser, continue circulating for approximately 50 additional
barrels. Watch for increased return flow, as before.
23. Stop pump and observe riser for 10 minutes, to be sure all gas has cleared riser and
riser is static.
24. Close #1 annular.

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WELL CONTROL OPERATIONS

11.11.7 CIRCULATE MUD BETWEEN LINES

25. Route choke line return flow through separator to shakers.
26. Open both upper choke line fail-safe valves.
27. Circulate kill-weight mud down kill line, through stack and up choke line. This will
remove any gas left in the choke line (Figure 11.22). Take choke line returns through
separator, but bypass separator and divert overboard if a solid flow of gas reaches
surface.
28. Pump one full choke line volume after kill-weight mud returns are noted at choke line
to ensure all gas and water has been removed from lines.
29. Stop and monitor choke/kill lines to be sure they are both full of mud and static.
30. Close all upper kill and choke valves. All subsea valves should now be closed.

11.11.8 CIRCULATE WELL THROUGH CHOKE

31. Open both lower choke line valves to monitor well below #3 rams (Figure 11.23).
Make sure well is dead. Close both lower choke line valves. All valves should now be
closed.
32. If hung off, pick up drill-string weight off #3 rams. Do not open rams yet.
33. Open both upper choke line valves to circulate well from TD.
34. Open #3 rams.
35. With rig pump, circulate down drill pipe and take returns out choke line through
separator. Circulate bottoms up (Figure 11.24). Flow check according to normal
procedures.

Caution: Gas may become trapped in stack any time gas is circulated from wellbore
below a closed annular BOP. Repeat trapped gas procedure any time gas is
circulated from wellbore.
36. Observe well to be sure kill is completed. Open #1 annular, and then close both
upper choke line valves. Proceed with normal post-kick operations.

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WELL CONTROL OPERATIONS

Figure 11.16 Figure 11.19

Figure 11.15 Figure 11.18

Figure 11.14 Figure 11.17

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WELL CONTROL OPERATIONS

Figure 11.22

Figure 11.21 Figure 11.24

Figure 11.20 Figure 11.23

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL CONTROL OPERATIONS

11.12 REFERENCES
IADC Deepwater Well Control Guidelines: First Edition October 1998
Exxon Company International, Floating Drilling Blowout Prevention and Well Control
Manual: Revision 1, 1997

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

12
Section

12.0 EMERGENCY DISCONNECT

OBJECTIVES
On completion of this lesson, you will be able to:

List the essential functions of an Emergency Disconnect Sequence.

List the reasons why an emergency disconnect is required.

Describe the alarms used on a typical rig for an emergency disconnect.

Use a graph from a drive off/drift off analysis to determine the alarm setting for an
emergency disconnect.

List the hourly checks that must be made between the Driller and the DP Operator to
confirm that the emergency disconnect alarms are operational.

Calculate drill pipe spaceout for hanging off the drill pipe.

List the emergency disconnect procedures that are typically used for non-routine
operations.

List the important items to confirm during emergency disconnect and hang-off drills.

Describe why the motion compensator should be used during an emergency

disconnect.

List the steps to re-enter the well after the drill pipe has been hung off and sheared.

Describe a typical fishing assembly used to fish the sheared drill pipe from the BOP
stack.

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EMERGENCY DISCONNECT

CONTENTS Page

12.0 EMERGENCY DISCONNECT............................................................................................................... 1

OBJECTIVES ........................................................................................................................................ 1
CONTENTS........................................................................................................................................... 2
12.1 INTRODUCTION ................................................................................................................................... 3
12.2 SEQUENCE AND TIMES...................................................................................................................... 4
12.3 ALARMS ............................................................................................................................................. 10
12.4 DETERMINING SPACEOUT AND DRILLPIPE HANGOFF ............................................................... 15
12.0 OPERATING PROCEDURES AND DRILLS ...................................................................................... 18
12.5.1 PERSONNEL ....................................................................................................................... 19
12.5.2 DRILLS ................................................................................................................................ 20
12.6 ACTIVATING THE EMERGENCY DISCONNECT SEQUENCE ........................................................ 21
12.7 MOTION COMPENSATION ................................................................................................................ 23
12.8 WELLBORE REENTRY ...................................................................................................................... 24
12.8.1 WELL CONTROL CONSIDERATIONS ............................................................................... 26
12.8.2 FISHING ASSEMBLY ........................................................................................................... 27
12.9 APPENDICES ..................................................................................................................................... 29
APPENDIX I: EDS - GENERAL ................................................................................................................... 29
APPENDIX II: EMERGENCY DISCONNECT PROCEDURES - DRILLPIPE ACROSS BOP ...................... 33
APPENDIX III: EMERGENCY DISCONNECT PROCEDURES - BHA ACROSS BOP ................................. 35
APPENDIX IV: EDS PROCEDURES - CEMENTING CASING ...................................................................... 37
APPENDIX V: EDS PROCEDURES - CASING ACROSS BOP ................................................................... 39
APPENDIX VI: EDS PROCEDURES - WIRELINE ACROSS BOP ................................................................ 41
APPENDIX VII: EDS PROCEDURES - WELL TESTING................................................................................ 42
APPENDIX VIII:EDS PROCEDURE - CEMENTING OPEN HOLE PLUGS .................................................... 44
APPENDIX IX: EDS PROCEDURES - STUCK PIPE ..................................................................................... 46
APPENDIX X: EDS PROCEDURES - TESTING BOP .................................................................................. 48
APPENDIX XI: EDS PROCEDURES - WELL CONTROL ............................................................................. 50

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EMERGENCY DISCONNECT

12.1 INTRODUCTION
When operating from a dynamically positioned rig, systems and procedures to secure
the wellbore and disconnect the LMRP from the BOP stack are required to protect the
well and equipment should the rig drive off or drift off from location. This section will
provide information on the systems and procedures used to perform an emergency
disconnect and re-entry of the wellbore afterwards.

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EMERGENCY DISCONNECT

12.2 SEQUENCE AND TIMES

During the construction of the BOP stack and control system, a list of critical functions
to operate during an Emergency Disconnect Sequence (EDS) is developed and
programmed into the control system software. Along with each function to operate, a
sequence is developed using appropriate time to initiate each function based on the
actual recorded time for each function to operate. During the initial function testing of
the BOP stack and control system, actuation times are recorded while simulating actual
operating conditions and pressure losses for the system at maximum water depth.
Shear tests are performed with the actual drill pipe that will be used. Test pressures
and times are recorded to determine the increased time for the preventer to actually
shear the pipe.

Listed in Table 12.1 are the typical items that are normally included in a EDS, but this list
will vary immensely depending on the BOP stack and control system.

Required Function Purpose of Function

Rapid BOP Regulator Manifold Required to shear the drill pipe unless the shear rams are
Pressure Increase equipped with a separate regulator
Blind shear close Required to shear the drill pipe and seal the wellbore
Blind Shear Lock Secures the blind shear ram in the closed position may not be
required for some manufacturers.
Middle pipe ram lock closed Provides lock pressure to the hang-off rams. Rams should have
previously been closed and locked by Driller, this is precautionary
to ensure that the pipe is not dropped.
Close all stack mounted failsafe Secures all choke and kill outlets prior to disconnect.
valves
Vent all stack functions and the Pressure must be vented to allow the POD stack stinger to be de-
upper annular energized and retracted prior to the LMRP being disconnected.
Choke/Kill line connectors unlatch Connectors must be unlatched before the LMRP can separate
from the BOP stack.
Riser Recoil Energize Prepares the riser recoil for the disconnect.
Stack stinger seals de-energize De-energizes the male POD stinger from the female receptacle on
the BOP stack.
Riser connector primary and Both primary and secondary are used to provide the maximum
secondary unlatch unlocking force and to provide a backup should one system fail to
function.
Upper Annular open Ensures that the annular is open during LMRP lift off.

Table 12.1 Critical Operations of an Emergency Disconnect Sequence

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

Listed in Table 12.2.1 through 12.2.2 is an actual disconnect sequence, for the Glomar
Ja ck R ya n , u se d d u rin g th e n o rm a l d isco n n e ct w h e n sh e a ra b le ite m s a re a cro ss th e
BOP stack.
Note that actuation times are sequenced for critical functions to allow them to fully
actuate before the next critical function is actuated (e.g. shear ram vent is 28 seconds
after shear ram close).

Table 12.2.1 N orm al E m ergency D isconnect S equence from Glomar Jack Ryan
Elapsed Function Action Comment
Time, sec
0 Start Emergency Disconnect Initiated on control surface panel.
0 Rapid BOP Regulator Increase Increase Increases BOP manifold pressure to 3000 psi
0 Enable Deadman Enables DM Enables the deadman system electrically
0 Blind Shear Close Close Blind Shearing Rams
0 Choke Line Connector Vent Vents "latch" side of kill line connector
0 Kill Line Connector Vent Vents "latch" side of choke line connector
0 Riser Connector Vent Vents "latch" side of riser connector
0 Blind Shear ST Lock Lock Locks ST-Locks on Blind Shearing Ram. Sequence valves inside
bonnets prevent locking until rams close

0 MPR ST Lock Lock Same as above - this is precautionary, only needed if Driller fails
to manually lock ST locks after closing rams.

0 Lower Inner Choke Valve Close Closes lower inner choke valve
0 Lower Outer Choke Valve Close Closes lower outer choke valve
0 Upper Inner Choke Valve Close Closes upper inner choke valve
0 Upper Outer Choke Valve Close Closes upper inner choke valve
10 Lower Inner Kill Valve Close Closes lower inner kill valve
10 Lower Outer Kill Valve Close Closes lower outer kill valve
10 Upper Inner Kill Valve Close Closes upper inner kill valve
10 Upper Outer Kill Valve Close Closes upper outer kill valve
10 Lower Annular Vent Vents pressure from opening & closing sides
10 Upper Annular Vent Vents pressure from opening & closing sides
10 Casing Shear Vent Vents pressure from opening & closing sides
10 Upper Pipe Ram Vent Vents pressure from opening & closing sides
10 Middle Pipe Ram Vent Vents pressure from opening & closing sides
10 Lower Pipe Ram Vent Vents pressure from opening & closing sides
20 Kill Line Connector Unlatch Unlatches kill line connector
20 Choke Line Connector Unlatch Unlatches choke line connector
20 Lower Inner Choke Valve Vent Vents lower inner choke valve closing pressure
20 Lower Outer Choke Valve Vent Vents lower outer choke valve closing pressure
20 Upper Inner Choke Valve Vent Vents upper inner choke valve closing pressure

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

20 Upper Outer Choke Valve Vent Vents upper outer choke valve closing pressure
20 Lower Inner Kill Valve Vent Vents lower inner kill valve closing pressure
20 Lower Outer Kill Valve Vent Vents lower outer kill valve closing pressure
20 Upper Inner Kill Valve Vent Vents upper inner kill valve closing pressure
20 Upper Outer Kill Valve Vent Vents upper outer kill valve closing pressure
28 Blind Shear Ram Vent Vents closing pressure from blind shear ram
28 Blind Shear Ram ST-Lock Vent Vents closing pressure from blind shear ram ST-Lock
28 Subsea Accumulator Vent Vents deadman fluid supply line between bottles & pods
30 Stack Stinger Seals De-energize De-energizes stack stinger seals.
36 LPR - ST Lock Vent Vents pressure rams and locks could be closed
36 MPR - ST Lock Vent Vents pressure rams and locks could be closed
36 UPR - ST Lock Vent Vents pressure rams and locks could be closed
36 Riser Recoil Fire Initiates Riser Recoil System controlling surface tensioners
42 Riser Connector Unlatch Unlatches Riser Connector (primary unlatch)
42 Riser Connector Secondary Unlatch Unlatches Riser Connector (secondary unlatch)
44 Upper Annular Open Opens annular to ensure lift off with tensioners should annular
not open by previously venting.

Table 12.2.2 N orm al E m ergency D isconnect S equence from G lom ar J ack R yan

Early generation multiplex control systems were limited to a single EDS. Newer BOP
multiplex control systems that are software driven offer the capability to have multiple
disconnect sequences that can be selected for various operating conditions. A common
co n fig u ra tio n o n th e n e w e r syste m s is to h a ve tw o E D S se le ctio n s, o n e N o rm a l se ttin g
th a t se cu re s th e w e llb o re w ith th e b lin d sh e a r ra m s a n d a se co n d C a sin g E D S
se le ctio n . T h e C a sin g E D S is u se d w h e n th e B O P sta ck is e q u ip p e d w ith a ca sin g
shear ram (shear only, does not seal) that is used to cut large tubulars and the blind
shear is closed afterwards to seal the wellbore.

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EMERGENCY DISCONNECT

T h e N o rm a l d isco n n e ct se q u e nce would be selected most often since it requires less

time to actuate. The selection of the Casing disconnect for all operations would provide
greater capability for shearing any item that may be in the wellbore, but the additional
time required may also provide watch circles that are not practical. Figure 12.1
illu stra te s a typ ica l w a tch circle fo r a ve sse l. A s a n e xa m p le , th e N o rm a l d isco n n e ct fo r
the Glomar Jack Ryan is programmed for the LMRP connector to unlatch in 42 seconds,
w h ile th e C a sin g E D S allows the LMRP connector to unlatch in 62 seconds. A copy of
th e G lo m a r Ja ck R ya n C a sin g E D S is in clu d e d in Table 12.3.1 through 12.3.2.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

Table 12.3.1 C asing E m ergency D isconnect S equence from G lom ar J ack R yan
Time Function Action Comment
sec
0 Start Casing EDS Initiated on control surface panel. Requires that pods be
engaged and remain functional during EDS
0 Rapid BOP Regulator Increase Increase Increases BOP manifold pressure to 3000 psi
0 Enable Deadman Enables DM Enables the deadman system electrically
0 Casing Shear Rams Vent Vents opening and closing sides of casing shear ram
0 HP Casing Shear Rams Close Closing high pressure casing shear rams with DM bottles
0 Choke Line Connector Vent Vents "latch" side of kill line connector
0 Kill Line Connector Vent Vents "latch" side of choke line connector
0 Riser Connector Vent Vents "latch" side of riser connector
0 Wellhead Connector Vent Vents "latch" side of wellhead connector
0 Lower Inner Choke Valve Close Closes lower inner choke valve
0 Lower Outer Choke Valve Close Closes lower outer choke valve
0 Upper Inner Choke Valve Close Closes upper inner choke valve
0 Upper Outer Choke Valve Close Closes upper inner choke valve - 10 second delay
10 Upper Annular Vent Vents opening and closing sides upper annular BOP
10 Lower Annular Vent Vents pressure from opening & closing sides
10 Upper Pipe Ram Vent Vents pressure from opening & closing sides
10 Middle Pipe Ram Vent Vents pressure from opening & closing sides
10 Lower Pipe Ram Vent Vents pressure from opening & closing sides
10 Lower Inner Kill Valve Close Closes lower inner kill valve
10 Lower Outer Kill Valve Close Closes lower outer kill valve
10 Upper Inner Kill Valve Close Closes upper inner kill valve
10 Upper Outer Kill Valve Close Closes upper outer kill valve - 13 second delay
23 Lower Inner Choke Valve Vent Vents lower inner choke valve closing pressure
23 Lower Outer Choke Valve Vent Vents lower outer choke valve closing pressure
23 Upper Inner Choke Valve Vent Vents upper inner choke valve closing pressure
23 Upper Outer Choke Valve Vent Vents upper outer choke valve closing pressure
23 Lower Inner Kill Valve Vent Vents lower inner kill valve closing pressure
23 Lower Outer Kill Valve Vent Vents lower outer kill valve closing pressure
23 Upper Inner Kill Valve Vent Vents upper inner kill valve closing pressure
23 Upper Outer Kill Valve Vent Vents upper outer kill valve closing pressure
23 Blind Shear Ram Close Closes Blind Shear Ram above Casing Shear Ram
23 Blind Shear Ram ST-Lock Lock Locks Blind Shear Ram with ST-Locks. Sequence valves
inside bonnets ensure lock occurs only after rams close
23 Kill Line Connector Unlatch Unlatches kill line connector

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

23 Choke Line Connector Unlatch Unlatches choke line connector

30 LPR, MPR, LPR ST Lock Vent Vents pressure - rams and locks could be closed
49 Blind Shear Ram Vent Vents closing pressure from blind shear ram
49 Blind Shear Ram ST-Lock Vent Vents closing pressure from blind shear ram ST-Lock
49 HP Casing Shear Rams Vent Vents closing pressure from high pressure casing rams
51 Stack Stinger Seals De-energize De-energizes stack stinger seals.
51 Riser Recoil Fire Initiates Riser Recoil System controlling surface
tensioners 6 second delay
57 Stack Stinger Retract Stack stingers are retracted (both pods) 6 second delay
63 Riser Connector Unlatch Unlatches Riser Connector (primary unlatch)
63 Riser Connector Secondary Unlatch Unlatches Secondary Riser Connector 6 second delay
69 Upper Annular Open Opens annular to ensure lift off with tensioners.

Table 12.3.2 C asing E m ergency D isconnect S equence from G lom ar J ack R yan

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EMERGENCY DISCONNECT

12.3 ALARMS
Along with developing an EDS, a drive off/drift analysis is performed to determine the
vessel offset with the maximum mud weight and environmental (wind, waves, current)
conditions for the proposed location. The EDS times are then combined with the drive
off/drift off analysis to determine the setpoint for the dynamic position (DP) alarms. The
alarm setting is then input to the DP computers as watch circles with an alarm typically
initiated based on vessel offset. Some rigs also have the capability to initiate alarms
based on the upper/lower flex/ball joint angles and/or tensioner stroke, but most just
correlate back to the calculated offset at a particular flex joint angle or tensioner/slip joint
stroke and use the offset position.
T h e m o st co m m o n d e sig n a tio n fo r D P a la rm s is Y e llo w a n d R e d . T h e se a la rm s a re
typically set based on a preselected criteria for vessel offset, thruster output, power
output, wind, seas, current, flex joint angle/tensioner stroke, or loss of DP redundancy.
When the criteria of any of the conditions is reached, the alarm is initiated. An example
of the criteria for each of the conditions used on the Glomar Jack Ryan is listed below in
Table 12.4.
Yellow given when a preselected limiting criteria is reached and requires the Driller to
position and hang-off the drill pipe in preparation for securing the well with the blind
shear rams. For operations when drill pipe is not in the wellbore, other preparations are
to be made by the Driller as discussed in Section 12.5.
Red given when a preselected limiting criteria has been reached that requires the
Driller to actuate the EDS that closes the blind shear ram and unlatches the LMRP
connector.
In a d d itio n , a B lu e A d viso ry is a lso u se d so m e tim e s to sig n ify a d e g ra d e d situ a tio n
where operations may be suspended or systems and/or personnel are positioned for an
enhanced operating environment.
As illustrated in Table 12.4, specific operating criteria for each condition (i.e. red, yellow,
blue) are typically developed for each well location and agreed by ExxonMobil and the
Contractor. This table is then used as a decision tree when problems occur with the DP
system.

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EMERGENCY DISCONNECT

Table 12.4.1 Example - Well Specific Operating Criteria from Glomar Jack Ryan

CONDITION Normal Operating BLUE YELLOW RED ALERT

Parameters ADVISORY ALERT
VESSEL <1.25% of water depth at all Vessel enters the "Blue Vessel's indicated Vessel's indicated position
OFFSET tim es 50 ft. Watch Circle" for more position crosses into crosses into the calculated
than brief or isolated the calculated Yellow RED Alert Circle
periods >1.25% (50 ft) Watch Circle.
> 5% (200 ft)
> 2% (80 ft)

THRUSTER Thruster output with all Thruster output with all Thruster output Thruster output with all
OUTPUT available units on line, available units on line, (excluding bias), with available units on line,
(excluding bias) does not (excluding bias) does all available thrusters exceeds 80% of total
exceed 50% of total not exceed 50% of total on line exceeds 65% available thruster power or at
available thruster power for available thruster power of total available the order of the OIM.
more than brief or isolated for more than brief or thruster power
periods. isolated periods.

POWER With all available With all available With all available With all available generators
OUTPUT generators online, generators online, generators online, online generator steady load
generator steady load does generator steady load generator steady load exceeds 80% of total
not exceed 50% of total does not exceed 50% does not exceed 65% available power for more than
available power for more of total available power of total available brief and isolated periods or
than brief or isolated for more than brief or power for more than at the order of the OIM.
periods. isolated periods. Less brief or isolated
than two engines on periods. On blackout, at the order of
one main buss. the OIM. On blackouts, wind
speeds>40 knots,
immediately Hang-off, Shear
Pipe and Disconnect.
WIND Steady speed < 40 knots, Steady speed < 40 Steady speed greater Speed greater than 70 knots
knots, than 60 knots or at the order of the OIM. On
Gusts < 45 knots blackout, windspeeds >40
Gusts < 45 knots knots, immediately Shear
Pipe and Disconnect.
SEAS Combined seas 15 ft or less Combined seas > 15 ft Combined seas > 20- Combined seas > 30 ft or at
25 ft the order of the OIM.

SURFACE < 2 Knots > 2 knots > 3.0 knots - POOH For surface currents above 4
CURRENT above the BOPs. knots at the order of the OIM.
Stand By until Yellow Pipe to stay above the BOP.
Alert resolved or
deteriorates into a Red
Alert
SLIPJOINT Up to 4 ft of stroke Over 6 ft of stroke due The tensioner stroke The maximum allowable
STROKEOUT to excursion off of criteria limits have tensioner stroke has
location reached the calculated occurred.
yellow alert angle due
to excursion off 11 ft.
location - >8 ft.
FLEXJOINT LMRP< 1.0 degrees Flexjoint angle at the Flexjoint angle at the Flexjoint angle at the LMRP
ANGLE LMRP is more than 1 LMRP has reached has reached the calculated
degree from setpoint the calculated yellow RED alert angle, 3 degrees
due to excursion off alert angle, >1.5 from setpoint due to
12 - 11
EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

CONDITION Normal Operating BLUE YELLOW RED ALERT

Parameters ADVISORY ALERT
location and cannot be degrees from setpoint excursion off location
corrected by re- due to excursion off
positioning the vessel location
DP SYSTEM Under DP control, operating The vessel is under DP Vessel is in DP control DP system failure causes an
normally. All appropriate control but there has but there has been a inability to maintain positional
backup (redundancy) been a failure in the sub failure in the systems, control and vessel drifting
systems are available for - system that has which has left the DP through red watch circle. OIM
use. degraded full DP system in an to be on bridge and oversee
capabilities, operational state but disconnect.
Redundancy still intact. without redundancy.
(i.e. Loss of 2 DGPS
sensors; 2 H.A.
Beacons; I gyro; 1
MRU; or VRU or
something to this
effect).
NOTIFY SCR and Drill floor at tour OIM, Driller, OIM, Driller, OIM, Driller, Toolpusher, Rig
changes will be noted of Toolpusher, Rig Toolpusher, Rig Superintendent, Company
normal operations Superintendent, Superintendent, Man (Ch. Eng, Elec Super,
Company Man, ECR, Company Man (Ch. ET as necessary) when
Subsea Eng. when Eng., Elec Super, ET and/or while the DPO/Driller
and/or while the as necessary) when take appropriate action.
DPO/Driller take and/or while the
appropriate action. DPO/Driller take
appropriate action.
ACTION None required until Blue DPO to activate the DPO to verbally DPO to verbally confirm the
Advisory or Yellow Alert or Blue Alert light. DPO to confirm the alert with alert with the drill floor. Once
Red Alert conditions are verbally confirm the the drill floor. The the alert is authenticated by
reached/experienced, alert with the drill floor. Driller immediately to the DPO, the Driller must
whichever occurs first. DPO to inform Driller of take steps to hang off initiate Disconnect
situation and update as the drill string (if Procedures. Driller advises
needed. The Driller will applicable) and secure the DPO when disconnect
evaluate the current the well. After hanging confirmed. Moonpool to be
operation and formulate off, the Driller and investigate for damage.
a plan which will leave DPO should stay in
the vessel in the safest constant
and most operationally communication as
advantageous position activities allow, and
should the situation evaluate the situation
continue to deteriorate. continuously.
Discuss situation with
all parties.
Mate on Watch to
make announcement
clearing all hands from
moonpool.

Note: The DPO and Driller have in conjunction with each other, when the OIM is not immediately available,
the authority to hang off and disconnect under an emergency condition if the situation such warrants.
The DPO and the Driller should utilize the Mate on Watch and A.D. respectively, to help them in the
notification process, as required.
Table 12.4.2 Example Well Specific Operating Criteria from Glomar Jack Ryan

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EMERGENCY DISCONNECT

A typical drift off analysis is illustrated below with hang-off and EDS times added to
determine the alarm setting for vessel offset.

Jack Ryan - Trinidad - 95% Environment - 17 ppg Mud - Drift-Off

15 0

Offset
LFJ Angle
Offset (%) & Angles (degrees)

Tensioner/Slip Joint Stroke

10 15

Stroke (feet)
5 30

0 45
50 sec
60 sec for
Upper Ball Joint Angle Driller hang- for EDS
off
-5 60
0 50 100 150 200 250 300
Time (seconds)

Figure 12.2 Example Of Drift Off Analysis And Disconnect Criteria

In the illustration above, the disconnect criteria is based on the lower flex joint angle
(LFJA) of 8o since it is the first to reach its limiting criteria. In the example, the LFJA limit
of 8 degrees is reached at 240 seconds after the drift off begins. Based on the EDS in
Figure 12.2, 50 seconds (42 seconds at LMRP unlatch and 8 additional seconds for the
connector to unlatch plus contingency) is required from the time the Driller initiates the
EDS until the LMRP connector unlatches and lifts off the BOP stack. This means that the
red alarm will occur at 190 seconds or 7.3% of water depth offset.
To provide time for the Driller to hang-off the drill pipe, the yellow alarm is set 60
seconds prior to the red alarm at 130 seconds or 3.8% of water depth offset.
The alarm setting and watch circles described above are the maximum settings that
would be used for the drift off analysis and EDS listed above. In addition to the drift off
analysis, a drive off analysis is also performed and the analysis that reaches the limiting
criteria first is used to set the alarms.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

Although the operating conditions will normally be less than those used in the analysis
and may provide additional time, the actual watch circles (alarms) that are used will
typically be set at a more conservative limit. As an example, the yellow alarm setting
may be set at 2% (67 ft offset) and the red alarm set at 5% (270 ft) for the 3381 ft water
depth well above to provide additional time for the Driller to hang-off the drill string and
for the EDS sequence to actuate. This conservative approach typically does not cause
unrequired hang-offs or disconnects since a DP system normally keeps the rig within 20
ft of the well location. Offsets outside of this 20-ft window usually only occur when a
major mishap has occurred, and the rig will continue to the upper limits anyway.
Actual communication of the alarms between the DP control room and the Driller is
accomplished by the following:
Red and yellow fla sh in g lig h ts a t th e D rille rs sta tio n .
Aud io a la rm s a t th e D rille rs sta tio n .
Clear call talk back system to allow the DP Operator and Driller to
simultaneously communicate.
Each tour after the BOP stack is installed, the DP Operator and Driller will test each of
the alarms and communication systems to verify each system is operational.
F o r h ig h e xp o su re o p e ra tio n s su ch a s w e ll te stin g o r w h e n th e C a sin g d isco n n e ct
sequence is to be used, special alarm settings will be substituted for the normal alarms.
For a well test operation where the pipe is already correctly positioned with the subsea
test tree (SSTT) landed in the wellhead, the yellow alarm setting may be reduced to
provide additional time to allow the well to be shut in downhole, the SSTT to be closed,
tubing pressure vented and the test string raised above the shear rams.
For rigs equipped with casing shear rams, the additional function of shearing the casing
with casing shear ram prior to closing the bind shear ram can add 20 to 30 seconds of
additional time to the EDS. In the example above, if the casing EDS required 70
seconds, the red alarm would need to be set at 170 seconds or 6% offset to achieve
unlatch prior to the LFJA of 8 degrees. If the disconnect criteria was not adjusted and the
red alarm was initiated at 7.3% offset (190 seconds), then disconnect would not occur
until 260 seconds when the LFJA had reached 9 degrees and the slip joint/tensioner
stroke out was at 30 ft.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

12.4 DETERMINING SPACEOUT AND DRILLPIPE

HANGOFF
Prior to performing an EDS, the drill pipe must be correctly positioned to ensure that a
tool joint will not be across the blind shear ram. To ensure that the tool joint is correctly
positioned and the assist in re-entry of the wellbore afterwards, a pipe ram is closed and
the drill pipe is hung off on the ram. In shallow water or when working with a surface
BOP stack, tool joint location in the BOP stack is estimated based on average lengths
for the drill pipe in use. As the water increases past 2000 ft, the variance in drill pipe
lengths can make tool joint location difficult to estimate based on average lengths. For
an emergency disconnect, the common practice of closing an annular preventer first and
locating the tool joint cannot be performed due to the limited amount of time available.
To provide an accurate tally for the tool joint location in the BOP stack regardless of the
bit depth below the stack, a spreadsheet similar to the one shown in Figure 12.3 is used
to keep a running tally. As the pipe in tripped in or out of the hole, the Driller finds the
stand number for the joint in the rotary on the spreadsheet. In the example shown, if
stand No. 66 is in the rotary, then the tool joint would be positioned 25 ft above the rotary
to place a tool joint 15 ft above the hang-off ram. For the spreadsheet above, a tool joint
location of 15 ft above the hang off ram is used to provide adequate clearance for pipe
stretch and rig heave. After the hang-off ram is closed the pipe would be slacked off 15 ft
to land the tool joint on the ram block.
If the pipe was at stand No. 72 when the yellow alarm was received, then the tool joint
would need to be placed seven ft above the rotary to position a tool joint 15 ft above the
hang-off ram. This spreadsheet tally provides a quick reference for spacing out a tool
joint in the BOP stack and is easily maintained by replacing joint lengths as pipe is
replaced in the string.
It is important to note that during actual conditions when the rig is offset from the
wellbore that the tool joint location will be different than the calculated location. Since
offset conditions will increase the distance to the BOP stack, the tool joint location will
always be closer to the rotary during an EDS. It is important that the Driller understand
the concept of the tool joint location during various scenarios and conditions to ensure
that correct positioning of the tool joint for hang off.
After the drill pipe is hung-off, 20/30 kips of weight is set down on the rams block, and
the remaining weight is supported by the motion compensator. The motion compensator
is used to keep the pipe stationary during rig heave and to provide stroke out adjustment
in pipe length below the rotary as the rig moves off location.

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EMERGENCY DISCONNECT

It is important that the tool joint remain on the ram block and not be picked up as the rig
moves off location to ensure that the tool joint is in the proper location when the pipe is
sheared. During an emergency disconnect in the Gulf of Mexico in 2001, the Driller
correctly positioned and hung off the pipe, but as the rig moved off location and tool joint
came closer to the rotary, the pipe was picked up to place the tool joint in its original
position causing the pipe to be sheared below the tool joint. This action caused the pipe
to be dropped and nearly placed the tool joint across the blind shear ram when they
were actuated. Closure of the blind shear rams on the tool joint would have left the well
open since the blind shear ram did not have the capability to shear the tool joint.

RKB to 18-3/4 Wellhead 3381

RKB TO MPR 3368
RKB to desired tooljoint location 3353

Stand Joint Cumulative T/J Above

Number Length Length Rotary
d 30.96 6201.39 25
66 30.43 6231.82 25 Stand No. 66 requires a tool joint to
s 30.46 6262.28 23 be 25 feet above the rig floor to
place the tool joint at the correct
d 32.10 6294.38 23
location in the BOP stack when the
67 31.97 6326.35 22
hang off ram is closed.
s 31.82 6358.17 22
d 31.15 6389.32 21
68 32.01 6421.33 20
s 30.68 6452.01 19
d 31.70 6483.71 18
69 32.21 6515.92 18
s 31.77 6547.69 18
d 31.09 6578.78 17
70 30.98 6609.76 15
s 30.30 6640.06 13
d 30.43 6670.49 12
71 31.79 6702.28 12
s 30.12 6732.40 10
d 31.07 6763.47 9
72 30.45 6793.92 7 If Stand No. 72 is in the rotary, the tool
s 31.30 6825.22 6 joint is now only required to be 7 feet
d 31.98 6857.20 6 above the floor to place the tool joint in
73 31.61 6888.81 5 the correct position in the BOP stack when
s 30.92 6919.73 4 the hang off ram is closed. The
d 30.63 6950.36 3 difference is caused by the variation in
74 32.16 6982.52 3 drill pipe length.
s 31.39 7013.91 3
Figure 12.3 Example of Drill Pipe
d 31.92 7045.83 3
Tally for Tool Joint Spaceout
75 30.53 7076.36 1

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EMERGENCY DISCONNECT

The motion compensator is also used to position the drill string during a drift off when
power is unavailable to the drawworks. For this reason, the motion compensator on DP
rigs should always be correctly pressured and ready for use even during operations such
as tripping when the compensator is not normally required. If the unlock function to the
compensator is electrically operated, this function should be on the emergency
generator or powered by an uninterrupted power supply.
Another important step that must be performed when the drill pipe is hung-off is
actuation of the ram locks. The ram locks are required to mechanically hold the rams
closed after the hydraulic pressure is removed during the EDS. If the ram locks are not
actuated, the rams may be allowed to open during the EDS, and the pipe will be
dropped. Some ram type preventers are equipped with locks that actuate automatically
when the rams are closed, but others require a separate function. Specific information
on ram locks can be found in Section 9.

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EMERGENCY DISCONNECT

12.5 OPERATING PROCEDURES AND DRILLS

The process of performing the emergency disconnect must be reactionary and as simple
as possible to ensure that it can be performed expeditiously without requiring personnel
to review instruction. Procedures for the emergency disconnect are typically a two step
process describing actions for a yellow and red alarm. The procedure used most often
lists the steps to secure the wellbore and disconnect the LMRP with drill pipe across the
stack or while out of the hole. This procedure is the one that the crew will practice most
often and be prepared to perform without additional instructions. Procedures for non-
routine operations such as casing operations or well testing are typically reviewed before
the operation to ensure that the crews understand the different steps.
Other procedures that are typically used are listed below. These procedures should be
reviewed and agreement reached between the Contractor and ExxonMobil before
beginning operations.
Drill pipe across the BOP stack.
HWDP, Drill Collars or Casing Larger than seven in. across the BOP stack.
Cementing.
Testing BOPs.
Well Control Operations.
Well Testing.
Wireline Operations.
Stuck Pipe.
Examples of these procedures are listed in the Appendices at the end of Section 12.

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EMERGENCY DISCONNECT

12.5.1 PERSONNEL
RIG FLOOR
While operating with the BOP latched to the wellhead, the Driller or a qualified person
re lie vin g th e D rille r m u st b e in th e D rille rs h o u se a t a ll tim e s. S in ce th e E D S ca n d e p e n d
o n se co n d s to co m p le te th e a ctu a tio n in tim e , it is e sse n tia l th a t th e D rille rs sta tio n b e
attended at all times. This requirement prevents the Driller from assisting rig up on the
flo o r o r a tte n d in g p re jo b sa fe ty m e e tin g s u n le ss th e y a re h e ld in th e D rille rs h o u se . In
addition, a second person qualified to assist and perform an EDS is typically required to
be on the rig floor at all times to assist the Driller during an EDS. Typically the Driller will
be relieved by the Toolpusher or an experienced Assistant Driller and the second person
on the floor may be either the Toolpusher, Assistant Driller, or Derrickman.
DP CONTROL ROOM
The DP control room should be attended by at least one operator qualified to operate the
DP system on the rig at all times. A typical DP control room manning would be to have
four qualified operators onboard at all times with two operators per shift. To provide
adequate overlap during shift changes, it is typical to stagger the shift change for the
operators six hours apart. This configuration provides two operators in the control room
at all times and allows the operators to have sufficient overlap. During a twelve-hour
tour, the operators would rotate two hours on and two hours off watching the DP control
panel. This allows the operator not on the panel to man the radios, maintain the log
books and keep up other administrative duties while still allowing one person to maintain
100% of their attention at the control panel.
ENGINE CONTROL ROOM AND ENGINE ROOM(S)
The engine control room would typically be manned continuously with at least one
qualified person along with at least one additional person in the engine room.

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EMERGENCY DISCONNECT

12.5.2 DRILLS
After the installation of the BOP stack, space-out and hang-off drills are typically
performed at each casing point and during the weekly fire and abandonment drills.
These drills will typically start at a point w h e re th e D rille r w o u ld re ce ive th e ye llo w
a la rm a n d e n d a t th e re d a la rm p o in t w h e re th e E D S w o u ld b e a ctu a te d .
The actuation of the EDS controls for the BOP stack is confirmed prior to deploying the
stack with the actuation of each function verified. Complete actuation of the EDS is
rarely performed subsea after the initial sea-trials for the rig and BOP control systems.
This is because an additional pressure test would be required for the LMRP seals.
Unlatching can also cause major damage to equipment due to riser recoil and could
require pulling the LMRP to replace pod seals. Re-latching can also be difficult.
During the hang-off drills, the following items are typically practiced and confirmed:
Pipe spaceout.
D rille rs kn o w le d g e o f th e ste p s to h a ng-off the drill pipe and lock the
hang off rams.
D rille rs kn o w le d g e o f m o tio n co m p e n sa to r syste m a n d h o w it w o u ld b e
used to support the drill pipe during rig offset.
D rille rs a b ility to h a n g -off the drill pipe using the motion compensator
without the use of the drawworks.
D rille rs a b ility to h a n g -off the drill pipe in the minimum time programmed
between the yellow and red alarm.
Since actual offset conditions are not present during these drills, it is important to
simulate various conditions (i.e. loss of drawworks power, loss of a communication
system to the DP control room) and quiz the Drill Crew on actions and conditions that
may occur during an actual disconnect.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

12.6 ACTIVATING THE EMERGENCY DISCONNECT

SEQUENCE
When the rig reaches the red watch circle and the red alarm is activated, the EDS must
be actuated immediately to ensure that disconnect occurs prior to any of the
components exceeding their limiting criteria. Failure to actuate the EDS when the vessel
reaches the red watch circle could result in the LMRP not unlatching prior to the rig
reaching offsets that exceed the bending/tensile loads of the wellhead, structural casing,
BOPs, flex joints, or riser. This increased offset may also exceed the limits at which the
LMRP connector is physically capable of unlatching.
The EDS is actuated by a button on the BOP control panel that is protected by covers
similar to the blind shear rams. In addition to the button located on the BOP control
panel(s), most rigs built or upgraded in the late 1990s also have a button located next to
the Driller so that the Driller can actuate the EDS without leaving the drawworks controls.
T h e a ctu a tio n o f th e E D S typ ica lly re q u ire s a P u sh to A ctu a te b u tto n to b e d e p re sse d
simultaneously with the EDS button to prevent accidental actuation.
When an upset occurs in the rig's stationkeeping, the following actions normally occur:
DP OPERATOR
1. Notifies the Driller immediately, even before the vessel reaches any offset limits. This
notification may occur before any major upset in the system and can provide the
Driller an early warning to prepare the wellbore for a possible disconnect.
2. Confirms the upset and notifies the appropriate personnel. If the vessel has lost
power and is drifting off location, the DP Operator will provide a yellow alarm
immediately.
DRILLER
1. Reviewed the proper disconnect procedure prior to performing that operation.
2. Ensures that the EDS is in the proper selection for the pipe in the BOP stack
N o rm a l o r C a sin g
3. Has the motion compenstor in operation or ready for use with air available to support
the weight of the pipe above the BOP stack plus 20/30 kips.
4. Verify the alarm with the DP Operator.
5. Position the drill pipe, close the hang off rams, activate the ram locks and hang-off
the drill pipe.
6. Adjust the motion compensator to support the weight of the pipe above the BOP
stack plus 20/30k additional to provide a lift off when the pipe is sheared.
7. Provide notice for personnel to clear the rig floor and moonpool prior to actuating the
EDS.
When the red alarm is received, the Driller confirms the alarm with the DP Operator and
actuates t.he EDS. On completion of the disconnect, the Driller notifies the DP Operator
that the LMRP is unlatched from the BOP stack.
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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

Following the disconnect, the following list of items may be required and should be
considered:
1. Closing the annular on the sheared pipe and displacing the mud from the riser
utilizing the riser boost line.
2. Do the riser tensioners need to be adjusted to minimize the effects of riser and rig
from heaving at different frequencies? When operating in ultra-deepwater and in an
environment where the vessel has substantial heave, the frequency of the vessel
heave and riser heave can get out of sync allowing for possible compression of the
riser or extremely high tension loads.
3. Pull the drill pipe from the riser and recover the sheared section of drill pipe from the
string. This will be necessary to rig up the riser-landing joint or tension tool needed to
re-latch the LMRP to the BOP stack.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

12.7 MOTION COMPENSATION

The motion compensator is a very important component during an emergency
disconnect and should be ready for use at all times when operating from a DP rig. It is
also important to ensure that the system is configured so that pressure can be rapidly
adjusted during an emergency disconnect.
The motion compensator provides for the following:
Can be used to position the pipe when power is not available to the drawworks.
Keep the pipe stationary during rig heave to assist with the following:
Keep the tool joint in position on the hang-off ram
Prevent movement of the pipe through the hang off ram
Keep the pipe stationary during shear
Provide a force to pick up the drill pipe out of the BOP stack immediately after it has
been sheared.
When using the Casing EDS, it provides a force to immediately pick up the pipe
above the blind shear to provide a clear wellbore for the blind shear rams to close.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

12.8 WELLBORE REENTRY

After stationkeeping problems are corrected and it is confirmed that the rig can maintain
position over the wellbore, the rig will be positioned to reconnect the LMRP to the stack.
Prior to re-latching the LMRP to the BOP stack the following should be confirmed:
1. Was LMRP gasket released or is it still in the connector or on the connector hub?
2. Is new gasket installed correctly?
3. Were choke and kill gaskets released or are they still in place?
4. Are new choke and kill gaskets installed correctly?
5. Is there any visible damage to pod receptacles, pod stingers, choke/kill receptacles
or stingers or the LMRP gasket profile.
6. If pod allows stingers to be retracted and energized, actuate stack functions to verify
integrity of pod seals.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

After the items listed above are confirmed, the rig floor is configured to re-land the LMRP
with a landing joint or riser tension tool using the drawworks and the motion
compensator. The drawworks must be used to land the LMRP instead of the riser
tensioners since the drawworks can provide the ability to pickup and slack off quickly.
Additionally, the drawworks have the sensitivity required to land out the LMRP on the
stack without damaging any stabs, seals or alignment pins. After the rig floor is
configured, the rig is positioned adjacent to the BOP stack and new gaskets are installed
for the choke/kill and LMRP connectors if required. During the re-latching of the LMRP,
the rig heading is adjusted to minimize rig motions and to align the LMRP to mate up
with the BOP stack. On some rigs, the outer barrel of the slip joint and the riser can be
rotated to allow the rig heading to be positioned into favorable weather while aligning the
LMRP to the BOP stack. Figure 12.4 illustrates an LMRP alignment with a BOP stack
during a reconnect.
Using the ROV to confirm
alignment from two
directions 90 degrees
apart, the LMRP is
lowered over the BOP
and final alignment is
completed by the
alignment pins on the
BOP. After the BOP stack
is landed, the LMRP
connector is latched and
the following items are Helical Slot and Alignment Pin
confirmed: Require for Orientation
Final Alignment Pins
Pod
stingers
extended
and tested.
Choke and kill
lines tested.
BOP functioned.
Pressure test
of the LMRP
connector. Figure 12.4 Re-connecting LMRP to BOP stack after a disconnect

After confirming the pressure integrity of the stack and control system, the riser would
then normally be displaced with weighted drilling fluid in preparation of opening the well
and recovering the sheared drill string.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

12.8.1 WELL CONTROL CONSIDERATIONS

After an emergency disconnect has occurred and the well is secured with the blind shear
rams, the hydrostatic overbalance of the mud in the riser is temporarily trapped, but may
dissipate over time depending on mud losses. Depending on the whole condition (fluid
loss), types of formations open and the amount of time that the well remains shut-in,
formation fluid lost to the formation could allow swap-out of formation fluids with the
drilling fluid and allow hydrocarbons into the wellborn. After re-latching the LMRP to BOP
stack as illustrated in Figure 12.5, the upper kill line valves would be opened to check
the pressure beneath the shear ram and the lower choke lines valves opened to check
the pressure beneath the middle pipe rams (hang-off ram). Depending on the conditions,
it may necessary to circulate the wellbore before opening the rams.

Upper
Choke Upper
Upper Choke
Kill Upper
Kill
Lower
Choke Lower
Lower Choke
Kill Lower
Kill

Figure 12.5 BOP Stack After Re- Figure 12.6 Circulating The Wellbore With
Latching The LMRP With Sheared Drill The Sheared Drill Pipe Hung-Off In The BOP
Pipe Hung-Off On Middle Pipe Ram Stack After Re-Latching The LMRP Connector

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

To circulate the wellbore with the BOP stack in Figure 12.6, the upper kill and upper
choke line valves are opened and fluid is circulated down the kill line, across the BOP
stack through the sheared off joint of drill pipe and down the drill string. Returns are
taken though the lower choke line to the choke manifold. After the well has been
circulated and the wellbore is static, the blind shear rams are opened and the
recovery process to fish the sheared joint of pipe can begin.fishing assembly

12.8.2 FISHING ASSEMBLY

After confirming that the wellbore is static and the blind shear ram is opened, the top of
the sheared joint of drill pipe (Figure 12.7) will need to be dressed off and the pipe
recovered with an overshot and grapple (Figure 12.8).

Figure 12.7 Example Of Shear

Profile From A Joint Of Drill Pipe
Sheared In A Shear Ram Test.

While milling off the top of the sheared drill pipe in the BOP stack, it is critical that the
mill not be dressed with any milling material on the outside to prevent damage to the
BOP stack. The most common method to fish for sheared drill pipe is to run a one-trip
system that includes a milling assembly with a grapple and pack-off. On a re-entry after
a disconnect in the GOM in 2001, the fish was dressed off with this assembly in less
than 30 minutes.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

After dressing off the fish, the overshot is latched onto the fish and the wellbore can be
circulated through the drill string to confirm that the well is free of hydrocarbons below
the closed hang-off ram. After the well is circulated, the hang-off rams are opened and
the wellbore circulated and conditioned prior to removing the drill string and sheared joint
from the wellbore.

Figure 12.8 Typical fishing assembly

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

12.9 APPENDICES

APPENDIX I: EDS - GENERAL

GLOMAR JACK RYAN
CRITICAL OPERATING PROCEDURES
PROCEDURES: EMERGENCY DISCONNECT PROCEDURES - GENERAL
PERSONNEL INVOLVED: DP Operators, Driller, OIM, Rig Superintendent, Toolpusher,
Subsea Engineer, Engineering Department, Company
Representative, & Drill Crew
SCOPE: WATCH CIRCLE PARAMETERS, MANNING, EDS
SEQUENCES, TUBULAR SHEARING
EMERGENCY DISCONNECT SEQUENCE
The EDS system is totally automated. Once the system is activated, at the Driller's panel or either
BOP panels, software with in the MUX pod takes over and initiates a sequence of predefined
functions. The actual sequence and timing of the functions are critical. The basic purpose of the
functions are to:
1. Shear tubulars that are across the BOP.
2. Seal off the wellbore and auxiliary lines.
3. Remove mechanical interface between the BOP and LMRP to allow ease of separation
between the BOP and LMRP.
4. Unlatch the LMRP from the BOP.
MANNING AND RESPONSIBILITIES
MANNING
When the vessel is on location operating in normal DP mode, the following minimum operational
manning levels will apply.
DP ROOM
One DPO for each 12 hour watch. The DP room must be continuously manned 24 hours per day.
When required for the DPO to leave the room, he will be relieved by a competent person trained
on the Nautronix ASK 5003 system, a trainee DPO is not to be left alone.
DRILL FLOOR
At all times when connected to the seabed, one person, qualified as a Driller, is to be present in
the Drillers control house. There shall also, at all times, be at least one other competent person
on the rig floor to assist the Driller as needed. When the Driller is required to leave the rig floor, a
Toolpusher will be present in his absence.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

ENGINE CONTROL ROOM (ECR)

The ECR must be manned at all times. At least one qualified person to be in the ECR at all times.
MISCELLANEOUS POSITIONS
There shall be on board at all times:
1. At least one qualified Electrician for each watch
2. At least one qualified ET for each watch.
3. At least one qualified Marine Engineer for each watch.
4. At least one qualified Subsea Engineer per tour when the riser and stack system is
connected to the seabed.
5. At least one Chief Engineer, Assistant Engineer or Mechanic shall be on watch.
SUBSEA ENGINEER
1. At least one Subsea Engineer shall be on tour at all times. During notification of a blue,
yellow or red alert, the Subsea Engineer should report to the rig floor.

OPERATING STATUS
NORMAL CONDITION
The ship is defined as being in "NORMAL" operating status when ALL of the following
conditions apply:
1. Ship's desired position remains within the Blue watch circle for all but brief or isolated
periods.
2. Flex joint angle at the LMRP is within the agreed allowable offset limit for the water depth.
3. Ship is under DP control and the DP system is operating normally. All appropriate back
up (redundant) systems are available.
4. Thruster output, excluding bias, not exceeding 50% of total available thruster power for
more than brief or isolated periods.
5. Generator steady load is not exceeding 60% of total available power for more than brief
or isolated periods.
6. Upper riser angle is less than 2 degrees (Provided the Intermediate Flex Joint has been
run).
7. Steady wind speed is less than 40 knots, gusts are less than 45 knots.
8. Combined seas are 15 ft or less.

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EMERGENCY DISCONNECT

BLUE CONDITION
The ship is defined as being in "BLUE" operating status when any one of the following conditions
apply:
1. Ship's position has entered the Blue Alert "watch circle" for more than brief or isolated
periods.
2. Flex joint angle at the LMRP is more than the agreed allowable offset limit for the water
depth
3. Ship is under DP control but there has been a failure in a sub system which has left the
DP system in an operational state but without appropriate back-up (redundant) systems.
4. Thruster output, excluding bias, is exceeding 50% of total available thruster power for
more than brief or isolated periods.
5. Generator steady load exceeds 60% of total available power for more than brief or
isolated periods.
6. Upper riser angle is more than 2 degrees (provided the Intermediate Flex Joint has been
run).
7. Steady wind speed is greater than 40 knots, gusts are greater than 45 knots.
8. Combined seas are greater than 15 ft.
9. Surface currents measured by the current meter are greater than 2.5 knots.
When one of the following conditions occurs, the DPO must inform the Driller that a degraded
condition has been reached. This must be done both verbally and by activation of the Blue Alert
light. The DPO should also inform the ECR and OIM.
The Driller or Assistant Driller will immediately notify the Rig Superintendent, Company
Representative, Toolpusher, and Subsea Engineer. OIM, Rig Superintendent, Company
Representative and Toolpusher will review the conditions and decide which operations are
acceptable under the circumstances and whether or not to proceed with the operations.
YELLOW CONDITION
The ship is defined as being in "YELLOW" operating status when any one of the following
conditions occur:
1. Ship's indicated position has crossed into the yellow "watch circle" for more than brief or
isolated periods
2. Flex joint angle at the LMRP and/or slip joint/tensioner stroke criteria limits has reached
the calculated yellow alert angle.
3. DP system or Power Plant failure results in inability to maintain positioning control even if
the vessel is remaining within the watch circle (i.e; deadreckoning and/or joystick control)
4. Thruster output, excluding bias, exceeding 65% of total available thruster power.
5. Generator steady load exceeds 75% of total available power.
6. Due to loss of reference system, the DP system has no redundant back-up system.
When any of the above conditions occur the DPO must inform the Driller, ECR, and OIM that
Yellow Alert Status has been reached, both verbally and by activation of the Yellow alert light (if
not activated by the automatic system). The Driller will immediately and without hesitation take
steps to hang off the drill string (if applicable) and secure the well. The Assistant Driller will
immediately notify the OIM, Rig Superintendent, Company Representative, Toolpusher, and
Subsea Engineer. More detailed procedures covering specific operations are detailed within the
Glomar JACK RYAN Emergency Disconnect Procedures.
The ship is defined as being in "RED" operating status when any one of the following conditions
occur:

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EMERGENCY DISCONNECT

RED CONDITION
1. Ship's indicated position has crossed the calculated RED alert circle.
2. Flex joint angle at the LMRP has reached the calculated Red alert angle and/or the
maximum allowable tensioner stroke has occurred.
When any of the above conditions occur, the DPO must immediately verbally acknowledge, with
the Driller, the validity that the Red Alarm status has been reached.
At RED ALERT status the Driller must initiate Disconnect Procedures. He will immediately and
without hesitation activate the EDS. He will then confirm proper functions are operating by
observing the BOP panel on the Drillers console. More detailed procedures covering specific
operations are detailed within the Glomar JACK RYAN Emergency Disconnect Procedures.

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EMERGENCY DISCONNECT

APPENDIX II: EMERGENCY DISCONNECT PROCEDURES -

DRILLPIPE ACROSS BOP
GLOMAR JACK RYAN
CRITICAL OPERATING PROCEDURES
PROCEDURE: EMERGENCY DISCONNECT PROCEDURE - DRILLPIPE
ACROSS BOP
PERSONNEL INVOLVED: Driller, Toolpusher, Rig Superintendent, DPO, Subsea Engineer,
OIM, Drill Crew, Company Representative
SCOPE: ACTIONS TO BE TAKEN WHILE DRILLING/TRIPPING
DURING A BLUE, YELLOW OR RED DP ALERT.
PROCEDURE
CROWN MOUNTED COMPENSATOR (CMC) POSITIONING
When drilling, certain practices must be followed to maintain optimum preparedness for a
potential EDS situation.
1. Standby bottles for the HP air system must be kept fully charged at all times. In the event
of complete power loss it may be necessary to utilize the CMC for positioning the drill
string across BOP.
2. Weather permitting, when drilling the last 25 ft of stand, allow CMC to "Drill off" and CMC
cylinders to collapse. This will give maximum stroke of CMC should it be required. When
tripping keep CMC on beams and hydraulically locked.
3. Ensure adequate APV pressure is available to lift estimated total string weight from the
BOP to the floor plus 20K.
CONDITION BLUE
1. DPO to open direct line of communication with the Driller and notify the OIM.
2. The Driller or Assistant Driller will immediately notify the Rig Superintendent, Company
Representative, Toolpusher and Subsea Engineer. The OIM, Rig Supt., Co. Rep., and
Toolpusher will review the conditions and decide which operations are acceptable under
the circumstances and whether or not to proceed with operations.
3. Verify pipe figures for hanging off on the UPR.

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EMERGENCY DISCONNECT

CONDITION YELLOW
1. The situation may arise where the Yellow alert will not be preceded by a Blue. In this
situation carry out all the steps listed at the condition Blue stage as well as the steps
listed within the condition Yellow.
2. Clear moonpool and rig floor of all personnel.
3. If drilling, pick up off bottom and shut off pumps.
4. If 5 1/2 in. drill pipe is in BOP stack, close MPR and ST locks.
5. If 3 1/2 in., 5 in. or 6 5/8 in. drill pipe is in BOP stack, close UPR and ST locks.
6. Slack off until tool joint lands out on MPR.
7. Adjust CMC for string weight above BOP plus 20kip
8. If no drawworks power is available, space out using CMC.
CONDITION RED
DRILLER:
1. Verbally authenticate Red Alert with DPO.
2. Driller to immediately, without question, activate EDS.
3. Unlock CMC, if not already unlocked and adjust air to lift string in riser plus 20 kips.
4. Verify unlatch and notify DPO of same.
5. Pick up on drill string to ensure sheared pipe end is well within the riser.
SUBSEA ENGINEER
1. Check MRT status. Using standby air boost MRT as required to collapse slip joint.

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EMERGENCY DISCONNECT

APPENDIX III: EMERGENCY DISCONNECT PROCEDURES - BHA

ACROSS BOP
GLOMAR JACK RYAN
CRITICAL OPERATING PROCEDURES
PROCEDURE : EMERGENCY DISCONNECT PROCEDURES - BHA ACROSS
BOP
PERSONNEL INVOLVED: Driller, Rig Superintendent, Toolpusher, DPO, OIM, Drill Crew,
Company Representative, Subsea Engineer
SCOPE: ACTIONS TO BE TAKEN WHILE BHA ACROSS BOP AND A
BLUE, YELLOW, OR RED DP ALERT OCCURS.
Note: BHAs larger than 6 1/2 in. will have a minimum amount of drill collars to reduce the
exposure time and the time required to remove the BHA from the stack should an alert
occur.
PROCEDURE
DRILLER
1. Driller will notify DPO prior to BHA entering the BOP stack and DPO to notify the
appropriate personnel of the "DP Standby" status.
2. Before tripping through the BOP stack with the BHA, the Driller will select the appropriate
EDS with the selector switch ("Shear"/"Casing Shear")
CMC POSITIONING
1. When tripping with BHA across BOP, certain practices must be followed to maintain
optimum preparedness for a potential EDS situation.
2. Standby bottles for the HP air system must be kept fully charged at all times.
3. In the event off complete power loss it may be necessary to utilize the CMC for
positioning the drill string across BOP.
4. Ensure adequate APV pressure is available to lift the estimated total string weight from
the BOP to the floor plus 20K.
CONDITION BLUE
1. DPO to open direct line of communication with Driller and notify the OIM and ECR.
2. The Driller or Assistant Driller to immediately notify the Rig Superintendent, Company
Representative, Toolpusher and Subsea Engineer. The OIM, Rig Superintendent,
Company Representative and Toolpusher will review the conditions and decide which
operations are acceptable under the circumstances and whether or not to proceed with
operations.
3. Continue running/pulling BHA to clear the BOP unless otherwise instructed.

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EMERGENCY DISCONNECT

CONDITION YELLOW
DRILLER
1. The situation may arise where the Yellow alert will not be preceded by a Blue. If this
situation occurs, carry out all the steps listed at the condition Blue stage as the steps
listed within the condition.
4. Clear rig floor and moonpool of all personnel.
5. If possible clear BOP of BHA by pulling or running current stand.
6. If BHA tubular can be cut by Blind Shear or Super Shear rams and be hung-off on rams
a. Open CMC while confirming space out.
b. Close MPR and ST lock if appropriate. Slack off until tool joint lands out on MPR.
c. Set CMC for string weight above BOP plus sufficient overpull.
d. If no drawworks power is available, space out using the CMC.
7. If BHA tubular can be cut by Blind Shear or Super Shear rams, but not hung-off on rams
a) Position tubular so tool joint is not across shear.
b) Set CMC for string weight above BOP plus sufficient overpull.
8. If BHA tubular cannot be cut by Super shear rams and pipe rams cannot be then attempt
to drop the string.
SUBSEA ENGINEER
1. Report to rig floor.
2. Verify Control System and MRT system are aligned as required

CONDITION RED:
DRILLER
1. Verbally authenticate Red alert with DPO.
2. Driller to immediately, without question, activate EDS.
3. Unlock CMC, if not already unlocked and adjust air to lift string in riser plus 20 kips.
4. Verify unlatch and notify DPO of same.
5. Pick up on drill string to ensure sheared pipe end is well within the riser.
SUBSEA ENGINEER
1. Check MRT status. Using standby air boost MRT as required to collapse slip joint.

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EMERGENCY DISCONNECT

APPENDIX IV: EDS PROCEDURES - CEMENTING CASING

GLOMAR JACK RYAN
CRITICAL OPERATING PROCEDURES
PROCEDURES: EMERGENCY DISCONNECT PROCEDURES CEMENTING
CASING
PERSONNEL INVOLVED: Driller, Toolpusher, Rig Superintendent, DPO, Subsea Engineer,
Drill Crew, Company Representative, Cementer, Wellhead
Serviceman.
SCOPE: ACTIONS TO BE TAKEN WHEN CEMENTING AND AN EDS
ALERT STATUS EXISTS.
Notes: Wellhead Serviceman should remain on the floor during cementing operations.
The special BOP Test Joint (4 1/2 in. IF pin by 5 1/2 in. HT-55 box) is 1.125 in. wall
thickness and requires shearing with the Super Shear Rams.
PROCEDURE
CROWN MOUNTED COMPENSATOR POSITIONING
1. When carrying out casing cementing operations certain practices must be followed in
order to maintain optimum preparedness for a potential EDS situation.
2. Standby bottles for the HP air system must be kept fully charged at all times.
3. In the event of complete power loss it may be necessary to utilize the CMC for positioning
the string across the BOP.
4. Ensure adequate APV pressure is available to lift the estimated total string weight from
the BOP to the floor plus 20K.
CONDITION BLUE
1. DPO to open direct line of communication with the Driller and notify the OIM and ECR.
2. The Driller or Assistant Driller will immediately notify the Rig Superintendent, Company
Representative, Toolpusher, Cementer and Subsea Engineer. The OIM, Rig
Superintendent, Company Representative, and Toolpusher will review the conditions and
decide which operations are acceptable under the circumstances and whether or not to
proceed with operations.
3. Continue to mix or displace cement.

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EMERGENCY DISCONNECT

CONDITION YELLOW
DRILLER
1. The situation may arise where the Yellow alert will not be preceded by a Blue. In this
situation carry out all the steps listed at the condition Blue stage as well as the steps
listed within the condition Yellow.
2. Notify Cementer to stop cementing and displace cement from the drill pipe if possible.
a) If cement is not displaced from landing string, shut down operations and close MPR
and ST locks.
b) If cement is displaced from landing string, stop pumping and release casing hanger-
running tool by rotating landing string to the right. P/U landing string to clear running
tool above shear ram.
3. Clear moonpool and rig floor of all personnel.
4. Unlock CMC and adjust for string weight above BOP plus 20kip (unless string weight is
less than 20k)
SUBSEA ENGINEER
1. Report to rig floor.
2. Verify Control System and MRT system are aligned as required.

CONDITION RED
DRILLER
1. Verbally authenticate Red alert with DPO.
2. Driller to immediately, without question, activate EDS.
3. Notify Cementer that EDS has been initiated and shut down displacing.
4. Verify unlatch and notify DPO of same.
5. Pick up on landing string to ensure sheared pipe end is well within the riser.
SUBSHEA ENGINEER
1. Check MRT status. Using standby air boost MRT as required to collapse slip joint.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

APPENDIX V: EDS PROCEDURES - CASING ACROSS BOP

GLOMAR JACK RYAN
CRITICAL OPERATING PROCEDURES
PROCEDURES: EMERGENCY DISCONNECT PROCEDURES CASING
ACROSS BOP
PERSONNEL INVOLVED: Driller, Toolpusher, Rig Superintendent, DPO, Subsea Engineer,
OIM, Drill Crew, Company Representative, Casing Crew
SCOPE: ACTIONS TO BE TAKEN WHILE RUNNING CASING DURING
A BLUE, YELLOW AND RED DP ALERT.
PROCEDURE
CROWN MOUNTED COMPENSATOR POSITIONING
1. When running casing, certain practices must be followed to maintain optimum
preparedness for a potential EDS situation.
2. Standby bottles for the HP air system must be kept fully charged at all times.
3. In the event of complete power loss it may be necessary to utilize the CMC for positioning
of the string across the BOP.
4. Ensure adequate APV pressure is available to lift the estimated total string weight from
the BOP to the floor plus 20K.
EDS SELECTOR SWITCH POSITIONED PER THE FOLLOWING GUIDELINES BEFORE
BEGINNING THE CASING OPERATIONS
EDS SETTING CASING SIZES
Regular 7 in., 38 lb/ft, P-110 and smaller
Casing - Super Shear Larger than 7 in.

CONDITION BLUE
1. DPO to open direct line of communication with the Driller and notify the OIM and ECR.
2. The Driller or Assistant Driller will immediately notify the Rig Superintendent, Co. Rep,
Toolpusher and Subsea Engineer. The OIM, Rig Superintendent, Company
Representative, and Toolpusher will review the conditions and decide which operations
are acceptable under the circumstances and whether or not to proceed with operations.
3. If above BOP, stop and await further instruction.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

CONDITION YELLOW
DRILLER
1. The situation may arise where the Yellow alert will not be preceded by a Blue. In this
situation carry out all the steps listed at the condition Blue stage as well as the steps
listed within the condition Yellow.
2. Clear rig floor and moonpool of all personnel.
3. If above the BOP stop. If casing is across BOP, space out casing collar to clear Shear
Blind rams or Super Shear rams.
4. Unlock CMC and set CMC for string weight above BOP plus sufficient overpull.
5. If no drawworks power is available, space out using the CMC.
SUBSEA ENGINEER
1. Report to rig floor.
2. Verify Control System and MRT system are aligned as required.
3. Assist Driller as required.
CONDITION RED
DRILLER
1. Verbally authenticate Red Alert with ______.
2. Driller to immediately, without question, activate EDS.
3. Unlock CMC, if not already unlocked and adjust air to lift string in riser 20 kips.
4. Verify unlatch and notify DPO of same.
5. Pick up on casing string to ensure sheared pipe is well within the riser.
SUBSEA ENGINEER
1. Check MRT status. Using standby air boost MST as required to collapse slip joint.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

APPENDIX VI: EDS PROCEDURES - WIRELINE ACROSS BOP

GLOMAR JACK RYAN
CRITICAL OPERATING PROCEDURES
PROCEDURES: EMERGENCY DISCONNECT PROCEDURES WIRELINE
ACROSS BOP
PERSONNEL INVOLVED: Driller, Toolpusher, Rig Superintendent, DPO, Subsea Engineer,
OIM, Drill Crew, Company Representative, Wireline Crew
SCOPE: ACTIONS TO BE TAKEN DURING WIRELINE OPERATIONS
AND A BLUE, YELLOW OR RED DP ALERT EXISTS.
PROCEDURE
CONDITION BLUE
1. DPO to open direct line of communication with the Driller and notify the OIM and ECR.
2. The Driller or Assistant Driller will immediately notify the Rig Superintendent, Company
Representative, Toolpusher, Subsea Engineer and Wireline Operator. The OIM, Rig
Superintendent, Company Representative, Toolpusher and Wireline Operator will review
the conditions and decide which operations are acceptable under the circumstances and
whether or not to proceed with operations.
CONDITION YELLOW
1. Inform logger of status and start POOH with wireline.
2. Clear the moonpool, rigfloor and wireline unit deck area of all personnel.
3. If tool is above BOP stack, inform logger to stop pulling tool and standby.
CONDITION RED
1. Verbally authenticate Red Alert with DPO.
2. Driller to immediately, without question, activate EDS.
3. Notify logger that EDS has been activated and to stop pulling wireline out of the hole if
tool is below BOPs.
4. Verify unlatch and notify DPO of same.
5. Check MRT status. Using standby air boost MRT as required to collapse slip joint.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

APPENDIX VII: EDS PROCEDURES - WELL TESTING

GLOMAR JACK RYAN
CRITICAL OPERATING PROCEDURES
PROCEDURES: EMERGENCY DISCONNECT PROCEDURES WELL
TESTING
PERSONNEL INVOLVED: Driller, Toolpusher, Rig Superintendent, DPO, Subsea Engineer,
OIM, Drill Crew, Company Representative
SCOPE: ACTIONS TO BE TAKEN WHILE WELL TESTING DURING A
BLUE, YELLOW OR RED DP ALERT.
PROCEDURE
CROWN MOUNTED COMPENSATOR POSITIONING
1. When testing the BOP certain practices must be followed to maintain optimum
preparedness for a potential EDS situation.
2. Standby bottles for the HP air system must be kept fully charged at all times.
3. In the event of complete power loss it may be necessary to utilize the CMC for positioning
the string across the BOP.
4. Ensure adequate APV pressure is available to lift the estimated total string weight from
the BOP to the floor plus 30 kips.
CONDITION BLUE
1. DPO to open direct line of communication with the Driller and notify the OIM.
2. The Driller or Assistant Driller will immediately notify the Rig Superintendent, Company
Representative, Toolpusher Well Test Supervisor and Subsea Engineer. The OIM, Rig
Superintendent, Company Representative, and Toolpusher will review the conditions and
decide which operations are acceptable under the circumstances and whether or not to
proceed with operations.
3. Verify pipe figures for hanging off on the MPR.

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EMERGENCY DISCONNECT

CONDITION YELLOW
DRILLER
1. The situation may arise where the Yellow alert will not be preceded by a Blue. In this
situation carry out all the steps listed at the condition Blue stage as well as the steps
listed within the condition Yellow.
2. Clear rig floor and moonpool of all personnel.
3. Close ST locks on well test rams.
4. Inform Well Test Supervisor to bleed annulus pressure to close downhole test valve.
5. Inform Well Test Supervisor to bleed tubing pressure.
6. Inform Well Test Supervisor to disconnect subsea test tree.
7. Pickup to remove upper section of test assembly from BOP stack.
8. Set CMC for string weight above BOP plus 20 kips overpull.
9. If no drawworks power is available, space out using the CMC.
SUBSEA ENGINEER
1. Report to rig floor.
2. Verify Control System and MRT system are aligned as required.

CONDITION RED
DRILLER
1. Once the Red Alarm has been verified, Driller to immediately, without question, activate
EDS
2. Unlock CMC, if not already unlocked and adjust air to lift string in riser plus 20 kips.
3. Driller must remain vigilant during EDS in case CMC requires further standby air or
drawworks are required to pull sheared tubular clear.
4. On tubular being sheared it is imperative that the tubular is pulled as far as possible clear
of the BOP and into the riser.
5. Verify unlatch and notify DPO of same.
SUBSEA ENGINEER
1. Check MRT status using standby air boost MRT as required to collapse slip joint
2. Lock inner and outer barrel of slip joint.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

APPENDIX VIII: EDS PROCEDURE - CEMENTING OPEN HOLE

PLUGS
GLOMAR JACK RYAN
CRITICAL OPERATING PROCEDURES
PROCEDURES: EMERGENCY DISCONNECT PROCEDURES CEMENTING
OPEN HOLE
PERSONNEL INVOLVED: Driller, Toolpusher, Rig Superintendent, DPO, Subsea Engineer,
OIM, Drill Crew, Company Representative, Cementer, Subsea
Engineer
SCOPE: ACTION TO BE TAKEN WHEN CEMENTING DURING A BLUE,
YELLOW OR RED DP ALERT EXISTS.
PRE JOB REQUIREMENTS
When cementing, certain practices must be followed to maintain optimum preparedness for a
potential EDS situation.
1. Driller should notify DPO to go to DP Standby immediately before beginning cementing
operations.
2. Tool joint location in the BOP stack should be calculated and positioned prior to starting
the cement job.
3. DP Operator should confirm that all systems are normal and rig is on DP Standby.
PROCEDURE
CROWN MOUNTED COMPENSATOR POSITIONING
1. Standby bottles for the HP air system must be kept fully charged at all times.
2. In the event of a complete power loss, it may be necessary to utilize the CMC for
positioning of the drill string across BOP. Ensure adequate APV pressure is available.
3. Ensure that CMC is online for all cementing operations and adequate APV pressure is
available to lift the estimated total string weight from the BOP to the floor plus 20 kips.
CONDITION BLUE
1. DPO to open direct line of communication with the Driller and to notify the OIM.
2. The Driller or Assistant Driller will immediately notify the Rig Superintendent, Co. Rep,
Toolpusher and Subsea Engineer. The OIM, Rig Supt., Co. Rep., and Toolpusher will
review the conditions and decide which operations are acceptable under the
circumstances and whether or not to proceed with operations.
3. Verify pipe figures for hanging off on the MPR.

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EMERGENCY DISCONNECT

CONDITION YELLOW
DRILLER
1. The situation may arise where the Yellow alert will not be preceded by a Blue.
2. In this situation, carry out all the steps listed at the condition Blue stage as well as the
steps listed within the condition Yellow.
a) Notify Cementer of current alarm status and stop cementing program and start
displacing cement.
b) Space out and displace cement with predetermined fluid to clear drill pipe of cement.
c) If cement is across BOPs attempt to circulate until cleared.
d) Clear moonpool and rig floor of all personnel.
e) If 5 1/2 in. drill pipe is in BOP stack, close MPR and ST locks.
f) If 3 1/2 in., 5 in. or 6 5/8 in. drill pipe is in BOP stack, close UPR and ST locks.
g) Hang-off tool joint.
h) Unlock CMC and adjust for string weight above BOP plus 20kip (unless string weight
is less than 20k)
i) If no drawworks power is available, space out using CMC
SUBSEA ENGINEER
1. Report to rig floor.
2. Verify Control System and MRT system are aligned as required.

CONDITION RED
DRILLER
1. Verbally authenticate Red Alert with DPO.
2. Driller to immediately, without question, activate EDS
3. Unlock CMC, if not already unlocked and adjust air to lift string in riser plus 20 kips.
4. Verify unlatch and notify DPO of same.
5. Pick up on drill string to ensure sheared pipe end is well within the riser.
SUBSEA ENGINEER
1. Check MRT status.
2. Using standby air, boost MRT as required to collapse slip joint.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

APPENDIX IX: EDS PROCEDURES - STUCK PIPE

GLOMAR JACK RYAN
CRITICAL OPERATING PROCEDURES
PROCEDURES: EMERGENCY DISCONNECT PROCEDURES STUCK PIPE
PERSONNEL INVOLVED: Driller, Toolpusher, Rig Superintendent, DPO, Subsea Engineer,
OIM, Drill Crew, Company Representative, Subsea Engineer
SCOPE: ACTIONS TO BE TAKEN DURING STUCKPIPE OPERATIONS
AND A BLUE, YELLOW OR RED ALERT EXISTS.
PROCEDURE
CROWN MOUNTED COMPENSATOR POSITIONING
1. When carrying out stuck pipe operations certain practices must be followed to maintain
optimum preparedness for a potential EDS situation.
2. Standby bottles for the HP air system must be kept fully charged at all times.
3. In the event of complete power loss it may be necessary to utilize the CMC positioning
the drill string across the BOP.
4. Ensure adequate APV pressure is available to lift the estimated total string weight from
the BOP to the floor plus 20k.
CONDITION BLUE
1. DPO to open direct line of communication with the Driller and notify the OIM.
2. The Driller or Assistant Driller will immediately notify the Rig Superintendent, Company
Representative, Toolpusher and Subsea Engineer.
3. Rig Superintendent, Company Representative and Toolpusher will review the conditions
and decide which operations are acceptable under the circumstances and whether or not
to proceed with operations.
4. Verify pipe figures for hanging off on the MPR.

CONDITION YELLOW
1. The situation may arise where the Yellow alert will not be preceded by a Blue. In this
situation carry out all the steps listed at the condition Blue
2. Clear rig floor and moonpool of all personnel.
3. If circulating, stop pumps.
4. If 5 1/2 in. drill pipe is in BOP stack, close MPR and ST locks.
5. If 3 1/2 in., 5 in. or 6 5/8 in. drill pipe is in BOP stack, close UPR and ST locks.
6. Set CMC for string weight above BOP plus 20.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

CONDITION RED
DRILLER
1. Verbally authenticate Red Alert with DPO.
2. Driller to immediately, without question, activate EDS.
3. Unlock CMC, if not already unlocked, and adjust air to lift string in riser plus 20 kips.
4. Verify unlatch and notify DPO.
5. Pick up on drill string to ensure sheared pipe end is well within the riser.
SUBSEA ENGINEER
1. Check MRT status. Using standby air, boost MRT as required to collapse slip joint.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
EMERGENCY DISCONNECT

APPENDIX X: EDS PROCEDURES - TESTING BOP

GLOMAR JACK RYAN
CRITICAL OPERATING PROCEDURES
PROCEDURES: EMERGENCY DISCONNECT PROCEDURES TESTING
BOPS
PERSONNEL INVOLVED: Driller, Toolpusher, Rig Superintendent, DPO, Subsea Engineer,
OIM, Drill Crew, Company Representative,
SCOPE: ACTIONS TO BE TAKEN WHILE TESTING BOP DURING A
BLUE, YELLOW OR RED DP ALERT.

PROCEDURE
NOTE: The special BOP test joint is 1.125 in. wall thickness and will require the Super
Shear Rams when shearing.
CMC POSITIONING
1. When testing the BOP certain practices must be followed to maintain optimum
preparedness for a potential EDS situation.
2. Standby bottles for the HP air system must be kept fully charged at all times.
3. In the event of complete power loss it may be necessary to utilize the CMC for positioning
the string across the hang-off ram.
4. Ensure adequate APV pressure is available to lift the estimated total string weight from
the BOP to the floor plus 20kip.

CONDITION BLUE
1. DPO to open direct line of communication with the Driller and notify the OIM.
2. The Driller or Assistant Driller will immediately notify the Rig Superintendent, Company.
Representative,Toolpusher and Subsea Engineer.
3. The OIM, the Rig Superintendent, Company. Representative andToolpusher will review
the conditions and decide which operations are acceptable under the circumstances and
whether or not to proceed with operations.
4. Verify pipe figures for hanging off on the MPR.
5. If time permits: Stop test. Bleed off all pressure. Open all preventers. Pull tool clear of
BOP using Drawworks.

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EMERGENCY DISCONNECT

CONDITION YELLOW
DRILLER
1. The situation may arise where the Yellow alert will not be preceded by a Blue.
In this situation carry out all the steps listed at the condition Blue stage as well as the
steps listed within the condition Yellow.
2. Clear rig floor and moonpool of all personnel.
3. If 5 1/2 in. drill pipe is in BOP stack, close MPR, close ST locks.
4. If 3 1/2 in., 5 in. drill pipe is in BOP stack, close MPR, close ST locks.
5. Set CMC for string weight above BOP plus 20 kips.
6. If no drawworks power is available, space out using the CMC.
SUBSEA ENGINEER
1. Report to rig floor.
2. Verify Control System and MRT system are aligned as required.

CONDITION RED
DRILLER
1. Once the Red Alarm has been verified,
2. Driller to immediately, without question, activate EDS.
3. Unlock CMC, if not already unlocked and adjust air to lift string in riser plus 20 kips.
4. Driller must remain vigilant during EDS in case CMC requires further standby air or
drawworks are required to pull sheared tubular clear.
5. On tubular being sheared it is imperative that the tubular is pulled as far as possible clear
of the BOP and into the riser.
6. Verify unlatch and notify DPO of same.
SUBSEA ENGINEER
1. Check MRT status. Using standby air boost MRT as required to collapse slip joint.
2. Lock inner and outer barrel of slip joint.
Note: There will always be two stands of shearable drill pipe below the test tool if it is weight
set type and HWDP or DCs are hung below for testing.

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EMERGENCY DISCONNECT

APPENDIX XI: EDS PROCEDURES - WELL CONTROL

GLOMAR JACK RYAN
CRITICAL OPERATING PROCEDURES
PROCEDURES: EMERGENCY DISCONNECT PROCEDURES WELL
CONTROL
PERSONNEL INVOLVED: Driller, Toolpusher, Rig Superintendent, DPO, Subsea Engineer,
OIM, Drill Crew, Company Representative
SCOPE: ACTIONS TO BE TAKEN CARRYING OUT WELL CONTROL
DURING A BLUE, YELLOW AND RED DP ALERT.
PROCEDURE
CROWN MOUNTED COMPENSATOR POSITIONING
1. When carrying out well control operations certain practices must be followed to maintain
optimum preparedness for a potential EDS situation.
2. Standby bottles for the HP air system must be kept fully charged at all times. In the event
off complete power loss, it may be necessary to utilize the CMC for positioning the string
across BOP.
3. Ensure adequate APV pressure is available to lift the estimated total string weight from
the BOP to the floor plus 20kips.
CONDITION BLUE
1. DPO to open direct line of communication with the Driller and notify the OIM and ECR.
2. Continue well control operations.
3. The Driller or Assistant Driller will inform the Rig Superintendent, Company
Representative, Toolpusher and Subsea Engineer.
4. The OIM, Rig Superintendent and Toolpusher will review the conditions and decide which
operations are acceptable under the circumstances.
5. If not hung off on MPR, hang off.
6. Set CMC for string weight above BOP plus 20 kips.
7. If no drawworks power is available, space out using the CMC.

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EMERGENCY DISCONNECT

CONDITION YELLOW
DRILLER
1. The situation may arise where the Yellow alert will not be preceded by a Blue.
In this situation carry out all the steps listed at the condition Blue stage as well as the
steps listed within the condition Yellow. Clear moonpool of all personnel.
2. Clear rig floor and moonpool of all personnel.
3. Stop circulating.
4. Record all pressures and close all BOP mounted failsafe valves.
5. If 5 1/2 in. drill pipe is in BOP stack, close MPR and ST locks.
6. If 3 1/2 in.or 5 in. drill pipe is in BOP stack, close and ST locks.
7. Bleed pressure from choke and kill lines.
8. If annular is closed, open sweep valves and bleed any pressure through kill line.
Note: EDS includes opening upper annular which will allow any gas trapped beneath to
be vented subsea as the LMRP disconnects.
SUBSEA ENGINEER
1. Report to rig floor.
2. Verify Control System and MRT system are aligned as required.
3. Assist Driller as required.

CONDITION RED
DRILLER
1. Verbally authenticate Red Alert with DPO.
2. Driller, to immediately, without question, activate EDS.
3. Unlock CMC, if not already unlocked and adjust air to lift string in riser plus 20 kips.
4. Verify unlatch and notify DPO of same.
5. Pick up on drill string to ensure sheared pipe end is well within the riser.
SUBSEA ENGINEER
1. Check MRT status. Using standby air boost MRT as required to collapse slip joint.

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WELL TESTING OPERATIONS

13
Section

13.0 WELL TESTING OPERATIONS

OBJECTIVES
On completion of this section, you will be able to:

Describe why we pressure test.

List the unique consideration in floating rig well test.

List the objectives of a well test.

List the design consideration for well testing.

List the down hole equipment required for a well test.

List the surface equipment required for a well test.

List the types of measurement and sampling equipment.

Describe the personnel responsibilities in the well test.

Describe the information obtained during the test.

List the pre-test planning items.

List the main steps for the test execution.

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CONTENTS Page

13.0 WELL TESTING OPERATIONS .................................................................................................. 1

OBJECTIVES ............................................................................................................................... 1
CONTENTS .................................................................................................................................. 2
13.1 INTRODUCTION .......................................................................................................................... 6
13.1.1 WHAT IS PRODUCTION TESTING? ........................................................................... 6
13.1.2 MOST COMMON FORM: PRESSURE TRANSIENT TESTING .................................. 6
13.1.3 UNIQUE CONSIDERATIONS IN FLOATING RIG WELL TESTS ............................... 8
13.2 WELL TESTING OBJECTIVES ................................................................................................... 9
13.2.1 HOW OBJECTIVES AFFECT THE CONCEPTUAL WELL TEST DESIGN ................ 9
13.2.2 DETERMINATION OF TEST OBJECTIVES .............................................................. 11
13.2.3 PRIORITIES OF TEST OBJECTIVES ........................................................................ 11
13.3 WELL TEST DESIGN CONCEPTS: STAGE I ........................................................................... 12
13.3.1 INTRODUCTION ........................................................................................................ 12
13.3.2 PHASE 1: WELL TEST DESIGN CONCEPTUAL STAGE ..................................... 12
13.3.3 DUAL FLOW, DUAL SHUT-IN TEST ......................................................................... 13
13.3.4 SHUT-IN PERIODS OR PRESSURE BUILDUPS IN PRODUCTION TESTING ........ 13
13.3.5 WHY THE PRESSURE BUILDUP WORKS ............................................................... 17
13.3.6 PURPOSE AND LENGTH OF THE FOUR DFDS TEST PERIODS .......................... 17
13.3.7 CONTENTS OF CONCEPTUAL TEST DESIGN DOCUMENT .................................. 20
13.3.8 BOTTOMHOLE PRESSURE MEASUREMENT COMPLICATIONS.......................... 20
13.3.9 GAUGE LOCATION AND CH A N G IN G H Y D R O S T A T IC C O R R E C T IO N ............. 21
13.3.10 SOLUTIONS FOR CHANGING HYDROSTATIC CORRECTIONS............................ 22
13.3.11 N O F L O W C O N D IT IO N VIOLATIONS ................................................................... 22
13.3.12 SOLUTION FOR AFTERFLOW AND PHASE HUMPING ......................................... 23
13.3.13 INFLUENCE OF TIDES ON BOTTOM HOLE PRESSURE MEASUREMENTS ........ 24
13.3.14 CONCEPTUAL TEST DESIGN WRAP-UP ................................................................ 24
13.4 WELL TEST DESIGN: STAGE 2 .............................................................................................. 25
13.4.1 DECISIONS ON BASIC PROCEDURES AND HARDWARE .................................... 25
13.4.2 BASIC TECHNICAL REQUIREMENTS FOR SUCCESSFUL WELL TEST .............. 26
13.4.3 KEY ITEM DECISIONS .............................................................................................. 28
13.4.4 ADDITIONAL KEY ITEM DISCUSSION..................................................................... 29
13.4.5 DEVELOP DETAILED EQUIPMENT SPECIFICATIONS AND OUTLINE TEST
PROCEDURE ............................................................................................................. 34
13.5 WELL TEST DOWN HOLE EQUIPMENT .................................................................................. 35
13.5.1 EQUIPMENT OVERVIEW .......................................................................................... 35
13.5.2 EQUIPMENT LEAD-TIMES ........................................................................................ 35
13.5.3 TEST STRING ............................................................................................................ 37
13.5.4 TYPES OF LOWER TEST STRINGS ......................................................................... 38
13.5.5 THE APO TEST STRING ........................................................................................... 40
13.5.6 BASIC PRINCIPLES OF OPERATION ...................................................................... 41
13.5.7 RETRIEVABLE AND PERMANENT PACKERS ........................................................ 41
13.5.8 ANNULAR PRESSURE CONTROL NOTE ................................................................ 42
13.5.9 INDEXED TOOLS....................................................................................................... 43
13.5.10 MAJOR APO TEST TOOLS ....................................................................................... 44

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13.5.11 DETAILED DISCUSSION OF MAJOR APO TEST TOOLS....................................... 44

13.5.12 BOTTOMHOLE SHUT-IN VALVE .............................................................................. 45
13.5.13 MULTIPLE CYCLE REVERSING VALVES ............................................................... 54
13.5.14 SINGLE SHOT REVERSING VALVES ...................................................................... 57
13.5.15 OTHER EQUIPMENT ................................................................................................. 58
13.5.16 SAMPLING AND PRESSURE MEASUREMENT RELATED
STRING COMPONENTS ............................................................................................ 59
13.6 UPPER TEST STRING OR LANDING STRING......................................................................... 62
13.6.1 INTRODUCTION ........................................................................................................ 62
13.6.2 PURPOSES AND FUNCTIONS OF LANDING STRING............................................ 62
13.6.3 COMPONENTS OF LANDING STRING .................................................................... 63
13.6.4 BOP STACK ............................................................................................................... 64
13.6.5 FLUTED HANGER ..................................................................................................... 65
13.6.6 SLICK JOINT.............................................................................................................. 65
13.6.7 SUBSEA TEST TREE ................................................................................................ 66
13.6.8 RETAINER VALVE..................................................................................................... 68
13.6.9 SPANNER JOINT ....................................................................................................... 69
13.6.10 SSTT CONTROL LINES ............................................................................................ 69
13.6.11 QUICK DISCONNECTING SSTT SYSTEMS ............................................................. 70
13.6.12 OPTIONAL TEMPERATURE MEASURING DEVICES.............................................. 71
13.6.13 SUBSEA LUBRICATOR VALVE ............................................................................... 71
13.6.14 OPTIONAL RISER SEALING MANDREL .................................................................. 72
13.6.15 STIFF JOINTS ............................................................................................................ 72
13.6.16 OPTIONAL LOWER MASTER VALVE ...................................................................... 72
13.6.17 SWIVEL JOINT........................................................................................................... 72
13.6.18 OPTIONAL CHEMICAL INJECTION VALVE ............................................................ 73
13.6.19 FLOW HEAD .............................................................................................................. 73
13.6.20 SUSPENSION OF THE LANDING STRING .............................................................. 75
13.6.21 SUBSEA HYDRAULIC CONTROL CONSOLE ......................................................... 75
13.6.22 SUBSEA HYDRAULIC CONTROL LINE REELS ...................................................... 76
13.6.23 HYDRATE INHIBITOR INJECTION ........................................................................... 76
13.6.24 WIRELINE/SLICKLINE LUBRICATOR AND BOP .................................................... 77
13.7 SURFACE TEST EQUIPMENT .................................................................................................. 78
13.7.1 INTRODUCTION ........................................................................................................ 78
13.7.2 FLEXIBLE FLOW LINE FLOWHEAD TO RIG FLOOR .......................................... 78
13.7.3 EMERGENCY SHUTDOWN (ESD) SYSTEM FLOWHEAD (AND FLOWLINE)
VALVE ........................................................................................................................ 79
13.7.4 DATA HEADER .......................................................................................................... 80
13.7.5 CHOKE MANIFOLD ................................................................................................... 81
13.7.6 HEATERS ................................................................................................................... 82
13.7.7 SEPARATOR ............................................................................................................. 83
13.7.8 SURGE TANK OR PRESSURIZED TEST TANK ...................................................... 85
13.7.9 GAUGE TANK ............................................................................................................ 85
13.7.10 TRANSFER PUMP ..................................................................................................... 85
13.7.11 PIPING ........................................................................................................................ 86
13.8 INSTRUMENTATION, MEASUREMENT AND SAMPLING EQUIPMENT ................................ 87
13.8.1 DOWNHOLE PRESSURE GAUGES ......................................................................... 87
13.8.2 ERRORS IN PRESSURE MEASUREMENT .............................................................. 90

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13.8.3 DEAD WEIGHT TESTERS AND CALIBRATION ...................................................... 92

13.8.4 PRESSURE GAUGE SPECIFICATIONS AND REQUIREMENTS ............................ 93
13.8.5 GAUGE PLACEMENT ............................................................................................... 96
13.8.6 SURFACE READOUT GAUGES ............................................................................... 97
13.8.7 INFLUENCE OF TIDES ON BOTTOM HOLE PRESSURE MEASUREMENTS ........ 99
13.8.8 VOLUMETRIC FLOW RATE MEASUREMENT OF GASES ................................... 100
13.8.9 VOLUMETRIC FLOW RATE MEASUREMENT OF LIQUIDS ................................ 102
13.8.10 WELLSITE CHECKLIST FOR GAS AND LIQUID METERS ................................... 104
13.8.11 COMPUTERIZED ACQUISITION OF SURFACE DATA.......................................... 106
13.8.12 GAS & FLUID SAMPLING ....................................................................................... 108
13.8.13 FIELD LABORATORY ............................................................................................. 111
13.9 FLARE, STORE, AND DISPOSAL EQUIPMENT .................................................................... 112
13.9.1 INTRODUCTION ...................................................................................................... 112
13.9.2 OIL DISPOSAL OFFSHORE USA ........................................................................... 112
13.9.3 OIL BURNER HEADS .............................................................................................. 113
13.9.4 BURNER BOOMS .................................................................................................... 114
13.9.5 WATER CURTAINS ................................................................................................. 115
13.9.6 BARGES................................................................................................................... 116
13.9.7 CARGO OFF-GASSING AND SAFETY ................................................................... 118
13.9.8 COSTS ..................................................................................................................... 118
13.9.9 BARGE RIG-UP LINES, FLOWLINE, AND EMERGENCY RELEASE................ 119
13.9.10 FLOW HOSE AND AUTO-DISCONNECT ............................................................... 121
13.9.11 EXAMPLE OF COMMUNICATIONS AND DISCONNECT PROCEDURES ............ 121
13.10 PERSONNEL RESPONSIBILITIES AND INFORMATION RETRIEVAL ................................. 122
13.10.1 PERSONNEL RESPONSIBILITIES ......................................................................... 122
13.10.2 INFORMATION RETRIEVAL AND HANDLING ....................................................... 131
13.10.3 SURFACE DATA...................................................................................................... 131
13.10.4 REVIEW OF TYPES OF WELL TEST DATA AS COVERED BY T H E D F O R M S 133
13.10.5 DESCRIBING, LABELING AND SHIPPING SAMPLES .......................................... 138
13.10.6 WELL SITE REPORTS ............................................................................................ 139
13.11 PRODUCTION TESTING OPERATIONS................................................................................. 140
13.11.1 PRE-TEST PLANNING ITEMS................................................................................. 140
13.11.2 EQUIPMENT CHECKS AND SET UP ...................................................................... 145
13.11.3 OVERVIEW OF TEST PROCEDURES ON DOWNHOLE OPERATIONS ............... 146
13.11.4 THREE BASIC TEST PROCEDURE STRUCTURES .............................................. 147
13.11.5 BASIC TEST PROCEDURES .................................................................................. 151
13.11.6 PERFORATION, INITIAL FLOW, INITIAL PBU PROCEDURE ............................... 152
13.11.7 POLLUTION CONTROL .......................................................................................... 158
13.11.8 EMERGENCY PROCEDURES................................................................................. 159
13.12 TEST EXECUTION ................................................................................................................... 161
13.12.1 INITIAL FLOW .......................................................................................................... 161
13.12.2 MAIN FLOW ............................................................................................................. 161
13.12.3 UNLOADING WELL ................................................................................................. 161
13.12.4 SWITCHING FLOW TO SEPARATOR .................................................................... 164
13.12.5 BRINGING THE WELL UP TO STABLE TEST RATE............................................. 164
13.12.6 BACKING OFF MAX RATE TO SUSTAINABLE STABLE RATE .......................... 167
13.12.7 SAMPLING ............................................................................................................... 168
13.12.8 UNEXPECTED (HIGH) WATER PRODUCTION ...................................................... 169

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13.12.9 SHUTTING THE WELL IN ........................................................................................ 170

13.12.10 REAL BUILDUP ANALYSIS WITH SRO ................................................................. 170
13.12.11 POST MAIN TEST OPTIONS ................................................................................... 171
13.12.12 WRAP-UP ................................................................................................................. 172
13.13 SPECIAL SITUATIONS............................................................................................................ 173
13.13.1 H2S, GAS HYDRATES, AND FLOW BACK TESTS .............................................. 173
13.13.2 HYDROGEN SULFIDE: PROPERTIES AND EFFECTS.......................................... 174
13.13.3 GAS HYDRATES: FORMATION AND PREVENTION............................................. 179
13.13.4 COMMON OCCURRENCE OF HYDRATES IN WELL TESTING OPERATIONS ... 180
13.13.5 HYDRATES IN GAS WELLS ................................................................................... 181
13.13.6 WATER AND ITS SALINITY .................................................................................... 182
13.13.7 PREDICTING LOCATIONS AND TIMES FOR HYDRATES IN THE WELL TEST
SEQUENCE .............................................................................................................. 185
13.13.8 METHANOL IS THE BEST INHIBITOR ................................................................... 188
13.13.9 CAN GAS HYDRATES BE A PROBLEM IN OIL WELLS? ..................................... 191
13.13.10 RULE-OF-THUMB FOR METHANOL INJECTION INTO GAS WELLS .................. 193
APPENDIX A - PERSONNEL RESPONSIBILITY ESSO EXPLORATION ............................................. 197
APPENDIX B - READINESS CHECK LIST ESSO EXPLORATION ....................................................... 198
APPENDIX C - EXAMPLE SPACE OF LANDING STRING ................................................................... 209
REFERENCES .................................................................................................................................. 210

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WELL TESTING OPERATIONS

13.1 INTRODUCTION

13.1.1 WHAT IS PRODUCTION TESTING?

Production testing is the most direct, reliable and comprehensive way to evaluate the
commercial potential of hydrocarbon bearing formations. It is conducted by flowing
through a completed well and surface facilities which are specially instrumented for
pressure, temperature, and flow rate measurements. The well is flowed, sampled, and
shut-in according to a specifically designed schedule, as specified in the test design.
Lease or political re q u ire m e n ts so m e tim e s d icta te te stin g fo r p re ss re le a se .

13.1.2 MOST COMMON FORM: PRESSURE TRANSIENT

TESTING

Production testing is sometimes called p ressu re tran sien t testin g . This is because
m e a su rin g th e p ro file o f th e p re ssu re tra n sie n ts re tu rn to the well bore, during the
shut-in period after production, is a crucial and integral part of most production tests.
Assuring the generation and capture of high-quality pressure transient data can be easily
overlooked in designing and operating well tests. In the design, equipment, and
operations sections that follow, we will emphasize what needs to be done to get good
pressure transient data. Running a production test without good pressure transient data
is like doing a seismic survey with geophones.

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Idealized Dual Flow - Dual Shut-in Sequence

6050

Initial Flow
6025

6000

5975
Main Flow Main Shut-in

5950
Pressure, PSIA

5925

5900

5875

Initial Shut-in
5850

5825
Figure 13.1 Idealized Flow Test
5800
0 12 24 36 48 60 72 84 96 108 120
Time (hours)
Figure 13.1 Idealized Flow Test

Such a test is often called the dual-flow, dual shut-in test (DFDS test). Figure 13.1
shows a typical bottomhole pressure response generated over the duration of this test.
W h e n w e u se th e te rm w e ll te st o r te st in th is te xt, it w ill re fe r to a p ro d u ctio n test of
the DFDS type, executed from a floating drilling rig, unless noted otherwise.

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WELL TESTING OPERATIONS

13.1.3 UNIQUE CONSIDERATIONS IN FLOATING RIG

WELL TESTS
Well testing theory is constant and applicable to all types of tests on all reservoirs from
all sorts of rigs. However, in planning and operating the well test from a floating rig, a
different set of constraints must be considered.
Some of the key constraints and considerations are listed below:
1. Concerns held in common with general floating rig operations
sea state, weather, safety of a confined crew, high environmental sensitivity.
High cost of operation.
2. Some concerns unique to floating testing:
Vessel motion, heave, rotation, off-station, emergency disconnects.
Heightened safety considerations due to high pressure, inflammable,
explosive, and possibly poisonous flowstream fairly proximate to personnel,
and their quarters.
Handling produced hydrocarbons, disposal and burning at a rate high enough
to te st o r stre ss fo rm a tio n .
High heat flux on rig due to flaring gas or burning oil.
V e ry co ld flo w stre a m (h yd ra te s, sta b ility o f sto ck ta n k cru d e ).
Complicated and expensive, but versatile equipment (especially test string).
High costs due to weather uncertainties mean usually just one shot at the
test, be prepared the first time with procedures and equipment for
contingencies.

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WELL TESTING OPERATIONS

13.2 WELL TESTING OBJECTIVES

Following is a typical set of objectives for testing an exploration or delineation well. Of
course, there may be additional specific objectives, but they are normally incidental ones
that do not impact the basic test design, equipment or operation. They are listed in order
of ease of attainment and frequency, that is, Objective 1 is the simplest and most
commonly encountered.
1. Confirm the existence of producible hydrocarbons in the reservoir.
2. Measure the productivity of the well, GOR, WOR, BCPM, etc.
3. Obtain fluid samples for PVT and chemical analyses.
4. Measure the formation pressure and temperature.
5. Obtain data that can be analyzed for bulk formation flow capacity (kh), and
completion efficiency (alternately, Skin damage).
6. Rule out any quick developing production problems, or very early depletion.
7. Determine reservoir limits, shape, and significant minimum connected reservoir
volume.

13.2.1 HOW OBJECTIVES AFFECT THE CONCEPTUAL WELL

TEST DESIGN

Objectives 1, 2 and 3: Objective 1 might be reached in a very qualitative way by a

wireline formation test (FMT) run. But objectives 2 and 3 require that the well be
completed, cleaned up, and produced until stable flow can be maintained at the surface.
Objective 4: Requires a short initial flow and shut-in/buildup to get the initial pressure of
the reservoir. This is the cornerstone parameter for not only subsequent pressure
buildup analysis, but for reservoir engineering studies.
Objectives 5 and 7: Objective 5, which is always sought in a production test, and
Objective 7 require using the dual-flow, dual shut-in technique to generate and monitor
pressure transient data for analysis. Objective 7 will usually require significantly longer
main flow times and shut-in times, and always very high-quality pressure-buildup data.
This will be discussed in more detail in section 13.3 Test Design Concepts.
Objective 6 will be reached if the other objectives are pursued. It should also be
emphasized that full pressure buildups are important the echo of the pressure
transients generated by the main flow should be harvested by a pressure buildup. There
have been examples where the pressure buildup was skipped or too short, and the
reservoir proved to be very small when another well was drilled close by and missed the
re se rvo ir. T h e flo w p e rio d p re ssu re tra n sie n t sa w th is, b u t n e ve r g o t th e ch a n ce to
report back in the pressure buildup.

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More on Objective 7
Test Economics: Objective 7 may add two or three days to the flow time, and three to
five days to the buildup time perhaps $2 to $3M to the test cost. But a point to keep in
mind regarding longer tests and the high cost is that, for a very short exploration well
test, approximately 8 0 % o f th e co st is fixe d . T h is fixe d co st in clu d e s co m p le tio n , rig u p ,
rig down, equipment standby, rig and design costs. Thus, as shown in Figure. 13.2, a
DEEPWATER
test with three timesESTIMATED
the flow and shut-in
WELL
periodsPER
TEST
costs about 40% more and will produce
TIME & EXPENSE PHASE
significantly more reliable and useful information. Three times the reservoir volume will
be investigated and up to three times the reserves can be proved up with a 40%
additional expense.
Information Gained From Test

6 days, 1.8 M $
12 days and 3.6 M $ 6 days, 1.8 M $

Figure 13.2 - Test Economics

Clean-Up/Flow/ Stim/Flow
4 Days, 1.20 M $

Constraints: On the other hand, a test aimed at establishing a commercial reservoir, or

at least proving up enough reserves to justify further drilling, may require days to weeks
of flow and a longer period of pressure buildup. Economic constraints aside, the practical
test length from a floating rig is limited by operational, weather, and environmental
constraints.

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So an aggressive test objective for proving up commercial reservoir size may not have a
high chance of approval or success. Once into the main flow period, flow interruptions,
especially one requiring a disconnect sequence in which the well is killed, are fatal to the
pressure transient analyses for Objectives 5 and 7.
Typically production tests from floating rigs will involve flows from 24 hours to 3 days,
with pressure buildups of one to two times the duration of the flow periods. The shorter
flow period tests will definitely be light on Objective 7. However, even if the list of test
o b je ctive s d o e sn t in clu d e a T yp e 7 o b je ctive , th e b u ild u p fo r a n e xp lo ra tio n w e ll te st
should always be conducted and analyzed as if it did. As mentioned above in reference
to Objective 6, there may be bad but very valuable news in the buildup data, like the fact
that a very small reservoir sand was tested and significantly depleted by the test.

13.2.2 DETERMINATION OF TEST OBJECTIVES

In th e o ry, th e clie n ts d e cid e th e te st o b je ctive s, w ith th e a ssista n ce a n d re co m m e n d a -

tions of the test specialist, reservoir engineers and drilling. Clients normally include the
exploration organization the well is being drilled for, the reservoir engineers in the
production organization that will develop the field, facilities design personnel, etc.
The test specialist will package the objectives into a Test Design document. Any special
equipment or procedure requirements will be added to the Test Design document.
Drilling will conduct a risk analysis, participate in equipment and vendor selection, and
develop detailed procedures.

13.2.3 PRIORITIES OF TEST OBJECTIVES

It is important that a consensus on the objectives, and their relative priorities, be reached
and documented. Priorities highly depend on specific circumstances. But generally,
lower priority objectives are often easily attained incidental to pursuit of larger objectives,
with no additional costs, when the test design is appropriate. Less often, because of
unforeseen developments or difficulties, certain objectives previously agreed to may
become mutually exclusive. This is the reason for pre-agreed, iron clad priorities.
Of course, things do change.

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WELL TESTING OPERATIONS

13.3 WELL TEST DESIGN CONCEPTS: STAGE I

13.3.1 INTRODUCTION

A well test design is the overall plan to be followed to attain the well test objectives.
It should include contingency plans for diagnosing unexpected poor well performance
and other problems and for correcting them, if possible.
The initial stage of the design, the conceptual stage, will require information on the test
objectives, estimated reservoir and fluid properties, and the application of pressure
transient principles. The latter usually takes the form of using well test or reservoir
simulators to determine flow times, and estimated rates and pressures. In some
cases, these will be gross estimates.
The second stage of the test design involves the specification of general types of
hardware, capacities, pressure ratings, design of the completion, and selection and
placement of instrumentation downhole. This will be discussed in the following topic
entitled Well Test Design Stage 2 Decisions on Basic Procedures and Hardware.
The third stage of well test design, which involves a step-by-step plan to execute the
test, is actually known as the Well Test Procedure. It may be subdivided into several
main parts covering such operations as the makeup of the test string, perforating and
completion operations, pressure testing equipment, flowing the well, on through to
abandonment. Before the procedures can be written, all test equipment must have been
specified/selected. Since procedures are at the finest level of detail, significant parts of
them are equipment specific.
The test design process seems like a formidable one, and it is. But in reality, hardly ever
does a test have to be designed from the ground up. Past experiences with the rig, the
equipment, and procedures are invaluable in streamlining the latter two stages of the
n e w te st d e sig n . O n ce th e te st o b je ctive s a n d th e re se rvo irs co n d itio n a n d flu id
properties are known, the conceptual test design can be quickly completed.
Then, past experiences with equipment and procedures can be drawn upon.

13.3.2 PHASE 1: WELL TEST DESIGN CONCEPTUAL STAGE

This stage is usually the responsibility of the well test engineer or test specialist. The
starting point is the collection of all available formation evaluation data (logs, cores,
wireline tester data, etc.) and a decision on the objectives of the test.

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13.3.3 DUAL FLOW, DUAL SHUT-IN TEST

Any typical set of test objectives requires use of the DFDS test. This test consists of the
following four events, always in the sequence below:
1. A (normally short) initial flow period.
2. An initial pressure buildup period, five to ten times longer than initial flow,
usually one hour minimum.
3. Then the main flow period, length to be discussed the major part of test design.
4. Then the main pressure buildup period, usually one to two times the main
flow period.

13.3.4 SHUT-IN PERIODS OR PRESSURE BUILDUPS IN

PRODUCTION TESTING

Why are pressure buildups needed in production testing? On the surface, it seems like a
waste of time and money to sit around doing nothing for several days after the flow test.
Figure 13.3 illustrates that the flow periods or pressure draw-down phases of the
DF/DSI test sequence are usually quite noisy. This is because the flow period is affected
by rate changes, completion cleanup, plugging and other changes in the flow path.

Real Dual Flow - Dual Shut-in Sequence

6050

Initial Flow
6025

6000

5975
Main Flow Main Shut-in
Pressure, PSIA

5950

5925

5900

5875
Initial Shut-in
5850

5825

Figure
5800 13.3 - Real Flow Test
0 12 24 36 48 60 72 84 96 108 120
Time (hours)

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As a result, the flow test (called the draw-down) only tells us what the well actually did in
the test - what we can see at the surface - a measured flow rate at a measured (overall)
p re ssu re d ro p . It d o e sn t h e lp to so rt o u t th e va rio u s co m p o n e n ts o f flo w resistance.
In theory, the draw-down pressure transient should be able to do more (see past
d a m a g e d co m p le tio n s, fa u lts, o r d e p le tio n ), b u t in p ra ctice , it ca n t.
We need this information, and only the buildup portion of the test can tell us what the
we lls p o te n tia l is (is p ro d u ctio n h a m p e re d b y a p o o r co m p le tio n ? ). A n d if d e sig n e d to d o
so, the buildup can give us some information about reservoir size and shape. We cannot
sort out any reservoir size or quality change effects from the draw-down. Pressure
buildups are required for any sort of reservoir description
The buildup can do this because it provides clean, noiseless, and focussed pressure
tra n sie n t d a ta fo r a n a lysis a n d m o d e lin g . B u t th is p re ssu re tra n sie n t d a ta is ve ry
d e lica te a n d su b tle . S o m e estimated but typical magnitudes of pressure disturbances
ca u se d b y flo w th ro u g h va rio u s e le m e n ts o f th e re se rvo ir syste m a re liste d b e lo w .
Many of the objectives of a production test analysis depend on sorting out these
elements from the pressure buildup data.

Reservior Element T yp ical P ressu re D istu rb an ce

Across completion sandface 10 2000 psi
Due to completion damage -200 1000 psi
Due to Faults, Heterogeneities 0.2 20 psi (/cycle)
Small Bounded Reservoir, early 5 30 psi
depletion
Table 13.1 Typical Pressure Disturbance

From Table 13.1, it is easy to see that most of the pressure drop occurs across the
completion. The additional pressure disturbances due to possible faults,
heterogeneities, or depletion would typically be only an extremely small percentage
of the total pressure drop observed at the completion. Looking at Figures 13.1 and
13.3, this is apparent. Ninety five percent of the pressure buildup occurs in the first
hour of shut-in. This is the recovery of the pressure drop across the completion and
near-wellbore region.
In addition to production rates, reservoir size is of critical importance. Reservoir size
(at least the minimum size proved up by the test) can be inferred by anomalies in the
pressure buildup caused by faults, heterogeneities, and depletion. These are subtle,
and occur gradually over days in the latter stages of the main pressure buildup,
so m e tim e s ca lle d th e la te tim e re g io n .

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Figure 13.4 illustrates some simulated pressure buildup results for a typical well test that
produced 4000 BOPD for 36 hours from a 400 md, 100-ft thick formation. The well is
considered to be in five different reservoir situations. The reservoir initial pressure is
6000 psia.
1. An infinite reservoir.
2. A single fault 1000 ft from the well.
3. We ll is ce n te re d in a 2 0 0 0 w id e ch a n n e l.
4. Well is centered in a 92 acre square closed reservoir, 2000 x 2000 ft
5. Well has pressure support on two opposite sides, each 1000 ft away.

Well Test Pressure Build-Up

Main Shut-In
6025

5 psi difference in PBU is critical to evaluation

6000
Pressure, PSIA

5975

5950

Infinite Reservoir
Fault @1000ft
5925
Channel 2000' west
92 Acres Closed
Nearby Pressure Support

Figure 13.4 - Pressure Buildup

5900
40 50 60 70 80 90 100 110
Time (hours)

There are several things to note on Figure 13.4. All the buildups recover most of the
pressure drawdown quickly, in the first half-hour or less. The pressure recovery in the 92
acre closed reservoir is noticeably incomplete, lining out at about 5967 psia. All the
other cases are approaching the initial pressure of 6000 psia, but from different
pressure levels.

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Note: The differences in pressure buildup levels are only two to six psi for these quite
different reservoir geometries. Also note that shape of the buildup curve is just as
important in pressure buildup analysis as the pre ssu re le ve l. S h a p e d iffe re n ce s a re n t
readily apparent here. To get a better definition of the shape, this data would be
tra n sfo rm e d (tim e sca le d isto rte d ) to m a ke a H o rn e r p lo t. F u rth e r d e fin itio n fo r
diagnostic work would result from a log-log derivative transform. These techniques are
very helpful but put a premium on getting excellent, distortion-free pressure buildup data.
To summarize, the diagnostic pressure transients resulting from reservoir quality
boundaries of depletion are overwhelmed by the n o ise in th e d ra w d o w n p re ssu re
disturbance due to even minute, undetectable rate fluctuations. And although the drilling
engineer does not need to interpret the buildup data, he will be required to ensure the
test objectives are meeting safety standards with no environmental incidents.

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13.3.5 WHY THE PRESSURE BUILDUP WORKS

With the well shut-in for a pressure buildup, the rate is zero and constant (hopefully with
only some initial, brief and slight exceptions, to be discussed). Having thus eliminated
the influence of the very large pressure transients at the completion, due to production
rate fluctuations, well cleanup, etc., the resultant buildup pressure transient should
clearly show the effects of completion efficiency, reservoir quality, nearby boundaries,
and apparent depletion, if any.
The buildup time is normally required to be one to two times the flow time to get all of the
information available from the pressure transients generated by the flow period.
However, under certain conditions the buildup period can be cut to the flow period
length. These conditions are not often satisfied, but will be stated here.

13.3.6 PURPOSE AND LENGTH OF THE FOUR DFDS

TEST PERIODS

INITIAL FLOW PERIOD

The purpose of the Initial Flow Period is to relieve the formation fluids near the wellbore
of any supercharged pressure due to drilling or completion operations. It does so by
taking a small amount of flow into the wellbore, and drawing the pressure below the
static reservoir pressure. With a bottomhole shut-in valve (now normally recommended
practice in floating well test strings), the produced amount may be as low as two to six
barrels of flow, depending on the bottom hole volumetrics, and geometry between the
pressure gauge and the completion.
The initial flow should also clean the perforation area of much of the debris and mud
solids lodged there, establishing good communication between the formation and the
bottom of the test string (Bottom Hole Assembly or BHA). A well-designed initial flow
volume will shut the well in before this debris gets into the production screen or screens
(in-line screens), allowing it to fall harmlessly down into the bottom of the rathole,
hopefully never to be seen again.
Without a bottomhole shut-in valve, it would normally be necessary to clean up the well
(including the production test string) during the initial flow period. Otherwise, phase
segregation might wipe out the pressure buildup for initial pressure. In this case, the
initial flow period could last more than six hours even in a productive well. The initial
buildup would be suspect in most cases, due to up-hole disturbances in the tubing, even
if it lasted many hours.

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INITIAL BUILDUP PERIOD

Shutting the well in at the bottom hole valve for a buildup ends the initial flow. The
pressure will build up and approach the initial reservoir pressure at a rate roughly
depending on the amount of time and fluid produced, fluid viscosity and formation
permeability, and communication through the perforations. It will also depend on bottom
hole contents and volume, but this is reduced to insignificance with bottom hole shut-in.
As rule-of-thumb, the initial buildup period, with bottom hole shut-in, should last for one
hour minimum, or five times the initial flow period, whichever is longer. In tight
formations, make that ten times.
MAIN FLOW PERIOD
The Main Flow Period has three purposes:
1. To complete cleanup of the well as much as possible, to establish stabilized
production from the well, and stable operation of the surface equipment,
especially the separator. On a productive deepwater well that kicks off with ease
(n o h e lp re q u ire d ), it is p o ssib le to re a ch th is sta b le o p e ra tio n in e ig h t to 1 6
h o u rs, a n d still a vo id g e ttin g ro u g h w ith th e w e ll. In m o re d ifficu lt w e lls, fo r
instance a well that was perforated and gravel packed with high completion fluid
lo sse s, th e clo ck o n m a in flo w isn t sta rte d u n til th e w e ll flo w s o n its o w n a t a
good rate.
2. To obtain a comprehensive set of samples of the produced fluids, possibly
downhole, certainly from the separator, and from other locations.
3. To introduce a steady pressure transient into the formation for a sufficient time to
reach a specified radius of investigation. This is associated with Test Objective 6,
and a flow period long enough to fulfill Main Flow Purpose 1 will fulfill Test
Objective 5.
The relationship between flow time and the radius of investigation depends solely on
fluid and rock properties, and not on flow rate. Hence, all required data can often be
obtained while producing at low or moderate (2000 to 4000 BOPD) flow rates. This often
determines the test tubing size. Of course, some of these properties are not known
before the test, and in fact, the test is designed to obtain them. In order to design the test
for Test Objective 6, assumptions must be made about rock and fluid properties.

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More specifically, the production time Tp (in hours) required to reach a radius of Ri
(in feet) is given by:
Tp = (Ri * Ri) /(4)
Where = 2.637*10-4 * K/( c)
K = permeability in md
= porosity (fractional)
c = compressibility, sips
= viscosity (cp)

T o g e t a fe e l fo r th e m a g n itu d e o f th e n u m b e rs th a t g o in to th is e q u a tio n , le ts se t so m e
input parameters:
K = 800 md, = .7 cp, = 28%, c = 1.2*10-5
= 2.637*10-4 * 800 md /(0.28*1.2*10-5*0.7)
= .21096/(2.352*10-6) = 89.694*10-3
For a 2500-ft radius of investigation the required production time would be:
Tp = 2500*2500/(4*89.694*10+3) = 17.42 hours for transient to reach a point
2500 ft from the wellbore.
Please note that this equation only gives the time for the first part of the pressure
transient to reach a point 2500-ft from the wellbore. As a practical matter, the bulk of the
transient (or peak of the ripple) must reach this point. Furthermore, if there is a reservoir
h e te ro g e n e ity a t 2 5 0 0 ft, th e p re ssu re tra n sie n t h ittin g it m u st re tu rn its e ch o to th e
wellbore during the flow period for this feature to be detected and properly characterized
as a heterogeneity in the pressure buildup. Otherwise, there will be interference between
the echo from the heterogeneity at 2500 ft and the shut-in.
What this all means is that the flow time given by this equation needs to be multiplied by
a factor of about three. This assumes a valid initial pressure is obtained on the same
pressure gauge as used in the main buildup. Thus, to properly investigate the fault at
2500 ft in our example, a 52-hour flow time would be required, and a 78-hour buildup.
Or about 5.5 days of major flow and buildup time.
Also note that for a given formation (constant rock and fluid properties), the flow time
required for the pressure transient to reach a given radius is proportional to the square of
that radius - called the radius of investigation. Since, for a constant thickness
reservoir, the amount of volume investigated is also proportional to the square of the
radius of investigation, the volume investigated is proportional to the flow time.
The purpose of the Main Shut-in period is to initiate the pressure recovery and record
the pressure buildup of the reservoir at the wellbore, beginning at the instant of shut-in
and continuing until the buildup has lasted for one to two times the main flow. It should
only be shortened if there are no type 6 Test Objectives whatsoever. Please note that
this situation is not advisable in an exploration or delineation well test, because you
should always want to know the minimum test proved-up reservoir size, no matter how
short the flow, and how small minimum is. Otherwise, you might be testing a small sand
lens, and not know it.

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13.3.7 CONTENTS OF CONCEPTUAL TEST DESIGN

DOCUMENT

The conceptual test design states:

1. The test objectives.
2. The interval to be perforated (carefully noting logged depth references).
3. The general test type (e.g., Dual Flow, Dual Shut-in).
4. The flow and shut-in times for the main flow.
5. Estimated flow rates, GOW.
6. Estimated cumulative produced volumes.
7. Sampling requirements.
This document should be circulated to the well owners, the Formation Evaluation group
at EMEC, project reservoir engineers from the client production organization, the drilling
group assigned to the well and key functions at URC (e.g., facilities design personnel,
fluid-property experts, and the completions/stimulation group).
Although the conceptual test design does not usually get specific with equipment
requirements, it will usually specify that a bottom hole test valve is required.

13.3.8 BOTTOMHOLE PRESSURE MEASUREMENT

COMPLICATIONS

Bottomhole pressures are the key data collected in pressure transient testing. As will be
d iscu sse d in S e ctio n 7 , to d a ys e le ctro n ic p re ssu re g a u g e s a re e xtre m e ly p re cise , h a ve
quite good accuracy, and are temperature compensated, reliable, robust, and have
sufficient memory to store the pressure data generated over months of test time.
So, what are the complications?
There are two separate problems that can largely be solved by a good test design. They
b o th ca u se n o ise o r d isto rtio n s in th e m e a su re d b o tto m h o le p re ssu re so th a t th e g a u g e
is not measuring what is required for meaningful analysis. Unfortunately, there are no
re a l m e a n s o f filte rin g th is n o ise o u t to g e t w h a t is n e e d e d . A n d fin a lly, th e n o ise ca n
obscure or wipe out the features in the pressure transient response that must be seen
and analyzed to reach test objectives.
Recall that pressure buildup analysis theory requires that the pressure transient data
re p re se n t th e p re ssu re a t th e sa n d fa ce o f th e re se rvo ir, u n d e r no flow or shut-in
conditions. There are two separate problems here, and neither is the fault of the gauges
themselves, but one solution helps solve both problems.

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13.3.9 GAUGE LOCATION AND CHANGING

H Y D R O S T A T IC C O R R E C T IO N

GAUGE LOCATION

T h e first d isto rtio n a rise s fro m th e co m m o n situ a tio n in w h ich th e p re ssu re g a u g e m u st

be located some vertical distance (usually above) from the completion. In some cases,
it is not possible to put the gauge opposite the perforations (e.g., conventional gravel
pack, or simple TCP perforate and test), without moving the string which contains
gauges fixed in the string.
So, in m a n y ca se s, th e p re ssu re g a u g e s a re n t lo ca te d a t th e co m p le tio n , b u t a fe w fe e t
up to one hundred feet or so above the perforations. This means that the gauges are not
measuring the reservoir pressure at the sandface, but measuring the pressure minus the
ch a n g e in h yd ro sta tic p re ssu re fro m th e g a u g e to th e re se rvo ir. W e ll ca ll th is th e
h yd ro sta tic co rre ctio n . U su a lly, th e re se rvo ir m id p o in t is u se d a s th e re se rvo ir p re ssu re
datum. So the gauge will indicate the reservoir midpoint pressure at the sandface minus
the incremental hydrostatic pressure exerted by the fluid(s) column(s) in the wellbore
between the gauge and the reservoir midpoint. This hydraulic correction will be directly
related to the fluid(s) density(ies) and the true vertical height of the gauge above the
reservoir midpoint.
If th is h yd ro sta tic co rre ctio n (ca ll it o ffse t) w e re co n sta n t th ro u g h o u t th e in itia l a n d m a in
pressure buildups, and we knew what it was, there would be no problem correcting the
gauge pressure data, assuming we knew its location relative to the reservoir midpoint.
U n fo rtu n a te ly th is o ffse t ca n ch a n g e d u rin g te st can this be quantified? We should
know the hydrostatic correction before initial flow, but maybe not after it, if we displace
some of the completion fluid, and the displacing fluid ends up between the gauge and
the reservoir. After the main flow, we must make an assumption about the fluid between
the gauge and the reservoir. It may be an easy one, if the well flow rates were high, and
it cleaned up and made no water. If the well was making any water at shut-in, then there
a re tw o p o te n tia l p ro b le m s: T h e re is a n u n kn o w n o ffse t, a n d th is o ffse t w ill b e
changing during the PBU.
In many cases though, there may be a change in this hydrostatic offset that ca n t b e
predicted, detected, or quantified. A few quick calculations can show that even in
oil-water systems, the uncertainties in the offset can range from 0.5 to 10 or 20 psi.
A n d th is fo rm o f n o ise in th e p re ssu re b u ild u p ca n d e stro y th e in te rp re tation.
In its m o st in sid io u s fo rm , th is n o ise m a y b e w e ll b e h a ve d a n d m im ic th e b e h a vio r o f a
fault or multiple boundaries in the pressure buildup analysis. At the minimum, it may
cause a discrepancy in the correlation of initial buildup pressure to the extrapolated final
buildup pressure, mimicking or masking depletion.
Rarely can gradient surveys be run to help in these situations. And when they can be, in
some cases they would disturb the measurements sought. It is better to try to mitigate
the problem in the test design.

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13.3.10 SOLUTIONS FOR CHANGING HYDROSTATIC

CORRECTIONS

The potential for problems with unknown and/or changing hydrostatic corrections to the
bottomhole pressure gauge is minimized by:
1. Using a bottomhole tester valve.
2. Putting gauges as close to completion as possible.
3. Design of BHA (e.g., put gauge below fluid entry point in tailpipe, not in some dead
end space up under packer).
4. Well-designed Initial Flow procedure, with produced volumes conducive to giving
hydrostatic correction at end of IPBU.

13.3.11 N O F L O W C O N D IT IO N VIOLATIONS

Pressure buildup analysis theory requires that the pressure transient data represent the
p re ssu re a t th e sa n d fa ce u n d e r no flow or shut-in conditions.
There are two real world complications to the no flow condition being satisfied during
the PBU.
1. Afterflow refers to the fact that fluid flows through the perforations some time after
the well is shut-in. This flow must occur to equalize the pressures in the wellbore and
in the reservoir at the perforations. The reservoir pressure is initially recharging very
rapidly near the completion at start of shut-in.

If the well is shut-in a t th e su rfa ce , th e n th e re s a la rg e vo lu m e in w h ich th e p re ssu re

must be equalized. Afterflow can extend for some time, the extreme being in low
productivity gas well tests. Afterflow distorts the PBU.
2. Phase Humping (AKA phase segregation, phase redistribution). This problem is
normally only a problem with wells producing at least some gas and significant
liquids. The root problem is analogous to that of a gas kick, and circulating it out. The
difference in the case of the well being shut-in is that there is a built-in outlet for the
large increase in pressure due to the rising gas buBbles. It is the perforations, and
the well will proceed to pump-in, or go into an injection mode. And the pressure
h u m p , q u ite o b vio u s o n th e p re ssu re b u ild u p p lo t, ca n b e u p to se ve ra l h u n d re d
pounds in magnitude. Its effect eventually begins to die out, but by that time it has
totally wiped out the buildup to that point, and cast serious doubts on the portion
which follows.

A similar effect may be seen when tests are run with strings that employ ESP pumps
and no bottomhole tester valve, or effective check valve. When the pump and well
are shut d o w n , th e p re ssu re b o o st su p p lie d b y th e p u m p ca u se s th e w e ll to g o o n
injection for a time, until the pressure in the test string equalizes with the reservoir
sand face pressure.

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13.3.12 SOLUTION FOR AFTERFLOW AND PHASE HUMPING

The bottomhole shut-in valve will, for all practical purposes, eliminate afterflow and
phase humping problems, and reduce problems associated with the changing
hydrostatic correction (Figure 13.5).

Volatile Oil
Gas Phase Humping & Falling Liquid Level

K = 190.59 md
S = 300.06
P = 5004.31 psia

Falling liquid level

Shut-In Pressure (psia)

Gas humping

Figure 13.5 - Phase Humping

Superposition Time Function

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13.3.13 INFLUENCE OF TIDES ON BOTTOM HOLE PRESSURE

MEASUREMENTS

The effect of tidal cycles can be seen in the latter stages of the PBU of offshore tests in
many cases. Even when reservoirs are abnormally pressured, tidal cycle oscillations are
observed in the latter stages of the buildup data, although at greatly reduced
magnitudes. This means that the added hydrostatic pressure due to sea height increase
is being transmitted down to reservoir depth by slight flexure of the rock.
Tidal fluctuations are well behaved and recognizable on the buildup. The best approach
to deal with this unwanted distortion of the pressure data is to filter it out of the data.
Using actual tidal data in the area while testing make this a much more reliable process.
One means to get this data is to affix a pressure gauge to the riser below the slip joint.

13.3.14 CONCEPTUAL TEST DESIGN WRAP-UP

We have covered the basics of the conceptual test design and what it encompasses
the DFDS test method, pressure transients, radius of investigation, flow and buildup
times, and practical considerations in getting representative bottomhole pressures.
The next section will deal with phase 2 of test design, the specification of general types
of hardware, capacities, pressure ratings, design of the completion, and basic
procedures.

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13.4 WELL TEST DESIGN: STAGE 2

13.4.1 DECISIONS ON BASIC PROCEDURES AND HARDWARE

In the next stage of the test design, key decisions must be made regarding the
completion, basic test string components, the subsea safety system, and surface
equipment. Then test procedures can be outlined. And as this process of reducing the
conceptual test design to practice plays out, some compromises involving the
completion, equipment, and even some test objectives may be necessary. For example,
there may be equipment-related restrictions on the maximum production rate or
regulatory restrictions on the duration or total volume of production.
Good communication among the key decision-makers is essential to reaching these
compromises to minimize negative effects on the test objectives. Excellent coordination
between the test specialist or engineer, the drilling engineers, drilling operations and the
various service companies must be in place from very soon after the beginning of
planning until the test is over. And of course, there should be prompt feedback to the
clients if any of the test objectives have to be sacrificed, or tradeoffs made.
O f co u rse , fa cto rs b e yo n d a n yo n e s co n tro l m a y a d ve rse ly im p a ct th e ch a n ce s o f
attaining a given set of well test objectives. This may occur in spite of the effort made to
employ the best pressure gauges, downhole tools, completion techniques, and test
procedures. Weather, reservoir complexity, operational difficulties, poor well condition,
malfunctioning equipment, and human error are some examples of these factors. It is
important, therefore, to develop an understanding of what can go wrong beforehand, and
have contingency plans in place. Some tests that have failed to reach their objectives
had test designs without plans to handle unexpected events or conditions.
Once stage 2 is completed as per this section, equipment can be selected and the third
sta g e o f th e T e st D e sig n ca n th e n b e co m p le te d . T h is sta g e is u su a lly ca lle d th e T e st
P ro ce d u re sta g e . It co n sists o f w ritin g d e ta ile d , ste p -by-step, nuts and bolts procedures
for the various parts of the test. In practice, procedures are usually not started from
scratch, but some or many parts are adapted from previous test procedures.

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13.4.2 BASIC TECHNICAL REQUIREMENTS FOR SUCCESSFUL

WELL TEST

Safety, operational integrity, and concern for the environment are of paramount
importance in any testing operation. They cannot be compromised. A well test cannot
be considered successful without an operation whose planners and participants are
all totally committed in each of these areas.
After the groundwork has been laid, specific technical requirements must be met to
conduct a successful well test:
1. The well must be mechanically sound, in good pressure communication with and
only with the interval to be tested. That is to say an efficient completion with no
cement channels or leaks.
2. A valid initial pressure buildup should recorded on the main test gauge(s), with
the information and means to accurately correct gauge readings to a reservoir
datum depth.
3. A significant pressure drawdown must be induced in the reservoir by flowing the
well at a stable rate for the time period required as noted in the well test design.
4. Recorded bottomhole pressure buildup that measures only the reservoir pressure
recovery, and free of wellbore effects. Bottomhole pressures during the flow
period, as well as static and flowing temperatures, are also desired.
5. Accurate surface measurements made on all flow rates at the separator, and
temperatures and pressures at the wellhead, choke manifold, heater, and
separator.
6. Capture of fluid samples representative of those in the reservoir, and the correct
recombination parameters if the samples are not single phase (e.g., separator
samples).
7. Compositions (especially for toxic contaminants such as H2S) of produced
hydrocarbons from real time field analysis, and later from laboratory pressure-
volume-temperature (PVT) measurements.
8. A record of chloride (and possibly calcium, sodium, or other diagnostic cations)
concentrations in the completion fluid and produced water, and a complete set of
samples of these fluids for more thorough analysis later. Must employ necessary
techniques to distinguish between formation, mud filtrate, cushion, and
completion fluid.
9. A plan for mitigating hydrate formation and/or or wax deposition in the production
test string, and on the surface, in order to ensure safe, unrestricted production.
10. A complete chronological record of all significant events during the test period (to
be covered in Personnel Responsibilities and Information Retrieval).

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WELL TESTING OPERATIONS

These are the basic requirements and most seem quite straightforward and simple.
However, there are possible complications and qualifications, particularly in regard to
basic requirements 2, 3, and 4. These requirements can best be met by carefully
designing the test to provide these features:

A bottomhole assembly that incorporates a bottomhole shut-in valve and allows

placement of the pressure gauges as close to the tested interval as possible.

A completion that is efficient, and does not absorb most of the pressure
drawdown. This allows a strong drawdown pressure transient to enter the
reservoir.

An unrestricted flow path through the test string and surface facilities that permit
flo w ra te s h ig h e n o u g h to te st th e fo rm a tio n .

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WELL TESTING OPERATIONS

13.4.3 KEY ITEM DECISIONS

Decisions must be made on certain key items. Primary responsibilities denoted:
1. Check service companies for lead-times for equipment availability, as soon as
possible test date, location known. See Introduction to Test Equipment in the
following section. This is especially critical in HP, HT, H2S, or very deepwater
applications (1)
2. Select most appropriate service companies to begin discussions, etc. (1).
3. Decide on method of perforation, underbalance (1, 3, 2 assists).
4. Decide on depth correlation technique; need for R/A tags in casing, perforation
string, and cased hole logging requirements (1,2,4).
5. Sand control requirements using local area experience, core data, acoustic log.
(1, 3, 2 assists, 4, rock strength experts, 5).
6. Geometry of the bottom hole region under the packer. Consider gauge
placement verses flow entry points (1, 3, 2 assists).
7. Number, types, and locations of pressure gauges (2, 1 assists).
8. Likelihood of possible risk of H2S (1,2, geology).
9. Completion fluid (1, 3).
10. Production logging requirements, rathole, packer location (1,2).
11. Packer type (1,3,6).
12. Cushion design (1,2 assists).
13. Preliminary Test String design (1, 2 assists,5).
14. Tubing wt., size, pressure drop calculations (1, 2 assists, use Nodal, etc.).
15. Properly sized production test equipment on the surface (1,2 assists, 5).
16. Production disposal requirements, methods (1, 5, 6).
17. Procedure for initial flow period (2).
18. Procedure for main flow period, unloading curve, rate ramp up (2).
19. Waxing, asphaltene, or hydrate mitigation requirements (2, 1, URC D&C group)
RESPONSIBILITY KEYS:

1. Drilling engineer.
2. Test specialist or test engineer.
3. Completions engineer.
4. Operations Geologist.
5. Appropriate service company.
6. Regulatory Compliance.

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WELL TESTING OPERATIONS

13.4.4 ADDITIONAL KEY ITEM DISCUSSION

ITEM 3: PERFORATION
Generally, balanced or over-balanced tubing conveyed perforation is used in deepwater
well tests. It typically produces more effective perforations (than wireline guns), can
handle long intervals without multiple trips, and does not require wireline runs and
equipment. The perforation guns are run on the test string itself, or on a completion
string, if in-place gravel packing is planned. In this case, of course, the test string is run
after the perforation and gravel-packing string(s) is (are) tripped in and out.
The effective underbalance used is usually quite moderate if formation integrity is a
concern, and in many cases the initial flowback volume is usually limited to several
barrels. This is to avoid getting perforation, cement, and formation debris into the
test tools or inline screens, if used. Use of too much initial underbalance with
unlimited flow may stick the perforation guns and totally plug the test tools, and
damage in-line screens. There are no proven benefits to taking a high
underbalance, high rate, and a large flow volume at perforation time with most
formations encountered in deepwater wells.
Initial pressure data is obtained after shut-in. If a full column liquid cushion is used
(see discussion on Item 11, below), with a well shut-in at the surface, perforation
underbalance can be made self-controlling by using a high initial underbalance.
Wellhead pressure is set at zero or low level before shots fired. This falls off to zero
after a few barrels of flow due to the low compressibility of the totally liquid cushion.
In this case, the well could be opened on a small choke immediately after the initial
low-volume surge for more cleanup. If an in-place gravel pack is planned, the perforation
procedure might differ from what was just described, with possibly a higher shot density,
more underbalance and more initial flow volume to clean out the perforation tunnels
more quickly and completely.
Note that perforation guns can be dropped down into the rathole automatically after
firing. This would permit running in production logs or pressure gauges by wireline
across the perforations, if the rathole is sufficiently deep.
ITEM 4: SAND CONTROL
The decision to employ sand control methods should be based on:
First hand company experience in the area.
Experience of other operators.
Core recovery and inspection.
Acoustic log interpretation.
Recommendations of rock strength experts, and service companies.

Whether the completion is expendable may also have some bearing on the type of sand
control chosen.

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WELL TESTING OPERATIONS

When deemed necessary, two types of sand control are typically used. These are in-line
screens and in-place gravel packs. In-line screens (e.g., excluder screens) are run as an
integral part of the test string, with the screens placed above the perforation guns and
below the packer. Excluder screens are applied when little or no sand production is
e xp e cte d . T h e scre e n s a ct a s a n in su ra n ce p o licy to ke e p sa n d p ro d u ctio n o u t o f th e
tubing and surface equipment. Obviously inline screens should not be run when
anticipated sand production would be great enough to cause formation collapse.
In this case, sand loss must be stopped at the perforations by other means.
A test procedure with in-lin e scre e n s is sim ila r to th e n o rm a l o n e -trip perforate and flo w
test string, except as follows:
With the inline screens, extra care should be taken to limit the initial flow after
perforation to several barrels (depending on bottom hole geometry, volumes) to
avoid pushing perforation, completion, and formation debris into the screens.
During the initial pressure buildup, most of this debris material should settle out
into the rathole.
The bottom hole gauges should be set up to record pressures external to and
inside the screens. This will sort out the apparent co m p le tio n d a m a g e in to tw o
parts - that from the actual damage in reservoir in the near wellbore vicinity and
that from the flow resistance of the screens.
This information is needed to diagnose screen plugging, even if it is only available after
the string is pulled. If necessary, inline screens could be back-flowed with a mud acid
mix if they are so severely plugged that meaningful rates cannot be reached, but this is
seldom required if precautions are taken to limit the initial flow, and let the debris settle
into the rathole.
With in-place gravel packs, two or three pipe trips are involved. In the three-trip case,
they are as follows:
1. The perforation.
2. The screen run and sand pack trip.
3. The final main test string run.
In the two-trip case (e.g., PerfPack), the perforation, screen run and sand pack trips are
combined into one, typically saving about two to three days of rig time. However,
ExxonMobil's worldwide experience to date (year-end 2001) with the two-trip process
has been mixed. One unsuccessful experience can easily cancel out several successful
ones. Most of the problems have been with the packer system they sometimes set too
so o n , w o n t se t, o r w o n t re le a se . In th e fu tu re , p ro b le m s su re ly w ill b e w o rke d o u t, a n d
the two step process will be improved enough to make it reliable.
There is much incentive for this system to work besides the two to three days saved in
rig time up front in the overall gravel packing process. More time might be saved in the
cleanup portion of the main flow test itself. This is because the two step process cuts
completion fluid loss between the gravel packing and the setting of the test string.
Recovery of large volumes of completion fluid losses can add days to getting the well
kicked-off and cleaned up.

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WELL TESTING OPERATIONS

The in-place gravel pack procedure makes the measurement of initial pressure more
difficult, and introduces more uncertainty into its true value. More detailed discussion can
be found in section 13.8 - Instrumentation, Measurement and Sampling Equipment.
Gauge precision (essentially repeatability) is much greater than gauge accuracy. This is
w h y w e ca n t u se fo rm a tio n te ste r p re ssu re fo r in itia l p re ssu re , fo r e xa m p le , w ith o u t
introducing a 5 to 15 psi uncertainty right off the bat. Even if the same gauge is used, it
loses some precision when it is tripped in or out, primarily due to temperature hysteresis.
This is the rationale for Basic Technical requirement 2, already discussed.
There is no easy solution to this problem but we should try to get another initial
pressure once the main test string is in place. It should take an extra two hours to go
through the initial flow and buildup sequence again. Once again, there may be difficulty
characterizing the fluid column between the gauge and the perforations after initial flow.
The best data may be obtained after the test string is stabbed through the packer. This is
definitely true if the two-trip procedure is employed, as the first trip leaves an isolation
flapper valve in place above the gravel pack.
After this is done, the wellbore pressure needs a day or so to fall to formation pressure.
This clearly illustrates that developing a procedure for getting a good initial pressure and
executing it can be quite involved. The initial best pressure procedure is specific to the
completion procedure, and results are sometimes fraught with uncertainties.
ITEM 9: COMPLETION FLUID
The make up of the completion fluid used depends primarily on the density required, but
other properties are important. The test string that we will be discussing in some detail in
the next section has several key tools in it that are operated by manipulating pressure in
the tubing-to-casing annulus chamber formed between the packer and the BOP. A
cle a r, filte re d co m p le tio n flu id w ith n o so lid s is m u ch preferred to ensure that there are
no pressure communication problems between the surface and these bottomhole tools.
But be aware that service companies do state that their tools will operate in a high solids
mud environment, within limits.
A completion fluid that has no environmental or human exposure risks is preferred, but
this may not be possible if testing highly over-pressure wells. Of course, the completion
fluid should be compatible with the formation itself, causing no precipitation, and be gas
h yd ra te p ro o f. C o m p le tio n flu id s co n ta in in g h ig h co n ce n tra tio n s o f N a C l o r C a C l2 h e lp
suppress gas hydrate-formation under most conditions. CaBr2 and ZnBr2 completion
fluids are also used. Brines which are near saturation at surface conditions may
precipitate salt at the pressure/temperature conditions at the mudline. This has been
known to completely plug tubulars and the BOP choke/kill lines.

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WELL TESTING OPERATIONS

POSSIBLE PRODUCTION LOGGING REQUIREMENTS

ITEM 10:

If production logging is planned or likely in the well testing program, then the completion
program and the bottomhole area of the wellbore should be designed to accommodate
production logging. Obviously, production logging across the completion interval is ruled
out if an excluder screen technique is employed. The production logging experts at URC
should be consulted early on, as rathole extension (or preservation) plans need to be
proposed early on.
ITEM 11: CUSHION DESIGN

The term cushion is used to describe the fluid placed in the test string (above the
bottomhole test valve) prior to perforation and/or starting flow. It is placed in the test
string by circulating, reverse circulating, or filling while RIH. The cushion true vertical
height and density determines the minimum pressure (i.e., its hydrostatic pressure) the
cushion column initially exerts on the formation. It also determines the minimum
pressure on the bottom side of the packer, and in the tubing. Obviously, the cushion
hydrostatic backpressure must be significantly less than the formation pressure to initiate
flow, and this difference would be the limiting or maximum initial drawdown pressure.
The cushion in the test string should permit a suitable range of drawdown pressures
while accommodating the expected volume of re-entry of completion fluid and mud
filtrate re-entry without the well dying. The cushion hydrostatic backpressure and any
restriction at the surface choke limit the drawdown, thus protecting the test string,
packer, and completion from excessive drawdown while it remains in the test string. A
liquid cushion design that gives about a 500 psi initial underbalance with a 500 psi
w e llh e a d p re ssu re is typ ica lly w h a ts id e a l. A g a s cu sh io n w ill h a ve a m u ch h ig h e r
wellhead pressure because the hydrostatic component of its backpressure is very low
(about 0.05 to 0.10 psi/ft, depending on pressure).

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WELL TESTING OPERATIONS

In normal to abnormal pressured wells, the best cushion is usually a liquid. A liquid
cushion provides better flow control immediately after perforation, due to its low
compressibility. However, it does not permit the widest range for pressure drawdown, or
accommodate large amounts of kill weight fluid entry that a nitrogen gas cushion does.
In almost all deepwater cases, the reservoir pressure is high enough to use some type
of liquid hydrocarbon cushion, such as diesel oil or base oil (oil based mud carrier).
In significantly over pressured wells, especially gas wells, an aqueous cushion can be
used. However, it must be heavily inhibitive against gas hydrate formation (see Section
12 - Special Situations, Gas Hydrates), and usually is with NaCl or CaCl2, for example.
The resulting weight is usually well above 9.5 ppg. So, in most cases cushions are liquid,
and usually base oil or diesel.
ITEM 12: PRELIMINARY TEST STRING DESIGN

The test tools that make up the test string will be covered in detail in the following
section. At this stage, the general test conditions, test design and the functions that
must be performed by the test string need to be outlined for discussion with the
downhole tool service company.
EXAMPLE:

Expected P and T.
water depth.
well location.
type of rig.
underbalanced perforation.
R/A tag(s).
bottom hole tester valve.
type of packer used.
packer depth.
test interval depth.
pressure gauge location.
possible surface readout on bottomhole gauges.
multiple cycles of reverse out and cushion re-establishment.
spotting acid.

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WELL TESTING OPERATIONS

13.4.5 DEVELOP DETAILED EQUIPMENT SPECIFICATIONS

AND OUTLINE TEST PROCEDURE

The production testing requirements are listed in the Drilling OIMS Manual (3-10):
Each program will contain the following sections, as applicable:
1. Cover page with review and approval signatures.
2. Distribution list.
3. Table of Contents.
4. General discussion: generalized test program outline.
5. Testing strategy & objectives.
6. Reservoir data.
7. Test intervals (by zones).
8. Perforating techniques.
9. Test rates and expected flowing temperatures.
10. Data acquisition requirements.
11. BOP stack/wellhead configuration and pressure test plan.
12. Sampling program (only mercury free sampling systems).
13. Environmental management (list of required onsite absorption material, etc.).
The next steps involve specific equipment selection. Before most of the step-by-step test
procedures can be detailed and finalized, specific equipment must be selected. The next
four sections cover downhole, surface, measurement, and production disposal
equipment, respectively.

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WELL TESTING OPERATIONS

13.5 WELL TEST DOWN HOLE EQUIPMENT

13.5.1 EQUIPMENT OVERVIEW

The test equipment system for deepwater testing must provide a secure flow path from
the completion to disposal, while providing safe and clean emergency disconnect at the
seafloor. To fulfill the test objectives, the equipment system must also accommodate the
measurement of pressures, temperatures, and flow rates at points along that path. This
all must be done in an environmentally friendly manner, and at a production rate and for
a time period adequate to reach the test objectives. It must then provide for a positive
shut-in of the well following production to measure reservoir pressure recovery.
Discussion of well test equipment will be divided into four areas:
1. Downhole equipment or the test string (made up of the lower test string and
u p p e r te st strin g , A K A th e te st strin g a n d la n d in g strin g , re sp e ctive ly).
2. Surface Equipment (vessels, piping, and safety).
3. Instrumentation, Measurement, Sampling, and Data Acquisition.
4. Production Disposal Equipment.

13.5.2 EQUIPMENT LEAD-TIMES

The lead-time or notice well testing service companies require (what they would like to
have to do best job) depends on the complexity of the job, the water depth, and
downhole and BOP environment (pressure, temperature, and H2S or CO2) under test
rates. It may be even more dependent on the degree of equipment tear-down, inspection
and testing required by the client and the job location. The critical class of equipment is
usually the subsea safety equipment, swivel and flowhead (part of the landing string, to
follow), and to some extent, the lower test string tools. Be aware that these times are
guidelines that might not apply in a specific case.
For the generic GOM oilwell test, a notice of about three months is desired. This
includes two months to do special equipment procurement and testing, to out logistics
and manning, and one month to set aside, assemble, and transport equipment. If the
test is similar to one done or planned recently, and then perhaps lead-time can be cut
d u e to re d u ce d p la n n in g a n d p ro cu re m e n t tim e . In th e fo rtu n a te ly ra re su rp rise - w e re
g o in g to te st it circu m sta n ce , th is tim e h a s b e e n cu t to le ss th a n a month. Below are
some atypical situations:

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WELL TESTING OPERATIONS

For an ultra-deepwater test from a dynamically positioned vessel in the GOM,

which requires LMRP disconnect speed and capability, a lead-time of six months
might
be required.
Bottom hole pressures over 19Kpsi, and temperatures over 375F, and high
flowing temperatures at the BOP stack would add to a month to the lead-time.
For a deepwater gas test where subsurface injection of hydrate inhibitors
(methanol) is required, six to nine months lead-time may be required.
Regardless, as soon as there is the remotest possibility of a test, the service companies
should be contacted and possible measures to hedge for the contingencies should be
explored. Enough key parameters will probably be known at this time to get started with
planning and equipment selection. In many cases, this could be near the time the well is
spudded. Of course, there is always the contingency that the well will not be successful,
but planning must proceed on the premise that it will be.
LEAD-TIMES OVERSEAS

For overseas areas, the rule-of-thumb is to add about a month to GOM lead-times.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

13.5.3 TEST STRING

This section will describe various components that make up the test string run from
floating rigs. This test string is made up of two major sections. The lower test string
starts at the completion (Figure 13.7), includes the packer, major test tools, and extends
up to the BOP stack at the seafloor. It is supported at its top by the fluted hanger resting
in the wellhead wear bushing (Figure 13.6), and by the packer at the bottom. This two-
point support can only be only guaranteed if slip joints are used in the lower test string.
Slip joints will be discussed shortly.
T h e u p p e r p o rtio n o f th e strin g , e xte n d in g fro m th e B O P to a b o ve th e rig s flo o r, is called
the landing string. The landing string will be discussed last, but it should be said now
that landing string functions are essentially distinct and independent from the those of
the lower test string, and its makeup is usually independent of the lower test string
components below it (the exception may be submudline injection equipment). Most of its
w e ig h t is su p p o rte d a t its to p b y th e rig s m o tio n co m p e n sa to r, a n d th e b a la n ce a t th e
bottom by the fluted hanger seated in the wellhead.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

13.5.4 TYPES OF LOWER TEST STRINGS

In the broadest spectrum of production testing, three types of test strings are
encountered:
1. The Open Hole Drillstem Test String (OH-DST).
2. The Production Test String (PTS).
3. The Cased Hole Drillstem Test String (CH-DST) or Annnular Pressure Operated
(APO) test string.
OH - DST
ExxonMobil does not conduct OH-DSTs from floating rigs so they will not be discussed.
T h e b a re fo o t te st m ig h t b e re g a rd e d a s a p o ssib le e xce p tio n to th is ru le . In th is te st, th e
casing shoe is set just above the formation of interest, and the packer and the pressure
operated test tools are in the casing. The discussion
to follow on cased-h o le d rillste m o r A P O te st to o ls w ill a p p ly to th is e xce p tio n .
Subsea BOP Normal Operations
SSTT Connected
Choke Line
Kill Line

Figure 13.6 - SSTT

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

PTS Tubing
The Production Test String (PTS) consists of production tubing
and a packer, and perhaps a series of nipples in the tailpipe for a
Slip Joints
plug or downhole pressure gauge, as found in a typical producing
well. This test string is simple and very economical, and has no
m o vin g p a rts m a kin g it q u ite re lia b le . H o wever, this type of Drill Collars
string is not conducive to getting good pressure data, because
there is no tester valve to minimize afterflow or to isolate the Redundant
pressure gauges from wellbore, phase humping, etc. Also, this Circulating Valve
type of string has little operational flexibility a n d ca n t e a sily
accommodate the remedial measures sometimes required to
reach test objectives. Primary
CH-D S T Nomenclature Outdated: Prefer Using A P O T est Circulating Valve
String RA Tag
T h e u se o f th e te rm d rillste m in th e d e scrip tio n ca se d h o le
d rillste m te st is o f h isto rical origin, and has been inappropriate
for some time since production tubing, not drill pipe, is used in
Surface Readout
this test string. But the name stuck because the OH-DST and
CH-DST employ an array of test tools with similar functions, even
though they usually operate on quite different principles. Downhole Valve

A more appropriate name for the CH-DST is the annular pressure Hydrostatic
operated (APO) test string. We will now officially dispense with Reference Tool
the CH-DST terminology. APO is preferred because it describes
how most of its tool-components are operated, and correctly Pressure Recorder
implies that the string is operated in a cased hole sealed by BOP
rams and a packer so that annular pressure can be manipulated. Hydraulic Jar

Safety Joint

Packer

Slotted Tailpipe

Debris Sub

Tubing

Firing Head

Safety Spacer

Figure 13.7Perforating
- Test String
Guns

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

13.5.5 THE APO TEST STRING

From here on, the focus will be entirely on the APO test string. APO tools are ideal for
testing from floating rigs because no pipe reciprocation or rotation is required to operate
the APO tools once the string is set. The string is securely sealed in the BOP stack and
at the packer. This makes for a safer test, and the failsafe shut-in feature of the bottom
hole tester valve reinforces the quick shut-in and disconnect capability afforded by the
subsea test tree.
Since the late 1980s, the APO test string has been firmly establishing a history of
reliability. ExxonMobil has been using the APO test string exclusively for floating rig tests
domestically (GOM and West coast, Alaskan coast) since about 1988, and overseas
since about 1995. Due to the almost universal use of the APO test string, the descriptive
te rm a n n u la r p re ssure operated bottomhole shut-in va lve h a s b e e n sim p lifie d to te ste r
va lve o r te st va lve . T h e u se o f e ith e r o f th e se tw o te rm s h e re w ill a lw a ys m e a n a n
annular pressure operated bottomhole shut-in valve.
The combination of the tester valve and pressure operated multiple-cycle reversing
valves provides test design and operational flexibility. More specifically, the APO
string can:
1. Accommodate a wide range of perforation and sand control options.
2. Be used with retrievable or permanent packers, and while the string is sealed off
by packer:
a) Establish and re-establish fluid cushions.
b) Reverse out produced fluids.
c) Circulate while set in packer.
d) Spot fluids or treatments.
e) Stimulate the well.
3. Prevent hydrate formation in deepwater pressure buildup tests by allowing
pressure to be bled off in from the test string without affecting the buildup below
the closed tester valve.
4. Accommodate wireline operations through the fullbore string (e.g., production
logging, sampling, add-on perforations, etc.).
5. Provide the only sure way to get good quality pressure data and meet typical
objectives when the testing time is limited, or when the reservoir fluid is neither
dry gas nor dead oil.

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WELL TESTING OPERATIONS

13.5.6 BASIC PRINCIPLES OF OPERATION

The APO test string is always run through a BOP stack on the wellhead. The lower test
string is supported at its top by a fluted hanger carefully spaced out in the test string.
When the string is in place, the fluted hanger rests in the wear bushing in the wellhead.
A slick jo in t is p la ce d in th e te st strin g above the fluted hanger so that specific (usually
the middle pipe) BOP rams can be closed on it. ExxonMobil operations usually strive to
have dual ram closure on the slick joint (i.e. LPR and MPR). The APO test string must
always be used in conjunction with a packer, either permanent or retrievable, seated in
the casing. The slick joint, in the pipe rams in the BOP stack, and the packer seal the top
and bottom of the tubing-casing annular volume.

13.5.7 RETRIEVABLE AND PERMANENT PACKERS

When a retrievable packer is used, slip joints are a mechanical necessity in testing
from a floating rig. Drill collars are used below slip joints to automatically keep the
required weight on the retrievable packer. A slip joint is a fullbore, integral part of the test
string that is essentially a joint of production tubing in two major pieces, one of which
slid e s a xia lly o r te le sco p e s a n d o n e se a ls w ith in th e o th e r. T h e tw o p ie ce s a re sp lin e d
internally so that they will transmit rotational torque. A slip joint 23 feet in length
(collapsed) will telescope five feet. Typically, three slip joints are used for wells of
average depth, but there is no practical limit. Deeper high-temperature wells might
require more. The slip joints are designed to be pressure compensated so that neither
internal nor external pressure affects axial forces.
Slip joints simplify the space out of the test string length required to properly seat the
fluted hanger in the BOP, while simultaneously seated at the packer. The slip joints also
take up any expansion/contraction of the test string due to pressure or temperature
changes, without changing the weight on the packer, or any other stress loading.
When a permanent packer is used, it is not an absolute mechanical necessity to use
slip joints, as the variable position of the seal assembly in the seal bore provides for
some uncertainty in the space out, and for some string expansion/contraction. In the
past, slip joints were sometimes avoided when possible (e.g. with permanent packer
applications) because they were thought to be a likely and unnecessary source of leaks.
But experience has shown slip joints to be very reliable, and they are now sometimes
used in APO test strings with permanent packers.
Drill collars must also be used below the slip joints in permanent packer applications
also to avoid pumping the string out of the seal bore (Note that this requires additional
cro sso ve rs to m a ke u p a n d re su lts in to o l jo in t co n n e ctio n s in th e te st strin g , w h ich a re
not gas tight). From a mechanical standpoint, simple is always preferable. Hence if the
slip joints can be eliminated from the test string they should be.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

Of course, there are several operational advantages to using slip joints with the
permanent packer, such as more accommodation of string expansion and contraction,
and easing the space out operation. But pressure data quality may make the best case
for using slip joints with a permanent packer. It should be kept in mind that any pressure
gauges set in nipples in the production string will also move if the seal assembly moves
with thermal contraction/expansion. In a test string without slip joints, the gauge height
above the perforations will probably be changing as long as the string is free-floating in
the seal bore assembly. It follows that the hydrostatic offset of the gauges will be
changing, with no means of quantifying the correction required to remove this distortion.
On the other hand, if the seal locator assembly is seated on the packer when the string
tries to expand, it corkscrews. Stresses are added to the string and any pressure gauges
above the seal assembly can be affected. However, gauges in a tailpipe assembly free
hanging below the packer would not be stressed.

In summary, with a permanent packer application and no slip joints, either the pressure
gauges move or the string corkscrews and stresses any gauges above the packer. If slip
jo in ts ca n t b e u se d , th e g a u g e s sh o u ld b e lo ca te d in th e ta ilp ip e b e lo w th e p a cke r to
reduce stress changes. Regardless, such a gauge location will give better pressure data,
but this will be subject will be covered later.

13.5.8 ANNULAR PRESSURE CONTROL NOTE

When the string is set and sealed by the packer at the bottom, and the BOP pipe rams
o n th e slick jo in t a t th e to p , th e a n n u la r p re ssu re chamber is formed. The lower test
string tools are controlled by pumping in or bleeding off fluid from this annular chamber
u sin g th e ch o ke o r kill lin e s o n th e rig a n d m a rin e rise r. T h e ch o ke a n d kill lin e s
extend from the rig floor down along the riser exterior to the BOP. This fluid path is
ported through to the bottom portion of the BOP stack, below the rams that are sealed
on the slick joint. With rig pumps, the annular pressure is raised, maintained at a
specified level and then bled off partially or totally, as required for the desired tool string
function.
Most downhole tools (e.g., ball and sleeve valves, flappers, and shear discs of several
types) are operated by applying pressure in this manner. These tools can either operate
at preset pressure levels, or after a preset number of cycles up to a specified pressure
level. Typical pressure levels range from 500 to 4000 psi above the normal baseline
annulus pressure (i.e., zero pressure on the rig floor and annular fluid hydrostatic
pressure at the tool). To ensure pressure transfer to the tool ports and minimize
plugging, the fluid in the annular chamber is usually a clear fluid, rarely mud, and
never high solids mud.

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WELL TESTING OPERATIONS

13.5.9 INDEXED TOOLS

Most APO major tools are simple in their operation, in that they are opened with
increased annular pressure, and closed when the pressure is bled off. This cycle can
occur numerous times. Other tools, such as single shot reversing valves, and string
pressure test valves, are actuated by one application of annular pressure, and then
permanently disabled - opened, or closed, respectively.
There is a third general classification of pressure operated test tools, which we shall
la b e l in d e xe d to o ls T h e te rm in d e xe d is in te n d e d to d e scrib e h o w o n /o ff cycle s o f
pressu re (e ith e r a n n u la r o r tu b in g ) ra tch e t th e to o l th ro u g h a fixe d se rie s o r cycle o f
pre-defined steps. Each step or index position controls the tool configuration. One cycle
o f p re ssu re m o ve s th e to o l to th e n e xt in d e xe d p o sitio n o r ste p .
Some index positio n s m a y b e n u ll w h ich in d ica te s th e re is n o ch a n g e in to o l
configuration from the previous configuration. Null index positions serve as safety nets
against inadvertent pressure cycles, and enhance compatibility with other pressure-
operated tools in the string. A tool cycle will normally consist of about 8 to 20 steps or
index positions, and a majority of these may be null positions, strategically placed
b e tw e e n g o to n e w co n fig u ra tio n p o sitio n s. O p e ra tio n o f a to o l strin g w ith m u ltip le
indexing tools can get quite complicated. It is possible to get in an untenable position if
ca re is n o t e xe rcise d . F o r th is re a so n , m o re re ce n tly d e ve lo p e d to o ls u tilize p u lse
technology.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

13.5.10 MAJOR APO TEST TOOLS

The major types of tools to be discussed are:

1. The bottom hole shut-in or tester valve, with required auxiliary tools
2. The multi-cycle reversing valves
3. Bundle carrier for pressure gauges
4. Systems for surface readout (SRO) of bottom hole pressures (the details on this
subject will be in Measurements, Instrumentation, and Sampling Section)

Supporting, backup, or safety tools include:

1. Test string pressure test valves
2. Test string fill valves
3. Safety joints and hydraulic jars
4. Single shot reversing subs
5. By-pass valve
6. Safety valves
7. Sampling valves (wireline-type bottomhole sampling valves will be discussed in
the Measurements, Instrumentation, and Sampling Section).
The major types of tools will be discussed in some detail. Differences between major
su p p lie rs to o ls w ill b e p o in te d o u t. G e n e ra lly, H a llib u rto n s (or other suppliers) tools
h a ve th e sa m e fu n ctio n s a n d sim ila r ca p a b ilitie s a s S ch lu m b e rg e rs, b u t im p o rta n t
differences and advantages will be pointed out.
Historically, ExxonMobil has almost exclusively used Schlumberger for APO test strings
on floating rigs. It has used Halliburton successfully from jackup rigs in the Sakhalin
Islands, and on one floating rig test (circa 2000).

13.5.11 DETAILED DISCUSSION OF MAJOR APO TEST TOOLS

The major tools associated with APO test strings will now discussed. Emphasis will be
g ive n to th e S ch lu m b e rg e r lin e o f A P O to o ls, b u t H a llib u rto n s m a jo r to o ls w ill a lso b e
discussed. For Schlumberger, mainly, some details on the operation and history of
reliability will be covered.

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WELL TESTING OPERATIONS

13.5.12 BOTTOMHOLE SHUT-IN VALVE

The bottomhole shut-in or tester valve is a fullbore (std. 2.25 in. ID) ball valve placed
near the bottom of the test string, but above the packer. It is the main valve used to shut-
in the well, and can be shut almost instantly on a well flowing at its maximum rate. The
most common types are actuated and powered by raising annular pressure levels to 800
to 1800 psi above hydrostatic. The number of operating cycles is theoretically
Ball Valve unlimited
for tester valves powered by annular pressure,
e xclu d in g p u lse typ e like the IRIS valve. It is
fa ilsa fe sh u t, u n le ss th e va lve is in th e H o ld -O p e n
Annulus Pres.
co n fig u ra tio n . H o ld O p e n m e a n s th e va lve sta ys
open with no applied annular pressure (e.g., while Control
GIH). Although manufacturers claim these valves Mandrel

can operate reliably with heavy (up to 16 ppg) mud

in the annulus, clear fluids (high NaCl or CaCl2 Spring
content, or CaBR, ZnBr) of kill weight are normally
swapped in for testing.
The valves can withstand a high differential
pressure, and most can open against a 5000 to Nitrogen
Chamber
10,000 psi differential pressure upwards. This is not
recommended, and an effort to equalize with applied
Compensating
tubing pressure, before opening, is usually made to piston
prolong valve life and reduce surging. The valves are
H2S rated, and are available in special high
temperature-pressure lines (up to 500F, 17,500
psi). Seal technology at high temperature, H2S is the
limiting element here. Note: These extreme service Hydrostatic
reference
tools may have lead-times much greater than the chamber
standard service test tools.
The more recent pulse technology developments
include a tester valve combined with a circulation Figure 13.8 - PCT Valve
valve. This tool performs multiple function Closed to Shut-in
Formation
sequences which can be triggered by lower level Open to Flow or
Treat Formation
pressure (250 psi) signals or patterns sent from the
surface. This tool has a finite number of valve cycles.
Schlumberger PCT Valve: The main APO
downhole shut-in valve is the Pressure Controlled
Tester (PCT) valve. It is opened by raising and
holding annular pressure from the surface, and
closed by bleeding off annular pressure. A schematic
cro ss se ctio n o f th e P C T , a s it is u n ive rsa lly kn o w n ,
is shown in Figure 13.8.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

The PCT is a ball valve operated by changing annular pressure levels by pumping
annular fluid into the choke line from the rig floor to the BOP section below the pipe rams
sealed on the slick joint. It is fullbore opening, and the standard 5 in. OD tool size has a
straight through opening of 2.25 in. bore. The PCT will pass standard wireline tools, logs,
and perforating guns. It is run above the packer and standard memory gauges, but
below any reversing valves. The PCT will generally cut standard wireline, but will not cut
through wireline tools. Thus wireline operations on DP rigs are often limited to staying
above the PCT.
OPERATING PRINCIPLES
A pressure-driven, double-acting power piston operate s th e va lve b a ll. T h e p o w e r sid e
of the piston is continually exposed to the current bottomhole annulus pressure. On the
o p p o site sid e , th e re fe re n ce sid e , th e p isto n is h yd ra u lica lly co n n e cte d to a n itro g e n
ch a m b e r co n ta in in g a ca p tu re d re fe re n ce p ressure. This pressure is the bottomhole
annulus pressure when the BOP choke line on the rig floor has no pressure applied.
A strong coiled spring on this same reference side of the piston pushes the piston to the
b a ll clo se d p o sitio n w h e n th e re is n o or a small net fluid pressure difference across the
piston. Thus, with zero surface pressure imposed on the annulus, the ball is closed and
the valve is shut. Almost failsafe, but not exactly.
When the upper side of the power piston, which is exposed to the current bottomhole
annular pressure, senses enough annular pressure rise above the normal annular
p re ssu re to o ve rco m e th e sp rin g s fo rce , it w ill m o ve to ro ta te th e b a ll va lve o p e n .
The surface annular pressure at which the ball opens is selected by choice of coiled
spring when the tool is set up. The PCT opens at a surface annulus pressure of 800 to
1800 psi with typical setup.
FAILSAFE CLOSURE
T h e to o l w ill clo se w h e n th e re is a lo ss o f a n n u la r p re ssu re , m a kin g it a fa ilsa fe clo se d
valve. In practice, the valve never fails to close, unless something substantial is lodged
in the ball opening that mechanically prevents it from rotating and closing, or the annulus
pressure ports are completely plugged. It is conceivable, though, that an emergency
condition may occur in which annular pressure cannot be bled to zero, such as a high-
pressure leak from the tubing into the annulus. In anticipation of this possibility, the PCT
ca n b e co n fig u re d w ith a sh e a r sh u t d isc, w h ich ca n b e se t-up to fail at some pressure
level above that required to operate any other APO tools in the string. Once this disc
fails, the hydraulic chambers on each side of the power piston will be connected, and the
sp rin g s fo rce w ill ke e p th e b a ll va lve clo se d , re g a rd le ss o f th e a n n u la r pressure levels.
This feature used to be standard, but is now only used for gas well tests.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS
Annulus Pres.

Seals
RELIABILITY

The ball valve PCT is very reliable, and has

continued to operate after many cycles (in one
test, at least 30 valve open/close cycles on one
trip into the hole) without problems. It is not
sensitive to debris, and in the very rare cases
when it does operate unexpectedly, there is Spline
usually an understandable reason for it. This is
why the tool service companies sometimes
request porting one pressure gauge to the
annulus above the packer. This is to get a Spring
reliable record of annular pressure history to help
pin down any unexplained valve activity. In this
event, the service company should pay for the
gauges that they have requested.
The ball valve can hold a pressure differential of Bypass seals
Bypass ports
10,000 psi upward and 7500 psi downward.
Differential pressure on opening should be held
to less than 5000 psi (the lower the better, for
several of the reasons just discussed). The
HRT Closed
temperature rating is currently about 300F for
the main line of tools. High temperature and Figure 13.9 - Hydrostatic Reference
HRT Open
pressure (500F, 17,5000 psi), and slim hole tool Tool
strings are evolving, but ExxonMobil has little
experience with them.
The PCT is always run with a companion tool
that acts as a bypass tool stabbing into the
packer and capturing the annular reference
pressure (ARP) the PCT needs as a baseline
pressure.
S ch lu m b erg ers H yd ro static R eferen ce T o o l
(HRT) (Figure 13.9) is one of two choices for the
re q u ire d co m p a n io n to o l to th e P C T . T h e H R T s p rim a ry fu n ctio n is to capture the
annulus reference hydrostatic pressure at bottomhole conditions when the surface
annular pressure is zero. It is a fullbore tool, run immediately below the PCT that can be
run with both permanent and retrievable packers. While running in the hole and seating
(in) the packer, it acts as a hydraulic bypass.
When the HRT is in the test string, slip joints are required, regardless of the type of
packer used. Slip joints are the only workable means to ensure that the correct setdown
weight is maintained on the HRT, which is about 30K to 40K lbs. This also means that
drill collars will normally be used to get this required setdown weight while permitting the
slip joints to sit low in the test string.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

S ch lu m b erg ers P ressu re O p erated R eferen ce T o o l (PORT) (Figure 13.10) is the

more frequently used alternative to the HRT as a companion to the PCT. It performs the
same two functions as the HRT (hydraulic bypass and capture of the ARP), but is
actuated differently. It is also a fullbore Drain valve
tool, run immediately below the PCT that PCT reference
can be run with both permanent and chamber

retrievable packers. Relief valve

L ike th e H R T , th e P O R T s p rim a ry fu n ctio n

is to capture the annulus reference
pressure at bottomhole conditions when
the surface annular pressure is zero. Atmospheric
However, an elevated annular pressure chamber
Reference port
rather than set-down weight initiates the
capture of the ARP. It also traps this Seal mandrel

elevated annular pressure at this time, Rupture disc

avoiding the pre-charge of N2 pressure

that the HRT requires before GIH. Bypass port
Actuation by annular pressure rather than
set-down weight eliminates the
requirement for slip joints and drill collars
with a permanent packer - the string can
hang in tension. Slip joints and drill collars
may still be necessary to prevent string
movement and/or corkscrewing as After Trapping
Before Trapping Reference Pressure
possible causes of pressure Reference Pressure
measurement problems. Figure 13.10 - Pressure Operated Reference Tool
One disadvantage of the PORT is that, if (PORT)
there are open perforations, the additional
annular pressure required to activate the
tool will cause additional fluid loss.
S ch lu m b e rg e rs a n sw e r to th is p ro b le m is
the Formation Protection Module; another
tool optionally attached to the bottom of the
PORT. It prevents the annulus
overpressure applied to close the PORT
tool from communicating with the rathole.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

S ch lu m b erg ers H o ld O p en M o d u le fo r P C T (H O O P ) m o d u le (Figure 13.11) is an

indexed accessory module that permits locking the PCT ball valve open, regardless of
annulus pressure.
The HOOP locked-open
position is used for
1. Going in the hole
while filling the test
string with annular
fluid.
2. Wireline work.
Lock mandrel
3. Stimulation.
Clutch ring
Of course, the PCT is Window sleeve Ratchet key
Ratchet lug
not failsafe shut in Index lug
this case. The mandrel Driver sleeve
locks open once in
every Nth annular
pressure application
cycle, with N selectable
on surface setup of the
tool and usually set to
three or six. The
mandrel is released
from the lock-open
position by the next
annular pressure Ball Valve
Ball Valve Ball Valve
on-off cycle. Closed
Open in Hold-Open

With the HOOP indexed Figure 13.11 - Hold Open Module (HOOP)
to the hold-open
position, an annular
pressure rise followed
by an annular pressure
bleed-off is required to
close the tool. For this
reason, you should
never be in a HOOP
lock-open cycle, or one
short of a lock-open cycle, in the major flow period of a test sequence, especially when
testing on a DP rig where you are counting on the PCT to close in the event of an
emergency disconnect. Obviously, when using this tool, an accurate history of PCT
valve cycles must be kept at all times.
Circumstances that might cause inadvertent PCT closings are very rare during test flow
periods, and when they do occur, something is usually wrong that would require
shutting-in the well anyway. Thus, HOOP should not be used as a means of avoiding
having to control and monitor annular pressure under normal circumstances.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

IRDV TESTER VALVE (PULSE TECHNOLOGY)

A more recently developed APO downhole shut-in va lve is S ch lu m b e rg e rs IR D V va lve

(originally called the IR IS va lve ), w h e re th e IR sta n d s fo r In te llig e n t R e m o te , a n d D V
denotes Dual Valve. The IRDV contains a fullbore ball valve that is the main tester valve,
plus a sleeve-type circulating valve. Both valves in the tool operate independently by
sensing low-le ve l p re ssu re p u lse sig n a tu re s o r p a tte rn s o f d iffe re n t p re ssu re le ve ls,
sent from the surface, as shown in Figure 13.12.

Independently
Operated
Circ. Valve

Tester valve
Sensor
Microprocessor

Figure 13.12 - Intelligent Remote Dual Valve (IRDV)

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

The pattern is converted into an electronic signature and compared with a set of stored
signatures, each of which triggers a distinct valve operation or sequence of operations.
Thus, more complicated operational sequences are feasible than with the standard APO
tester valve, possibly without imposing a higher pressure on the casing (or on open
completions in other applications). Standard APO test tools are compatible with IRDV,
because conventional pressure level changes meant for APO test tools have little effect
on IRDV operation, and vice-versa. Power to operate the valves is provided by the
differential pressure between hydrostatic and an atmospheric chamber within the tool.
As the valve is functioned, a portion of the hydraulic fluid used to move the piston is bled
into the atmospheric chamber. After about 12 cycles, the chamber is full, and the tool is
now powerless. A booster chamber attachment is being tested to increase the number
of open/close cycles to 24.
The IRDV responds to four types of commands:
1. The direct or independent commands operate on both the tester and circulation
valves. They are stand-alone commands, not part of a sequence, used to open or
close both valves. An intelligent controller prevents both being opened
simultaneously.
2. Sequential commands are used only for the tester valve
3. Nitrogen commands are used for the circulating valve alone. They open and close
the circulating valve with a gas in the tubing so that gas cushions can be safely and
accurately spotted.
4. Preset commands are programmed into the tool before GIH with the string. Preset
commands can be used to close the circulating valve at a prescribed depth (actually,
hydrostatic pressure) when GIH. Preset commands are used with the IRDV valve in
the single trip perforate-gravel pack (PERFPAC) operation.
ExxonMobil has used the IRDV valve in offshore gravel packing operations and in the
main test string with very good success. However, there is some resistance to using it in
the main flow test string as it currently (Jan. 2002) has a limited number of valve cycles
due to its internal atmospheric chamber. There have been instances in which multiple
diesel cushions had to be re-established to get a well kicked-off, overall requiring 15 to
25 valve cycles. One particular well took a lot of completion fluid during gravel packing.
The PCT was used, and the current IRDV would not have had enough cycles to
complete the job. However, as mentioned above, Schlumberger is now testing a booster
module to supply power for 24 IRDV valve cycles.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

H allib u rto n s L P R -N(R) APO tester Valve has been the main Halliburton APO TEST
downhole tester valve. It is an indexed tool. It is a fullbore (2.25-in. ID) ball valve
operated by annular pressure cycles. The valve is always in one of four configurations,
a s d icta te d b y th e h isto ry o f a n n u la r p re ssu re ch a n g e s a n d th e va lve s in d e xin g :

Valve shut with zero surface annular pressure

Valve open with applied elevated surface annular pressure.

Valve shut with applied elevated surface annular pressure.

Valve open with zero surface annular pressure.

This indexing provides the flexibility to go into the hole either filling or dry, do wireline
work, or pressure test the annulus without opening the tool.
But the LPR-N and the PCT (even with HOOP) are fundamentally different. The LPR-N
does not capture an ARP like the PCT-HRT or PCT-PORT. The nitrogen chamber is
charged at the surface to a pressure that takes into account anticipated bottomhole
annular pressure and temperature.
The tool has a total of eight indexing positions in a complete cycle. An index position is
advanced by one annular pressure increase to a pre-set level and then a bleed-off of
annular pressure. Across the first three index positions, the tool operates in a manner
similar to the standard PCT, i.e. the ball valve is shut at zero surface annular pressure, it
is opened with applied annular pressure, and is held open until the annular pressure is
bled off.
Once past the first three indexing positions, however, the tool is either held open or shut
for several consecutive index positions, regardless of applied annular pressure. In other
words, several cycles of annular pressure increase and release must be supplied to
ch a n g e th e to o ls co n fig u ra tio n . In th is m a n n e r th e to o l ca n b e lo cke d o p e n w ith n o
annular pressure, as well as locked shut with annular pressure applied. In most
configurations, the overall tool cycle sequence starts anew after eight cycles of pressure
a p p lica tio n , b u t th is m a y va ry w ith th e to o ls se tu p o n su rfa ce .
The application of annular pressure generates the pressure charge to drive the piston
that rotates the ball valve. The side of the piston charged (which determines close or
open) depends on the current number in the indexing cycle. It is critical to keep an
accurate record of the starting position, and how many times the tool has been
cycled, to determine the current location in the LPR-N indexing sequence. While the
tool has a lot of operational flexibility, it can quickly become a liability if this record is
not kept carefully.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

H allib u rto n s S elect T ester V alve is the latest fullbore APO tester valve offered by
Halliburton. ExxonMobil used the valve extensively in the 1998 Sakhalin Island
campaign on jackup rigs, and on one offshore West Africa test. It is offered in two sizes:
5-in. OD, 2.28-in. ID, and 7-in. OD, 3.5-in. ID The valve operating mechanism is different
from the existing Halliburton and Schlumberger APO tester valves. It does not use a
fixed indexing cycle, nor does it require that an annular pressure reference be captured
up front. It can be run in the hole open, so no bypass is required, and it does not require
capture of an annulus reference pressure.
The Select Tester valve has four main sections:
Ball valve section.
Upper hydraulic section.
Lower hydraulic section.
Nitrogen chamber section.
The operating sequence is as follows. To open the ball valve, annular pressure is
applied. Both the upper and lower hydraulic sections are ported to the annulus. The
increased annular pressure acts immediately on the upper hydraulic chamber, whereas
the annular pressure is metered slowly into the lower chamber. This delay causes a
temporary pressure imbalance that forces the ball valve open. After an additional short
delay, the metering cartridge in the lower hydraulic section closes, capturing the raised
annular pressure in the nitrogen chamber of the lower hydraulic section. The ball will
remain open until the annular pressure is bled off. This causes the resulting pressure
imbalance to force the ball valve to close. After a short delay after closing, the lower
hydraulic section nitrogen pressure chamber is metered back to the normal (zero
surface) annular pressure.
The hold-open feature is activated by:
1. Opening the valve with applied annular pressure.
2. Raising the annular pressure to a higher level about 1300 psi surface pressure.
This disconnects the ball closing mechanism, locking the ball valve open. It will remain
open until another 1300 psi of annular pressure is applied, which re-engages the ball
closing mechanism. Then, release of annular pressure closes the ball valve.
Note: With this valve, the next type operation is always optional and is not pre-ordained
by the indexing of the tool, as with the LPR-N valve. Moreover, the tool is failsafe shut,
as only an annular pressure bleed-off is required to close the valve if it is not locked
open. Recall that with the LPR-N valve, it takes an annular pressure increase followed
by bleed-off to shut the valve in some of the index positions.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
WELL TESTING OPERATIONS

13.5.13 MULTIPLE CYCLE REVERSING VALVES

Multiple cycle reversing valves are extremely useful in well testing operations, simply
because the are multi-cycle. They add a lot of flexibility and capability for establishing
cushions, spotting acid, reverse circulating, and re-establishing cushions. They are
always used with APO test strings. They are operated by a number of methods, as will
be discussed. In general, th e y ca n b e se n sitive to d e b ris, ru st, e tc., a n d th e y d o n t m ix
well with drill pipe or dirty drill collars. This because they are sliding sleeve-over slot type
valves.
S ch lu m b erg ers
Multi-Cycle Circulating
Valve (MCCV), (Figure
13.13), is a fullbore (2.25-in.
ID) circulating valve that
operates on tubing side
pressure and flow reversals Index
(tubing-to-annulus and System

annulus-to-tubing). It is
placed above the tester Fluid
Flow
valve - as much as several Operating
hundred feet above it if Mandrel

significant formation and/or

completion debris will be
Flow
produced. Normally a Restrictors
placement just above the Fluid
Flow
tester valve is suitable.
The valve has three
positions:
1. Both paths closed
(tubing isolated from the
annulus and vice versa). Open to Reverse Out Circulating to Spot Nitrogen
Formation Fluid or to Let Cushion or to Treat Fluid
2. Open path from tubing to String Fill During Run-in Slug
annulus (via the
circulation port). Figure 13.13
Closed - Multicycle Circulating Valve (MCCV)
for Testing
Or Treating Formation
3. Open path from annulus
to tubing (via the reverse
circulation port).

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WELL TESTING OPERATIONS

The valve typically is 6 or 12 cycle, meaning that it takes 6 or 12 pressure/bleed cycles

to reach the reversing position. The tubing side of the valve is fullbore open in all
circulating, reversing and shut positions.
This circulating valve is superior to the MIRV circulating valve for establishing or
re-establishing gas cushions because of the more positive closure control attained
with gases.
There is a version of this tool (called the MCVL) that can be locked open or shut,
preventing the tool from responding to external or internal pressure until a pre-set disc is
ruptured by high annulus pressure.
S ch lu m b erg ers
Multi-Indexing Reversing
Valve (MIRV) (Figure 13.14),
is a fullbore (2.25-in. ID)
circulating valve that operates
on cycles of tubing side
Index
pressure and forward Section
circulation flow rate. Its
placement criteria and
sensitivity to a dirty
Piston
environment are the same as Mandrel
with the MCCV. Scale, rust,
cement, or any other solid
debris may cause it to plug or Spring
shut prematurely, and
perhaps fail to reopen.
The valve has only two Reversing
positions: Ports

1. Closed (tubing isolated

from the annulus and
vice versa).
2. Open to flow in both
directions (tubing to
annulus and annulus
to tubing).
The tubing side of the valve is
fullbore open in all circulating, Closed Cycling Open
reversing, and shut positions.
Figure 13.14 - Multiple-Opening Internally Operating
The circulation valve is closed Reversing Valve (MIRV)
by a high circulation rate, or
more directly, a high pressure
drop across the open
circulation port. To close the
circulation port, it takes a pressure drop equivalent to that generated by 2 Bbl/min of
water circulating (per active port) through the port(s).

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If a m o re visco u s liq u id is b e in g circu la te d th ro u g h th e to o ls p o rts, th e n th e a b o ve ra te s

will need to be lower. Since the circulation closing is actually triggered by pressure
drop across the ports, it is easy to see how solid debris would cause the tool to
close prematurely.
This circulating valve has a very good reliability record, and has been used in all Exxon
deepwater exploration tests in the USA since about 1984. The very few failures have
been attributed to dirty pipe, and these were temporary (but time-consuming) ones,
resolved without pulling the test string. In a 1997 Exxon GOM deepwater oil test, the
MIRV survived the test with about 20 open/close cycles, and was used to re-establish
eight diesel cushions.
H allib u rto n s O M N I M u lti-Indexing Reversing Valve is a fullbore (2.25-in. ID) indexed
combination circulating valve and test valve that operates on cycles of annular pressure.
The test valve is of the ball type, and sleeve valves are used for the circulating function.
The OMNI is placed above the tester valve, and usually above any drill collars added to
the string for weight. It is not as sensitive to debris as the MIRV.
The OMNI valve has three different basic positions, arranged in four configurations as
shown below:
1. Test position: test ball valve open, circulation ports closed.
2. Blank position: test ball valve and circulation ports closed.
3. Circulating position: test ball valve closed, circulating ports open.
4. Blank position: same as 2.
The ball valve and circulating sleeve valve in the OMNI are coupled so that the ball valve
is always closed before the circulating sleeve valve is opened. Most of the annular
pressure cycles serve to advance the indexing position in the tool cycle, with only four
out of the fifteen total index positions actually causing the OMNI to change configuration.
T h e in te rve n in g d u m m y cycle s a re d e sig n e d to p ro te ct th e O M N I fro m in a d ve rte n t
annular pressure cycles, and to permit other APO tools to be actuated without actuating
the OMNI. This can get quite complicated, requiring careful tracking of exactly where
each indexed APO tool is in its cycle at all times.
Although the ball valve portion of the OMNI functions similarly to a tester valve, and
could function as one under certain conditions, it is not usually used as a test valve
because the ball cannot open against high differential pressures. It is usually run above
the LPR-N serving as the main tester valve. This particular combination of two indexed
tools is a prime example of when extreme diligence is required to coordinate the APO
indexing valve cycles to avoid tool gridlock, which has occurred on more than one
occasion.

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13.5.14 SINGLE SHOT REVERSING VALVES

Most single shot reversing valves are annular pressure operated, but tubing pressure
operated tools are also available. As the name implies, they are single action tools that
permanently open one or more ports between the annulus and tubing. They may not be
sh o t o r o p e n e d u n d e r n o rm a l circu m sta n ce s if a m u lti-cycle circulation valve is in the
string and operating properly, but if they are, it is only after the test is over and the test
valve is closed. Thus, their activation pressure should be set considerably higher than
those of the tester valve, the samplers and the multi-cycle circulation valves.
T h e sim p le st o f th e se to o ls is S ch lu m b e rg e rs S in g le S h o t H yd ro sta tic O ve rp re ssu re
Reversing Tool (SHORT). It is permanently opened by one shot of annulus
o ve rp re ssu re . A n o th e r ve rsio n , S ch lu m b e rg e rs S in g le S h o t A n n u la r R e ve rsin g V a lve
(SSARV) has two safety features to prevent premature operation:
1. Two cycles of annular overpressure are required, and
2. The second cycle of overpressure must be completely bled off before the
reversing valve will open.
In Halliburton's line, the APO TEST single shot reversing valve is called the Rupture Disk
Safety Circulating Valve.
S ch lu m b e rg e rs tu b in g p re ssu re o p e ra te d to o l is ca lle d th e S in g le S h o t O ve rp re ssu re
Reverse Tool Internal/External (SORTIE). It can be operated by tubing or annular
overpressure. Halliburton offers the Internal Pressure Operated (IPO) circulating valve.
Raising tubing pressure to a set level above annular pressure operates it. This pressure
difference can be from 500 psi to 10,000 psi. Once activated, the tool is permanently
locked open.
All of these single shot reversing valves, as well as any multiple cycle reversing valves,
are usually placed atop the drill collar section if drill collars are used. If debris or sand
production is likely they are placed a minimum of several hundred feet above the main
tester valve to prevent debris that may settle on top of the tester valve from stacking high
enough to plug the circulation ports in the circulation/reversing valves.
While the most important tool in the APO TEST string is the bottomhole shut-in valve,
other components are essential to conducting a successful test by way of providing
flexibility in cushion replacement, remedial work, and dealing with unexpected events.
This subsection briefly describes these tools.

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13.5.15 OTHER EQUIPMENT

RA TAG OR MARKER SUB

This is simply a short tubing sub that contains an insert of radioactive material that gives
a strong response on the GR-CCL log. It can be helpful when placed in any of the strings
connected with packer setting, completion and testing. It is most helpful when used in
conjunction with RA markers in the casing, as this greatly simplifies and strengthens the
depth correlation and verification process for setting the CHAMP or retrievable packer,
positioning the perforation guns, etc. at a specified depth relative to the test interval.
These two RA tags can be invaluable when the natural formation gamma ray signal
is weak, and further attenuated by the casing and tubing string. Their use is highly
recommended in both casing and tubing strings.
TEST STRING PRESSURE TEST VALVES

The test string pressure test valve is placed in the test string to facilitate pressure testing
of sections of the string as it is assembled and run in the hole. The flapper seals
intermittently for multiple pressure tests top down while GIH. In order for the string to be
filled from the annulus GIH, the main tester valve must be in the locked open position.
Increasing annular pressure to rupture a disc disables the tool. At this point, the tool
locks open full-bore and acts as a piece of tubing.
TUBING FILL VALVE

A close cousin to the test string pressure test valve is the tubing fill/test valve. The
difference is it has its own bypass ports, in addition to the flapper valve, which combine
to a llo w fillin g w h ile G IH w ith th e te ste r va lve in its d e fa u lt clo se d p o sitio n . T h e fla p p e r
valve seals intermittently for multiple pressure tests top down while GIH. This valve is
also permanently retired by increasing annular pressure.
SAFETY JOINTS AND HYDRAULIC JARS

A safety joint and jar sub, if run, would be placed on the bottom portion of the tubing
immediately above the permanent or retrievable packer. Their function is to help free the
string if it becomes stuck. In most cases, it is the retrievable packer that gets stuck. If the
packer does not release, any retrievable gauges are first pulled, and the jar sub is used
to attempt to knock the packer loose. If this fails, then the safety joint is parted using
left-hand torque.
SAFETY VALVES

Safety valves, when operated, seal off the test string to flow from below. Although the
main tester valve is primarily a failsafe shut-in device, there are conditions under which it
will not operate as such.

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13.5.16 SAMPLING AND PRESSURE MEASUREMENT RELATED

STRING COMPONENTS

SAMPLING VALVES

APO test samplers discussed below are in-line fullbore tools, and there are three
basic types:
1. The dual-ball sampling valve, called the Dual Ball Safe ty V a lve in S ch lu m b e rg e rs
line.
2. The flow-through annular sampling valve, called the Fullbore Annular Sampling
Chamber (FASC) by Schlumberger, and the FUL-FLO sampler by Halliburton.
3. The bundled mono-phasic sampler (e.g., OIL-P H A S E typ e S C A R , o rig in a te d as a
wireline type of bottom hole sampler, but now mounted in bundle carrier run with the
test string).
Dual-Ball Sampling Valve is basically two in-line full-bore ball valves mounted in a
mandrel-carrier. The distance between the ball valves determines the sample volume,
so very large samples can be captured. This type of sampler can only capture a sample
at the end of the test, because when the two ball valves close simultaneously, capturing
a sample, they close off the test string permanently. These valves are normally activated
by an annular pressure that is significantly higher than that required to operate the main
tester valve, but below that required to operate single-shot reversing valves. This type of
sampling valve can also serve as a safety valve.
Flow-Through Annular Sampling Chamber (FASC), the well stream flows through the
central bore of the fullbore tool before and after sampling. An annular chamber in the
tool wall serves as the sampling chamber, which can be sealed to capture the sample at
any time in the test, with the well flowing or not. Sample volume is typically from 600 to
1200 cc. This sampling tool is also activated by an annular pressure well above that
required to operate the main tester valve, but well below that required to operate single
shot reversing valves or any other APO test tool that ends the test when it is activated.
Several annular sampling valves can be stacked, and each can be set up to trigger at a
different annular pressure. This permits capturing samples at different times in the test.
In practice, the flow-thru annular sampling chamber has been prone to leaks, and
requires special efforts to transfer a sample correctly (under single-phase conditions) at
the surface. Because they are APO test tools, they must be above the packer, which
means they sample at a lower pressure than wireline bottomhole samplers do. This is a
serious limitation for saturated or near-saturated systems.
Note: T h e a n n u la r sa m p le ch a m b e r in th is to o l is n o t a flo w th ro u g h ch a m b e r, b u t is
filled by drawing in a sample from the flow path. Thus, in a two-phase situation, it is less
likely to capture a representative sample than a dual ball sampler, which captures the full
flow stream.

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WELL TESTING OPERATIONS

ExxonMobil may run these two types of tools as backups to wireline bottomhole
sampling devices in certain situations. For example, in a deepwater test, wireline
bottomhole samplers are thought necessary to get a reservoir sample before any
possible wax or asphaltene deposition in the very cold upper test string. Inline samplers
are run in case there are problems with hydrates that could prevent wireline operations.
Bundled Mono-Phasic Sampler This type of sampler was adapted from the highly-
developed wireline sampler (e.g., OIL-PHASE in the case of Schlumberger), it is fairly
small in O.D, and is carried in a bundle carrier that can accommodate more samplers of
the same type or even gauges (ported to tubing or annulus). The sampler uses a
pressure-balanced, metered piston system to slowly sample from the flow stream at very
low-pressure drawdown. This is to avoid flashing additional gas off in the sampling
process, and thus getting an unrepresentative sample. Once the sample is taken, a high
back-pressure is placed on the sample chamber piston to keep the sample in the
m o n o -p h a sic co n d itio n .
Like the annular sample chambers, sampling does not affect well flow or terminate the
test per se. In Schlumberger colors, the bundled mono-phasic sampler is triggered by
annular pressure. Thus, it must be placed above the packer. In other colors, pressure or
acoustic signals can trigger the bundled mono-phasic sampler. Of course, the use of
timers in APO test string applications is unworkable, whereas this is the primary means
of triggering sampling in slip line applications of this sampler.
These bundle-mounted mono-phasic samplers overcome many of the disadvantages of
the inline ball valve and annular samplers (namely, leakage, sampling ends testing,
possible gas flashing during and after sampling). However, they still cannot offer what
wireline bottomhole sampling can and that is getting samples closer to the perforations,
a n d re trie vin g a n d Q C in g sa m p le s, a n d G IH fo r m o re w ith o u t p u llin g th e te st strin g .
However, they benefit by saving rig time required to run wireline samples, eliminating
lu b rica to rs a n d risk o f b ird -n e stin g w ire , a n d h a ve p ro ve d ve ry re lia b le .
In summary, bottom hole samples are of limited use for PVT work unless the flow stream
being sampled is one phase. However, there are situations in which wireline runs are not
advised, one being in an extremely hydrate-prone well. In these cases, the bundled
mono-phasic sampler nicely fills a niche, and the annular chambered sampler can serve
as a backup sampler.
Comments on SRO Pressure Readout
Surface readout (SRO) pressure measurement systems will be discussed in the
Measurement and Sampling section. Real time readout of bottomhole pressures or
batch-type readout of memorized bottomhole pressures can be very helpful in
conducting a successful test, and can p ro ve in d isp e n sa b le in d ifficu lt w e ll te sts.
This access to downhole data with string still in place can be used to quickly diagnose
and correct many types of problems, monitor the progress of the test, and make an
educated decision to end the pressure buildup. But it is quite expensive. It is the sort of
option that may pay for itself five times over in rig timesaving once every three to eight
applications. Its use in a development well where there is lots of prior experience to draw
on may not be economically justifiable. But for now, we will confine the discussion to
memory gauge carriers.

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MEMORY (NON- SRO) PRESSURE GAUGE BUNDLE CARRIERS

The standard way to run standard memory pressure gauges in an APO test to use a
fullbore bundle carrier below the tester valve. The typical fullbore bundle carrier has a
2.25-in. ID and a 5 to 6-in. OD. In most cases, though not always, the carrier is
straight-through, which means the axis of the bore of the bundle carrier is not offset from
the main axis of the test string. It can normally carry four gauges, but bundle carriers can
be stacked to get more gauges downhole.
If a permanent packer is used, the bundle carrier will have to be placed above the seal
locator sub if it cannot pass through the seal bore assembly. This limits how close the
g a u g e s ca n b e p la ce d to th e p e rfo ra tio n s. T o o ve rco m e th is, a ta ilp ip e o r stin g e r ca n
be run below the seal (of smaller OD than the seal bore) to house gauges mounted on
the test string bore axis, below the perforated or slotted flow entry sub. Usually gauges
run in this manner can be pulled and replaced with wireline. A more detailed discussion
o n m o u n tin g g a u g e s in ta ilp ip e s w ill b e p ro vid e d in th e se ctio n M e a su re m e n t a n d
S a m p lin g .
When running an APO test string with a retrievable packer, it is possible to place the
bundle carrier below the packer, because seal bore clearance is not a factor. In many
cases, however, TCP perforation is employed with APO test strings having retrievable
packers, and bundle carriers are not usually run directly on top of or near to the TCP gun
firing head. Nonetheless, with improvements in gauge mechanical integrity and shock
absorbing subs, it is possible to get the gauges closer to the guns than in the past.
If this is not close enough, or if the risks to gauges are not acceptable, then with
pre-planning it is possible to run additional gauges via wireline after the TCP guns have
been fired and dropped. The additional gauges could be set in a stinger extension sub.
This requires a fullbore APO test string. Such a gauge assembly was run in the
Diana-3 test, as previously described.

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WELL TESTING OPERATIONS

13.6 UPPER TEST STRING OR LANDING STRING

13.6.1 INTRODUCTION

T h is se ctio n co ve rs th e u p p e r p o rtio n o f th e te st strin g , co m m o n ly ca lle d th e la n d in g

strin g , a n d it extends from the BOP stack on the seafloor up through the rig floor.
It is always used with wells drilled from floating rigs, regardless of the type of test string
below it. However, as discussed earlier, almost all current deepwater tests are with the
APO-type test string.
Both moored and dynamically positioned rigs employ the same basic landing string,
although the dynamically positioned application will usually have more stringent quick
disconnect time requirements for the test string.

13.6.2 PURPOSES AND FUNCTIONS OF LANDING STRING

The major purposes and functions of the landing string are as follows:
1. To complete the full bore flow path from the top of the lower test string in the
BOP up through the sea and riser to the rig floor, where it is supported by the
rig s m o tio n co m p e n sa to r.
2. To employ the subsea test tree (SSTT) to provide a quick, safe, pollution free
disconnect from the lower test string and withdrawal from the BOP stack in case
of an emergency, such as loss of rig position, etc., by:
Shutting the well in immediately below the disconnect point.
Shearing any wireline or coiled tubing at the disconnect point.
Sealing the bottom of the landing string to prevent hydrocarbon pollution,or
large volumes of gas escaping into the riser.
3. To employ the fluted hanger as a hang-off point in the subsea wellhead (high
pressure housing) to support the test string weight down to the slip joints, support
part of the landing string weight, and to position the slick joint (not to be confused
with the slip joint) opposite the appropriate rams in the BOP and the shear joint
opposite the blind/shear ram.
4. Provide a smooth, uniform cylindrical surface for the BOP rams to seal on.
5. Provide support and protection for the various external control lines, and
chemical injection lines.

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13.6.3 COMPONENTS OF LANDING STRING

The components of the landing string will now be considered, beginning at the BOP at
the seafloor and working upward to the rig floor. Figures 13.15 and 13.16 show the
BOP stack in more detail.

Subsea BOP Normal Operations

SSTT Connected
Choke
Kill Line Line

Figure 13.15 - Subsea BOP Stack during Well Test

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13.6.4 BOP STACK

The subsea BOP stack is the key piece of well control equipment in deepwater drilling
operations. In deepwater testing operations, the BOP stack performs some additional
test specific functions. It also houses the pipe ram(s) that seal off on the slick jo in t in
the test string, making the casing-tubing annulus a pressure chamber to control the test
tools. It also provides the manifolding necessary to pass choke or kill line fluids and
pressure from the rig floor around the BOP rams to operate the test tools. The subsea
test tree assembly, and shear joint, must be spaced out across the BOP stack such that
the blind/shear rams willSubsea shear the BOP Production
shear joint in the event of Testan emergency disconnect.
And finally, the BOP houses specialAfter subsea Disconnect
safety tools that are positioned near the
b o tto m o f th e la n d in g strin g . T h e se to o ls a re cla ssifie d a s su b se a te st tre e e q u ip m e n t
and will be discussed next.

Choke Line
Kill Line

Fluted Hanger

Figure 13.16 - Subsea BOP Disconnect During Well Test

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13.6.5 FLUTED HANGER

The fluted hanger is the bottommost special-purpose tool in the landing string. Shown in
Figures 13.15 and 13.16, it is a round, tapered collar (like a truncated cone) affixed to a
threaded mandrel joint. When the string is positioned in the packer, the fluted hanger
rests in a tapered seat in the bottom of the BOP stack. The hanger supports the weight
of the string below it down to the slip joints. If there are no slip joints (permanent packer
application), the entire string is hanging or is in some degree of compression. Whether
or not slip joints are used, neither the lower test string nor the landing string moves
vertically with the heave of a floating rig. Both are stationary at the seafloor via the fluted
hanger seated on the wear bushing in the wellhead.
The fluted hanger is threaded onto the special mandrel sub, which permits easy
adju stm e n t o f th e co lla rs d ista n ce fro m th e e n d o f th e su b to sim p lify sp a ce o u t. O n ce
adjusted, it is then locked into place to fine-tune the position of the slick joint above it
relative to the appropriate BOP rams, the shear joint across the blind/shear rams, and/or
to fine tune the space out of the string. The fluted hanger has passageways for fluid to
pass through the choke line, lower chambers of the BOP, and into the annular space
below the hanger. This is necessary to operate the APO tools in lower test string.

13.6.6 SLICK JOINT

A slick joint (as opposed to slip joint) is a smooth cylindrical section of pipe with no
external upsets at the joints so that a uniform sealing surface is provided for the pipe
rams of the BOP. For well testing on floating rigs, usually dual ram closer is strived for,
but this may require fabrication of special-length slick joints (depending on BOP ram
spacing in relationship to the fluted land-out point). A special variety of slick joint, called
th e p o rte d slick jo in t, is required if sub-mudline chemical injection into the test string is
required. The ported slick joint has a small passage drilled along the length of it in the
slick joint wall, parallel to its axis. The passage runs almost the length of the slick joint,
up to its threaded ends, where it connects to external ports. The ported slick joint is used
to pump chemicals past the closed BOP rams, and theoretically to any depth short of the
packer. Its use is mandatory if hydrate inhibitor (methanol) is required below the mudline
(typical of gas tests in deepwater).
In some circumstances, two slick joints might be spaced out to give sealing at two test
string positions. For instance, it might be desirable to conduct some temporary operation
with the test string pulled up, but while the annulus is sealed. For instance, checking on
gas under the packer after killing a well while pulled up out of the permanent packer. In
this instance, the second slick joint would be below the fluted hanger.

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13.6.7 SUBSEA TEST TREE

The subsea test tree (SSTT) is the heart of the

landing string, providing a quick, remote means
for shutting-in the well at the BOP and
disconnecting the bottom of the landing string Latch
above the sealing pipe rams so that it can be Assembly
safely pulled from the BOP. This capability will
normally be used only in an emergency
Latch
situation. dog
The SSTT is an assembly comprising two
sections, a lower ball valve section, and an Latch
upper hydraulic section. Both valves require profile
hydraulic pressure to open and are failsafe
closed. A cutaway is shown in Figure 13.17. In
most models, the lower section of the SSTT
also houses a secondary sealing valve, either a
flapper valve or another ball valve. The upper
and lower sections mate and latch together,
and rest atop the slick joint(s) and the fluted
hanger, which support it in the BOP stack.
Valve
The SSTT is controlled from the rig floor via Assembly

hydraulic lines (or electro-hydraulic for

deepwater applications) that run down along
the landing string (in the riser annulus),
strapped to it and protected by some means
(standoffs) from being crushed against the riser.
Additional chemical injection lines (methanol or
wax inhibitor) may be included with the main
co n tro l lin e s u m b ilica l. T h e S S T T is p o rte d to
allow injection of chemicals into the flow stream
at the SSTT or to pass chemicals through it
to a lower injection line (i.e. sub-mudline
Figure 13.17 - SenTree 3 Latch &
injection sub).
Valve Assembly

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WELL TESTING OPERATIONS

The primary purpose of the SSTT is to provide a safe, clean way to disconnect the string
in a hurry. To do this, it must:
Cut any coiled tubing or wireline in the string with the lower ball valve.
Shut-in the well at the seafloor.
Disconnect the test string immediately beneath the shear rams after the retainer
valve has sealed off the upper disconnected end.
Provide for full reconnect with all functions restored, including chemical injection.
Provide pump-in capability to kill the well in case of a system failure.
Comment [NKM1]: Page: 46
If the SSTT fails to disconnect, first hydraulically, and then after attempting mechanical Is this 37 or 38 or something else? Your number is
backup measures, the shear rams immediately above the SSTT are closed on special 35, but you have a ref. to Figure 1 at the start of the
shear subs in the string. Obviously, this is a last resort. SSTT section.

Note: Many older floating rigs have blind/shear rams that are incapable of shearing
standard shear joints provided by the testing companies. The dimensional and material
properties of the shear joint should be provided to the BOP manufacturer in order to
ensure shear-ability. Special-order or turned-down shear joints are frequently required.

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13.6.8 RETAINER VALVE

A retainer valve is run above the

shear sub on top of the SSTT to
isolate pressurized well fluid in
the upper part of the landing
string from the riser (Figure
13.18). It prevents any surging
forces that might drive the
landing string upwards, loss of
pollutants to the riser, and filling
of the riser with gas buBbles.
The retainer valve opens and Ball
cage
closes in a delayed sequence
with the SSTT ball valve, and is
Seal retainer
controlled by the same hydraulic Ball
lines. It is normally a fullbore Ball valve spring
ball-type valve, having the same Pins
wireline and coiled tubing cutting
capabilities as the SSTT ball
valve. Trapped pressure Piston
between the SSTT and retainer
ball valves is bled off in a
controlled manner to the riser
before the SSTT unlatches. The
valve is usually failsafe closed,
but the ball can be pumped off
its seat by annular pressure from
below if it is packed off by
closing the annular BOP on the Sequencing
landing string. The spanner joint valve
facilitates this seal-off in the
annular BOP. Figure 13.18 - SenTree 3 Retainer Valve
BOV Open Closed

Figure 13.18 - SenTree 3 Retainer Valve

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13.6.9 SPANNER JOINT

The spanner joint rests on the retainer valve and provides the sealing surface opposite
the annular BOP, while protecting control lines, if it becomes necessary to close the
annular. With this tool, annular pressure can be used to open the retainer valve for
reverse-out after disconnects if the control hoses are lost. The spanner joint also
contains a hydraulic manifold to sequence the timing of the SSTT shut-in and disconnect
operations.

13.6.10 SSTT CONTROL LINES

Three hydraulic lines control the standard subsea test tree. In the normal configuration:
Line A is pressured and must be kept pressured to keep the lower main ball valve open.
This valve is failsafe closed.
Lines B and C are kept at normal riser hydrostatic pressure.
In an emergency disconnect, the following sequence is followed:
1. The pressure is bled off Line A, and the lower SSTT ball and retainer valve close
or attempt to close if wireline or coiled tubing is in the SSTT.
2. Line B is pressurized, giving a strong boost to the ball valve closing mechanism
so that it cuts any wireline or coiled tubing. Both the ball valve and the retainer
valve should close, sealing off upper and lower sections of the test string.
3. Line C is pressurized, disconnecting the upper section of the SSTT from the
lower SSTT section. The upper test string is picked up and pulled clear of the
BOP. If pressurizing Line C fails to achieve a disconnect, the SSTT can be
disconnected mechanically by a rotary motion.
4. Close the blind rams above the lower portion of the SSTT left in the stack. If the
SSTT and upper test string remain connected, the blind rams will shear the shear
joint and umbilical, thereby closing the SSTT valves and sealing the wellbore.
5. Pull out of the hole with the upper test string and begin pulling the riser if the
situation permits.
Note: For DP rigs timing for these steps is critical. It may be determined that insufficient
time exists for attempted disconnect, and reliance on the blind/shear rams to shear the
shear joint may be the disconnect option of choice (certain situations).

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13.6.11 QUICK DISCONNECTING SSTT SYSTEMS

The earliest SSTT systems were totally hydraulically powered, and this power was
generated at the rig floor with pumps and transmitted through small, flexible, high-
pressure lines. However, as water depths increased, the control length, volume, and
pressure drop increased to the point that disconnect times became unworkable for an
emergency. The first technique to shorten response times was to employ a downhole
hydraulic accumulator. This is a source of nitrogen-charged hydraulic energy stored just
above the retainer valve, within several feet of the SSTT. In the Schlumberger line, it is
called the hydraulic accumulator pod. It can be recharged from the surface, if necessary,
but this would not normally be required or desirable. This deepwater accumulator pod is
triggered by a hydraulic relay system, which is controlled from the surface in the manner
of the original SSTT control system. So this is a hydraulic relay system, with the power
source located where it is needed.
Because only very small volumes of hydraulic fluid from the rig floor are required to
control the relay system that actuates the valves, the response time is shortened
considerably. However, the response time with this system may still not be short
enough. In 5000 ft of water, the hydraulic relay system takes 30 seconds to disconnect
S ch lu m b e rg e rs th re e -inch 10K SSTT. This is considered too long for some dynamically
positioned rigs. And for sure in deeper water, a faster system was needed.
An electro-h yd ra u lic syste m is re q u ire d fo r fa ste r d isco n n e cts. S ch lu m b e rg e rs S E N -
TREE-3 e le ctro -hydraulic system uses electronics from the rig floor and an electric relay
instead of a hydraulic one to activate the hydraulic accumulator pod at the seafloor.
These systems can effect a complete shut-in and disconnect in about 20 seconds,
regardless of water depth. The SSTT must be shut-in, must unlatch, and the landing
string must be pulled up clear of the riser connector - all in less than 37 seconds. This
pushes the 20-second response of the electro-hydraulic SSTT. A hydraulically actuated
system could not meet this requirement.

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13.6.12 OPTIONAL TEMPERATURE MEASURING DEVICES

For deepwater tests in new areas, it may be helpful to collect flow stream temperature
data near the seafloor during a well test at all flow conditions for modeling heat loss and
flowstream temperatures for the design of the production gathering system. Or it may be
necessary for gas hydrate mitigation design on the low temperature side, or assuring
that the temperature limits on elastomer seals in the BOP are not exceeded on the
high side.
A subsea pressure and temperature carrier can be used to record temperatures and
pressures, and (optionally) pass them up to the rig for real time monitoring (SRO).
Although this carrier uses the same standard temperature/pressure gauges that are
used bottomhole; the carrier has a special temperature probe to measure as close to the
flowstream as possible.
Typical pressure gauge bundle carriers are not suitable for the measurement of flow
stream temperature, because the temperature-sensing device in the gauge measures
the temperature of the pressure sensing crystal in the gauge (for compensation
purposes), not of the actual flow stream.
Schlumberger offers a real-time SRO temperature measurement from a probe as
described above. It is normally run atop the spanner joint. The probe is very close to the
flow stream wall, insulated from riser fluids, and should provide a representative flow
stream temperature measurement. While this temperature measurement might not be in
the ideal location for temperature data for design of subsea facilities, production risers,
and so forth, it is much better than can be obtained with a standard pressure gauge and
bundle carrier. Halliburton has temperature and pressure probes that are integral to
their electro-hydraulic SSTT package that communicate the data to the surface via the
control line bundle.

13.6.13 SUBSEA LUBRICATOR VALVE

This is a fullbore, hydraulically-actuated ball valve that is placed in the landing string
about 50 to 100 feet below the rig floor (not always actually subsea). Lines from a
hydraulic pump system on the rig floor supply actuating power. The valve is balanced in
such a way that it remains in its last position in case of hydraulic failure. It can withstand
high differential pressure in both directions. To open, pressures across the ball valve are
automatically equalized by means of an internal valve. This minimizes the violent surge
and seal wear that would occur otherwise.
The primary purpose of the lubricator valve is to permit longer sections of wireline tools
to be introduced to a pressurized test string without the need for a full-length wireline
lubricator suspended above the surface flow head. In many cases, this would be
impossible or dangerous to do. The lubricator valve also helps to isolate the test string
for purposes of pressure testing.

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13.6.14 OPTIONAL RISER SEALING MANDREL

The riser sealing mandrel is a recently offered (circa 2000) safety device that facilitates
sealing the landing string at the BOP-diverter just below the rig floor. At increased water
depths, a gas leak in the landing string near the seafloor will expand into a much larger
volume as it comes up the riser to the rig floor. The riser sealing mandrel will contain this
volume, allowing the BOP diverter system to handle it safely.
The riser sealing mandrel is a full bore in-line section of pipe with an offset 9.5 in. OD,
the thicker face of which is scalloped to provide a protective recess for the SSTT control
and injection lines. A half-cylindrical section protective plate is bolted over the lines while
internally it compresses seals around the various lines. Now the diverter BOP has a
uniform cylindrical surface to seal on, the riser can be sealed, and all of the hydraulic
(electric too, if used) lines are protected.

13.6.15 STIFF JOINTS

Stiff joints are rigid, thick-walled sections of tubing that are used immediately below the
surface flow head (or surface test tree), extending below the rotary table on the rig floor.
Their purpose is to provide structural integrity and an additional safety factor into the top
of the landing string. Stiff joints prevent the high weight of the flow head (with perhaps a
lubricator on top of it) from causing the string to bend over or whip around, especially in
heavy heave conditions when the motion compensator is not supporting the landing
string from above.

13.6.16 OPTIONAL LOWER MASTER VALVE

The lower master valve is an additional, optional safety valve. Its position in the upper
part of the landing string. If there is a leak in the flowhead this valve (and the lubricator
valve, if present) could be closed to isolate the surface test tree for repair or
replacement.

13.6.17 SWIVEL JOINT

The swivel joint is immediately above the lower master valve and below the flow head.
Its sole function is to allow the landing string below it to rotate with respect to the string
above it, without limit, under full operating pressure and flowing conditions. This ability to
rotate while flow testing is an absolute requirement for drilling vessels such as
dynamically positioned drill ships, because they must change their heading with
changing wind direction and sea conditions. Moreover, there are other situations in
which a rotational capability is needed. After all the surface flowlines have been rigged to
the flow head, a swivel joint would make it possible to quickly disconnect at a safety joint
or at the SSTT, if it fails to disconnect hydraulically, by means of string rotation while the
flow head remains stationary.

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13.6.18 OPTIONAL CHEMICAL INJECTION VALVE

A chemical injection valve is an option that allows chemicals to be injected upstream of

the flow head. Injecting methanol to prevent hydrate formation is one example. Hydrates
might form below this point in a deepwater test string, but plugging tends to occur at
sharp turns in the flow path like those found in the flow head. This is, accordingly, a likely
supplemental injection point, but deeper injection points (mudline at the SSTT, or sub-
mudline) may be required. It is also a good place to inject hydrate inhibitor when the well
is shut-in. The inhibitor will fall down the string and prevent hydrates from forming in the
gas cap in the test string. It will continue to driBble down the cold sea leg of the landing
string, where it will do the most good.

Handling Sub
13.6.19 FLOW HEAD

The flow head, also called the Failsafe

Actuator Hydraulic Operated
surface test tree (STT), has a Swab valve

central body constructed out of a Coflex Support

solid forged block of alloy steel
that houses four gate valves. As Kill Line Failsafe
shown in Figure 13.19, these Actuator

valves are the:

Master valve at the bottom
flow entry point, connected to Production
the test string underneath Dynamic Swivel line

Crown or swab valve atop the

STT.
Wing valve on the kill line
side.
Wing valve on the opposite
flowline side connected to the Hydraulic Operated
Master Valve
production test equipment. It
normally has a failsafe shut Figure 13.19 - Schlumberger Surface Flowhead
actuator connected to the
surface ESD system.

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The master valve can be used to shut the well in if there is no wireline in the well. As
discussed, there may be an optional master valve below it and below the swivel joint.
There may also be a lubricator valve below deck that can be used to shut-in the well if
wireline tools are being loaded into the lubricator atop the flow head.
The swab or crown valve is on top of the flow head and isolates a straight through, full
bore entry port into the top of the test string. This valve and port is fitted to accommodate
a wireline BOP and lubricator to be attached to the top of the flow head so that wireline
tools can be introduced into and withdrawn from the pressurized test string.
The kill side wing valve isolates another entry port to the top of the test string. This valve
and line off the side of the flow head is usually connected to the rig pumps so that the
well string can be circulated, pressurized to operate certain tools, or pumped full of kill
weight completion fluid in a hurry to kill the well.
The flowline side wing valve isolates the exit port where the flow stream exits the test
string and flows through a flexible flowline to the surface production equipment. An
emergency shut down (ESD) valve is always placed on the flowline immediately
downstream of the flowline side wing valve or it may be attached to the flow head itself.
This is a failsafe-shut safety valve with a control system set up such that the flow stream
can be reliably shut off in seconds from any one of multiple strategically located stations
on the rig. This important piece of equipment is discussed in detail in section on surface
equipment, to follow.

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13.6.20 SUSPENSION OF THE LANDING STRING

The test string is fixed with respect to earth in one or possibly two places: at the packer,
and via the fluted hanger in the wellhead, and possibly at the packer. When seas cause
the floating drilling rig to heave, yaw, pitch, and roll, the rig floor will move with respect
to the top of the test string. Some type of dynamic tensioner or motion compensation
system is required to support the landing string.
There are two requirements for a motion compensation system:
1. It must maintain a reasonably constant vertical tension on the test landing string,
regardless of rig motion. A tension somewhat less that the total landing string
weight is normally applied, so that the SSTT is not in tension in the BOP.
2. It must provide sufficient clearance for whatever is to be mounted atop the flow
head during the course of the test, normally the wireline BOP and lubricator.
In most cases, the drill string motion compensator on the travelling block will suffice, but
there has been at least one rig whose compensator did not adequately support the
landin g strin g . A m o tio n co m p e n sa to r b o o ste r ca n b e u se d in su ch ca se s.
Note: All the equipment on top of the STT must clear the travelling block and other rig
fixtures. In this adaptation, pulleys are used to increase the effective speed and travel of
the tra ve llin g b lo cks co m p e n sa to r.
Note: The STT must by spaced out in relation to the rig floor so as to always remain
above the rig floor. Hence, rig heave, tides and a safety margin will determine how high
the bottom of the STT should be above the rig floor. Should the STT bottom out on the
rig floor:
1. The landing string could pick up the test string, shifting the SSTT across the blind
shear rams and making an emergency disconnect impractical.
2. The rams sealing on the slick joint could be damaged by the fluted hanger
upward movement.
3. The packer seals may unseat.

13.6.21 SUBSEA HYDRAULIC CONTROL CONSOLE

The subsea hydraulic control console is the rig floor control station for the SSTT. It
contains the pumps, valving, gauges, and piping to supply and control hydraulic
pressure to the SSTT, and to bleed these pressures off quickly. It typically will contain
four separate systems:
1. A p re ssu rize d a ir co n tro l syste m to o p e ra te th e syste m s p n e u m a tic p u m p s.
2. A circuit to control the pressurized hydraulic fluid used to operate the SSTT.
3. A separate hydraulic fluid circuit to trigger the downhole hydraulic relay, which in
turn triggers the hydraulic accumulator pods to unlatch the SSTT.
4. A chemical injection system.

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13.6.22 SUBSEA HYDRAULIC CONTROL LINE REELS

Subsea control lines are kept in the form of flexible hose bundles on large skid-mounted
reels. They connect the subsea hydraulic control console to the various landing string
valves. When the various valves are placed in the landing string, the appropriate
hydraulic hose connections are made. At this point the valves in the landing string can
be operated, even as the string is being lowered into the riser.
As the landing string assembly continues, and as it is lowered into the riser, the control
line bundles are played off these reels and affixed to the landing string. Protector clamps
are usually used to secure the lines to the landing string. In many cases, a strong
waterproof plastic tape is used to bind the control line bundle to the string.

13.6.23 HYDRATE INHIBITOR INJECTION

Hydrate inhibitor injection is usually required downhole, at least as low as the SSTT, in
deepwater gas wells, and in most deepwater oil wells (see section entitled, Special
Situations, Gas Hydrates). Additional lines, surface pneumatic pumps, and injection subs
will be required. Methanol is normally the inhibitor of choice, and 0.25-in. minimum ID
lines will be required. In the past, line crushing and subsequent leakage has been a
major problem, especially below the BOP. Now an armored line is used that is much
stronger and resistant to crushing. One example of this improved line looks like Romex
electric wire, but about five times the size. It is more or less flat in shape, and each edge
is embedded with a cable. The flowline is in the center.

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13.6.24 WIRELINE/SLICKLINE LUBRICATOR AND BOP

The purpose of this equipment is to provide pressure control so that wireline or slickline
runs can be made on a live well under pressure. Wireline or slickline work is not always
required when testing with the APO test string, but such capability adds to the versatility
of the test string, and certain test objectives may require its use. Since the APO test
string is typically fullbore opened to 2.25 in. ID, it easily accommodates wireline work.
Wireline work may be required to run gauges, run production logs, add perforations, or
provide surface readout of bottomhole gauge data. Slickline runs may be required to pull
or set plugs or pressure gauges, run bottomhole samplers, etc.
The typical lubricator is adaptable to housing different types of pressure sealing
components. A grease injection head must be used to make the seal around a conductor
cable (i.e., stranded wireline), whereas a simpler stuffing box is used to accomplish this
for slickline. The lubricator will have extension pieces to give it the length required to
load the wireline/slickline tools and weights into the lubricator barrel before it is secured
to the crown valve at the top of the flowhead.
Note: The lubricator/BOP can be quite tall, especially in high wellhead pressure cases.
Its height might interfere with the travelling block or complicate safe support of the
la n d in g strin g w ith th e rig s m o tio n co m p e n sa to r. T h e o p tio n a l su b se a lu b rica to r va lve ,
described a few pages earlier, is designed to prevent this situation. It effectively extends
th e lu b rica to rs le n g th d o w n th ro u g h th e cro w n a n d m a ste r va lve s to th e su b se a
lubricator valve, a hundred feet or so below the rig floor. Long bails (typically 40-ft)
sh a ckle d to th e rig s b a ils sh o u ld p ro vide the clearance needed to thread the wireline
tools into the STT above a closed lubricator valve.

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13.7 SURFACE TEST EQUIPMENT

13.7.1 INTRODUCTION

Fluids produced in a well test must be processed, separated and measured through a
train of surface equipment on the rig deck(s). Normally this equipment is part of a
temporary, modular installation, piped together with hammer unions. Larger pieces are
skid mounted in protective frames for easy hoisting and protection during transport.
Produced fluid properties, rates and flow conditions are usually not known prior to
exploration well testing. Thus, surface test equipment must be designed to operate
safely and reliably under a much wider range of conditions than production equipment
in permanent facilities. However, all of the equipment will have pressure, temperature,
rate, and H2S (and CO2) partial pressure design limits. The test design specifications
furnished to the service company must provide expected upper limits for these
parameters.
Most pieces of surface equipment used in deepwater well tests are fairly standard and
are proceeding in the direction of flow: the emergency shutdown (ESD) system, data
header, choke manifold, heater, three-phase separator, surge tank, transfer pump,
booms and burner.
A discussion of the functions and operating characteristics of the major pieces of surface
equipment follows. Details on separator instrumentation and measurements will be given
in the following section, Measurement Equipment. The section after that, Crude
Disposal, will detail oil burners, and the equipment required to off-load produced liquids
to barges.

13.7.2 FLEXIBLE FLOW LINE FLOWHEAD TO RIG FLOOR

We will now pickup the well test flow where we left off in the previous section, at the
flowhead. Since the landing string is stationary at the seafloor with the fluted hanger
landed in the wear bushing, there is relative movement between it and the rig-floor of the
floating rig as it heaves. COFLEXIP-type flexible hose is run from the wing valve
actuator on the flowhead down to the rig deck in most deepwater tests. This hose is
usually three to four in. ID It is a heavily reinforced, armored hose of composite material,
available in 15,000 psi rating. It will accommodate the motion of the rig relative to the
flowhead.
Often rigs will have permanent piping installed from the rig floor to the well test area.
Occasionally, pipe sections with swivel joints are used to accommodate rig motion.

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13.7.3 EMERGENCY SHUTDOWN (ESD) SYSTEM FLOWHEAD

(AND FLOWLINE) VALVE

The emergency shutdown (ESD) system controls the flowline valve actuator on the
process side wing valve of the flowhead. Another safety valve may be added, the
surface safety valve. It is installed on the deck floor between the flexible piping coming
down from the flowhead and the choke manifold. Both of these valves are failsafe
closed, hydraulic pressure is required to keep them open. The ESD system does not
control any of the SSTT functions.
ESD stations are usually located at the heater or steam exchanger, separator, surge
tank, on the drill floor, along the primary escape route and near the main entrance to
living quarters. The ESD is activated manually at any of the several stations by pushing
a clearly marked large red pushbutton-plunger, which bleeds pressure out of a looped
low-pressure circuit. This, in turn, actuates a control valve that bleeds off the hydraulic
pressure to the safety valves, closing them. This low-pressure line is usually of some
composite polymer or plastic material that can be cut with an axe or pocketknife, or
would melt in a fire anywhere along the loop to shut the valve(s).
The ESD system is flexible and can also be configured to shut-in automatically. High/low
pressure pilot sensors and erosion probes can be placed along the flow path to trigger
the ESD system in case of plugging, leaks, ruptures or sand erosion.
The final ESD design depends on the testing equipment and how it is laid out on the rig,
as well as safety requirements. But in any case, any person authorized to be on the
rig outside the living quarters should also be authorized to push the red ESD button
in an emergency.

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13.7.4 DATA HEADER

The data header is a manifold immediately upstream of the choke manifold. It is used for
accessing the flowstream for field sampling, injecting inhibitor, or sand production
measurement, in addition to monitoring the temperature and pressure of the flowstream
Figure 13.20. It a lso p ro vid e s a cce ss fo r w e llh e a d p re ssu re (e ve n w ith ch o ke m a n ifo ld
closed) and temperature sensors used in computerized data acquisition.

Sandec probe

Thermo well

Flow
Figure 13.20 - Data Header with Sandec Probe

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13.7.5 CHOKE MANIFOLD

T h e ch o ke m a n ifo ld h o u se s th e ca lib ra te d ch o ke tu b e s o r b e a n s th a t co n tro l th e flo w

rate. Choke manifolds are available with working pressure up to 20,000 psi and internal
pipe diameters of two to three inches. The manifold comprises two choke boxes and
usually a five-valve configuration to allow flow through one of three paths. Each box can
accept either a fixed choke tube or bean (of assorted sizes) or adjustable choke
(resembling a giant needle valve).
Calibrated choke beans (tubes) can be used in both choke boxes, if desired. Each bean
is bored out accurately to a specific size. They are available in increments of 1/64 inch.
B u t m o st co m p le te ch o ke tu b e se ts w o u ld o n ly h a ve a b o u t 3 0 to 35 choke tubes.
A b o ve in ., fo r e xa m p le , b e a n size s m ig h t b e 3 2 , 3 4 , 3 6 , 5 4 , 5 6 , 5 8 , 6 0 , 6 4 . M a n y
ve te ra n se ts yo u m a y e n co u n te r a re n o t e ve n th is co m p le te a s b ro u g h t to th e fie ld .
To change choke sizes on a flowing well, the affected choke leg is bypassed to the other
sid e , su ita b ly ch o ke d , iso la te d a n d th e p re ssu re b le d o ff. T h e o ld ch o ke b e a n is
unscrewed and removed, and the desired size choke bean is screwed into the box, and
the box secured with a flanged plug, which usually has a WECO-type hammer joint. The
flow is then re-d ive rte d b a ck th ro u g h th e le g w ith th e n e w ch o ke .
An adjustable choke is fitted to make choke adjustments without having to change out
the fixed choke tubes. It would normally be used during cleanup or initial flow when the
desired choke size is uncertain and frequent changing is required. The adjustable choke
h a s a va ria b le flo w a re a g e o m e try th a t ca n b e re d u ce d o r e n la rg e d o n lin e , w ith o u t
isolating the choke box, or interrupting flow. It is basically a large needle valve with a
Vernier scale.
The choke manifold is fitted with threaded taps for sampling valves, pressure gauges,
etc. Choke tubes and manifold turns are especially affected by sand and gas cutting as
well as asphalt and wax deposition. These factors can change the shape and size of the
choke, causing errors in choke calculations. A cut choke will result in underestimated
rates.

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13.7.6 HEATERS

Production heaters are used to raise the temperature of the well effluent after it moves
through the choke manifold, just before entering the separator. Natural gases contain
water vapor. Serious problems can occur if freezing occurs in the surface equipment.
Furthermore, gas hydrates can form at temperatures of about 60 to 70F at pressures
commonly encountered upstream and sometimes downstream of the choke. Hydrates
and ice can also form when testing oil wells that have a significant
gas-oil ratio and free water. Following are conditions requiring the use of a heater, and
these conditions are likely to be more severe in deepwater tests because of the much
cooler flow stream:
1. H yd ra te s a re d iscu sse d in m o re d e ta il in th e se ctio n o n S p e cia l S itu a tio n s.
2. An emulsion or foam is being produced in the separator (made worse by cold
fluid temperatures).
3. High viscosity oil difficult to atomize in burner nozzle separator (made worse by
cold fluid temperatures).
4. Wax deposition may occur inside flow lines and vessels. Heating the oil will
minimize this deposition downstream.
TYPES OF HEATERS

For safety reasons, steam heat exchangers are used exclusively in deepwater well
testing operations. Their use permits the heat generating source (normally a diesel fired
auxiliary steam boiler, or the rig boiler) to be remote, not only from the wellhead - which
is a universal safety requirement, but also from the vicinity of the process flow lines.
A steam heat exchanger is similar in construction to a typical process heat exchanger,
with the well flowstream passing through the tube side and the steam on the shell side.
Steam from the boiler is passed to the exchanger through heavy duty, reinforced high-
pressure rubber hoses (3 to 4 in. OD, somewhat insulated), where it transfers heat to the
well stream in the coils. The steam condenses to water, which is normally recycled to the
boiler in a similar hose. This type of heater is very efficient, easier to operate and safer
than the diesel-fired indirect heater. The boiler and its required full-time operator is
normally supplied by a third party.
Heaters are currently available with working pressures as high as 20,000 psig for H2S
service. For well testing operations, heaters with 3 or 4 in. coils are normally used.
Heaters are rated in British Thermal Units (BTU) and vary in capacity from 0.5 to 6
MMBTU/hr. Special purpose heaters are available with 5 in. coils and have heating
capacities up to 12 MMBTU/hr.
On natural gas wells (and other flow streams prone to hydrates), the heater choke
(located at the midpoint of the heater coil system) is used to take some or most of the
pressure drop normally taken at the choke manifold. This keeps expansion cooling from
taking place until the flow stream is partially heated. If the choke manifold is used to take
all of the pressure drop, the line between the choke manifold and heater could freeze or
hydrate up.

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13.7.7 SEPARATOR

The hydrocarbon stream at the flowhead comprises a mixture of gas, liquid

hydrocarbons, and perhaps some free water. It is necessary to separate these three
phases to measure their respective rates. This is accomplished by directing the heated
well stream through a three-phase or oil-gas-water separator. Gas is discharged from
the top of the vessel, oil from an intermediate position, and water from the bottom.
Separators used in well testing are normally horizontal self-contained units with the
necessary valving, pneumatic controls, and level controls to control vessel pressure at a
set level, and control the fluid interface levels. Well test separators are skid-mounted and
have appropriate external fittings for onsite rig up.
The separator is equipped with a gas metering system, liquid meters for measuring oil
and water rates, and sampling points for oil, gas, and water. The gas meter is an orifice
meter. Liquid meters are normally of the turbine meter type (or rarely the positive
displacement type). Well test separators must be rugged enough to handle gas, gas
condensate, light oil, heavy oil, foaming oil, oil containing water, spent acid, perforation
debris, mud and sand and vessel motion. The meters and level control systems take a
lot of unintended abuse from well trash, so the separator may be bypassed until the well
cleans up some. A separator with trash in the control system is hard to control; the
pressure and flow may cycle in an unstable manner, and may become dangerous.
A clean separator in good working order, overseen by a skilled operator, is essential to
a safe successful test.
Separators are normally rated for 1440 psi working pressure at 100F. Test separators
are usually operated at 400 to 800 psi on a productive well. The safety design
incorporates the standard features of a preset relief valve and a rupture disc, which is
piped to an emergency vent relief system when the separator is installed. In deepwater
tests, low temperature and marshaling enough heating capacity to get the flowstream
amenable to good separation is the problem, not high temperature.
Optimal operating pressure for the separator is selected considering the available
pressure, efficient separation, operational stability, and downstream pressure
requirements. The separator will normally be easier to operate (i.e., more stable, less oil
carryover in the gas) at higher pressures, but the oil exiting the separator will have more
dissolved gas in it. If the oil is to be burned, this is a good thing. If it is to be barged, a
surge tank should be used to degas the crude at near atmospheric pressure.

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CAPACITIES OF SEPARATORS

Flow capacities of separators are stated in terms of BL/D for liquids or SCF/D for gas,
but these maximum rate capacities are somewhat exclusive of one another, and they are
not totally independent of operating pressure either. For example, a 14,400 BL/D liquid
rate capacity may be stated in the specifications. However, for this rate to be reached,
the separator liquid level control must be set to the upper level range. This is required to
give the liquid more separator volume, and increases liquid residence volume at the
expense of gas residence volume. The small table below illustrates the two endpoint
settings for the standard duty separator.
High Liq.Lv. Cntl Max. Liq. Rate 14,400 BL/D Max Gas Rate 25 MMSCF/D
Low Liq.Lv. Cntl. Max. Liq. Rate 6650 BL/D Max Gas Rate 60 MMSCF/D
Even so, these numbers may be optimistic as they are for the higher operating pressure
range, and well-behaved systems. Actual separator capacity is also dependent on flow
stre a m p ro p e rtie s a n d th e se tu p o r tu n e a n d co n d itio n o f th e se p a ra to rs co n tro l
system. So if predicted (test design) rates even approach these numbers, it would be
best to specify a larger, premium separator. It would have capacities about 15% higher
for the liquids and 50% higher for the gas.
OPERATING PROBLEMS

Sand or other solids can be very troublesome in separators. They can cause cutout of
valve trim, plugging of separator internals, and accumulation in the bottom. Hardened
trim can minimize effects of sand on the valves. For this reason, it may be best to
bypass the separator until the well has cleaned up some, perhaps employing the surge
tanks (discussion follows) as a cleanup vessel.
Emulsions cause separator operating problems. Emulsions adversely affect the liquid
level control and decrease the effective oil or water retention time in the separator,
thereby decreasing water-oil separation efficiency. Emulsion breaking chemicals and
heat are the best solution.
Liquid carryover and blow-by are additional operating problems. Carryover occurs when
liquid escapes with the gas phase. It is symptomatic of a high liquid level, damage to
vessel internals, foam, improper sizing, or plugged liquid outlets. It will adversely affect
gas orifice rate measurements in two ways: by distorting and amplifying the pressure
drops across the orifice plate as liquid driBbles through it, and by building up liquid in the
manometer legs, measuring the pressure drop across the orifice plate.
Blow-by occurs when free gas escapes with the liquid phase, and can be an indication of
low liquid level, vortexing, or level control failure and may be amplified by rig motions.
It will affect the liquid turbine meter accuracy.

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13.7.8 SURGE TANK OR PRESSURIZED TEST TANK

The surge tank is a low pressure but closed vessel that usually has a 50 to 75 psi
working pressure. Surge tanks are available with working pressures up to 175 psi. It is a
single or double-compartment vessel with an automatic pressure control valve on the
gas outlet line to maintain a backpressure that can be set to any pressure up to 45 psi.
The process objective is to keep the necessary backpressure on the surge tanks to feed
the (transfer pump fo r) p ro d u ctio n d isp o sa l syste m s, a t th e sa m e tim e a llo w in g o n lin e
calibration of the liquid flow meter on the separator via coordinated liquid level readings
from the surge tank. This backpressure alone is usually sufficient to offload production to
a barge, in most cases. It is not sufficient to push oil through high efficiency burner
nozzles, though. Consequently, the surge tank is not in the flow path most of the time
when burning, but only for intermittent calibration periods.
Sight glasses allow the change of volume of liquids in the tank to be measured. Tank
capacity is usually 50 or 100 barrels. Safety features include a safety relief valve for
accidental over-pressuring. The surge tank was originally designed as a secondary
stage of separation bu t n o w se rve s p rim a rily a s a sa fe g a u g e ta n k o n o ffsh o re te sts.
Surge tanks come in both vertical and horizontal configurations. Vertical tanks are
definitely preferred on drill ships to minimize liquid level sloshing.

13.7.9 GAUGE TANK

The gauge tank is a non-pressurized vessel with either a single or a double

compartment. Since it is vented to the atmosphere through flame arrestors, this type of
tank is not recommended for use for hydrocarbons in any confined locations or where
H2S is present. It would come in very handy for measuring and storing volumes of
cushion and brine/oil interface fluids produced when unloading the well (i.e.: fluids that
will not burn in the flame but would cause a sheen).

13.7.10 TRANSFER PUMP

Transfer pumps are either centrifugal-type pumps powered by an electrical motor or a

diesel engine, each supplying up to about 125 HP or a pneumatic pump. Gear and
screw type pumps are also used occasionally. Pump capacities vary from 2,000 to
10,000 bpd, at discharge pressures between 200 and 500 psi. The pumps are used to
boost oil pressure to the burners when there is not enough flow stream pressure for the
well effluent to achieve atomization at the burner. Transfer pumps are also used to move
fluids from the rig to the oil storage barge, or move low pressure oil from the surge tank
or storage tank to the burners. The electric motors must be explosion proof, and the
diesel engine drive must have a flame arrestor on the gas exhaust.

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13.7.11 PIPING

Pipework selection is based on anticipated service pressure, flow rate, and layout of
equipment. The pressure specification is determined by the highest pressure expected
at a particular section in the well test flow stream. Thus a 15,000 psi rating might be
required between the flow head and the choke manifold, whereas only 5000 psi to the
heater, and 2000 psi to the separator.
The predicted flow rate is used to determine the pipe size. The service company will
design the system, and give predicted pressures along the entire flow path for a range of
oil rates and GORs. Service pipe diameter is usually 2 to 3 in. upstream of the choke
and 3 in. downstream. 4 in. piping is sometimes used downstream of the separator for
high-rate gas tests.
Pipework typically comprises straight lengths of 5 to 10 ft Pipe connections are
manufactured for standard or H2S service. All pipe, connections, and assemblies should
comply with ANSI B31.3 and API-6A. For sour service, compliance with NACE MR-OI-75
is necessary. Piping is usually connected w ith W e co typ e wing unions.

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13.8 INSTRUMENTATION, MEASUREMENT AND

SAMPLING EQUIPMENT
Even a production test with limited objectives will require pressures and temperatures
to be measured at bottom hole almost continuously during the test, and at the surface
separator on a regular basis. Also, rates of gas, oil and water must be measured at the
separator and samples taken. For test monitoring and control purposes, additional key
points along the flowstream and downhole must be instrumented for pressure and
temperature readings. Some of these measurement points are in the tubing-casing
annulus, at the well head, downstream of the choke, at the heater outlet, at the surge
tank, and oil supply pressure to the burners.

13.8.1 DOWNHOLE PRESSURE GAUGES

Test objectives involving reservoir characterization require that high quality electronic
pressure gauges be employed to collect a large quantity of bottomhole pressure data.
An adequate number of the best gauges available and suitable for the application must
be employed.
In recent years gauge suppliers have made significant technological advances in
instruments that have the precision and repeatability to accurately measure pressure,
and store large quantities of this pressure data in memory chips. Computer component
miniaturization has been essential, but the development of quartz crystal sensors and
long-life high temperature batteries have played an even bigger role.
U p u n til th e la te 1 9 8 0 s, th e m o st re lia b le g a u g e s h a d b e e n th e m e ch a n ica l o r A m e ra d a
Bourdon tube gauge, but they were not very accurate and definitely had limits on data
recording capacity. They were mainly used as backup to the electronic gauges of that
time. Now the electronic gauges are very reliable, and backup with mechanical gauges
is not common. At all conditions except extreme pressures and temperatures (>350F
and >16,000 psi), the electronic gauge, properly set up, is considered more reliable than
the mechanical gauge.
PRESSURE GAUGE BASICS

Pressure gauges use sensing elements that convert fluid pressure into a physical
displacement or deformation. In mechanical gauges, this displacement or deformation is
recorded or displayed directly.

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BOURDON TUBE - MECHANICAL TYPE

The Bourdon type gauge is still in use today for very high temperature applications due
to the temperature limitations (about 350 to 400F, circa 2002) of the batteries that must
be used with electronic gauge. Its mechanism is a tube formed into a helix anchored at
one end and free to rotate at the other. The tube uncoils with increased pressure.
In the BHP application, w h e re it is kn o w n a s th e A m e ra d a g a u g e , a drum is rotated by
a mechanical clock, and a stylus attached to the free end of the coil scratches a fine line
on a coated, very thin metal sheet wrapped around the timed drum. The Bourdon tube is
also the mechanical heart of the dial display type of pressure gauge commonly seen on
all types of surface equipment.
ELECTRONIC GAUGES

In electronic gauges, the displacement resulting from applied pressure is coupled to a

transducer, which will undergo a change in an electrical property under the stress.
That property may be resistance, capacitance, or resonant frequency. These properties
must change in a smooth, orderly, predictable, and reversible manner with applied
pressure. Unfortunately, response over the range may not be totally linear, but is very
nearly proportional to the applied pressure. This slight nonlinearity impacts calibration
of electronic gauges (to be discussed shortly).
There are three types of electronic gauge transducers that have been in common use in
production testing applications. The quartz gauge has largely replaced the strain and the
capacitance gauges.
Strain Gauge: Strain gauges employ the first common type of transducer. It was often
used in wireline formation testers, up through 1995. Two types, bonded foil and
sputtered, have been widely used in down-hole applications. A resistor pattern on an
insulator is bonded to or deposited directly onto a diaphragm that is exposed to applied
pressure. The resistor pattern changes resistance when the diaphragm undergoes a
displacement due to pressure.
The strain gauge provided fair accuracy, rugged construction, small temperature effects
and resistance to shock and vibration. However, its poor long-term stability, limited
temperature range, medium frequency response and low level output have made it
obsolete for pressure transient analysis applications.
Capacitance Gauge: A common transducer used for bottomhole pressure
measurement is the capacitance gauge. This gauge uses a capacitor with parallel plates
precisely gapped. As pressure is applied, displacement reduces plate separation, and
the capacitance changes. The advantages of the capacitance transducer are excellent
frequency response, low hysteresis, good linearity, and excellent stability and
repeatability. But it is highly sensitive to temperature variations and vibration.

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Vibrating Crystal Gauge: The third type of common transducer is the vibrating crystal.
Quartz or sapphire crystals are typically used, but quartz is the choice for most oilfield
applications. Quartz has excellent elastic properties, long-term stability, and is sensitive
to stress. When external stress is applied to the crystal, the resonant frequency of the
crystal shifts in proportion to the stress. Unfortunately, the resonant frequencies of
quartz crystals are also quite sensitive to temperature.
Therefore quartz gauges must be compensated for temperature effects. The standard
quartz gauge will use a calibration algorithm to reduce temperature effects. But the best
quartz gauges use direct temperature compensation. This is accomplished by adding
another identical quartz resonator exposed to the same temperature as the primary
pressure crystal, but kept in vacuum. The second crystal provides the reference to back
out temperature effects. The advantages of the vibrating quartz transducer are its
excellent accuracy, resolution, and long-term stability. The disadvantages are its
sensitivity to temperature and high cost. The compensated quartz crystal gauge has
only the disadvantage of relatively high cost.

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13.8.2 ERRORS IN PRESSURE MEASUREMENT

Errors in pressure measurements are rarely discussed in well test reports. Pressures
tend to be regarded as if they have no accuracy limitations. But this is never true for any
typ e o f p re ssu re g a u g e . E ve n if a g a u g e is ca lib ra te d p e rfe ctly a t n u m e ro u s p re ssu re
points, there will be an average error across the range of calibration. This is because of
th e n o n lin e a rity o f th e re sp o n se o f th e g a u g e s se nsor. The calibration is stored as a
p o lyn o m ia l b e st fit cu rve , w h ich ca n n o t e xa ctly re p re se n t p re ssu re a t e ve ry p o ssib le
pressure in the range. The Unigage CQG (compensated quartz gauge) pressure gauge
has a pressure accuracy of 1 to 2.5 psi. This is the absolute best accuracy for this
g a u g e in p e rfe ct ca lib ra tio n a n d o p e ra tin g co n d itio n .
The minimum error specified for the (uncompensated) Unigage Quartz gauge is 3.2 psi.
The error beyond that of the compensated gauge is due to the use of an algorithm for
temperature correction, rather than direct compensation with the second quartz crystal.
The Unigage H-Sapphire pressure gauge has a higher operating temperature limit of
375F, but more error at that range, 10 psi. Below 350F, the accuracy is 5 psi. It is
only used in very high temperature applications.
W e ve b e e n citin g e rro rs in p re ssu re m e a su re m e n t fo r a p e rfe ctly ca lib ra te d g a u g e .
Additional errors in pressure measurement will result from calibration mistakes, shock,
hysteresis from extreme pressure and temperature cycles, aging components, prolonged
service, and so forth. These are impossible to quantify, and can only be detected and
minimized by frequent calibration. Gauge errors accumulating due to expired calibration
or gauge wear and tea r a re n o t se rvice co m p a n ie s fa vo rite to p ic o f co n ve rsa tio n .
The service company may claim that these errors can be neglected because they may
be systematic, and the pressure trend is more important than the absolute value.
There is an element of truth to this, if use is subject to some very restricted conditions.
Three major ones are:
1. The same gauge that is used to measure initial pressure must be used for the
main flow and final buildup.
2. This gauge is not tripped in and out of the hole between the initial pressure and
the final buildup.
3. This gauge data is never, in any application, combined with data from another
gauge, be it BHP data from another test, wireline formation tester data, etc. to
reach an interpretation without mention of the probable errors compounded
between gauges (e.g., 5 to maximum of probably 15 psi).
Obviously these restrictions are rarely met or recognized, and are unacceptable for a
service costing $10K to $25K/day.

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So the best absolute value of the pressure measurement, and the accuracy of that
absolute value, needs to be known for the best analysis of a well test, and for its use in
other applications. Any pressure measurement, especially including pressure
measurements with wireline formation testers, should routinely specify the estimated
associated error and quote the calibration history.
Pressure gauges on wireline formation testers seem to be infrequently calibrated and put
through lots of rough treatment. They provide the good resolution required for pressure
gradient work, but their absolute accuracy for pressures is not as good as test gauges,
generally.
When pressure data from different gauges, perhaps different trips into the well bore, are
mixed, serious interpretation errors can occur, especially if the gauges are not in
well-calibrated condition. For example, making a pressure gradient plot by including
pressure(s) from a well test with pressure(s) from a wireline formation tester run is not
good practice. There could easily be a 10 to 15 psi difference from different gauges
reading the same pressure.
The same logic applies to why a serious attempt should be made to get the initial
pressure buildup and the main pressure buildup on the same (well-calibrated) gauge.
A n d w h y fo rm a tio n te ste r p re ssu re s sh o u ld n t b e u se d for initial pressure in a well test
interpretation.

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13.8.3 DEAD WEIGHT TESTERS AND CALIBRATION

When speaking of high quality accurate pressure data, one must be reminded that all
pressure measurement instruments, except for two types, measure pressure indirectly.
The two direct measurements are made with the dead weight tester and the manometer.
The manometer can only measure low pressures or low differences in pressure.
The dead weight tester is the mechanical embodiment of the definition of pressure,
Force/Area. A horizontal plate that can be loaded with an assortment of weights rests
atop a cylindrical piston of specified cross-sectional area. The total weight of this
a sse m b ly, in a kn o w n g ra vity fie ld , d ivid e d b y th e p isto n s cro ss se ctio n a l a re a , p rovides
the force per unit area, or pressure. The sliding piston is free to move in an absolutely
vertical cylinder, which forms a closed hydraulic chamber with the piston. The hydraulic
fluid in the chamber will be under a pressure equal to the weight of the piston divided by
the cross sectional area of the piston, any static friction between the piston and
cylinder.
To be accurate a deadweight tester must have very low friction between the piston and
the cylinder, and be in a stable, motionless environment, and the axis of the cylinder
must be absolutely vertical. Elaborate versions of the simple mechanism just described,
housed in controlled high temp environments, and employing methods to minimize
piston friction, are used to calibrate the most scientifically advanced pressure gauges,
regardless of type. This is the standard.
C a lib ra tio n o f S ch lu m b e rg e r g a u g e s o n d e a d w e ig h t te ste rs is d o n e p e rio d ica lly a t o n e
of 20 locations worldwide. Every gauge should come with a calibration document that
provides the calibration coefficients and other key information obtained during the
calibration procedure. The pressure calibration curve for the compensated quartz gauge
makes use of 16 coefficients for the fit of pressure versus sensor response.

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13.8.4 PRESSURE GAUGE SPECIFICATIONS AND

REQUIREMENTS

This will be a brief review of specifications for the downhole pressure gauges needed for
a well test:
Gauge resolution.
Gauge backup.
Battery options.
Gauge programming.
There will also be a more detailed discussion of surface readout of bottomhole pressure
systems and use of surface readout gauges. It must be mentioned that a successful test
requires good pressure gauges, calibrated, set up, and programmed appropriately by a
good, experienced gauge technician.

GAUGE RESOLUTION AND RANGE

The first step in specifying a pressure gauge for a planned well test is to determine the
required gauge resolution. To accomplish this, it is necessary to predict the pressure
response of the reservoir. For a buildup test, the slope of pressure-time data plotted on
semi-log paper is given.
A pressure gauge should be chosen with adequate sensitivity to detect the expected
pressure change during the buildup period. The high range of the pressure gauge must
be chosen to be higher than the maximum expected operating pressures. Stimulation,
well killing procedures, DST circulating and hydrostatic pressures are often substantially
higher than reservoir pressures. Allowing a pressure gauge to see pressures out of its
range may ruin the gauge, or at the minimum, its calibration.
The Schlumberger WTQR quartz gauge is widely used. This gauge is calibrated over
the range of 1000 to 16,000 psi and has a resolution of 0.01 psi. This resolution is
more than adequate for deepwater Dual Flow-Dual Shut-in Tests. This is not
accuracy, but resolution, which means it can detect and record a pressure change
as small as 0.01 psi.
GAUGE REDUNDANCY

Modern electronic gauges have high reliability in normal operating conditions.

Nonetheless, it is recommended that a minimum of three pressure gauges be run below
the bottomhole shut-in valve on well tests to provide backup and to verify gauge data.
This guideline applies to normal operating conditions of temperature, pressure, proximity
to perforating gun, and other shock exposures. Surface readout gauges (SRO) are not
considered to be the primary gauges and are not usually included in this count. More
gauges may be required if special pressure measurements are necessary, such as
annulus pressure or pressure inside and outside an inline sand screen.

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BATTERY OPTIONS

Verify that the Service Company is using batteries with a sufficiently long life and
adequate temperature rating for the planned well test. In deepwater wells, keep in mind
that the maximum recorded temperature (from W/L logs) may be as much as 20 to 35F
lower than the temperature seen in flow. This is dependent on water depth, total depth
and circulating history. As of 2002, the best batteries available for downhole gauges are
lithium batteries; they are good to 350F and will last an average of 27 days. Doubling up
on batteries can increase the useful recording life of the gauge.
PROGRAMMING THE SAMPLING FREQUENCY

The timing of most well test events is unpredictable. It is difficult to predict exactly how
long it will take to run the test string, space it out, pressure test it and get everything
ready to perforate and test. Furthermore, the duration of the flow and shut-in periods
may be adjusted during the test because of long cleanup times, well performance, the
need to stimulate, and other operational considerations. Programming the memory
pressure gauges prior to placing them in the test gauges is an important consideration in
designing a well test. Gauge programming involves setting the sampling rate (and
perhaps a series of time windows with different sampling rates) before putting the
gauges in the bundle carrier in the test string. The gauge technician will always ask the
test specialist or engineer for instructions on programming the gauges.
Fortunately electronic gauges have large memories. And well tests from floating rigs
are usually fairly short operations, requiring that the test string be in the hole an average
of six to ten days. What this means is that simple gauge programming will usually
be adequate.
Nonetheless, a number of options are available to vary the sampling rate to reduce the
number of non-useful data points, and to free more space in the memory chip for
denser data sampling over the region of interest. Furthermore, practically all gauges
w ill h a ve d e la ye d sta rt fe a tu re s. Ju st a s e ffe ctive a s d e la ye d sta rt a n d sa fe r is a
method that takes a pressure/temperature reading at very sparse intervals (say every 5
to 20 minutes).
For varying the sampling rate in the heart of test data collection, there are three methods
in use:
1. Data reduction algorithms reduce the amount of memory required to store the
data. An example is storing pressure differences from an automatically chosen
reference pressure.
2. S m a rt S a m p lin g sa m p le s ra p id ly when pressures are changing rapidly, and
slowly when pressures are stable. But this reduces gauge resolution, and
weights data collection most heavily on the drawdown. Improperly set, it can
easily skimp on data collection in a critical area, the late time region, which
re sp o n d s su b tly to re se rvo ir b o u n d a rie s, e tc. A lso , to b e sm a rt, it m u st u se
m o re b a tte ry p o w e r. O u tsm a rt S a m p lin g co m e s to m in d .

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3. And finally, manually setting time windows with a constant sampling rate within
each window. This method has no inherent flaws when used sparingly, but its
flexibility does tempt one to overwork the problem. For example, trying to guess
exactly when the main buildup will start, a high sample rate is specified to
capture the rapid rise in pressure to get dense d a ta fo r a p re tty p lo t. A ctu a lly,
the data during this momentary change of pressure levels is not used at all in the
pressure analysis. But the main disadvantage is that an otherwise harmless
electrical glitch in the gauge could cause a sampling window to be skipped. So
an unintended and inappropriate sampling rate window is used. If this happens,
the situation is definitely much worse than if the feature had not been used.
GAUGE PROGRAMMING GUIDELINES

Current electronic gauge memories can store 100,000 to 400,000 readings (one
pressure-temperature-time set). For example, a gauge with a memory capacity of
100,000 readings, programmed to make one reading every 10 seconds, has a life of
100,000 x 10 = 1,000,000 seconds or about 11.6 days. A recording time delay of 1.5
days would extend the total time under the rig floor to 13 days.
This may be a little longer than the average test string will be below the rig floor, but a
100% safety factor is usually advised. A uniform 15 to 20 seconds per sample with a 1.5
day delay should give an adequate safety factor and adequate data density. A total test
time span of about 19 to 24.5 days would be covered. Going to a gauge with a memory
capacity of 400,000 readings would permit a constant sampling interval of 5 seconds.
This is probably overkill for typical DFDS tests from floating rigs. But such capacities will
surely be standard in the near future.
Remember, total test duration includes all operations: RIH, space out, pressure testing,
perforation, cleanup, stimulation, flow/buildup and time to run in and pull out of the hole.
T h e o th e r fa cto r th a t m a y co m e in to p la y is b a tte ry life . T h is is a so fte r n u m b e r th a n
memory capacity, so battery life limits should not be pushed. If necessary, batteries can
usually be d o u b le d u p to e xte n d th e g a u g e s o p e ra tin g life tim e . A ve ry h ig h sa m p lin g
rate may unnecessarily reduce battery life.
Three bottomhole gauges are recommended for recording the primary BHP data
collection. All of the gauges can be programmed the same way, conservatively, to cover
the longest possible test. Or one or two of the gauges can be programmed with no or
different delays GIH. Delays should be conservatively short. It is usually advisable to
specify a very long sampling interval (2 to 5 minutes) inste a d o f a d e la y. Y o u d o n t w a n t
to risk being set and ready to perforate with the gauges in wait state.
The manual selection of sampling rate windows should be used sparingly. A maximum
of 2 to 3 windows are recommended, and the programming should consider the
consequences of a skipped window on data collection.

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13.8.5 GAUGE PLACEMENT

The gauge components (battery, memory, sensor, and pressure transmitting bellows)
are contained in sections of stainless steel housings, cylinders about 1.2 in. OD and
about 6 feet long made up.
BUNDLE CARRIERS

In TCP applications with retrievable packers, the BHP gauges are usually run in with the
test string on a full bore, in-line bundle carrier. The bundle carrier holds 4 gauges, which
are secured in deep cut scallops cut in the wall along the exterior length of the carrier.
Individual gauges can be ported to the interior or exterior. A typical fullbore bundle
carrier has a minimum OD of about 5.5 in. The bundle carrier is usually run below the
packer, with a shock sub between it and the TCP guns. If SRO is used, there will usually
be another special gauge carrier placed just above the packer, below the tester valve, to
carry the SRO gauges.
TAILPIPES OR STINGERS

With permanent packer applications in smaller holes, the bundle carrier may have to be
ru n a b o ve th e se a l a sse m b ly, a s it w o n t cle a r th e se a l b o re . It m ig h t b e a lo n g d ista n ce
above the perforations. But in these small to medium hole applications with permanent
packers, the gauges can be run inside tail pipes or stingers. The gauges are stacked
end to end in these instances. The tailpipes are usually blanked off (preferably with
weep holes), and the gauges are protected (but not isolated) from the flowstream.
There are methods to isolate gauges carried in this manner from perforation shock.
This method is also commonly used with excluder type completions.
It is possible to latch the gauges into nipples in the tailpipe so that they can be pulled to
surface and replaced by wireline. This is one area where the tailpipe method of running
gauges has an advantage over the bundle carrier method. But the full bundle carrier
does permit wireline activities without pulling anything. Remember, the closer to the
perforations the better the chance for good pressure data.

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13.8.6 SURFACE READOUT GAUGES

Because of the high rig costs in deepwater testing environments, real-time monitoring of
bottom-hole pressure is often justified. Specialized, surface readout (SRO) equipment is
available for this purpose. It is specialized mainly because it must somehow transmit
bottomhole pressures past a shut tester valve.
SRO of gauge data can be invaluable if operational problems occur as it provides
diagnostic pressure data without disturbing the test string. It also allows real time
analysis to adjust flow and buildup periods to meet site-specific objectives. For example,
to lengthen the buildup in tight or layered zones or to shorten the buildup if the data
trend shows infinite reservoir behavior, meaning that the data trend has a constant
Horner slope and extrapolates exactly to a good initial pressure on the same gauge. The
advantages must be weighed against the additional operational time involved with
rigging up and running these gauges. A wireline lubricator has to be used on top of the
flowhead.
BASIC TYPES OF SRO

There are two types of SRO systems compatible with bottomhole shut-in valves in wide
u se to d a y T h e m o st w id e ly e m p lo ye d is S ch lu m b e rg e rs D a ta la tch syste m , w h ich u se s a
porting system to directly transmit bottomhole pressure past the PCT (or IRDV) to
gauges above. M e tro l T e ch n o lo g ys T .R .I.C .S . S R O syste m employs acoustic data
transmission across the shut-in va lve , u sin g a ta lkin g g a u g e b e lo w th e va lve , a n d a
liste n in g g a u g e a b o ve .
DATA-LATCH

S ch lu m b e rg e rs D a ta -Latch inductive readout system combines the advantages of

memory recording gauges with real-time surface readout (SRO) of bottomhole pressure
data. When used, it is normally in a test string with the Schlumberger PCT or IRDV APO
tester valve. It comprises three major sections:
1. The pressure gauge section.
2. The LINC housing and coupler section (defined below).
3. The LINC running and pickup tool.
The pressure gauge section is a special fullbore gauge bundle carrier called the DST
gauge adapter (DGA). In the SRO application, the DGA sits above the PCT or the IRDV,
but is specially ported so that its gauge ports are in communication with tubing pressure
above and below the tester valve, as well annulus pressure. It holds up to four state of
the art quartz pressure gauges, su ch a s w e ve ju st d iscu sse d , w h ich ca n b e p o rte d to
the BHP, the annulus, or tubing above the PCT. The gauges can be selectively
downloaded and/or read in real time in the SRO mode.
The LINC housing and coupler section rests atop the DGA and contains the electronics
re q u ire d to se le ct, re p ro g ra m a n d d o w n lo a d e a ch g a u g e s m e m o ry, a n d to m o n ito r th e
gauges in real time. It converts downloaded data into an inductive current that is read by
the LINC running and pickup tool.

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The LINC running and pickup tool is run in on electric line when:
1. SRO data is required in real time.
2. It is necessary to download the memory gauges.
3. It is necessary to reprogram the memory gauges.
The LINC pickup tool reads the induction signal put out by the downhole LINC coupler.
It requires no hydraulic or electrical wet-connection. The pickup tool is usually
mechanically latched into the LINC housing and coupler section, though this is
not a requirement.
Data-Latch is fullbore straight-through open (2.25 in. ID) when the LINC pickup tool is
not being used. When the LINC pickup tool is in the well, there is no fullbore opening,
but the cross-sectional area for flow is not reduced. Exxon has used this system, in most
of its deepwater exploration well tests in the GOM since its debut in 1989. It has been
very reliable.
Normally, the LINC pickup tool is not placed in the well when flowing. But when the well
is shut-in, LINC is run, and pressure gauge data from the prior flow period(s) are
dumped from the gauge memories, and the real time buildup data is transmitted.
In a recent GOM oilwell test, the well was flowed at about 4800 STB/D with the LINC
pickup tool latched into the string. The only effect was that the wireline noticeably
increased the frictional pressure drop in the string.
Data-Latch requires a lubricator and one or two additional personnel and is quite
expensive. It could save some rig time with diagnostic pressure information in instances
of plugging, damaged completion, uncertainty if guns fired, etc. More likely it will improve
the quality of the test by facilitating real time computer analysis of the pressure data.
However, the DGA-mounted gauges may be up to several hundred feet above the
completion. It is recommended, therefore, that additional memory gauges be placed
much lower in the test string, as close to the completion as possible. The final analysis
of the data would normally be done using data from the lowest gauges in the string,
other factors (such as gauge quality) being equal.
METROL TECHNOLOGY T.R.I.C.S.

This is an acoustic transmission system, which uses transmitter-memory gauges

positioned below the shut-in valve and a receiver-gauge positioned above. Data is
transmitted acoustically across the shut-in valve. Another receiver-gauge is lowered on
mono-conductor line that can receive data acoustically from the receiver-gauge in the
test string, and send it to surface in real time. If the receiver-gauge is RIH on slickline,
it can unload data from the downhole gauge, and bring it to surface for dumping when
it is POOH.
The acoustic system is compatible with any tester valve, because no electronic,
induction or hydraulic paths are required between the special inline pressure gauges and
the pickup unit, which is also a special pressure gauge. It can be run with its own
wireline shut-in tool, D.H.S.I.T., discussed in the section on the production-type test
string, or with those discussed in this section (PCT, IRDV, LPR-N, etc.). In the APO test
string application, the inline gauges are carried in a fullbore inline bundle carrier up to
300 ft beneath the shut-in tool.

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HALLIBURTON SRO-E

H a llib u rto n s S R O -E surface pressure readout system is much less expensive and
le ss co m p lica te d th a n S ch lu m b e rg e rs D a ta -Latch SRO system. The SRO-E system
comprises a pressure gauge lowered via electric line and latched into a sleeved
hydraulic connection housed on top of the LPR-N valve.
Unfortunately, the SRO-E has several disadvantages inherent in its design:
The gauge and wireline must be in the hole to get data.
Only that pressure data generated while the complete system is in the hole is
captured.
No previously recorded data (from another gauge) can be accessed. Thus, to get
flowing bottomhole pressure data for skin damage analysis, the SRO electric line
and gauge must be in the hole prior to end of the flow period.
HALLIBURTON RT-91

H a llib u rto n s R T -91 surface pressure readout system did not see commercial use before
it was withdrawn from the market. The RT-91 was very similar to the Data-Latch system,
so much so that anticipated legal and patent problems contributed to its demise. This
tool is mentioned for completeness and to offer an explanation as to why Halliburton
offers no state of the art SRO system of its own.

13.8.7 INFLUENCE OF TIDES ON BOTTOM HOLE PRESSURE

MEASUREMENTS

The effect of tidal cycles can be seen in the latter stages of the PBU of many offshore
tests. Even when reservoirs are abnormally pressured, influences from tidal cycles are
observed in the latter stages of the buildup data, although at greatly reduced
magnitudes. This means that the added hydrostatic pressure due to sea height
increase is being transmitted down to reservoir depth by slight flexure of the rock.
Tidal fluctuations are well behaved and recognizable on the buildup. But they need to be
removed from the pressure data to properly analyze and interpret the late time buildup
data. Using actual tidal data collected in the area while testing makes this a
straightforward and reliable process. The normal procedure to get the basic tidal data is
to affix an electronic pressure gauge to the riser somewhere below the slip joint. The
gauge will record hydrostatic pressure on it, and the changes in this value with time will
reflect the tidal influence.

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13.8.8 VOLUMETRIC FLOW RATE MEASUREMENT OF GASES

Orifice meters have traditionally been used for determining gas flow rates in most
applications where high gas rates must be measured. If conditions are controlled, the
meter, manometer runs, and orifice plate areas kept free of liquids or trash, the
measurements are very accurate if the correction factors are applied. Gas is measured
for sales at the commercial distribution level by orifice meters. For well testing, gas
orifice meters are the only practical way to get accurate gas rate measurements.
The basic measurement in an orifice meter is the pressure drop (differential pressure)
across a constriction (orifice) in the meter run. A typical meter system consists of a
concentric, square-edged orifice plate, a fitting that holds the orifice plate centered in the
meter run, taps in the meter run for differential pressure measurement and a pressure
measuring/recording device.
For well testing applications, the most common of the plate-type orifices are thin sharp-
edged concentric orifice plates. The fitting that holds the orifice plate and provides
p re ssu re ta p lo ca tio n s is kn o w n a s a se n io r o rifice fittin g . T h is a cts like a
decompression chamber and allows the orifice plate to be changed under pressure, with
only a momentary flow disruption. The plate can be cranked into the upper chamber,
which is external and sealed from the meter run by a sliding valve. This capability for
ch a n g in g th e o rifice p la te o n -the-fly is im p o rta n t in w e ll te stin g a p p lica tio n s b e ca u se th e
test gas rate is not known in advance. Therefore, the plate orifice size will need to be
ch a n g e d to ke e p th e d iffe re n tia l p re ssu re in th e m e te rs m o st a ccu ra te w o rkin g ra n g e .
There are two basic types of pressure taps for sensing differential pressure the flange
tap and the pipe tap, and they are located in different positions upstream and
downstream of the orifice plate. It is important to know what type of pressure tap is used,
because that will dictate the correction factor used for taps.
The orifice meter is generally equipped with a two-pen recorder for continuous recording
of both static and differential pressure on a circular chart. The paper chart has a
pressure scale on it to enable direct reading of the measured pressures. Static pressure
is generally measured in psia with a Bourdon tube that moves the pen on the chart.
Differential pressure is measured in inches of water using a bellows meter. Any change
of differential pressure between two chambers in the bellows causes a movement of the
bellows to a new position of equilibrium, which moves the pen-arm shaft that records the
differential pressure on a chart. These pressures, along with meter temperature, will also
be recorded with transducers if a computerized data acquisition system is used.
The gas flow rate across an orifice plate in well testing applications is calculated using a
short form of the equation used for commercial gas sales. The short form includes four
correction factors. The long commercial form includes eleven correction factors.
These seven additional terms entail corrections of less than one percent and are
neglected in testing applications.
Without getting into the correction factors and absolute values, the gas flow rate, at
standard conditions, is proportional to the square root of (differential pressure * absolute
pressure/gas gravity). The gas gravity should be available from field lab measurements.
If not, a temporary value of gas gravity, very well documented, must be used for the
calculations. The rates will have to be adjusted later when the gas gravity is available.

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GAS ORIFICE METER CHECKPOINTS

Prior to any production testing on the rig, all orifice plates should be examined for
obvious defects. The plate should be flat, and the edge of the orifice edge should be
clean, without nicks. The static and differential pressure recorders should be checked
and calibrated against a precision pressure gauge. An orifice plate should be installed
that will result in a differential between 40% and 80% of full scale during operation, to get
recordings into the range with the best sensitivity. This should be done only after the
rates have stabilized. The charts can be examined visually (i.e., to ensure that there are
no gaps in data, that the pen is tracing a measurable deflection, etc.) to verify that the
correct orifice size is being used. In making rate calculations, the differential and static
values should be averaged over the period between calculations.
Gas metering problems can be caused by:
Liquid carryover to the orifice plate and tap connections.
Trash and obstructions in the orifice run, plate, taps and lines.
Liquid accumulation in the bottom of a horizontal pipe run, in pipe sags or in the
meter body.
Flow disturbances (pulsing and slugging) caused by rig motion, insufficient
provision for flow stabilization or by irregularities in the pipe.
Differences or changes in prevailing operating conditions from those used for
calculation purposes.
Orifice plate eroded or not sized correctly.
Bellows out of calibration.
Incorrect zero adjustment of the meter.
Bent pen on the recording chart.
Wrong factors used in the orifice equation, Especially Gas Gravity.
Orifice plate size not as documented.
Formation of hydrates in the meter piping or body.
Sour gas.

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13.8.9 VOLUMETRIC FLOW RATE MEASUREMENT

OF LIQUIDS

One would think that liquid rate measurements are straightforward and accurate. The
most direct way to measure liquid rates is by taking liquid level measurements in a
calibrated low-pressure surge tank. In some cases, this is possible, and when it is, it is
preferred. It is extra work for the surface equipment and not highly welcomed. When the
oil is produced to a barge, low-pressure surge tanks are alternately in the flow stream
and essentially continuous strapping of the tanks is recommended.
However, when the oil is being pumped to burners, the low-pressure surge tanks are
not normally in the flow stream circuit because the burners require high-pressure oil to
operate efficiently. The surge tanks are used to calibrate the oil flow meter on the
separator, and the calibrated flow meter readings are used to calculate the oil rate.
Water and oil rates flowing through a separator are typically measured with turbine
meters, and much less frequently, with positive displacement meters. The rotary vane
type of positive displacement flow meter is usually a special order item in well testing
separators. They have fairly tight clearances and do not hold up well to well test
applications, where debris may find its way to the separator.
Turbine meters are used to measure liquid flow rates. The turbine meter measures flow
rate (instantaneous or cumulative) by converting liquid velocity into rotational velocity.
A turbine or propeller-like device rotates on a shaft. The speed of the turbine is
proportional to the linear velocity or flow rate of the fluid moving through the meter.
The rotation of the turbine is counted and accumulated to give the cumulative flow rate.
Normally there are two liquid flowmeter legs manifolded on the oil line. The 1 in. size is
typically suited for rates of 200 to 2000 BOPD. The 3 in. meter can handle rates in the
2000 to 25,000 BOPD range.
Turbine meters have a stated accuracy of 1% of reading with 0.05% flow rate
repeatability. Rangeability is generally 10:1. But these numbers are for ideal conditions,
with the meter carefully calibrated under the exact application conditions. When turbine
type flowmeters are installed in industrial applications, basic requirements are stipulated.
For example, strainers, vapor traps and dependable pressure and flow controllers must
be in place.

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Continuous flow is said to be preferred over intermittent dumping. The latter is more
common in well test applications. If all these factors are considered, plus a flow
stream that may contain debris, spent acid, etc., we can begin to understand why it is
rare to see a flowmeter calibration that hold constant to 5%. In fact, changes of 15%
have been witnessed in tests while flow conditions were apparently lined out and
constant. BHP, WHP and gas rate were constant, but liquid rate as per the flowmeter
jumped 15%.
It is important to realize that in well testing, the turbine flowmeter on the oil leg should be
used only as an indicator of flow rate if at all possible. Tank straps should be relied on
for volume calculations. If this is not possible (e.g., high pressure oil supply required for
burners), then the flowmeter should be calibrated at actual separator main flow
conditions several times during the main flow period. When the oil is burned, there
is no final validation available for meter measured oil rates.
W h e n su rg e ta n k stra p s a re m a d e o n p ro d u ce d o il, th e re su ltin g m e te r fa cto r is a ctu a lly
a lumped meter and shrinkage factor. This should be mutually understood so there is no
inadvertent double dipping with the shrinkage part of the overall factor. This sometimes
happens because the well-testing service company data sheets and computer program
break out the overall meter factor into a mechanical and a shrinkage component.
A mechanical component can be derived by calibrating the meter with water
(overall = mechanical because there is no water shrinkage). But all flowmeter references
say the mechanical factor component changes with the fluid and the conditions. So there
is really no way to measure the applicable mechanical factor without the shrinkage,
without a surge tank that will operate at separator conditions.
Even so, before the well test starts, both the oil and water meters on the separator
should be given a preliminary calibration. Flowing a known volume of water through both
meters at a steady rate is the technique used. This procedure will identify major metering
problems before the test starts. A meter will have to be replaced if it is found grossly
inaccurate in this calibration procedure.

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13.8.10 WELLSITE CHECKLIST FOR GAS AND LIQUID METERS

The following checklist should be followed for the best wellsite metering of liquids
and gas.
1. Verify that meters are clean and functioning correctly, and that the orifice place
differential pressure bellows are calibrated.
2. Document and validate all factors used by service companies in their onsite
calculations. The factors do not have to be the final numbers (e.g., gas gravity
may not be available) but they must always be documented.
3. There must be clear agreement on what the liquid meter factor means and
how to calculate separator oil rates for the correct PVT recombination ratio.
Is sh rin ka g e in clu d e d in a co m p o site fa cto r, o r is o n ly a tru e m e ch a n ica l fa cto r
reported? There should be no double dipping on shrinkage.
4. Require and observe strapping of tanks.
5. Always check calculations if rates take an unexplained jump or if
unusually steady.
6. Observe the shrinkage measurement process and verify that all pressure
and temperature measurements are taken at the correct locations.
7. Furnish any subsequent adjustments to rates to the PVT laboratory, and in some
instances, a shrinkage tester is installed downstream of the separator to correct
oil rates (measured at separator conditions) to stock tank (14.7 psia, 6F)
conditions. Oil is measured through a flow meter at separator pressure and
temperature. This oil rate is not at stock tank conditions, as some gas will evolve
when the oil passes from the separator to the surge tank and/or gauge tank
(described below). The shrinkage tester isolates a known volume of separator oil
and then allows the oil to shrink at atmospheric conditions outside the separator.
Because of the small volume of the shrinkage tester, it is not recommended to
calculate shrinkage factor in this manner. The recommended method is to flow
the oil to an atmospheric test tank and correlate the measured volume in the tank
with the separator oil meter reading. The correlation (known variously as the
meter factor or shrinkage factor) then incorporates both a meter factor and oil
volume correction.

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SHRINKAGE FACTOR

Determine the shrinkage factor as follows:

1. Measure the level in the surge tank five minutes before beginning calibration.
2. Take the separator oil meter reading and carry out Step 3 simultaneously.
3. Operate the tank bypass valves to direct oil to the surge tank.
4. Let oil flow into the tank. Allow sufficient volume to reduce the significance of
liquid height measurement errors.
5. At the exact end time, take the separator oil meter reading and carry out Step 6.
6. Operate the tank bypass valves to direct oil to temporary storage holding tank.
7. Wait until the surface of the liquid in the atmospheric tank is calm and there
is no froth.
8. Take tank level reading and temperature. If necessary, take a sample to
measure gravity.
This procedure should be repeated regularly (at least twice a day or once every four to
eight hours), and at every choke change, to get a meter or shrinkage factor and to see if
it is changing.
Changing meter or shrinkage factor at a constant choke size will alert the well test
engineer to potential problems such as foaming or a low separator level, or just
screwed up turbine meters.

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13.8.11 COMPUTERIZED ACQUISITION OF SURFACE DATA

System and Types of Measurements Acquired

Service companies now use computerized data acquisition systems to sense, transmit,
and record all pertinent surface flowstream parameters, as shown in Figure 13.21.

Figure 13.21 - Surface Testing Acquisition Network

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These would include the following measurements at the minimum:

Liquid turbine (or positive displacement) meter temperature, pressure,
and revolution counts with time.
Gas orifice meter pressure, temperature, and differential pressure.
Flow head temperature and pressure.
Casing surface pressure.
Separator temperature and pressure.
Downstream choke temperature and pressure.

Optional but helpful measurements would include:

Upstream choke temperature and pressure.
Heater outlet pressure and temperature.
Surge tank temperature and pressure.
Oil pressure to burners.

The data gathered from sensors mounted at measurement points along the flow stream
is collected through several interfaces and is routed to co m m a n d ce n tra l. T h is is a
controlled environment (positive pressure, w/ AC/Heat) data acquisition cabin with office
workspace, several computers and plotter/printers. Here the raw data can be displayed
real time on monitors for validation and well test control. Note: that The SRO system
usually uses the real time display of its own, usually in the wireline logging unit.
The cabin may also house a separate controlled environment module, which is used as
a field laboratory, to be discussed shortly.
COMPUTER CALCULATIONS, REPORTS, AND SPREADSHEETS

Gas rate calculations are made from the orifice meter data on the separator, employing
the five most significant orifice meter correction factors. Gas gravity drives one of the
more important correction factors, but it may not be available at the time. So an estimate
must be used, with adjustments to be made later. This adjustment can be easily handled
later, but only if the original estimate used in the calculations is well documented.
Liquid flowmeter rates are calculated from raw turbine meter data and manually
determined correction factors.
Even though a computerized acquisition system is used, some data must be determined
manually and entered into the system. Manually entered data will include physical
property data (e.g. gas gravity) and calibration data.
Excel -typ e co m p u te r g e n e ra te d sp re a d sh e e ts, ve ry sim ila r to th e D se rie s o f h a rd
copy forms used by ExxonMobil in past years, are used to report the surface data. The
data is reported in three stages of preparation once full measurements begin after the
flow stream is routed through the separator in the main flow period:
1. Raw data.
2. Intermediate results.
3. Final numbers for clie n t co n su m p tio n , in clu d in g flo w ra te s in sta n d a rd u n its.

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These sheets will contain data displayed at time intervals normally ranging from
15 minutes to hourly, depending on length into the main flow and its stability. Field lab
results will be included in the display that includes water chlorides and sp.gr., oil API
gravity, gas gravity (actual or temporary values used in meter calculations), and gas H2S
and CO2 content.
At the beginning of the main flow, during cleanup, flow rates are not normally available
b e ca u se th e se p a ra to r is b yp a sse d . A se p a ra te sp re a d sh e e t fo rm ca lle d th e cle a n u p
sh e e t is u se d to d isp la y d a ta . It w ill re co rd te m p e ra tu re s a n d p re ssu re s a lo n g th e flo w
path, and a cumulative volume of liquids produced, if this is available for surge tank or
gauge tank measurements, or (last resort, estimated from P across the choke).
The importance of the information on the cleanup sheet is that it is used to track water
and cushion volumes and properties (ppg, chlorides) and gas content (especially H2S
and CO2). Most of this information is recorded manually from field personnel tally books
o r o n E xxo n M o b il typ e D fo rm s fro m o b se rva tio n s a n d fie ld la b re su lts, a n d th e
computer-produced cleanup sheet is mainly for the records. It typically includes no
calculations.
T h e re is a n o th e r ve ry im p o rta n t e ve n t o r ch ro n o lo g ica l re co rd ke p t o f a ll sig n ifica n t
events during the overall test period, from test personnel arrival on deck to departure.
This record is kept on the computer data acquisition system, but all entries are manual.
E xxo n M o b il p e rso n n e l a re u rg e d to ke e p th e ir o w n te st d ia rie s, b u t sh o u ld a lso h e lp
the service company with suggested entries or times of events as appropriate.

13.8.12 GAS & FLUID SAMPLING

There are several ways to categorize the types of sampling of well test fluids:
What is sampled.
Where it is sampled.
How it is sampled.
The purpose of the sample.

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PURPOSES OF SAMPLING

W e w ill sta rt a t th e e n d o f th e list a n d w o rk fo rw a rd . W h a t is th e p u rp o se o f th e

sa m p le ? is a good place to start. There are two basic uses of sampling in well testing:
1. A basic use is samples used by test personnel to check for hazardous effluents,
monitor the progress of the test, and diagnose any problems or unexpected
results. We call these fie ld sa m p le s b e ca u se th e y a re a n a lyze d in th e fie ld .
Analysis will include produced water properties, water cuts, oil gravities, toxic gas
components, and gas gravity. Field samples may also be required of the
completion and cushion fluids. If a test progresses normally to a successful
conclusion, field sample results are normally only of historical interest, except
perhaps to the test specialist.
2. The second basic use is to obtain samples for offsite laboratory analysis for
specific properties. Within this broad category are several types of samples but
the main type is called pressure-volume-temperature (PVT). This describes the
parameters which are controlled in several types of studies at reservoir
conditions. This type of sample must usually be taken under very specific
conditions, which restrict the methods and sampling locations. In contrast to field
samples, the results of lab studies on properly taken lab samples will be used by
reservoir, production and facility design engineers for many years.
FIELD SAMPLES

Liquid field samples are usually taken downstream of the choke manifold, through a
needle valve for fine control. At this point in the flow stream, the shearing forces
encountered passing through the choke will mix oil and water components. The liquid
mixture is decanted into a centrifuge test tube, where it is heated and spun in a
centrifuge to separate the oil and water phases. Water cut is noted, and the water is
analyzed for chlorides and other components by pre-arrangement. The mud engineer or
mud logger, in addition to the test service company, can provide this analysis. Oil
analysis in the field is usually minimal; API gravity is usually sufficient.
Gas field samples can be taken into an evacuated or purged cylinder or balloon for
chromatographic analysis. For toxic gas detection by Draeger or sniffer tube type
apparatus, the best results are obtained by using a plastic soft drink or milk bottle to
catch a consistent pre-sample for Draeger tube use.

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OFFSITE LABORATORY SAMPLES

These samples fall into two broad categories. The first is PVT quality samples, which are
the highest quality, taken under carefully controlled and recorded conditions. These
strin g e n t co n d itio n s a re n e ce ssa ry if th e se sa m p le s a re to b e u se d a s re se rvo ir
representative sa m p le s in P V T la b o ra to ry stu d ie s.
PVT Samples Taken at Surface Separator: PVT samples must be taken under
single-phase conditions. Since well flow streams, at least at the surface, are usually
multi-phase, surface PVT samples must be taken at the separator. The samples should
be taken at stable separator conditions when both oil and gas rates can be measured
accurately. Oil samples are taken from the oil outlet line of the separator, into 600 to
1200 cc evacuated sample cylinders. The sampling flow line is designed to sample
directly off the oil flow stream, with a minimum of dead space. The throttling of the
sample stream should take place as close to the sample bottle as possible. The sample
should be taken at a controlled, uniform slow rate so there is no flashing upstream of the
throttling, filling the cylinder over a 10 20 min. period.
Gas samples are taken from sampling ports on the gas outlet line of the separator.
Gas sample bottles should be evacuated, but purging with gas may be an acceptable
second choice if there is no liquid carry-over into the gas outlet line. The sampling port
should be arranged so as to minimize picking up liquid carry-over. If the separator
temperature is greater than ambient temperature, it may be necessary to heat the
sampling line to avoid condensation in the line and non-representative gas samples.
Gas sample cylinders come in 10 to 20 liter sizes. Enough gas sample must be taken to
recombine with the oil sample to restore it to reservoir composition. If the GOR is
high and the separator pressure is low, several gas samples may be required for
recombination with one oil sample.
Determining the recombination parameters for separator samples is crucial to getting
PVT quality lab samples. The relative rates of oil and gas must be known at the time of
sampling, and the parameters (shrinkage factors) for converting these rates to rates at
separator conditions must be supplied to the PVT lab with the samples. This has been
discussed at the end of the Liquid Rate Measurement section.
PVT Samples Taken at the Bottom of the Well: There is another location where the
flow stream may be single phase and PVT sampling can be done. That is near the
bottom of the well, just above the completion.
Bottomhole sampling is normally used only to sample under-saturated oil reservoirs.
It is never used for gas condensate reservoirs. The bottomhole sampling tool (or a linked
string of tools) is run in the hole on slickline or wireline, (so a wireline BOP and lubricator
is required) or can be run with the test string (operated by annulus pressure). An SRO
pressure and temperature gauge may be added to the bottomhole sampler string if it is
run in on wireline.
When the samplers are triggered (by a timer if on slickline), a pressure-balanced,
metered piston is withdrawn to slowly sample from the flow stream at very low-pressure
drawdown. This is to avoid flashing additional gas off in the sampling process, and thus
getting an unrepresentative sample. Once the sample is taken, a high backpressure is
p la ce d o n th e sa m p le ch a m b e r p isto n to ke e p th e sa m p le in m o n o -p h a sic co n d itio n .

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Sampling is normally done after the well is cleaned up, but before the well is drawn down
below its saturation pressure. Sometimes this is not possible if the well is initially near its
saturation pressure, and it must be drawn down below the buBble point to clean it up. In
this case it is best to employ the bottom hole sampler in the cleaned up well after it has
been shut-in for a period of several days.
Immediately prior to bottomhole sampling, the well is flowed at a very low drawdown and
rate for several hours. Hopefully, the sampler will see oil at its original condition of
saturation. Remember that the bottom hole sampler must be in a single-phase
environment if the samples are to be used for PVT studies.
A major advantage of bottom hole samples is that they require no recombination, and
better yet, no recombination recipe th e sa m p le s a re tra n sfe rre d to th e la b s P V T
equipment as is.

13.8.13 FIELD LABORATORY

The field lab may be contained within the Data Acquisition Lab structure, but as a
separate module. It will have a controlled environment (positive pressure, with AC/Heat)
with several stainless steel workbenches and sinks. The field lab will contain the
equipment to perform basic analysis of the formation, cushion and completion fluids.
These properties include gas and liquid specific gravities, H2S and CO2 content of
gases, water cuts, BS&W, water salinity, etc. A centrifuge to speed oil-water separation
is always supplied.
Gas chromatography capability is not standard in service company field labs, but is
available through the mud loggers. However, the lab should house an instrument that
measures gas gravity from the separator outlet on a semi-continuous online basis.
This instrument is generically known as the Ranarex but it may be of another
manufacturer. Lab fluid analysis instruments, kits and other tools will vary depending
on local requirements. The default equipment may not always be adequate, so th e la b s
capabilities need to be verified in the planning stage, and again when the lab module
arrives at the well.

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13.9 FLARE, STORE, AND DISPOSAL EQUIPMENT

13.9.1 INTRODUCTION

Only the largest exploration drilling rigs can accommodate the tankage required to store
the produced liquids from the typical oil or rich gas-condensate well test. Some of the
newest drillships have dedicated onboard tankage for up to 100,000 Bbls of test fluid
storage. As a practical limit on older/smaller floating rigs, such onboard tankage would
be limited to about 500 to 1000 barrels, due to deck space, and perhaps weight limits.
Special arrangements could perhaps be made for more storage, but capacities would
still limit the typical test length for a productive well.
Furthermore, even if sufficient storage were possible, safety considerations would not
fa vo r th e sto ra g e o f th e la rg e a m o u n ts o f live cru d e o r co n d e n sa te (e .g ., 1 0 K to 3 0 K
barrels) in temporary tankage on the rig. A specially designed venting system, at the
minimum, would be required. Note: There are special purpose vessels with adequate
crude stabilization facilities, and built-in tankage with closed venting system, but such
systems are only available on a few of the newest drilling rigs. So, the decision for oil
disposal comes down to two possibilities - either burn it, or offload it to a
storage/transport vessel.

13.9.2 OIL DISPOSAL OFFSHORE USA

In the GOM (and other offshore U.S. areas) there is no practical leeway for a decision -
oil cannot be burned. MMS regulations prior to 1996 allowed burning oil, in theory, as
lo n g a s th e re w a s n o sh e e n w h a tso e ve r visib le o n th e w a te rs su rfa ce . A s a p ra ctica l
matter, this meant only gas condensate and very light oils could be burned with any
confidence, and very carefully at that. Current MMS regulations do not allow burning of
liq u id h yd ro ca rb o n s u n le ss th e a m o u n ts to b e b u rn e d w o u ld b e m in im a l o r th a t th e
alternatives to burning are infeasible or pose a significant risk to offshore personnel or
th e e n viro n m e n t. A p p lica tio n s fo r e xce p tio n s u n d e r th e in fe a sib le o r sig n ifica n t risk to
p e rso n n e l o r e n viro n m e n t cla u se h a ve b e e n su b m itte d a n d re je cte d . T h u s, in e ffe ct,
the current MMS regulations forbid premeditated burning of liquid hydrocarbons.
Burning oil or condensate is permitted only in emergencies.
Consequently, since 1988, Exxon and operating partners have employed barges to take
the oil produced during well tests from floating rigs. Heretofore, these have been
anchored (moored) rigs.
Before proceeding to discuss barging and burning separately, it should be noted that
both methods of disposal are subject to unexpected disruptions. Thus, some on-board
tankage should be kept in reserve to take the production necessary to keep the well
flowing at a stable rate if brief upsets occur with the burners, or the barge has a
temporary problem.

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13.9.3 OIL BURNER HEADS

Oil burners are used to dispose of produced oil during well tests in most other parts of
the world. Recent technical advances have been made towards developing clean and
efficient burner nozzles for most but the heaviest crude oils. Figure 13.22 shows
S ch lu m b e rgNozzle
e rs E ve rG re e n b u rn e r h e a d . M o st se rvice co m p a n ie s n o w g u a ra n te e a
cle a n b u rn ca p a b ility o ve r a sp e cifie d flo w ra te ra n g e w ith m in im a l fa llo u t.

Pilot
Ignito
r

Propane line

Oil inlet
Figure 13.22 - S chlum bergers E verG reen B urner H ead

In practice, however, it is difficult to obtain a clean and uninterrupted burn on medium to

heavy oil (say 16 to 30API) over the entire length of a flow test without a small amount
of dropout and sheening. It has been done with gas condensate, but this volatile oil
needs little or no help to burn completely. Rathole debris, mud, sand, heavy paraffins or
heavy completion fluid emulsions will cause intermittent fallout problems. This is another
reason some auxiliary storage is necessary to store the poorly burned effluents during
cleanup.
High efficiency burners require compressed air and high flowline supply pressure to
shear and atomize the oil into tiny droplets to make even the heavier oils more amenable
to burning. High-efficiency burners require large volumes of air (0.66 scf/min per BOPD,
or 1000 scf/min per 1500 BOPD) supplied at 400 to 500 psi. Onboard air compression
capacity is usually the limiting factor in clean burner capacity. Typically five 1200 scf/m
air compressors are required to burn 9000 BOPD.

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Air compressors are additional critical pieces of equipment in the oil burning system, and
should have some backup. If a compressor goes down, there may be a very limited
amount of time (i.e., backup storage) to get the burners back to clean burn status.
Furthermore, if sufficient flow stream pressure (about 350 to 450 psi) is not available at
the separator outlet for efficient burning, then transfer pumps will need to be used to
boost the pressure to the nozzles. Note: When oil is burned, the normal flow path is
straight from the process separator to take advantage of the higher pressure and more
dissolved gas in the oil, both of which enhance burning.
Two burners are normally used for offshore tests to allow continuous testing, regardless
of wind direction, or for backup if wind is neutral. A valved manifold allows selection of
either port or starboard burners on the fly.
Burner capacities up to 20,000 STB/D can be achieved through stacking of multi-nozzled
burner heads. The maximum capacity for the single head 12-nozzle burner shown in
Figure 13.22 is 12,000 BOPD. These are maximum physical throughput capacities,
irrespective of the surroundings being able to handle resulting radiant heat loads. Recall
that about 8000 scf/min of air compression would be required to burn 12,000 BOPD.
Where oil flow is insufficient for efficient atomization and combustion, the number of
burning heads or individual nozzles can be reduced. The supply manifolds permit this
flexibility.
If the backpressure at the burner is too high for the separator to operate properly, larger
piping could be used, additional burner heads could be used, the separator control
pressure could be raised, or the transfer pumps could be used. In some instances, if all
these measures fail, then the well needs to be choked back accordingly. This is a last
resort, of course.

13.9.4 BURNER BOOMS

Burner booms are the extension arms and platforms for the burners, designed to keep
the burners well away from the rig, but secure and accessible. They comprise two or
three sections pinned together and supported by wire rope cables attached to a
stationary kingpost, which is rigidly attached to the deck. The booms have walkways for
access to the burner head, and carry a bundle of piping to supply produced oil and gas
for burning, compressed air line, pilot flare fuel, and water for spray shields and/or for
injecting into the flame for cleaner combustion.
Booms typically come in lengths of 45 to 90 ft However, they are available in shorter or
longer lengths. Some rigs have booms permanently attached. Boom length requirements
depend on their location and oil and gas rates all of which go into determining the
radiant heat flux expected on various rig surfaces. Spray shields are usually mounted on
each burner boom. Gas flares (no burner head necessary here) are included in the
booms. They will flare up to about 80 Mscf/D of gas. Wear you ear protectors!

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13.9.5 WATER CURTAINS

The service company supplying the surface equipment will make radiant heat flux
calculations based on the estimated flow rates in the test design. If the radiant heat flux
is expected to be very high, or if the burners will be close to heat sensitive equipment in
the rig (e.g., helicopter fuel tanks, landing pad, etc.) or some combination of these, some
form of additional heat protection is needed. Usually, this will take the form of water
spray curtains mounted along the rig deck perimeter, or in some cases, surface
inundation with cascades. Companies that specialize in this service can be employed, or
effective water shields can beset up by rig crew and operations personnel. Often one of
the rigs mud pumps can be lined up to provide additional water curtains. Auxiliary fire
fighting type pumps or rig centrifugal pumps and seawater are used, so after a long test,
there may be quite a bit of salt remaining on deck.

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13.9.6 BARGES

Seagoing flat-bottomed barges have been used by Exxon and its operating partners
approximately half-dozen times to offload oil produced in production tests from floating
rigs. Typically, the barge was moored to the rig, but held off about 200 feet from the rig
by two sea going tugs (Figures 13.23 and 13.24).

200 H aw ser L in es

3 P ro d u ctio n h o se

Figure 13.23 - Top View of Moored Barge during Well Test

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These barges are sea going and typically range in capacity from 12,000 to 40,000
barrels. Regardless of capacity, they have multiple separate compartments so
completion fluid, spent acid, diesel cushions, dirty and clean produced oil can all be
stored on a segregated basis. The contents are stored at atmospheric pressure. The
compartments are vented to the atmosphere through a common manifolded system,
terminating through a flame arrestor.

Figure 13.24 - Moored Barge during Well Test

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13.9.7 CARGO OFF-GASSING AND SAFETY

These barges were designed and approved for transport of stock tank type oil and not
specifically for production test oil. The important distinction here is that production test oil
w o n t b e sta b ilize d , a n d w ill still b e d e g a ssin g fo r so m e tim e a fte r it e n te rs th e b a rg e . In
fact, in deepwater wells, the flowstream comes to rig floor quite cool, and gets downright
cold after expanding across the choke. Heater capacity onboard is limited, and may not
be sufficient to get the flow stream up to ambient (i.e., barge) temperature.
When the cool, slightly pressurized oil moves into the barge it will be depressured, will
probably be warmed, and thus will evolve significant dissolved gas which will be coming
out of the vent line. Fortunately, the vent line is situated near the stern of the barge and
is normally downwind of the tending tug alongside the barge and the rig. Normal wind
conditions should disperse the gas with no trouble. However, the barge crew needs to
be apprised that there will be much more gas vented than when they fill their barge with
oil from a field stock tank where the gas has already been weathered at atmospheric
conditions for days, most probably.
These potential problems could be more acute with gas condensate being much more
volatile. On one well, in 1989, barging of gas condensate was the backup to burning.
Fortunately, the condensate burned as clean as a whistle without a drop spilled for five
days. With current MMS rules, ExxonMobil would have to barge this condensate in
the GOM.
H2S, even a small amount, would probably make barging as discussed above, unsafe
and unworkable. A closed vent system would have to be devised that returned all gases
vented from the barge to the rig, where it would be compressed, perhaps stripped of
H2S, but then vented to flare.

13.9.8 COSTS

Recent (1997) GOM tests used a barge and two tugs, and total costs averaged about
$20K per day. An additional $25K was charged to clean the barge after it was offloaded.
Typically, the oil recovered is sold at the end of the test but it cannot be credited back to
the drilling AFE due to royalty issues. But accounting issues aside for the moment, using
the barging option for a successful GOM test will normally more than pay for itself.

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13.9.9 BARGE RIG-UP LINES, FLOWLINE, AND

EMERGENCY RELEASE

The barge is moored to the rig with two 200-foot hawser lines, bow to the rig. Each of the
lines, at both the rig end and the barge end, is connected to the vessels through a
pelican hook arrangement, as shown in Figure 13.25. The pelican hook enables quick
remote disconnecting of the lines when a release line to it is pulled. To further facilitate
release on the rig end, the release line, in the form of a looped sling, is suspended from
the rig crane for a strong, quick pull.
The barge bow is held about 200 feet off the rig by a tug maintaining tension on a
1500 ft tow cable affixed to the stern of the barge. A second tug is positioned alongside
the barge to act as backup in keeping the barge in position, and as means of relief and
housing for the barge tankermen.
During loading, the barge is manned continuously by the barge tankerman, who is in
constant two-way radio contact with the rig tankerman. The rig tankerman keeps the
barge tankerman advised of any changes in flow stream content, quality and anticipated
volumes and rates. In this manner, the various liquids can be segregated, and the clean
oil volumes can be maximized for sale.

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Figure 13.25 - Emergency Release System

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13.9.10 FLOW HOSE AND AUTO-DISCONNECT

A flexible reinforced (rubber) transfer hose, usually about 3 in. ID, is used to move the oil
from the rig to the barge. The hose has dry quick-disconnects at each end, so no oil will
be spilled on emergency disconnect. The transfer hose is loosely looped about a support
line running from the rig to the barge that it is under no tension load, save its own weight.
But should the hose come under tension, the hose connections are designed to unlatch
before the hose ruptures. Total hose volume over water is about two to three barrels.
Note: The normal process flow path for oil barging is different than that for oil burning,
The oil exiting the separator is directed to a low pressure surge tank, where more gas
flashes from the oil. The normal range of surge tank operating pressures is 30 to 70
psig, and this is usually sufficient pressure to push the oil to the barge via the 3 in. ID
hose. If this is not satisfactory, surge tank pressures can be raised or transfer pumps
can be used.

13.9.11 EXAMPLE OF COMMUNICATIONS AND DISCONNECT

PROCEDURES

An overview of a generic loading and emergency disconnect procedure is given below:

1. The barge company will have distributed their loading procedures, protocols, and
re q u ire m e n ts a n d d iscu sse d th e m w ith th e d rillin g su p e rin te n d e n t, sh ip s ca p ta in ,
drilling engineer, test engineer, and rig tankerman.
2. Two-way radio communications will be maintained throughout the loading
process between the barge tankerman and the rig tankerman.
3. The barge tankerman will be responsible for loading the cargo, segregating fluids
as instructed, watching the mooring lines, the hose and connections for leaks,
and the water for any pollution.
4. The rig tankerman will be responsible for coordinating the loading, both with the
surface equipment personnel on the rig and the barge tankerman. He will
indicate what is going to be loaded, and how it is to be compartmentalized. He
will watch the mooring lines, the hose and connections for leaks, and the water
for any pollution.
5. The two tugs will have someone in their wheelhouses at all times. Both tugs will
have their engines running at all times.
6. A procedure for Emergency Disconnect protocol will be in place and reviewed
by all. It will detail incidents requiring disconnect, who gives the orders, levels of
emergency, which end is disconnected in what order, and where the tugs and
barge go after disconnect.

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13.10 PERSONNEL RESPONSIBILITIES AND

INFORMATION RETRIEVAL

13.10.1 PERSONNEL RESPONSIBILITIES

The overall responsibility for conducting a safe and successful test rests with the
company Drilling Superintendent. The Drilling Superintendent will work closely with the
tool pushers, the company drilling and testing engineers, the testing service company
personnel and all other contractors involved to ensure that safe practices and approved
procedures are followed. The test engineer must keep the drilling engineer and drilling
superintendent apprised on the progress towards meeting the test objectives. Likewise,
the drilling superintendent and drilling engineer should keep the test engineer informed
of any events that could impact reaching those objectives.
On a more detailed level, guidelines for specific responsibility assignments for a typical
floating rig well test are listed below. An example personnel responsibilities sheet can
also be found in Appendix A. All tests, procedures and rigs are different, so some
additions or shifts of responsibility may be necessary.

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DRILLING ENGINEERING (shared with test specialist*, Drilling Supervisor #)

1. Alert primary test equipment contractors to possible testing ASAP.
2. Review the early stages of the Test Design with Test Specialist, determine
special equipment needs.*
3. Decide if sand production, gas hydrates, or H2S may be encountered. If so,
consult with experts, and supervise design of appropriate control and safety
procedures.
4. Select, contact required service companies, supply them with Test Design
document, rig and test timing details.
5. Design completion procedure.*
6. Design the test string with downhole tool service company.
7. Review surface equipment weights, space requirements, and rig deck
loading and space restrictions. Map out rig floor plan for surface equipment and
piping.
8. Develop production disposal procedure in line with local regulations, and see that
necessary permits from regulatory agencies are applied for and obtained.
9. Develop mechanical design for completion string, sand control (if required).
10. Develop procedures for running perforation and testing string(s).
11. Ensure that all test equipment is mechanically sound and that all connections
with adjacent equipment are compatible. Ensure that critical spares and sufficient
varied length pup joints are available.
12. Witness pressure and function test of surface and subsurface test equipment,
including emergency shutdown safety system.*
13. Supervise the make-up of test string and check clearances. This should
be accomplished as soon as possible in order to prevent delay during the testing
operation.
14. Ensure that permanent packers, seal assembly, and tall pipe assemblies are all
inspected.
15. Ensure that string space out is correct, cross check with downhole tool service
company and drilling superintendent.
16. Verify (with Drilling Superintendent, Test Specialist and/or Operations Geologist
in attendance) that packer will be set and perforations will be made at correct
depth (with respect to formation).
17. Monitor operation of surface equipment, especially routing of produced liquids to
storage tanks, burners, or barges.
18. Coordinate proper selection of barge compartments for various off-loaded liquids
with rig and barge tankermen.Assist in monitoring test parameters in Data
Acquisition Lab, gather data reports at selected intervals *

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TESTING ENGINEER OR SPECIALIST

1. Set test objectives and priorities with input and approval from client organization.
2. Gather all pertinent formation evaluation and fluid property data.
3. Consult with Drilling Engineer on estimated maximum pressure drawdown
allowed.
4. Develop Conceptual Test Design giving flow and shut-in times, estimated rate
and formation pressure drawdown, wellhead pressures, water cuts, salinities, etc.
5. M a ke sp e cia l e q u ip m e n t re co m m e n d a tio n s (a s p e r 2 , 3 a b o ve , D rillin g E n g in e e rs
section).
6. Design sampling program: to include type, number, location sampled, sample
handling, and shipping information.
7. Write procedures for initial pressure, bringing well on for main flow, reaching
stable rate, and sampling.
8. Consult with drilling engineer on cushion design.
9. Specify an unloading curve to start the main flow, giving the minimum wellhead
pressure permitted as a function of produced cushion.
10. A ssu re th a t se rvice co m p a n ys co m p u te rize d te st d a ta fo rm s m e e t E xxo n M o b ils
standards and requirements.
11. Coordinate data gathering activities.
12. Make sure that calibration standards are met, especially for all liquid and gas
meters on separator. Witness calibrations.
13. Supervise initial flow, and buildup.
14. Supervise unloading and clean up of well with drilling engineer.
15. Reach decision on maximum sustainable test rate with drilling engineer, drilling
superintendent, surface equipment supervisor and captain.
16. Monitor test parameters in Data Acquisition Lab, gather data reports at selected
intervals.*
17. Verify constants, calculations and sensors used in Data Acquisition system by
occasional visual check of pressures and temperatures measured conventionally,
and by using hand calculations.
18. Supervise all surface sampling and entire bottomhole sampling operation, with
assistance from drilling engineer.
19. Continually advise the drilling engineer and drilling superintendent regarding
test progress towards objectives, problems and any anticipated test schedule
changes.
20. Evaluate test data onsite for completeness and accuracy; communicate test
progress and results to clients during and after the test.
21. If SRO is being used, instruct bottomhole gauge technician as to when SRO
pickup wireline is to be RIH, and how/when data is to be transmitted to test
specialist for analysis.

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22. Analyze PBU in real time if SRO of bottomhole pressure is available. Compare
results to predictions, simulations to decide if buildup time is adequate.
Determine if PBU extrapolates to initial pressure.
23. If SRO of bottomhole pressure data is not used, analyze bottomhole pressure
data after the test string is pulled, verify data will meet test objectives, notify
drilling superintendent and clients.
24. Do follow up on test equipment and service company personnel performance
with drilling engineer.
25. Back onshore, collect all data, sample analysis, PVT studies, complete
interpretation, and write report.

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OPERATIONS OR STAFF GEOLOGIST

(if not onsite, Test Specialist/Engineer will perform*)
1. Determine number of zones to be tested and provide initial information on
pressure, temperature, and types of fluids contained in the reservoir (for test
design).
2. Analyze electric logs to determine perforation interval(s).
3. Supervise perforating depth correlation and operations.*
4. Supervise or assist with setting packer on depth.*
5. Assist in gathering and analyzing test data.*
6. Assist in labeling samples and gathering for shipment to labs.*

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DOWNHOLE TEST TOOL PERSONNEL

1. Distribute detailed diagram of finalized test string to drilling contractor,

ExxonMobil drilling superintendent, drilling engineer, and test engineer or
specialist.
2. Discuss and finalize space-out procedure with ExxonMobil and drilling contractor.
3. Prepare test tools and subs for make-up on drill floor.
4. Supervise make up of the test string, in coordination with the drilling engineer.
Make independent string tallies for space out calculations.
5. Function and pressure test tools in pipe rack.
6. Check nitrogen pre-charge on certain annulus pressure operated (tester valve)
tools.
7. Oversee make-up of bottom-hole test assembly.
8. See that bottomhole pressure gauges are set up, programmed, mounted, and
started by the gauge specialist. Gauge technician supervises mounting of gauges
in the carrier, gauge pressure port position with respect to a positive depth
reference in the test string is determined.
9. Be on rig floor at all times while GIH, POOH with test string.
10. Be on rig floor at all times while manipulating annular pressure, during
perforation, during flow and at all other times when any of the bottomhole test
tools are being operated.
11. Ensure that all parts of the SSTT and lubricator valve are in good working order.
Function test hydraulic and mechanically unlatch prior to RIH on each test.
12. One downhole test tool operator must be on the rig floor at all times during
testing operations and be prepared to unlatch SSTT in the event of an
emergency shut-in and disconnect.
13. Operate lubricator valve as needed for wireline operation, or in emergency.
14. If required, operate downhole chemical injection of methanol as necessary.
Conduct as per procedure, and modify as instructed by test engineer as main
flow period proceeds. Record methanol injection volumes and back pressures as
a function of time. Assist the test engineer in monitoring wellhead pressures,
temperatures, and water production and salinity for continuous hydrate potential
assessment (surface equipment personnel may assume or assist with these
duties).
15. Supervise POOH with test string, remove any samples, bleed off pressures, and
disassemble the test tools and return to tool racks or baskets.

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SURFACE PRODUCTION TEST EQUIPMENT PERSONNEL

1. Assemble the surface equipment and piping system.

2. Set up the field lab, the computerized data acquisition system, and the ESD
system.
3. Coordinate the steam supply to the heat exchanger with the steam boiler
operator.
4. Assemble pollution control equipment.
5. Hydraulically pressure test the system internally and the pressure pilots for the
ESD system with the drilling engineer witnessing test.
6. Take oil, gas and water samples during cleanup. Do shakeouts on full well
stream samples during cleanup. Analyze water for chlorides and resistivity, oil for
gravity and gas for H2S, CO2.
7. Make decision on putting flow stream through the separator.
8. Operate test separator and surface sampling equipment as agreed to by testing
engineer or specialist. Keep them advised of changes required in separator
operation.
9. Change choke and orifice plate as necessary. Keep orifice meter free from liquid
buildup in legs and meter run.
10. Adjust separator controls and trim as needed for smooth operation.
11. Ensure flowmeter has valid calibration done at actual separator operating
conditions.
12. Monitor all flow stream parameters from the flowhead to final disposal. Monitor
casing annulus pressure.
13. Ensure the proper functioning of oil burner and monitor wind direction. Operate
all manifold valving under the direction of the separator operator.
14. Coordinate burner operation with separator supervisor and rig floor personnel in
emergency shut down situation.
15. Monitor burners, offloading lines, and surface equipment for leaks or other
pollution.
16. Assist with keeping any leakage minimized, confined to drip pans, and soaked up
with absorbent material for disposal.
17. Coordinate shut down of all downstream surface equipment with the downhole
tool personnel on the rig floor in the event of emergency shut down.
18. When test is over, prepare surface equipment to take reversed out fluids.
19. Flush out equipment, disassemble for removal from rig, clean up site.

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MUD LOGGER

1. Take periodic samples of gas at the choke manifold during flow periods as
directed by test engineer and analyze samples with chromatograph.
2. Use gas detectors to determine presence of H2S or CO2 from choke manifold
samples and on the rig floor.
3. Assist with chloride analysis and resistivity measurements on water samples
as directed.

CEMENTER

1. Perform well killing and cementing operations as required. Have pumping

equipment in a state of readiness to kill the well and/or cement on short notice.
2. Pump into or bleed the annulus to attain desired pressure as directed by
downhole tool service company supervisor to operate perf guns, downhole tools.
3. Maintain adequate number of cement retainers and conversion kits to bridge
plugs for casing size used in production test.

TOOLPUSHER

1. Ensure that well killing equipment is ready and coordinate the well killing
operations.
2. Oversee running of test string and rigging up of surface control equipment.
3. Participate in the space out procedure.
4. Review the test string make up procedure with the drillers.
5. Consult with the APO tool service company personnel to ensure the necessary
valves on the drillfloor are properly configured for annulus pressure control.
Pass how this will be handled to the drillers and assistant drillers.
6. Help coordinate various steps of the production test sequence as pertains
to the downhole equipment, rig up of the flowhead and lines, wireline
BOP/lubricator, the ESD system, and the emergency disconnect procedure.
DRILLER

1. Emergency disconnect understanding.

2. Maintain proper top tension on the landing string.
3. Share in the responsibilities of observing wellhead equipment with subsea TV
and ensuring pressure integrity of rig floor piping.
4. Coordinate the Assistant Driller and/or floormen to provide constant observation
of the annulus pressure.
5. Ensure that production test string is properly made up.
6. Ensure that drillfloor valves are properly configured to operate the test tools with
annular pressure.

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ASSISTANT DRILLER

1. Assist the drilling engineer with pipe tallies.

2. Verify that the necessary valves on the drillfloor are properly configured for
annulus pressure control.
3. Monitor the annulus pressure.
4. Assist in emergency situation with unlatching and subsequent shut-in.

CAPTAIN

1. Monitor weather forecast and outlook, and report anything of potential danger to
the Operations Supervisor and Rig Superintendent.
2. Oversee operation of the production barge and the tending tugs.
3. Enforce all safety regulations and coordinate any evacuation proceedings.

SUBSEA ENGINEER

1. Under company supervision, conduct pressure and function test on BOP stack
prior to beginning the production testing operations. Ensure that the BOP rams
are appropriate for the subsea safety assembly (SSTT) of the test string.
2. Work with downhole tool personnel, SSTT operator and Drilling Engineer to
ensure that the fluted hanger space out and the SSTT makeup is such that the
tool string alignment with the rams in the BOP stack is correct.
3. Monitor status of BOP stack and control system.
4. Watch for gas flow and hydrate buildups on the BOP stack , especially the
LMR area.

SUPPLY VESSEL CAPTAIN

1. Supervise the operation of standby boats. Visual signals should be prearranged

and used in the event of power or radio failure in an emergency. If there is a loss
of radio contact, the supply vessel will go to the rig and make contact.
2. Ensure that Corexit dispersant supply is ready for immediate usage with pollution
control equipment.

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13.10.2 INFORMATION RETRIEVAL AND HANDLING

The purpose of the production test is to generate high quality data and samples
sufficient to meet the test objectives. Proper recording of these test data and samples,
and the conditions under which they were obtained is very important.
O ve r th e ye a rs a se t o f 1 6 d a ta fo rm s, kn o w n a s th e D -forms, was developed by the
predecessor of ExxonMobil URC to help organize and facilitate the laborious task of
collecting and standardizing the recording of data from all types of well tests.
About 12 of these forms are applicable to well tests from floating rigs using downhole
electronic gauges. They are contained in Ref. 1, Section 11. Fortunately, since that time,
computerized data acquisition of surface data and electronic downhole memory gauges
have simplified this task and reduced the labor required to do it properly. But the
fundamentals of required data collection have not changed, nor has the ultimate
responsibility of seeing that it is done completely and correctly. The test specialist or
engineer has this responsibility.
There is a multitude of ways to categorize well test data, and all have their shortcomings.
The most general starts with two classifications, surface data and bottomhole data.
Surface data has many ways to sub-classify, but here is one way.

13.10.3 SURFACE DATA

COMPUTERIZED DATA ACQUISITION

With computerized data acquisition, Excel formatted printed reports and data sets have
supplanted some of these key forms (D-05, D-06, D-07). These forms contain the largest
surface data sets, the complete raw surface data, calculated intermediate rate results,
and final data for the main flow period. Some of the data, such as choke size or orifice
plate hole diameter, and event descriptions, are entered manually when changes occur.
But the basic data is usually reported at 10 minute to one-hour time intervals. A
typical test will produce a 12 to 30 page surface data report, legal size landscape
Excel -type format.
As a part of pre-te st p la n n in g , th e te st e n g in e e r sh o u ld b rin g a se t o f D fo rm s o r o th e r
examples of what is wanted to a meeting with the service company so they can present
the required data in the desired format. Usually the standard format offered by the
service company is suitable, perhaps requiring a change or two. This change will usually
involve presenting some auxiliary data not integral to the basic calculations, such as field
sampling results, methanol injection rates, or oil pressure at the burners.
E ve n th o u g h re p la ce d , th e se D fo rm s a re a lso ve ry h e lp fu l in u n d e rsta n d in g th e d a ta
collection process, and the flow in the calculations. They are also helpful to manually
record data for occasional checks on the computerized data acquisition system. This is
highly recommended and helps one to become familiar with the computerized data
acquisition system's processing software logic.

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MANUALLY RECORDED DATA

This data can be of any type, except bottomhole data. But certain types of data must
always be manually recorded or entered. These types would include static descriptive
data of all kinds, significant events in the test, choke and orifice plate sizes, and field
analysis results for water cut, oil, gas and water properties. The well clean up process is
also described with manual data entries prior to the well stream being put through the
separator. The description of sampling conditions, techniques, and containers is all via
manual recording of data on the sampling forms (D-8, D-9, D-14, and D-15).

BOTTOMHOLE PRESSURE DATA

The advent of electronic memory gauges has totally automated the recording and
reporting of bottomhole pressure and temperature data. The gauge technician will
generate summary reports of the data, and PC computer readable diskettes or CDs
onsite for the test engineer as soon as the gauges are retrieved from the string and
dumped to the service company computer.
If SRO is used, the gauges are read real time, but normally dumped to diskettes in (4 to
12 hour) batches. The test engineer will incrementally add these data to a data set that
is re-analyzed to extend the buildup analysis. In this way, a decision can be made as
soon as practically possible that sufficient buildup data has been obtained. For the final
analysis and report, the deepest bottomhole gauge data are normally used. These are
usually not the SRO gauges.

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13.10.4 REVIEW OF TYPES OF WELL TEST DATA AS COVERED

B Y T H E D F O R M S

T h e d iscu ssio n b e lo w sh o u ld b e ta ke n a s o n ly a b rie f o ve rvie w o f th e D fo rm s a n d th e

data to be entered therein. Copies of the actual forms are in references 1 and 2. It is
recommended that anyone assigned to a well test gets a set of these forms, and takes
several copies of each to the wellsite.

D-1 WELL TESTING OBJECTIVES AND TEST PERSONNEL

D-1 contains a very brief summary of the test objectives, the roles of key personnel, and
contact information. It is best used as a rough guide for statement of objectives. The test
design document (Sect. 13-3) is a more comprehensive source for information on test
objectives. Test specialist is responsible for information.

D-2 COMPLETION DATA

D-2 is an essential form that contains a thorough description of the completion. This
data must be gathered from a number of sources. It contains information on depths,
bottomhole dimensions, mud, completion, and cushion fluid properties, pressure gauge
sensor port depths, etc. Drilling and/or completion engineer is responsible.
D-3 PERFORATION DATA

D-3 is partially obsolete in that it is set-up for multi-run wireline perforating. But most of
the information requested is applicable to any method of perforating. Some of the data
recorded manually will be available from the electronic memory gauges when they are
pulled. Test engineer or test specialist is responsible.
D-4 INITIAL FLOW PERIOD DATA

The D-4 form may be partially obsolete because it assumes that formation fluids will
su rfa ce d u rin g th e in itia l flo w p e rio d , w h ich isn t u su a lly tru e w h e n a b o tto m h o le te ste r
valve is employed. But most of the requested data is pertinent, such as underbalance,
flowing wellhead pressure, choke size, volumes and times. Test engineer or test
specialist is responsible.

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D-5 PRODUCTION TEST DATA SHEET

The D-5 form is where the heart of the surface data and the calculated rates from the
main flow period are recorded. Recording intervals typically range from 5 to 15 minutes
(first several hours of main flow) to 30 minutes to 2 hours (for the last part of very stable
production).
The data form contains flow rates and cumulative production volumes for gas, oil, and
water from the main flow period. Wellhead pressure and temperature, choke size, casing
pressure, and field-measured properties of the gas, oil, and water are also recorded.
These are usually gas gravity, API oil gravity, and chlorides (or resistivity), respectively.
If any H2S or CO2 is present, these concentrations are measured and entered on (a
slig h tly m o d ifie d ve rsio n o f) th e fo rm . T h e W e ll T e st R e p o rt sh e e t p ro d u ce d b y th e
Schlumberger computer system is an expanded equivalent of the D-5 form. But it may
be too large for faxing, and the manually filled D-5 form or an Excel version may be used
for daily reports to Drilling offices and the clients.
While the test engineer or test specialist is ultimately responsible for this data, most
of it is actually gathered and processed by the surface facilities crew and/or the
computerized data acquisition system. In any case, the test and drilling engineers should
use this form and the two that follow (D-6 and D-7) to manually record data to verify the
readings and calculations made by the surface facilities crew or the computer.

D-6 SEPARATOR DATA AND LIQUID RATE CALCULATIONS

The D-6 form is used to record the raw liquid flowmeter data for oil and water from the
separator, to make meter factor, shrinkage and temperature corrections. It also contains
water BS&W, and API gravity of the oil. This form does not fully accommodate the
frequent calibration recommended for the oil flow meters. The test engineer or test
specialist is ultimately responsible that calibrations be made as frequently as possible at
actual separator operating conditions (See Section 13.8 - Volumetric Flow Rate
Measurement of Liquids).

D-7 GAS RATE CALCULATIONS

The D-7 form is used to record the gas meter orifice diameter, the various correction
factors, gas gravity (from field measurements, or assumed) temperature, static pressure,
differential pressure, and the calculated gas rate for the main flow period. The test
engineer or test specialist is ultimately responsible for checking the condition of the
orifice meter, and use of the correct parameters. Of prime interest is use of the correct
g a s g ra vity (if a va ila b le ), o r d o cu m e n tin g w h a t g a s g ra vity is u se d a s a te m p o ra ry
p la ce h o ld e r. M e te r re a d in g s are made by the surface facilities crew and/or the
co m p u te rize d d a ta a cq u isitio n syste m . T h e in p u t sh e e t fo rm g e n e ra te d b y
Schlumberger is the equivalent of the D-6 and D-7 forms combined.

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D-8 LIQUID SAMPLE FIELD ANALYSIS RECORD

The D-8 form is handy for keeping track of field liquid sample results, such as those
taken from the choke manifold during well clean up. Field samples are taken to monitor
test progress and are analyzed onsite. Typical analysis results include those from
sh a ke o u t fo r B S & W , oil gravity, water salinity, resistivity, pH and measurement
temperature.
Once clean up is complete and the well stabilizes, the emphasis shifts to obtaining
samples for offsite lab study, and field samples will be taken less frequently. The test
engineer is responsible for overseeing the sampling, determining frequency, monitoring
the analysis techniques and interpreting the results with respect to the progress of the
w e lls cle a n u p .
D-9 GAS SAMPLE FIELD ANALYSIS RECORD

The D-9 form is the gas equivalent of the D-8 form. Field gas samples are taken from
the choke manifold initially and later from the separator. Analysis results should always
include H2S and CO2. If a chromatograph is available, C1 through C5+ compositional
analysis can be obtained and recorded. Gas gravity as determined for the online
Ranarex , if available, can be entered on this form. But the primary utility of this form is
that it offers a gas sampling record for H2S and CO2. The test engineer is responsible
for overseeing the sampling and monitoring the analysis techniques. But if H2S shows
up, the test engineer and the drilling engineers should be made aware of this even
before it hits the form!
The following D forms are seldom used in deepwater exploration well tests, as explained
below their headings.

D-10 WELLBORE GRADIENT DATA

W e llb o re g ra d ie n ts a re n t n o rm a lly ru n u n le ss b o tto m h o le sa m p lin g is e m p lo ye d ,

production logs are run, or the well never totally cleans up. Data recorded are time,
wellhead pressure, depth, downhole pressure and temperature at depth, and calculated
gradients. Much of this electronic gauge data will be automatically recorded, so the form
is for transcription and making the gradient calculations, which is the responsibility of the
test engineer and the service company gauge technician.

D-11 BOTTOMHOLE PRESSURES

This form is a holdover from the mechanical gauge days and will not be used as the
primary bottomhole pressure medium is computer readable, from which listings can be
made at the desired time and sampling intervals.

D-12 BUILDUP ANALYSIS

This form is used to record milestone data, and is a step-by-step guide to a manual
Horner analysis. It can be used if requested, and is valuable if PC software is not

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available for onsite computer analysis. But normally PC computer analysis is preferred
for speed in handling the massive amounts of data, reports and plots of results.

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D-13 MCKINLEY TYPE CURVE ANALYSIS

This is only used if the well has a significant amount of afterflow. If the bottomhole tester
valve is used, this technique and form are not used. These last three forms are generally
applicable, as noted.

D-14 SEPARATOR SAMPLE DATA

This data form is used to record the time, conditions, and method under which separator
gas and liquid samples were taken. These conditions encompass the flow path from the
completion through the separator and include gas and oil rates, and water cuts. The
container ID numbers and volumes are described, as well as any special instructions or
contacts for the destination laboratory. The sampling technician will have a similar form.
The test or drilling engineer should check this form prior to the sampling operation to see
if it m e e ts E xxo n M o b ils n e e d s.

D-15 BOTTOMHOLE SAMPLE DATA

This data form is analogous to the D-14 form, but for downhole samplers. There is much
less data on flowstream conditions because conditions uphole are not critical. WHP is of
some interest, and rate could be important. Sampling depth, pressure, temperature, flow
rate, time, and sampler description are recorded.
Also important are the conditions of the sample transfer to shippable containers back at
the surface, including pressure and temperature, measured buBble point pressure, and
sample volumes. The container ID numbers and volumes are described, as well as any
special instructions or contacts for the destination laboratory. Again, the bottom hole
sampling service technicians will have their own forms, which will include most of this
information and probably more. The test or drilling engineer should check this form prior
to th e sa m p lin g o p e ra tio n to se e if it m e e ts E xxo n M o b ils n e e d s.

D-16 PRODUCTION TEST SUMMARY

This form contains no new data but is a compact and useful summary of the important
test parameters and analysis results. The test engineer usually completes it before
leaving the well site. However the analysis results that are entered on this form are very
preliminary, by necessity, because some of the calculations are made with physical
properties that are estimated, pending onshore lab results. The D-16 form gives such a
handy synopsis of the test that it is widely circulated, and the preliminary nature of the
analysis is sometimes overlooked.

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13.10.5 DESCRIBING, LABELING AND SHIPPING SAMPLES

A very important, and usually tedious, part of the overall sampling process is getting the
samples to the onshore lab or client in a safe, secure, expeditious, and totally legal
manner. Shipping hazardous materials is impacted by the regulations and practices of a
number of company departments and governmental agencies, domestic and
international. This is a matter where experts experienced in the geographic area
should be consulted.
Even with such expert assistance, the test or drilling engineer is going to be responsible
for several items in connection with sample handling. The sample cylinders must have
an indelible label firmly affixed that lists the well, company, contact, date, place and
time taken.
Sometime the well test service company or the sampling contractor will handle the
samp le sh ip m e n t. T h is w ill b e m o re like ly if th e sa m p le s a re g o in g to th e co n tra cto rs
lab for the PVT studies, etc.

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13.10.6 WELL SITE REPORTS

There are several types of reports that are typically written at the well site by the test
engineer for several audiences:

DAILY REPORT TO CLIENTS

A d a ily re p o rt is w ritte n fo r th e clie n t th a t g ive s a su m m a ry o f th e te stin g o p e ra tio n s

progress over the last 24 hours. It should cover any major breakthroughs or problems,
and give operations plans for the next several days. Usual items of interest are rates and
properties, and progress towards objectives. This report can have a fixed tabular format
o r h a ve a fle xib le n a rra tive . T h e clie n t a n d th e te st sp e cia list d e cid e . D fo rm s m a y b e
supplied as requested.

DAILY REPORT MATERIAL FOR DRILLING

Comprehensive test information is normally furnished to the drilling superintendent every

1 2 h o u rs. T h is w o u ld in clu d e ke y D fo rm s o r se rvice co m p a n y sh e e ts, ra te s, cu m u la tive
volumes, and bottomhole pressures from SRO, if available. The report to the clients is
also furnished. The drilling superintendent will use this data in his daily drilling report.

REPORTING TO REGULATORY AUTHORITIES

Regulatory reporting requirements should be determined before the test gets underway.
Reports of rates and cumulative volumes of oil, gas, and water may be required as the
test progresses, depending on jurisdictional area. The D-5 forms may be requested. The
to ta l cu m u la tive vo lu m e s o f p ro d u ctio n w ill b e re q u ire d a t te st e n d . A co m p le te d D -1 6
form (below) or a similar regulatory agency form may be required at the end of the test.

PRODUCTION TEST SUMMARY (AND PRELIMINARY ANALYSIS) FORM

T h e D -1 6 fo rm is co m p le te d b y th e te st e n g in e e r a t th e e n d o f th e te st, u su a lly b e fo re
leaving the rig. It includes a preliminary analysis of the bottomhole pressure data.
It is widely circulated, and becomes a permanent part of the well file.

SURFACE READOUT OF BOTTOMHOLE PRESSURES, REAL TIME

ANALYSIS

If SRO is used, the bottomhole gauges can be read in real time. More commonly, the
data are dumped to diskettes in 2 to 6 hour batches and given to the test specialist.
The specialist will add these data to the previous pressures and re-analyze the updated
pressures to extend the buildup analysis. In this way, a decision can be made as soon
as practically possible that sufficient buildup data has been obtained. For the final
analysis and report, the deepest bottomhole gauge data are normally used. These are
usually not the SRO gauges.

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13.11 PRODUCTION TESTING OPERATIONS

13.11.1 PRE-TEST PLANNING ITEMS

Coordination, planning and preparation are the keys to conducting a safe and
successful deepwater well test. A coordination meeting should be held with all key
personnel as far in advance as practical to discuss test objectives, procedures, general,
personnel responsibilities, special equipment requirements, safety issues, and any
special considerations.
Any special requirements regarding strip down and inspection of equipment in the
se rvice co m p a n ys ya rd s n e e d to b e put forth at this time. And all surface equipment and
downhole tools should be pressure and function tested before delivery to the rig.

BOP RAM CONFIGURATION

At the earliest opportunity, the ram configuration in the BOP stack must be reviewed
and, if necessary, be refitted with the proper type and size of rams to seal on the slick
joint and to accommodate the subsea test tree (SSTT) assembly.
The BOP slick joint is spaced out such that, with the fluted hanger landed in the
wellhead, the lower pipe rams (LPR) and the middle pipe rams (MPR) can be closed on
the slick joint to seal off the tubing annulus. The casing pressure is controlled at surface
through the kill line.
If an emergency disconnect is required due to excessive vessel offset or other adverse
conditions, the blind/shear rams can be closed on the shear joint. If sufficient time is
available, the SSTT can be disconnected and pulled well above the shear rams. The
shear rams can then be closed above the remaining portion of the SSTT and the Lower
Marine Riser Package (LMRP) can be disconnected from the BOP stack.
Note: Many older floating rigs have blind/shear rams that are incapable of shearing
standard shear joints provided by the testing companies. The dimensional and material
properties of the shear joint should be provided to the BOP manufacturer in order to
ensure shearability. Special-order or turned-down shear joints are frequently required.

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SOME SPECIAL CONSIDERATIONS

Deck Space and Loads: The variable deck load capacity or available deck space of
some of the smaller floating rigs (especially drillships) may require that some materials
be offloaded onto supply vessels or sent to shore before production testing equipment
ca n b e p la ce d o n th e rig . T h e rig s va ria b le d e ck lo a d is d e te rm in e d d a ily by stability
calculations, and the weight to be off loaded in order that test equipment can be brought
on board is thereby determined.
Radiant Heat Flux Loads from Burners: Short burner booms or confined spaces on
smaller rigs may result in excessive radiant heat flux loads on rig equipment when the
well is under test at design rates. Given the rate data from the Test Design Document,
the burner locations, and the rig layout, the surface equipment service company can
assist the drilling engineer with these calculations. Obviously, any oil and jet fuel tanks,
lifeboats, and composite helicopter pad surfaces cannot tolerate high radiant heat flux
loads, and will
have to be protected with water curtains, sprays, or cascades.
Offloading Oil Production to Barge (see 13.9).
Gas Hydrate Inhibitor Injection System (see 13.13, Special Situations).

PRE-TEST CONFERENCE

A pre-test conference (or several if needed) should be held with company personnel and
the Rig Superintendent, toolpushers, drillers, Rig Captain and other supervisory
personnel involved with the test. This is not the general safety meeting as it is for the
personnel who will run and supervise the test, but safety will be discussed. During the
pre-test meeting, the following items should be reviewed and discussed:
Test objectives and associated requirements.
Test equipment and hook-up.
Test procedures overview.
Personnel responsibilities.
Special Situations (H2S, offloading production to barges).
Safety procedures.
Emergency procedures and drills.
Supervisory personnel will discuss all pertinent pre-test meeting topics with their
respective personnel. Supervisors must ensure that the responsibilities of all personnel
associated with the test are clearly assigned and understood. The Operations
Supervisor will inform the supply vessel captains of their role in the impending test.

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SAFETY CONSIDERATIONS

Any operation, which brings explosive, flammable, and potentially toxic materials to the
surface under high-pressure in proximity to a large number of personnel poses a
potentially hazardous situation. Safety and emergency planning for such an operation on
a deepwater well test is made more complex because it has to include all aspects of
general marine safety and emergency disconnects.
A safe well test must be built around a thoughtfully designed process to control and
dispose of these fluids. Hydrocarbons are produced, often at high pressures and rates,
through a temporary system. Plans must include handling disruptions, and must
recognize that some of the rig crew may be unfamiliar with equipment and procedures
used during production testing.
After the detailed well test design is completed, and the, process to control and dispose
of these fluids is laid out, a safety meeting should be conducted for the wellsite
supervisory and technical personnel. Some general safety connected topics are
listed below:
Safety procedures during testing.
Procedures for recognition and mitigation of H2S.
Procedures for handling emergencies, including disconnect and shear
deformations.
Descriptions of test string components (including working pressure and
temperature ratings).
Procedures for pressure testing of surface equipment.
Data on surface equipment throughput capacities, working pressure, and
temperature rating.
Schematic of surface test equipment layout and location.
Procedures for monitoring and control of testing operations.
Diagrams for process and instrumentation, with key parameters to watch.
Diagrams for overpressure alarms, shut down systems, vent lines.
Description of emergency shutdown system.

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GENERAL SAFETY MEETING TOPICS

The ExxonMobil supervisor in charge should conduct a safety meeting for everyone
onboard before the well is perforated. A second safety meeting should be held before
the well is opened for flow to the surface if an intervening (e.g., gravel packing) operation
occurs between perforation and production. All personnel on location must attend,
including supply boat captains for offshore tests, and barge tug captain, if applicable.
The following topics should be discussed at the first meeting and reviewed at
subsequent meetings, as appropriate:
Job responsibilities of each person during test operations, with emphasis on
safety aspects.
Special safety rules in effect.
Emergency contingency plans.
Warning alarms or signals, and actions that should be taken in response.
Hazards of hydrogen sulfide (see 13.13, Special Situations)
The ExxonMobil supervisor in charge is responsible for the following:
1. Decisions regarding weather conditions that may warrant killing the well and
securing it so that the riser can be pulled if necessary.
2. Ordering the shutdown of all radios and ignition-type internal combustion
engines for the duration of well perforating operations.
3. Making sure that H2S detectors are located around the rig floor and test
equipment.
4. Ensuring that portable H2S detectors are provided and used, if permanent
detectors are not installed around the well and production equipment.
5. Preparing and implementing a toxic gas contingency plan.
T h e sh ip s cap tain should:
1. Hold abandon-ship drills prior to the first well test and regularly once the test
commences
2. Check fire-fighting equipment and assign personnel to be responsible for
using the equipment
3. Organize and hold separate H2S drills, if H2S production is possible.

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GENERAL SAFETY RULES

The following general rules should be observed during well perforating and for the
duration of the production test:
1. No smoking ANYWHERE except in designated areas in living quarters.
No smoking in mud loggers lab, data acquisition lab, etc.
2. Close portholes and watertight doors.
3. N o w e ld in g , b u rn in g , ch ip p in g , o r g rin d in g w ith o u t th e E xxo n M o b il su p e rviso rs
permission.
4. D o n o t u se cra n e s e xce p t w ith th e E xxo n M o b il su p e rviso rs p e rm issio n .
5. Turn out unnecessary lights in the derrick, on the rig floor, and around the
separator.
6. Clear helicopter landings while the well is flowing with the ExxonMobil supervisor,
or decide in advance whether landings will be permitted while the well is flowing.
7. Have supply vessels stand off (not anchored) a reasonable distance while the
well is flowing.
8. Under no conditions should a well be perforated, produced or kept alive unless a
standby vessel is nearby to help in emergencies.
9. Start a flow test only during daylight and if the well will surface formation fluids
during daylight.
10. Personnel not required for the test or maintenance must remain in the living
quarters.
11. Limit personnel onboard to those required for testing and essential rig operations.
12. In all matters regarding the safety of the crew and ship, the captain has the final
authority.
A fire and boat drill should be conducted well in advance of the initiation of flow. If
there is a possibility of H2S in the produced fluids, a separate H2S drill should also
be conducted.

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13.11.2 EQUIPMENT CHECKS AND SET UP

SHIPMENT CHECKS

Equipment sent to the rig for the production test should, as much as possible, be
pressure tested onshore before being sent out. Test string components are delivered to
the rig in metal cargo containers or tool baskets. Using a readiness checklist (see
Appendix B), the Drilling Engineer can verify that all of the required test tools, along with
an adequate supply of spares, are available on the rig. The compatibility of all test tool
connections should be checked.

SURFACE EQUIPMENT SET UP, PRESSURE TESTING AND

CALIBRATION

Most of the surface equipment layout will probably be a near duplicate of that from
previous jobs on the same rig by the same service company. However, there may be
differences in layout of lines, location and capacity of storage tanks, etc.

LAYOUT OF FLOW LINES

All high-pressure lines should be firmly anchored to rig deck. Lines should be clearly
marked and stepways should be constructed over line clusters crossing walkways.
Test surface equipment and calibrate as follows:
1. After swinging out the burner booms, install all necessary connections between
the boom, separator, heater, transfer pump, gauge tank and rig floor.
2. Fill up the separator, burner lines, and gas flare line with water by using the
cementing unit.
3. Close the valves on the burner and gas flare lines and pressure test the
separator and lines.
4. Calibrate gas orifice meter differential pressure gauge.
Test burner function as follows:
1. Flush water and oil lines from the separator to the burner with water using
cementing unit or rig pump.
2. Test propane pilot lighters and water shields on both burners. Pump water
through the shields at a pressure of 120 to 150 psi or as recommended by
serviceman.
3. Vent the burner air line to clean out debris.
4. Conduct a burner test by pumping about 50 barrels of diesel from the gauge
tank, through the transfer pump, to the burner.

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Calibrate the separator flow meters with water or diesel as follows:

1. Pump water through the separator. Flow to the gauge tank long enough to fill the
outlet lines.
2. Stop flow and gauge the tank.
3. Again, flow to the tank through the flow meter to be tested. At the same time,
record the flow meter reading.
4. When the gauge tank is full, stop flowing and record the flow meter reading.
5. Gauge the tank and calibrate the flow meter.
Note: For the oil flow meters, these are only very rough calibrations to see if the
flowmeter is functioning. The calibrations obtained here will not be accurate at operating
conditions. The oil flowmeter must be calibrated under actual flowing conditions.
Ensure that all electronic pressure recorders and pressure gauges have been calibrated
on land and that documentation is available (see Section 13.8 - Dead Weight Testers
and Calibration).

13.11.3 OVERVIEW OF TEST PROCEDURES ON DOWNHOLE

OPERATIONS
Step-by-step written procedures for every phase of the overall testing operation are
required for a safe and successful test from a floating rig. The drilling engineer is
responsible for writing these procedures. This section will present a brief overview of the
types and general content of procedures for the various stages of these operations. A
sample procedure is located in Appendix C.
Within the particular procedure written for the Dual Flow-Dual Shut-in Test itself, one or
several sub-procedures may be referenced. These are written by the test specialist or
engineer and will deal in detail with subjects such as initial flow, bringing the well to
surface, and sampling. These test sub-procedures will only involve minor surface
operations, such as changing choke size, adjusting separator pressure, taking
samples, etc.
Procedures for completion related operations might be written with assistance from the
completion engineer.
These step-by-step procedures are formulated to reach the test objectives, but their
specifics are dictated by safety, reservoir fluid conditions, completion technique,
downhole and surface equipment, geographical area, the rig, and regulatory agency and
company policies. Obviously, off the shelf procedures that are universally or even widely
applicable cannot be written, so the summaries of actual procedures which follow are not
universally applicable. However, smaller sub-sections of them may be adapted to new
well tests.

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13.11.4 THREE BASIC TEST PROCEDURE STRUCTURES

Given that the test string will use a bottomhole tester valve, and that tubing conveyed
perforation will be employed, there will be three basic methods to get set up for
conducting the test. The method will hinge on the need for in-place gravel packing.
1. One trip with the test string Perforate, go directly into DF-SI test. This option
will employ in-line sand screens or gravel pre-packs (seldom used), or no sand
control at all. A permanent or retrievable packer can be used.
2. Two trip Gravel Pack, trip with test string A sump packer is set by wireline.
First trip is made with a perforation string, second trip with the gravel packing
string, and third trip with the test string. The DF-DSI test begins at this point.
3. One trip Gravel pack, trip with test string First trip is made with a special
combination string to perforate, drop guns, release packer, lower string and set
p a cke r w ith scre e n s a cro ss co m p le tio n , a n d g ra ve l p a ck. S ch lu m b e rg e rs se rvice
is kn o w n a s P e rfP a k . A fla p p e r va lve is le ft in p la ce to stop fluid losses after
the gravel pack operation is completed. The test string is run in with a
stinger/tailpipe that breaks the ceramic flapper valve.

CASED HOLE PREPARATION

1. Driller runs bit and scraper in casing, swaps in completion fluid for mud and
circulates the well clean.
2. Service company runs wireline gauge ring and junk basket.
3. Service company runs CCL- Gamma Ray.

SPACING OUT THE LANDING STRING

An example space-out can be found in Appendix C

T h e p h ra se sp a ce o u t re fe rs to th e p ro ce ss o f a d ju sting the in-place length of a specific
section of the test string to conform to a pre-determined fixed length requirement. The
space outs of the landing string and the lower test string are independent operations,
although they might be performed at the same time.
The landing string is spaced out from the fluted hanger upward to some distance above
the rig floor. The space out is simple and unchanging, except for deciding how much
vertical clearance to allow between the lower master valve under the flowhead and the
rig floor to allow for rig heave and tide changes.
Large tidal cycles and rig heave will impact the space out of the landing string. When
the first run with the landing string is made (without the fluted hanger/SSTT, but with the
lower test tools), the tubing should be marked at the rig floor using the index line. The
tide should also be noted. When the test string lands out on the packer, the MPR are
closed on a painted tubing joint. This mark provides the reference position for both the
landing string and lower test string space-out. At the same time a mark should be made
on the guidelines that hold the riser below the riser slip joint.

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This sounds more complicated that it is the purpose of this is to simply record where
the rig was in the tidal cycle when the landing string space out mark was made on the
tubing at RKB.
Once the landing string is spaced out, stands are marked, tallied, and kept segregated
for the several reruns that are required. Normally the subsea safety equipment (SSTT,
retainer valve) is not placed in the initial landing string, but its length is represented with
d u m m y tu b in g .

SPACE OUT OPERATIONS - LOWER TEST STRING

The lower test string space out is a little more complicated and time consuming, as the
final length adjustments indicated by the space out can only be made after the pipe
immediately below the fluted hanger position has been pulled up to the rig floor. But
lower string depth control and space out is much easier to understand if you remember
that the space out in the string below the stack must be directly referenced to the top of
the interval to be tested as shown on the master log. This is done after the hole is cased
with a CCL-GR logging run that is depth correlated to the master log by means of tying it
to a GR characteristic feature above the test interval that is shown on both the openhole
and cased hole log.
In determining the test string length required to span the distance between the fluted
hanger and the top of the interval to be tested (the top shot), the correct space out must
be confirmed or determined by an actual trial fitting. Absolute measurements will not
work. Logging cables stretch with load and higher temperatures, and may also slip a little
in the calibrated cable-measuring wheel. So subsequent log runs are always depth
a d ju ste d to th e m a ste r lo g ru n . A lso , th e lo w e r te st strin g le n g th w ill va ry w ith
temperature and tensile load. This all goes to explain some or most of the differences
typically seen between logging depth and drillers d e p th s.

PRIMARY DEPTH REFERENCE

The master depth reference for locating the bottom of the lower test string for perforating
must be the top of the interval to be tested, as shown on the master reference master
log. Everything to follow must be tied to th e ch a ra cte ristic fe a tu re o n th e m a ste r lo g th a t
delineates the top of the interval.

LOWER TEST STRING SPACE OUT

The procedure to be followed for the lower test string space out will depend on what type
of packer is used, and how this packer is run.

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DEPTH CONTROL AND SPACE OUT: TEST STRING USING A

RETRIEVABLE PACKER

If the packer is a retrievable packer, then the space out operation is conducted with the
test string, made up to its estimated required length below the fluted hanger, hanging
from the fluted hanger seated in the wellhead wear bushing. An RA tagged pup joint is
placed in the test string a few hundred feet up from the bottom. The required depth
control and space out adjustments are determined at the same time by CCL-GR
logging and noting the depth differences between the RA pip mark in the test
string and a GR feature chosen from the first GR-CCL log run after casing was set.
This feature should be about 200 to 400 ft above the top of the zone to be tested.
The CCL (Casing Collar Log)-GR log is examined to make sure that the packer will not
span a casing collar when it is set at correct depth. If it will, the string length below the
packer is changed. The string length between the packer and the top shot is measured.
Note: We are going to have to equate test string increment lengths to wireline measured
depth differences of a hundred feet or so, but any measurement discrepancies will be
relatively small numbers, in the several inches range, as opposed to errors of 10 to 20 ft
that can build over 10,000 to 20,000 ft if measurements are referenced to the surface.
A ll d e p th s a re re fe re n ce d to th o se o n th e m a ste r lo g g in g ru n , in th is ca se th e A IT lo g ,
which should be qualified by date and run number. The top of the zone is at 6356 ft AIT
depth and the top perforation should be at that depth.
1. There is a strong GR feature at 6090 ft AIT depth, on the open hole AIT log. It is
in a convenient position of 266 ft above the top of the zone to be tested.
2. This GR feature at 6090 ft will be used as the benchmark to tie in the depths of
the cased hole CCL-GR log run. The CCL-GR log also responds to this strong
GR, and it is easily recognized. Now the Casing Collar log is also depth
re g iste re d to th e m a ste r d e p th o n th e o p e n h o le lo g .
3. The test string is strapped from the top perforation shot to the RA tag placed in
the test string. In this example, that distance is measured to be 371.3 ft
4. When the test string is at correct depth, the top perforation will be at 6356 ft AIT
depth, and the RA tag will then be (371.3 to 266 ft) or 105.3 ft above the
benchmark GR feature.
5. The string is run to approximate depth without setting the packer. The string is
logged hanging in tension with CCL-GR and the difference in depths between the
RA tag and the benchmark GR feature is noted.
6. The amount the string below the fluted hanger has to be adjusted for the top shot
to be on depth is calculated, including adjustments for desired slip joint
compression (about half extension available and seen in this logging run), jar
compression, and packer stroke.
7. Check CCL and space-out before GIH to make sure that the retrievable packer
will not be set in a casing collar when on correct depth. Adjust packer setting
depth or string length between TCP guns and packer as required.
8. Insert or remove joints and pups as necessary. Run string, re-run CCL-GR log as
double check if necessary, set packer, lower string to rest on fluted hanger.

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Note: In this example there was a strong, distinct GR feature conveniently located about
250 ft above the interval to be tested. This is not always the case, and if the GR log
signals are fairly weak and not particularly distinctive, there might be some ambiguity in
the depth registration process for the test string. This is because the detected response
from the GR log is attenuated through casing, and gets even weaker when logged from
inside the test string.
A solution to this problem, and a great help in any case, is putting an RA tag in the
casing itself. The first CCL-GR log run in open casing is used to tie the RA casing tag
in to th e m a ste r d e p th o f th e re fe re n ce lo g . O n ce th is is d o n e , fu tu re lo g s n e e d o n ly to
see the strong casing RA pip mark for positive tie ins. Another RA tag is still placed in
the test string. The approximate depths of the casing and test string RA tags should be
coordinated so that they are about 100 to 200 feet apart when string is on depth so that
there is no mistaking which RA pip mark is on top.

DEPTH CONTROL AND SPACE OUT USING A PERMANENT PACKER

When a permanent packer or gravel pack sump packer is employed, depth control and
the test string space out are two separate operations. The permanent or sump packer is
normally run in on wireline and set at the required depth using the CCL-GR log. Once
the permanent or sump packer is set, all subsequent space-outs (and perforating) are
performed from that packer depth.
With the retrievable packer, the depth registration is done with the GR-CCL log as with
the retrievable packer example just discussed. But picking the feature to depth correlate
to is probably more clear cut since the CCL-GR log should be essentially identical to the
original CCL-GR log, as both are run in open casing. Given the strapped distance from
the CCL-GR reference point on the logging tool to the top of the packer, setting the
packer at specified distance above the top of the interval to be tested is straightforward,
once the GR-CCL log is depth correlated to the original GR-CCL log.
The space out of the test string is different than for the retrievable packer case in that the
packer is already set at the correct depth. The lower string for space out is essentially
the same as will be run for the test, except that it has no fluted hanger.
The test string is made up, and a painted stand or two of tubing is placed in the string at
the position estimated to be where the pipe ram in the BOP stack will seal on the string
swhen it is fully seated in the permanent packer. Normally a white oil-based paint is used
and it is applied when running through the rotary, so that it is still soft enough to hold the
mark of the rams. To properly space out to determine the correct position of the fluted
hanger, the seal locator assembly in the lower test string is fully seated on the packer, as
determined by string weight loss. The MPR are then closed on the painted joint and
simultaneously the tubing is marked at the rig floor, using the index line (for the landing
string space-out discussed previously). Once the string is pulled up past the painted
stand, the exact location for the fluted hanger can be determined from the ram marks
and the internal dimensions of the BOP stack.
The fluted hanger is placed in the string in the proper position using pup joints. For a
typical floating test, 15 to 20 pup joints (minimum) of varying lengths are required. Some
w ill b e u se d fo r h a n d lin g p u p s (o n th e va rio u s te st to o ls), b u t m o st a re n e e d e d to
ensure proper subsea and landing string space-out.

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FINAL ASSEMBLY OF LANDING STRING

Once the final fluted hanger position has been determined by space out, the key
co m p o n e n ts o f th e la n d in g strin g a re in se rte d in to th e strin g , re p la cin g d u m m y
components used for space out. The subsea safety equipment (SSTT, retainer valve
and lubricator valve) is inserted as the string is RIH. The control lines for the subsea
safety equipment and any injection lines are run with the landing string at this time. The
seal assembly is stabbed in the bore, the string lowered until the fluted hanger is seated
on the wear bushing. If slip joints are utilized, the space out should allow them to be one-
half to two-thirds extended.

13.11.5 BASIC TEST PROCEDURES

PERFORATION AND INITIAL FLOW PRESSURE BUILDUP

If in-place gravel packing is to be employed, then perforation will take place well before
the final test string is in place, and it will usually be done overbalanced with no flow to
surface. However, some of the main issues are the same for perforate-and-pack as the
perforate-and-flow operations. These are:
1. Type of gun, charge, shot density and phasing pattern.
2. How guns are to be fired.
3. If and when guns are to be dropped.
4. Type and location of bottomhole pressure gauges to run (if any).
5. Underbalance for perforation.
6. Type of cushion.
7. Well open at surface or closed at perforation.
8. Amount of flow desired immediately after perforation.

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11.11.6 PERFORATION, INITIAL FLOW, INITIAL PBU

PROCEDURE

BACKGROUND FOR PROCEDURE EXAMPLE

The perforation procedure summarized below is a simple one-step perforation procedure

run before a standard gravel packing operation (as opposed to a single run perforate
a n d g ra ve l p a ck o p e ra tio n , a s w ith P e rf-P a k).
A gravel pack sump packer has already been set using the GR-CCL log to tie into the
re fe re n ce o r m a ste r o p e n h o le lo g d e p th s. In itia l d e p th re g istra tio n w ill b e b y sn a p p in g
the string into the sump packer, and pulling up required distance.
The current status of the well is summarized, giving casing program, casing shoe
depths, drifts run on casing, top of cement and maximum wellbore angle. Measured and
T V D d e p th s (b o th in re fe re n ce m a ste r lo g d epths) of the interval to be perforated are
listed, and the pore pressure of the interval, as well as overbalance with the completion
fluid in place.
The TCP gun type, diameter, charge, shots per foot and required underbalance for
shooting are listed. The perforation work string make up is described, with drifts given for
each pipe size weight.

PERFORATING PROCEDURE

A step-by-step TCP perforating procedure summary is given below:

1. Make up perforation string using minimum pipe dope on pin ends to avoid any
pipe dope in annulus or pipe. String to include these major tools going from
bottom up:
Snap latch, bull nose, required length of TCP guns, safety spacer, gun-firing
heads (drop bar primary with hydraulic backup).
Ported circulation sub, tubing joint(s).
RA tagged sub (optional) with tubing to surface.
2. RIH with string to specified depth, snap into sump packer.
3. Pick up from sump packer specified distance to space out guns across interval.
4. Circulate an LCM pill (through the ported sub) into the annulus above the guns
(pill can be clear fluid but more often contains CaCO3 LCM material).
5. Load drop bar into control head with lower master valve closed. Close upper
valve and open lower master when ready to drop bar.
6. Monitor fluids on trip tank and note when guns fire. Record drillpipe and tubing
pressure for 15 to 30 minutes until stabilized.
7. Sting back into sump packer (to ensure wellbore is clear), and POH with TCP
guns. Spot additional LCM pill if losses are excessive.

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RUNNING STRING, TESTING, SRO, BHS, KILLING WELL AND TPA

Background on Example - This procedure picks up after the completion has been
gravel packed in the conventional two step procedure. A permanent gravel pack packer
with seal bore assembly has been set about 100 ft above the gravel pack screens.
The well is filled with 10.3 ppg CaCl2, and is about 400 psi overbalanced. The
perforations have been open most of the period since between the perforation run until
present. Fluid losses were controlled by spotting a LCM pill. The CaCO3 contained in
the LCM pill was dissolved by HCl acid immediately prior to gravel packing.
The memory gauges will normally be in a carrier located above the gravel pack packer.
However, if gauges must be closer to the formation, they can be run on a tail-pipe
assembly into the gravel pack assembly.
The lower test string main components will be: a seal assembly, an APO tester valve,
pressure gauges (with an optional system for surface readout of bottomhole pressures),
and a multi-cycle reversing valve. The string will also contain a tubing pressure test
valve to facilitate pressure testing the string as it is assembled and RIH. For space out,
the string is run with a soft painted stand to locate the fluted hanger, as in the previous
e xa m p le in S p a ce O u t w ith a P e rm a n e n t P a cke r.

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PROCEDURE TO MAKE UP AND PRESSURE TEST STRING

1. Program MRO gauges, place in carrier assembly.

2. P/U seal assembly with snap-latch indicator.
3. P/U tubing fill and test valve, annular sampling chamber, confirm operating
pressures.
4. P/U programmed gauges in carrier.
5. P/U HRT, PCT, with PCT locked open, confirm operating pressures.
6. If surface read-out is required, P/U Data Latch assembly.
7. P/U sand barrel, multi-cycle indexed circulating/reversing valve, confirm
operating pressures.
8. P/U SHORT, confirm operating pressure.
9. P/U one stand of tubing and pressure test assembly.
10. P/U test tubing. Pressure test immediately prior to picking up painted joints.
11. M/U 90-ft stand of tubing, painted white with oil-based paint and semi-dry.
12. Continue to P/U test tubing.
13. Stab into GP packer with seal assembly and snap seal assembly in bore to
seal locator.
14. Unsnap from locator, snap back in and adjust motion compensator to neutral.

DO LOWER TEST STRING AND LANDING STRING SPACE OUTS

15. Mark tubing at rig floor using the index line, and note position of rig in tidal cycle.
Mark white painted stand in BOP stack by shutting VBR pipe rams on it.
16. Pull string up to painted stand and determine fluted hanger position.
17. P/U pre-assembled section consisting of crossover, fluted hanger, slick joint,
SSTT, shear sub, retainer valve.
18. Attach methanol injection lines. Attach control line bundle.
19. Function test SSTT tools, noting time to complete the disconnect via the control
hose umbilical. Note: The disconnect time will be the critical component of
emergency disconnect procedures, especially for dynamically positioned rigs.
20. RIH with rest of landing string, feeding control bundle and injection lines, affixing
to landing string with protective fixtures. Dual slips or special spiders made for
running umbilicals should be used.
21. P/U pre-assembled lubricator valve section, M/U, add control lines. Pressure test
assembly against tubing tester valve.
22. Add stiff joint(s) and space out flowhead with the bottom connection on the
surface test tree, spaced out such that it will remain at least 10 ft above the rig
floor at high tide and with rig heave.

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23. Attach 40 to 45 ft long bails to support flowhead. M/U Coflex hose to wing valve
of flowhead and to the kill side of the flowhead (connected to cement unit).
24. Stab seals in GP packer. Observe weight while travelling additional distance prior
to seating the fluted hanger on wear bushing. Adjust motion compensator to
slack of the weight of the string below the fluted hanger. Lower master valve
should be at least 10 ft above the rig floor at high tide and upward rig heave.
25. Close middle VBR rams and test packer seals .

RIG UP FLOWHEAD AND PRESSURE TEST TO CHOKE MANIFOLD, FINAL

PRESSURE TEST OF TEST STRING ASSEMBLY

26. R/U Coflex hoses (kill side to cementing unit, flow side to choke manifold).
Close master and swab valves, open Manumatic valve, and flush across
flowhead, filling lines to choke manifold with completion fluid.
27. Close choke manifold, and pressure test equipment and connections from the
lubricator valve up through the surface spread and cementing unit. Close
Manumatic, bleed off pressure through choke manifold.
28. Close lower VBR rams and pressure annulus to unlock PCT from HOOP cycle
and disable the tubing tester valve. Bleed off to close PCT. Perfs are now
isolated by packer and closed PCT.
29. Cycle the circulating/reversing valve open with tubing pressure, and load the
tubing string with cushion fluid (base oil or diesel), being careful to not pump any
base oil into the annulus.
30. Cycle circulating/reversing valve closed. Note: The first hydrocarbon to surface
should occur only during daylight. Hence the PCT should remain closed until
ready to initiate flow.
31. Equalize pressure across the PCT valve by pressuring up on the tubing from the
cementing unit.
32. Line up choke manifold. Open PCT with annulus pressure.
33. Flow well as per the well test protocol.

COMMENCE DUAL FLOW-DUAL SHUT-IN PROCEDURE

(see Section 12 - Test Execution)
T h is p a rt o f th e p ro ce d u re is co ve re d in th e se ctio n T e st E xe cu tio n th a t fo llo w s.
It covers the DFDS test a n d se ve ra l co n tin g e n cie s in ca se th e w e ll d o e sn t flo w in itia lly.
The overall procedure picks up below at the point where the well has been shut-in at the
PCT for the final pressure buildup.

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PRESSURE TEST W/L LUBRICATOR, RUN SRO LINC TOOL TO

DATALATCH DOWNHOLE

1. Shut the well in at the PCT by bleeding the annular pressure to zero.
2. Keep the surface lines and choke manifold open and allow the test string
to depressure to 100 to 200 psi (monitor PCT for leaks). Then shut-in at
choke manifold.
3. R/U W/L lubricator, R/U Link SRO tool, pull up into lubricator barrel.
4. Isolate flowhead at wing (Manumatic) and kill line valves, close lubricator valve
below rig floor.
5. Pressure test W/L lubricator to lubricator valve with glycol-water mixture,
pressure test to 5000 psi. Bleed off pressure to equalize across lubricator valve
below rig floor, and open lubricator valve.
6. RIH with Link SRO tool and latch into DataLatch assembly, download memorized
data, monitor and record pressure buildup data real time at surface pressure.
7. Download data to external media every 4 hours or as requested by test engineer
or specialist.
8. When buildup is ended, POOH with Link SRO tool.

IF WIRELINE SAMPLES ARE REQUIRED

9. Bleed tubing pressure to zero and fill with diesel or base oil, close lubricator
valve, and P/U the BHS string into W/L lubricator barrel. Pressure test lubricator
using base oil (to prevent completion brine from contacting gas and forming
hydrates).
10. Pressure annulus to open PCT, cycle to hold open position. Note that on DP rigs,
wireline sampling is normally restricted to staying above the PCT valve, and the
PCT valve should never be cycled to hold open unit pulling out of the hole
following the test.
11. Load tubing with base oil, and pressure up flowhead to equalize pressures
across lubricator valve. Open valve, and RIH with BHS string.
12. Once samplers are in place, open well on small choke (#8 est.) and flow well at a
low rate as instructed by the EMEC testing specialist.
13. POOH with BHS string, close lubricator valve, and bleed off pressure above
lubricator valve. R/D BHS string from lubricator, check samples for validity
(buBble point pressure check).
14. When bottomhole samples are validated, R/D W/L lubricator, cycle PCT out
of hold open cycle to closed position with annular pressure cycles.
15. Reverse Out Test String.
16. Open upper master valve on flowhead and equalize pressures across
lubricator valve.

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17. Open lubricator valve and apply tubing pressure cycles to open the MIRV.
18. Open Manumatic to surface equipment. Reverse circulate completion fluid, one
tubing volume above the MIRV. Stop when tubing is full of completion fluid.
19. Flush the surface lines.
20. Circulate completion fluid down tubing at 2 BPM to ensure MIRV open, increase
rate to 4 BPM, shut down pump when MIRV closes.
21. With tubing down to MIRV full of 10.3 ppg completion fluid, differential pressure
across PCT should be about 200 to 300 psi top down. This is OK to function
PCT, but check with last buildup pressure from SRO Data Latch.

KILL AND TEMPORARY ABANDONMENT PROCEDURE

22. Cycle annular pressure to lock PCT into hold open position. Well will probably
take fluid due to overbalance.
23. Bullhead 90 Bbls. of 10.3 ppg completion fluid into perfs, monitor well to
ensure dead.
24. Open lower VBR rams and pull seal assembly out of GP packer bore.
Reverse circulate two tubing volumes.
25. Open ram used for conventional reverse circulation and circulate bottoms up
conventionally.
26. POOH and lay down landing string and test string.
27. RIH with GP plug and sting into GP packer. Dump 20 ft of sand on plug.
28. Circulate inhibited kill wt. Completion fluid into the wellbore, POOH.
29. RIH and set cement retainer 150 ft below the mudline. Put 100 ft balanced
cement plug on top. POOH.
30. Pull BOP stack while laying down the riser.
31. RIH with corrosion cap, place on subsea wellhead, POOH.
32. Perform seafloor site survey with ROV.

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13.11.7 POLLUTION CONTROL

Pollution control is critical in offshore well testing. In most areas outside of USA,
produced hydrocarbons can be burned, and very little or no oil pollution or sheening
results. But regardless of the method of disposal, pollution control equipment should
be on hand in the event of an incidental oil loss.

DISCHARGE OF COMPLETION AND CUSHION FLUIDS

When reversing out the tubing contents, take whatever precautions are required to
prevent mixing any oil contaminated completion or cushion fluid in with the completion
brine in the pits or annulus.
Do not discharge any completion fluid overboard prior to confirming that the fluid will
meet the requisite discharge criteria for the country in which you are operating.
One potential method of disposing of oil contaminated brine is to reinject it.

SURFACE EQUIPMENT LEAKS, SPILLS

Make use of drip pans under major surface equipment and leak prone junctions.
Ensure that drip pans do not overflow.
Use absorbent pads under leak or spill prone areas where drip pans are not feasible.
If an uncontained spill does occur, make every effort to clean up with absorbent pads,
etc. Do not wash overboard and take care to ensure it does not enter drains.
Corrective action should be taken to contain any leaks or spills on the rig and clean them
u p , w ith o u t a n y o il re a ch in g th e w a te rs su rfa ce . O il sh e e n s ca u se d b y a ccid e n ta l sp ills
should be treated with dispersant. Dispersant will normally be applied by boom-mounted
systems temporarily mounted to a supply vessel or by portable eductor systems
o p e ra tin g w ith p re ssu re su p p lie d b y th e ve sse ls fire m a in . T h e fo llo w in g co rre ctive
actions will normally be followed in the event of an oil spill:
Supplies of dispersant will be maintained on a supply or support vessel.
Oil spill contingency plans are usually included in the operations manual and
addressed in the risk assessment.
Use workboat propellers to cause turbulence to promote mixing the dispersant
with the oil film.
Dispersant will be applied to oil films away from the rig using booms aboard
the workboat.

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13.11.8 EMERGENCY PROCEDURES

EMERGENCY SHUT DOWN

This topic is discussed in Section 13.6 - Surface Equipment

Emergency Barge Disconnect
This topic is discussed in Section 13.8 - Equipment to Flare, Store or Offload
Produced Liquids.

FIRE ON BOARD

Listed below is a general procedure example for securing the surface facilities and well
if a fire occurs during the test. Circumstances make the sequence of steps in this
procedure inappropriate, depending on the source, size and location of the fire.
1. Trigger the surface ESD system which will shut-in the well at the flow line
isolation valve (if present), and the Manumatic valve on the flowhead.
2. Activate the portion of the subsea safety system, which closes the ball valve on
the SSTT. Close the downhole shut-in valve (i.e. PCT).
3. Close the master valve and the crown valve.
4. With the cementing unit, pump water through the surface lines, separator and
burner to flush all hydrocarbons from surface equipment. Do not do this if fire
is being fed by leak in surface equipment.
5. Kill the well by bull heading and/or reverse circulating the well. Note: Be ready
to disconnect the subsea test tree at the hydraulic (or mechanical) latch and
the riser at the hydraulic connector in case the drilling vessel has to be moved
off location.

BAD WEATHER

Weather, such as high wind and waves and strong currents threatening to push a rig
off-station can necessitate an emergency disconnect. Emergency disconnect may also
be necessary because of a drive-off/drift-off, loss of mooring lines, the failure of
equipment or well control problems.
1. If there is a predictable, reasonable probability of losing station in the near future,
end the test and kill the well as follows:
a) Stop test by shutting well in at bottomhole tester valve. If wireline is in test string
POOH. Close master and swab valves.
b) Kill the well by displacing the tubing and the casing below the packer to the
bottom perforation with 10 barrels of base oil followed by kill weight completion
fluid. Over displace perforations by 5 barrels.
c) Monitor tubing and annulus pressure.

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d) Prepare to disconnect landing string at SSTT, pick up a distance sufficient to

place the released SSTT inside the riser above the LMRP disconnect point.
e) If necessary disconnect the marine riser from the BOP.
2. In the event that an emergency disconnect at the SSTT and at the riser connector
becomes necessary, a disconnect during testing procedure should be applied.
This procedure should be addressed during the risk assessment, and drills should
be conducted prior to well testing operations.

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13.12 TEST EXECUTION

13.12.1 INITIAL FLOW

A safety meeting, rig abandonment, and fire drills are held prior to the initial flow.
Since there will be no surfacing of reservoir fluids with initial flow, it can be initiated at
any time of the day. The well will be opened and shut-in at the downhole tester valve.
The well can be shut-in or opened at the choke manifold as per procedure. This will
depend on several factors, such as if perforation was just prior to initial flow, the initial
flow volume, and the type of cushion (full liquid, air gap, or full N2 cushion).
After the initial flow period, the well will be shut-in at the bottomhole tester valve until
main flow begins. Precautions must be taken to ensure formation fluids stay below the
downhole tester valve. If gas were to migrate upward to the mudline, hydrates would
likely form inside the test string.

13.12.2 MAIN FLOW

PRE-FLOW CHECKLIST
All surface equipment is pressure and function tested with the well open from tester
valve through to choke manifold, which is closed. Pressure is balanced across tester
valve. Downstream surface equipment is open. Separator is bypassed to surge tank.
Burner pilots are lit.
Barge, if used, is moored in position with flow line hooked up, tankermen (on rig and
barge) are in communication.
The main flow is not to begin in darkness, and not to begin if reservoir fluids will not
surface in daylight.

13.12.3 UNLOADING WELL

Design and oversight is the responsibility of the EMDC testing specialist, in consultation
with the drilling engineer and rig supervisor.

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UNLOADING CURVE
An unloading curve should be prepared in advance (by the EMEC testing specialist)
using bottom hole pressure data and maximum pressure drawdown limits. It should be
used to help keep the bottomhole pressure drawdown within predetermined, acceptable
limits. It uses the simplifying assumptions that
1. No water is being produced from the zone.
2. Piston displacement of the load fluid occurs.
3. That frictional pressure drops are negligible.
These all combine to make this curve conservative. However, it should be honored until
we are reasonably certain that honoring it will kill the well. Recovery of completion fluids
lost to the formation, water influx, gravel pack failure (or screen plugging) or no effective
permeability will be the cause.

UNLOADING PRECAUTIONS
T h e o p e ra tive p h ra se h e re is E a sy d o e s it. N o th in g is g a in e d b y g e ttin g ro u g h with a
new well early on and irreparable damage can result. So usually the choke manifold is
configured with a No. 8 (1/8 in.) positive choke on one side, and the variable choke on
the other. Opening the well on a small choke initially ensures that either:
1. There is communication to the reservoir.
2. Or, there is a problem.
If there is a problem, opening the well on a large choke can aggravate the problem.
Note, however that the well should be brought on at a fast enough rate to ensure brine is
unloading from the wellbore.

OBSERVE STATIC WHP

Open the well downhole at the tester valve with the well shut, observe WHP, and let
stabilize. It should stabilize at formation pressure minus the hydrostatic pressure of the
cushion. If not, the tester valve may not be open.

START UNLOADING THE WELL VERY SLOWLY

Open well on No. 8 choke and observe for several minutes. The wellhead pressure may
drop for a few seconds, but should recover and stabilize as the well begins to flow
slowly. If wellhead pressure drops significa n tly a n d d o e sn t re co ve r, th e n th e w e ll sh o u ld
be shut-in at the surface and the problem diagnosed.
A t th is p o in t, th e w e ll te st se rvice co m p a n y w ill b e g in re co rd in g d a ta fo r its C le a n u p
D a ta S h e e t. T h e se d a ta w ill b e tim e w e ll o p e n e d , in itia l w e llh e a d pressure, and at 5 to
15 minute intervals, the time, choke size, FWHP, cum volume produced. Field samples
will be taken at the choke manifold for water cut shakeouts and water chlorides analysis.
As soon as gas surfaces, it must be checked for H2S and CO2, and produced fluid
properties, which initially will be those of the cushion fluid.
Also, downhole methanol injection, if required, should be started at this time at maximum
rate called for in procedure.

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After about 5 minutes of observing normal wellhead pressure behavior on the No.8 fixed
choke, the flowstream should be diverted to the variable choke side of the manifold to
proceed with the unloading. The flowing wellhead pressure should be controlled with the
variable choke to honor the unloading curve.
The well unloading should proceed honoring the unloading curve, which relates
minimum permissible flowing wellhead pressure to the cumulative volume of the cushion
produced. Because the flowstream is not normally routed through the separator at this
stage, some sort of gauging or a surge tank must be used to measure the cumulative
volume of cushion liquid produced. As well unloading progresses, the variable choke is
opened further as permitted by the unloading curve.
Normally a good well left on an appropriate choke setting will pretty much follow the
flowing wellhead pressure versus load water produced curve. In other words, a good
well will usually unload itself properly if it is properly choked back. However, sometimes
th e w e ll w o n t u n lo a d , a n d th e u n lo a ding curve can act as guide to help determine what
is going on.

FLOWING WELLHEAD PRESSURE BEHAVIOR DURING CLEANUP

Usually, one of three general types of WHP responses occurs during the unloading
effort, once flow is underway and the choke size is increased to produce a FWHP within
safe limits as indicated by the unloading curve:
1. The unloading proceeds with increasing FWHP and rate to cleanup, and follows the
unloading curve without further choke changes.
2. The unloading process begins to die slowly, and FWHP drops slowly with production.
Small (or large) increases in choke size do not appreciably help. Soon, the unloading
curve cannot be honored. If allowed to continue, the flow dies out exponentially.
The problem here is probably entry of kill weight completion fluid previously lost to
the formation. This can be verified by gradient logging in the tubing or just discerned
by well behavior. If so, the tubing contents will have to be reversed out, the cushion
will have to be re-spotted and the unloading process restarted. The original
unloading curve will now have more limited use, only as a rough guide.
3. If a large amount of completion fluid was lost to the reservoir in prior operations, not
all of it will be recovered before the well will unload. Normally, only about 30 to 40%
of lost completion fluid is recovered in bulk, killing the well. After that amount of
recovery, the waters cut drop sharply, down to about 1% to 3%, permitting the well to
finally unload with a fresh cushion.
The unloading process ends prematurely and rather abruptly. Flow rate and well head
pressure drop quickly. The temptation here is to open the choke wide open, but a well
sh o u ld n e ve r b e o p e n e d u p o n a la rg e ch o ke if th e w e ll h a s d ie d u n d e r th e se
conditions. A problem downhole may be limiting flow, and it needs to be diagnosed
and corrected.

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13.12.4 SWITCHING FLOW TO SEPARATOR

Continue taking field samples at the choke manifold for water cut shakeouts and water
chlorides analysis. Take gas samples for H2S and CO2 analysis.
Once the flo w stre a m co n ta in s h yd ro ca rb o n s in a m o u n ts su ch th a t it ca n t b e d u m p e d
pollution free, or stored safely, it must be put through the separator. Spiking the fluids
to the burners with diesel or base oil in an attempt to ensure complete combustion has
been a tte m p te d a n d m e t w ith p o o r su cce ss. H e n ce , co n ta m in a te d in te rfa ce flu id s
should be captured and disposed of by other means (i.e. pumped into the well during
the kill procedure). Oil going to the barge should be segregated from the higher quality
oil to follow.
At this point, the service company will begin recording a more comprehensive collection
of data, and continue to record this data until the end of the main flow period. The liquid
flowmeters will need to be calibrated, but this should be postponed until the well is at
stable rate conditions.

13.12.5 BRINGING THE WELL UP TO STABLE TEST RATE

MAXIMUM RATE TESTS

The client sometimes requests maximum rate tests. They are not usually necessary to
evaluate the reservoir. These are run after the Dual Flow-Dual Shut-in sequence to take
advantage of the prior completion clean up, and to avoid putting the main test objectives
at risk. If the rate has already been determined to be limited by surface facilities or
drawdown, there is no point in doing this test.
Once it is obvious that the well will unload successfully, unloading curve is discarded.
Other methods or criteria will be used to reach the optimum safe and sustainable rate for
the duration of test.
Before upping the rate, carefully monitor water cuts and the adequacy of methanol
in h ib itio n . D o n t p ro d u ce w a te r a t a ra te yo u ca n t in h ib it a d e q u a te ly. W a it u n til w a te r
cut goes down to increase rates if inhibition capacity is limited. In some cases,
production of formation water will necessitate that the test be ceased due to the
like lih o o d o f fo rm in g h yd ra te s. T h is e n d o f te st sce n a rio sh o u ld b e in th e p ro ce d u re
and pre-approved, as the decision may have to be made quickly on the rig.

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SUSTAINABLE TEST RATE

Note that very frequently, all test objectives can be met while flowing the well at relatively
low or moderate rates (2000 to 3000 BOPD). Hence the need for higher rates needs to
be weighted against the cost associated with higher-rate test spread designs. Often the
desire for a high-rate press release cannot be justified.
One of four factors or a combination of them will limit the test rate:
1. Pressure drawdown in the reservoir and across the completion.
2. Pressure drop in the test string.
3. Pressure drop or capacity limits in the surface equipment.
4. Safe rate limits in disposal equipment (e.g., radiant heat from burners).

LIMITS ON PRESSURE DRAWDOWN

Typically, across a new gravel pack, the initial drawdown should gradually buildup to
a maximum of 500 psi during cleanup. Once the water cut drops to below about 3%,
the drawdown can be gradually increased (over several hours) to a drawdown limit
of 1000 psi.
ExxonMobil does not usually run SRO of bottomhole pressure data during cleanup or
main flow periods. Therefore, some means of estimating flowing bottomhole pressure
(FBHP) from observed surface parameter must be employed to keep from exceeding
drawdown limits during the test. Programs such as Nodal that calculate multi-phase
flowing pressure drops in vertical systems should be used to simulate the test string
pressure drops over a range of representative conditions. These results for a number
of cases should be available at wellsite.
Additional cases may need to be run once more fluid property and GOR data become
available. Flowing bottomhole pressures will be calculated or estimated marching
downhole using parameters measured at the surface as the main flow progresses.
Note that these calculations for FBHP may have substantial errors, especially in higher
GOR oil wells. In these cases, the major component of the pressure drop, the
hydrostatic component, is very sensitive to phase behavior properties which vary due to
sharp temperature and pressure changes coming uphole.

PRESSURE DROP IN TEST STRING LIMITS RATE

This is rare but can happen in very productive but low pressure gas reservoirs (which
usually are not tested from an expensive floating rig). It should not happen in other
cases if the string is properly sized.

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PRESSURE DROP IN SURFACE EQUIPMENT LIMITS RATES

This is fairly common with moderate to high GOR, productive oil wells and gas wells.
As the choke is opened and the rate is increased, the pressure downstream of the choke
increases due to backpressure from the surface equipment. In many cases, the
separator pressure has to be raised to push the gas through the flares. If the well
is stable and the separator is operating smoothly, the separator control pressure
effectively takes over controlling the wellhead pressure as the choke size is increased.
The choke is effectively out of the control loop, although still in the flow path.
Unexpected high draw-down may need a supplemental acid job or a back flush through
the in-line screens. An SRO run, if available, is one means of confirming completion
damage or plugging.

SAFE CAPACITY OF SURFACE EQUIPMENT OR DISPOSAL EQUIPMENT

LIMITS REACHED
The separator design capacity or its practical capacity may be reached. Oil may be
carried out the gas line or entrained gas vapor may flow out the oil line. These conditions
cause poor rate measurements, make pollution more likely, and may impact safety.
Obviously this cannot be tolerated and the rate must be decreased. The separator
operator should be able to make the judgement - is this the limit of the separator or could
some online adjustments correct the problem?
Oil and/or gas rates may be limited due to disposal. Safe heat flux output from the
burners may be reached while the well itself and the rest of the surface equipment still
has a way to go. Noise levels from high flow rates through the equipment or burners may
be excessive, even with ear protection.
Oil barge capacity may limit to below the maximum rate.

JUDGEMENT BY SUPERVISORY PERSONNEL THAT MAXIMUM SAFE

RATE HAS BEEN REACHED
A consideration of the above factors may go into a decision that the rate should not
increased further. The test design will usually state a target rate, and if that rate is
reached, and some of the limits just discussed seem to have been approached, then
there is a good case for stopping rate increases, perhaps backing off a little, and
maintaining the current rate for the remainder of the test.

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13.12.6 BACKING OFF MAX RATE TO SUSTAINABLE

STABLE RATE
If the maximum rate seems to be limited by the reservoir/completion, or by safety or
environmental concerns, then it is usually wise to back off the perceived maximum rate
by about 10% to give better assurance that the rate can be maintained for the duration of
the test. However, if the rate seems limited by the completion, and the completion
continues to clean up, then a rate back off may not be necessary. Sometimes the
completion (esp. gravel packs conducted with high fluid losses) will clean up over days,
and a continual small increase in rate may occur on same choke setting.

SEPARATOR LINE OUT

The separator operator is responsible for bringing the separator online, selecting the
optimum operating pressure, liquid level control points, and trimming out the pneumatic
control system. Other specific duties include:
1. Monitoring pressures and oil and gas flow rates for separator operating
problems. Wildly fluctuating rates could indicate surging, foaming, trash in control
valve or orifice plate, low liquid level, carryover, rig heave or blow-by.
2. Making sure the right size plates are in the orifice meter, that the meter is
calibrated, and that there is no liquid in the meter body or differential
pressure lines.
3. Supervising the taking of separator samples for a shrinkage estimation.
This is critical and is used to convert separator barrels to stock tank barrels.

SURGE TANK
If surge tanks are used, keep records of temperatures and pressures. These will be
needed to make adjustments to the separator shrinkage factor just measured.

HYDRATES
Follow the downhole methanol injection program until produced water rates, salinities,
wellhead pressure and temperature indicate adjustments should be made.
Watch for line frosting and monitor temperatures of surface equipment. Methanol
injection at surface may be required to supplement downhole injection.

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13.12.7 SAMPLING
Usually, three to four sets of surface separator samples are taken during the main flow
period. The first set is taken soon after flow has been routed through the separator,
water cuts are stable, and the separator rates and operating conditions are all stable.
This is a contingen cy sa m p le se t, a n d p ro b a b ly w o n t b e u se d if th e m a in flo w p ro ce e d s
successfully as scheduled.
The remaining three sets of separator samples should be taken under stable separator
conditions. If possible, the separator oil flow meter should be re-calibrated just prior
to sampling. A separator shrinkage measurement should be taken at this time.
Separator and surge tank temperatures and pressures should be recorded on the
appropriate forms.
The second set of separator samples is taken about midway through the main flow
period. The last two sets are normally taken right before the end of the main flow period.
Field samples are continued through the main flow. Sampling for H2S and CO2 should
continue through the test, even if none has been found so far. Trace amounts may show
late in the flow period. It is important to document where all of these routine samples are
obtained, and get these locations standardized among the service company personnel,
on all the shifts. Otherwise, results may be confusing.

METHANOL CONTAMINATION OF SAMPLES

Methanol injected into the flow stream cannot be removed. It will concentrate in water if
available. Methanol contamination is not a problem for dry gas wells. For condensate or
oil wells, methanol contamination will affect the PVT analysis results in an unpredictable
manner. Hopefully, methanol injection has already been terminated due to no water
before it is time to get separator samples.
But if methanol injection is still necessary overall, it may be possible to suspend it briefly
for sampling. If this is done, flowstream parameters will have to be monitored
continuously and closely for signs of increased flow resistance. Stopping methanol
injection in oil wells for a brief time is probably a very low risk approach (see Section
13.13). To get further assurance that the oil sample is not contaminated, the water leg
in the separator should be dumped, but the separator operator may not favor this.

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13.12.8 UNEXPECTED (HIGH) WATER PRODUCTION

If th e w e ll d o e sn t cle a n u p in th e m a in flow period but surfaces formation water with a
very high water cut, the well should usually be kept flowing while water analysis confirms
the water is formation water. That is, if there is no hydrate problem or if there is, it is
manageable with inhibitor. Usually the client organization will want to keep the well
flowing long enough to see if the oil cut will increase. It is strongly recommended that the
well be flowed long enough to confirm the water is formation water, and that the oil cut is
not increasing.
Most probably the test will be quickly halted because of hydrate concerns, or lack of
further interest beyond initial pressure, and a calculation or reservoir permeability and
the completion efficiency. The client should be pre-informed of limits on water production
that would cause the test to be halted, and it should be documented in the procedure.
This will enable quick action by the test team on the rig to take the required actions.
The well should be shut-in at the bottomhole tester valve, the tubing contents reversed
out with kill weight brine, and a short pressure buildup may be taken. With a bottomhole
tester valve, acceptable quality data can be obtained in spite of the oil-water mix in the
test string. In the meantime, if mechanically feasible, production logging might be
considered to diagnose the origin of the water production.

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13.12.9 SHUTTING THE WELL IN

After the prescribed length of stable flow, and all required surface separator samples are
taken, the well is shut-in at the bottom hole tester valve. This is done by bleeding off the
annular pressure in the casing to zero.
Hydrates will be a concern at this point if the well was making any water and pressures
in the landing string put the landing string in the hydrate region. So, in most deepwater
well tests, the test string is allowed to bleed down through the surface facilities
immediately after bottomhole shut-in to as low a pressure as practical. This would be to
about 50 to 100 psi wellhead pressure (monitor tubing pressure to ensure the downhole
shut-in valve is not leaking). An immediate bleed down will minimize any impact on the
pressure buildup due to mechanical effects on the gauges above the packer.
There could be some water vapor remaining in the test string, so as a safety precaution,
methanol should be pumped down the tubing or injected at the subsea test tree. If
wireline is to be run in the hole, for SRO of pressure data or any other reason, the
methanol dump should be considered mandatory. Let well sit in this condition,
proceeding with buildup. Monitor the BHP with SRO if available.
Typically, if the well is an oil well and has a moderate to high GOR, the test string will
only contain about 30% to 40% oil by volume after the pressure is bled off. So, at the
end of the main buildup, the test string will have to be filled with diesel or base-oil before
opening the tester valve, or operating the circulating valves. Ensure only hydrate
inhibitor fluids contact the gas in the wellbore. Hydrates have been known to form very
quickly in stationary non-inhibitive fluids.

PROTECTING THE PRESSURE BUILDUP

Every precaution should be taken that the well is not disturbed during the pressure
buildup phase. The only operations in the string above the tester valve should be the
immediate bleed down of tubing pressure, dumping some methanol in the top, or
optionally loading the tubing with base oil, and RIH with SRO if used.

13.12.10 REAL BUILDUP ANALYSIS WITH SRO

If SRO of bottomhole pressures is available, the Test Specialist can begin real time
analysis of the buildup data within several hours of shut-in. The initial analysis will give
a good fix on completion efficiency. As more buildup data is available. A preliminary
analysis of reservoir properties can be made. At the end of the buildup, a preliminary
estimate of any reservoir boundaries or depletion can be made. These results are
q u a lifie d b y p re lim in a ry b e ca u se th e S R O g a u g e s m a y b e fa rth e r fro m th e p e rfo ra tio n s
than the main test gauges, and final results hinge on PVT lab data.

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13.12.11 POST MAIN TEST OPTIONS

BOTTOM HOLE SAMPLING

Bottom hole samples are sometimes specified in oil tests, especially if asphaltene
analyses are required. They are usually not appropriate in gas or gas condensate wells,
except perhaps where trace amounts of or other contaminants are suspected.
Bottomhole samples, if they are to be used in PVT studies, must be taken from a flow
stream that is one-phase. This is theoretically impossible if the oil is saturated at
reservoir conditions. But as a practical matter, the problems associated with this are
minimized if:
1. The well is shut-in for a time prior to sampling.
2. It is flowed at very low drawdown an hour or so prior to and during sampling.
3. Samples are taken as close to the perforations as possible.
The best bottomhole samples are usually taken with wireline because of the flexibility in
locating and timing the sampler. However, due to the ease and efficiency of monophasic
sa m p lin g in sp e cia l a n n u lu s p re ssu re o p e ra te d to o ls (i.e . S ch lu m b e rg e rs S C A R to o l),
wireline sampling is most often avoided.
If wireline samples are required, it will be necessary to rig up the wireline lubricator, refill
the tubing string, pressure test the lubricator (using base oil or another hydrate inhibitive
fluid), load the well with base oil, equalize pressures across the tester valve, and open it.
RIH with the sampler assembly, flow well at low rate/drawdown, and take samples.
On DP rigs, wireline samples are restricted to staying above the downhole shut-in valve
due to the need for the valve to be shut-in in the event of an emergency disconnect.

PRODUCTION LOGGING
If the tested interval is not gravel packed, is thick, and appears to be layered or
non-uniform, production logging may be advised. Preparation for this operation is the
same as for bottom hole sampling via wireline, and the limitations for DP rigs are also
the same. Production logging may involve flowing the well at several rates with
intervening shut-in periods. Pay special attention to the possibility of hydrates forming.
If low salinity water is being produced in any quantity, wireline activities are not
recommended without a very carefully planned mitigation study.

MULTI-RATE TESTING OF GAS WELLS

Multi-rate testing is rarely recommended or required for deepwater exploratory gas wells.
The multi-rate test results are compromised if the well completion is still cleaning up
during testing. This is generally the case for a deepwater gas well test, especially if it
has been gravel packed.
For any gas test, a detailed hydrate analysis should be performed, and sub-mudline
methanol injection equipment will likely be required.

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13.12.12 WRAP-UP

DATA COLLECTION
Before leaving the rig, the Test Specialist should obtain and check the pressure gauge
data from the bottommost gauges (non-SRO) after the test string is pulled. All surface
data and downhole pressure data should be collected as per Section 13.9.

SAMPLE LABELING AND SHIPMENT

Instructions should be given to service company personnel regarding disposal of all field
samples. Test Engineer should ensure that all samples destined for lab or crude assay
analysis are in proper containers labeled for shipping, with accompanying instructions.

PRELIMINARY REPORTING
The Test Specialist should complete preliminary buildup analysis before leaving the rig,
if p o ssib le . T h e P ro d u ctio n T e st S u m m a ry fo rm D -16 should be completed, and
distributed. It should be clearly noted that the results are preliminary. A preliminary draft
of a summary analysis of the overall testing operation what went well and what needs
improving, and any recommendations should be circulated to Drilling and
clients/partners as soon a practical.
Completion of the final report on the well test must await receipt of the PVT laboratory
analysis results on the samples.

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13.13 SPECIAL SITUATIONS

13.13.1 H2S, GAS HYDRATES, AND FLOW BACK TESTS

Two situations which require special planning and heightened precautions during the
execution of a deepwater production test are the possible presence of hydrogen
sulfide in the produced fluids and the likelihood of gas hydrate formation.
Unexpected, hazardous levels of H2S in the produced fluids can be extremely
dangerous and will probably require the test be terminated. The possibility of H2S in
deepwater well tests commands special attention due to the number of personnel on
the rig in a relatively confined situation.
Hydrate formation can restrict flow and prevent the passage of wireline tools, or even
completely plug the well flow path and bring the test to an abrupt halt. Dealing with the
aftermath of a complete plug-off and high trapped pressures in the test string is a
delicate and dangerous operation, not to mention time consuming. Deepwater wells are
much more prone to hydrate, especially near the mudline, than other wells. Hydrate
formation must be prevented through proper planning, use of inhibitive fluids and a
proper inhibition program.
Flow back testing is discussed at the end of this section only because it is a special
situation under production testing, not because it has any special connection to H2S or
gas hydrates.

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13.13.2 HYDROGEN SULFIDE: PROPERTIES AND EFFECTS

Hydrogen sulfide (H2S) is a corrosive and extremely toxic gas, ranking just beneath
hydrogen cyanide in the toxicity table. It is colorless, collects in low areas because it is
heavier than air, and is explosive over a very wide range of concentrations in air.
Fortunately H2S has an extremely offensive and penetrating odor at concentrations
well below lethal and even harmful concentrations. Unfortunately, after a short exposure
to m ild ly h a za rd o u s le ve ls o f H 2 S o n e s se n se o f sm e ll is to ta lly d e a d e n e d b y it.
The presence of H2S in the production stream requires special procedures for
conducting the well test and testing equipment that has metallurgical properties
compatible with the H2S environment. Most test equipment from leading suppliers
patronized by ExxonMobil will be specified to tolerate H2S at the very low maximum
levels generally considered safe from a deepwater operations perspective. However,
this should not be assumed across the board.
B u t te st e q u ip m e n t is u su a lly n o t th e w e a k lin k, e xce p t in h ig h te m p e ra tu re , h ig h
pressure H2S applications. Here, elastomer, seal and metallurgical technology may be
the weak link. H2S causes sulfide stress cracking or embrittlement of steels, depending
on steel composition, hardness, and presence of water. These hostile conditions
always require special engineering studies and equipment testing programs, as well
as safety programs.
DECISION TO PLAN FOR H2S
The potential for encountering H2S while well testing must be addressed during the well
test planning and design stages using all available pertinent data. Later, during drilling or
wireline formation testing, there will usually be some indication of H2S, if moderate to
high concentrations are present in the reservoir fluids, but not always. Moreover,
reservoirs with only trace to low concentrations of H2S (less than 10 to 20 ppm) may
not show measurable H2S content prior to flowing, even during the first several hours
o f flo w in g . T h is d e la y is ca u se d b y th e strip p in g a ctio n o f th e m u d filtra te (e sp e cia lly in
water-based muds) and to a lesser extent, the adsorption of H2S on steel surfaces
inside the test string. H2S is extremely soluble in water and quite soluble in oil. Water
can physically contain dissolved H2S in concentrations up to 29,000 ppm. So areas
where produced water or oil is vented to or open to the atmosphere may collect lethal
concentrations of H2S.

The decision to make special preparations for H2S usually hinges on the expectation
that H2S concentrations will exceed 10 ppm in the produced fluids. This is a safe, very
conservative H2S level guideline from the standpoint of toxicity to humans, because
10 ppm of H2S is considered harmless for 8 hours of continuous exposure, day in, day
out. There is another condition imposed by equipment considerations. It is that the
p a rtia l p re ssu re o f H 2 S m u st b e le ss th a n 0 .0 5 p si. T h is is e xp la in e d in H 2 S a n d
E q u ip m e n t b e lo w .

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LEVELS OF H2S TOXICITY, TERMINOLOGY

Three common standards are used to quantify the toxicity levels of gases. They are:
Threshold Limit The highest concentration to which workers may be exposed, day
after day, 8 to 12 hours per day, without harm. This is 10 ppm for H2S.
Hazardous Limit T h e lo w e st co n ce n tra tio n th a t is like ly to ca u se d e a th a fte r a n h o u rs
exposure. This is 250 ppm for H2S. People in poor general health or with respiratory
p ro b le m s m a y su ccu m b w ith le ss th a n a n h o u rs e xp o su re to le ss th a n 2 5 0 p p m .
Note: There is a broad range between the Threshold Limit and Hazardous Limit.
H2S can be hazardous to health when exposure exceeds 2 to 5 minutes at levels
of 80 to 100 ppm.
Lethal Limit The lowest concentration that will cause death after short term exposure
of about 2 minutes. This is 600 ppm.
The upper concentration limit for an unprotected worker intermittently exposed is 20
ppm. At concentrations above 20 ppm, the worker must wear a breathing apparatus
appropriate for the job ergonomics and duration of exposure.

H2S EFFECTS ON EQUIPMENT

C o n ce n tra tio n s o f H 2 S in th e p ro d u ce d te st flu id a re cla ssifie d a s L o w C o n ce n tra tio n
a n d H ig h C o n ce n tra tio n fo r th e p u rp o se s o f e q u ip m e n t se le ctio n a n d sa fe o p e ra tio n
practice.

Low Concentration: Less than .05 psia partial pressure of H2S.

Where: Partial pressure = pressure x volume fraction of H2S in the flow-stream.
Example: 50 ppm @ 1,000 psia = .05 psia partial pressure.
5 ppm @ 10,000 psia = .05 psia partial pressure.

High concentration: Exceeding .05 psia partial pressure of H2S.

Anytime a test is being performed with non-H2S resistant equipment and the presence
o f H 2 S in H ig h C o n ce n tra tio n is d e te cte d , th e te st sh o u ld b e te rm in a te d a s so o n a s
safely possible. Termination of the test should be accomplished by downhole shut-in,
if possible, and then reverse circulation of the wellbore fluids out of the test string as
soon as possible. Further tests must then be conducted according to the requirements
for known H2S presence.

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SAFETY EQUIPMENT AND SERVICES

Preparations for H2S involve special equipment and procedures to handle the corrosive
aspects of H2S and safety equipment as shown below:
Remote-supplied air breathing apparatus, with lines, manifolds and
breathing masks.
Self-contained breathing apparatus (SCUBA type).
Detectors, monitors and alarms.
Liberal placement of windsocks, ventilating fans, etc.
Specialized training or certification in H2S by all on rig floor, testing crew and
support personnel.
Key personnel trained in CPR and administration of oxygen.
Drills with safety equipment.
Detailed evacuation, rescue and first aid plans.
A safety service contractor will likely be required to coordinate procuring and maintaining
the additional safety equipment, holding training sessions and drills, and setting up
rig-specific procedures required for H2S safety.

ALWAYS LOOK FOR H2S WHEN FLUIDS COME TO SURFACE

Even if H2S is not expected, the well testing service company, mud logger, and H2S
safety contractor should start testing for H2S and CO2 at the choke manifold as soon as
fo rm a tio n flu id s sta rt su rfa cin g , d u e to th e p o ssib le la te a rriva l o f H2S at the surface.
The trip tank should be monitored, continuously if possible, once the well is perforated.
Both H2S and CO2 can be detected accurately down to 1 ppm with Draeger-type gas
detector tubes. The length of discoloration on the scale indicates the concentration
of H2S or CO2 when a set volume of air is drawn through the detector tube. Battery
operated H2S monitors can also be worn by individuals to indicate the concentration
of H2S to which they are being exposed, as well as lead-acetate paper indicators.
Immediate and deliberate action must be taken when H2S is detected. Depending on the
concentrations, this could involve shutting the well in during a flow test or, at a minimum,
obtaining respiratory protective equipment prior to proceeding.

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H2S SAFETY PROCEDURES

The following safety procedures should be observed on all well tests where H2S is
known or expected.
1. Prior to beginning the well test, all personnel are briefed on the hazards of
hydrogen sulfide. A gas mask drill is held.
2. Each person on the rig floor, the testing crew and any associated support
personnel should have completed a certified H2S training program.
3. The test string should be of modified N-80 or lower yield strength. All sub-surface
test equipment must have a Rockwell C value of 22 or less.
4. Packers, seal assemblies, and BOP rubbers should be free from cuts and
scratches and made of H2S resistant material.
5. The rig floor and choke manifold, separator, and surge tank areas should be well
ventilated before the well is opened. Gauge tank areas for produced water, and
other areas where produced water is released to atmospheric pressure must be
very well ventilated and closely monitored.
6. Each individual who will be on the rig floor or working with the hydrocarbon
processing equipment (separator, burners, etc.) must have a self-contained
breathing apparatus suitable for hydrogen sulfide gas exposure.
7. Prior to formation fluid surfacing, the burners must be lit and operating on
supplemental fuel in a manner to ensure against flameouts.
8. Beginning at first gas to surface or when formation liquid surfaces, and at 15
minute intervals thereafter, the sour gas sniffer or Draeger tubes should be used
to determine if any H2S is present in samples bled off the choke manifold very
carefully through a very restrictive needle valve. If the gas has 20 ppm H2S or
more, all the following precautions will be observed:
a) All non-essential personnel will remain in the quarters and be prepared in the
event that transfer to the standby boat is necessary.
b) All personnel remaining on the drill floor and in the test equipment area will
wear continuous H2S monitors.
c) At 15 minute intervals, the sour gas sniffers, Draeger tubes or monitors
will be used to determine H2S concentrations throughout the vessel,
including the rig floor, separator area, accessible sunken areas (enter
closed areas only with breathing apparatus), other working areas, and the
living quarters area.
d) If the concentration in the air in any area exceeds 25 ppm, the well will be
shut-in and killed, and the test will be terminated until satisfactory corrective
action can be taken.

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e) If H2S concentration reaches 50 ppm in the air in any area, in addition to the
well being shut-in, all test personnel not required for H2S control will be
alerted and assembled on the windward end of the vessel until acceptable
concentrations are attained.
f) The well will be shut-in at the bottomhole tester valve rather than the surface
valve, unless conditions warrant otherwise.
g) The separators will not be operated at pressures exceeding 75% of the
working pressure.
h) Sampling from the flow stream to the atmosphere, while necessary, should
be through restrictive needle valves, if possible, and into a semi-closed
co n ta in e r fo r sn iffin g w ith D ra e g e r tu b e s. T h is sa m p lin g sh o u ld b e o n ly
done when another person is observing.
i) H2S is extremely soluble in water and quite soluble in oil at high pressures,
but less so at low pressures. So areas where produced water or oil is
depressurized and vented could contain a hazardous buildup of H2S. Avoid
these areas if possible, entering only as required to make measurements,
with proper safety devices (Scott air packs) and observing partner. As a
practice, atmospheric tanks should not be used to store produced water if the
well contains H2S. Oil should not be stored in atmospheric tanks on the rig
regardless, and should not be barged without closed venting and H2S
removal systems.
j) The test string will be completely reverse circulated at least twice prior to
pulling out of the hole. If reverse circulation cannot be completed, the
operations office should be notified so that special preparations for pulling
the tubing wet can be made.
k) Under no circumstances should any person enter an area that has an H2S
concentration of 250 ppm or more unless wearing a self-contained fresh air
breathing apparatus.
l) Prior to the start of a production test, the chain of command should be clearly
identified so that someo n e is a va ila b le to a ssu m e e a ch p e rso n s
responsibilities should they become incapacitated.

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13.13.3 GAS HYDRATES: FORMATION AND PREVENTION

WHAT ARE GAS HYDRATES?
Gas hydrates are chemical combinations of water and hydrocarbon gas molecules
(C1-C4). They can form at temperatures as high as 70-80F at the moderate to high
pressures typically encountered in gas well production and testing. Hydrates have a
physical consistency that ranges from ice to packed-snow, and they are usually dirty
white to pale yellow in color.
Figure 13.26 illustrates a map of the hydrate formation areas for methane and for
various mixtures of methane and C2-C4 hydrocarbon gases and fresh water. It shows
that methane will form hydrates with fresh water at 73F at any pressure above 4000
psia, and more generally, anywhere on the map to the left of the hydrate line. The
particular composition of the hydrocarbon system affects the hydrate map, and the
water salinity can have an even greater effect. Hydrogen sulfide and carbon dioxide
can form hydrates with water themselves, and they promote hydrate formation in
hydrocarbon gases.
Hydrates occur naturally under the mudline in deepwater. At 2500 ft water depth, the
hydrostatic pressure is about 1110 psi, indicating that gas hydrates can form at any
temperature below about 50F. The deeper the water, the higher the pressure and the
lower the temperature, hydrates become even more likely.
Free gas is not necessary to form hydrates. Gas dissolved in oil can form them if water
is present, under similar conditions of temperature and pressure. Their formation in oil
is usually much slower, their ability to agglomerate is inhibited naturally, and their
tendency to cause problems is lower. This will be discussed separately, after the dry
gas well case.
PROBLEMS WITH HYDRATES
Hydrates can cause total plugging of the flow path and trap pressures. They can cause
flow restrictions and interfere with equipment instrumentation and controls. They can
interfere with unlatching mechanisms, and valve operation. They can incapacitate the
BOPs and choke/kill lines.
Hydrates seem to dissociate much slower than they form. The chemical bonding
b e tw e e n th e g a s a n d w a te r is ca lle d w e a k in g a s h yd ra te s. T h is m e a n s th a t if th e
conditions of temperature and/or pressure favorable to their formation are removed, the
hydrates will dissociate back to water and gas. But this breakdown usually takes place
ve ry slo w ly. A n d b e su re th a t g a s h yd ra te s th e m se lve s a re b y n o m e a n s w e a k
mechanically, because as they can plug tubing and pipe, trapping many thousands
of psi of pressure.
Depending on where gas hydrates form, it may not be easy, safe, or even possible to
change the temperature and/or pressure conditions sufficiently to force their
decomposition in a reasonable amount of time. Thus conditions must be controlled to
avoid hydrate formation at all costs, especially downhole. Hydrate inhibiting chemicals
must be injected into the flow stream when the pressure and temperature conditions
favoring hydrate formation are unavoidable. Methanol (methyl alcohol) is usually used
as the inhibitor.

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13.13.4 COMMON OCCURRENCE OF HYDRATES IN WELL

TESTING OPERATIONS

HYDRATES IN THE WIRELINE LUBRICATOR AND WELLHEAD AREA

ExxonMobil has had numerous problems with hydrates in deepwater drilling and testing.
Because of the remedial costs and associated safety/well control issues, all efforts
should be employed to ensure they do not form during well testing operations.
The most common instance of serious hydrate problems actually has little to do with
whether the well is deepwater, shallow water or onshore. It will be mentioned up front
because it can be easily prevented. It happens on moderate to high-pressure gas wells
during pressure testing of wireline lubricators with water that has not been (sufficiently)
inhibited.
When the pressure testing is finished, the pressures are equalized across the swab
valve, and then it is opened. The water in the lubricator immediately contacts the high-
pressure gas a n d it is h yd ra te h e a ve n . W h a t a mess! Note: This can also occur in oil
wells that have a gas cap at the subsea wellhead, if the pressure and temperature
conditions are in the hydrating area of the map.
But this is just a problem of oversight or not being aware of hydrating conditions, and
can easily be prevented. Use a 50% glycol-water mixture for pressure testing or even
base oil in extreme pressure cases.
But in deepwater tests there are unique locations and conditions that cause hydrates, in
a d d itio n to th e sta n d a rd o n e s. P re d icting these conditions offers technical challenges,
and so do the remedies.

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13.13.5 HYDRATES IN GAS WELLS

The possibility of gas hydrate formation in the flowstream is dictated by four factors:
1. The composition of the gas or gas/oil system.
2. The pressure.
3. The temperature.
4. The presence of water, and the amount of impurities (salt, CaCl2, inhibitor, etc)
in that water.
When all of the above factors are present, then it is said that hydrate formation is
th e rm o d yn a m ica lly fa vo re d . T h is m e a n s th a t h yd ra te fo rm a tion is possible, and any
formed will be stable at these conditions. In gas wells, with no oil present, hydrates will
fo rm ra p id ly w h e n e ve r fa vo re d , a n d ca u se p ro b le m s if fo rm e d in su fficie n t q u a n tity.
The maximum amount of hydrate that can be formed in most well testing situations will
be limited by the amount of water present. However, even small amounts of hydrates
may begin to stick at ID upsets or elbows, then collect, build up, and eventually form a
plug, stopping flow.
The basic parameter determinin g a p a rticu la r in h ib ito rs e ffe ctive n e ss is th e
concentration of the inhibitor in the water. The amount of total inhibitor required will be
proportional to water production, all other things being equal.

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13.13.6 WATER AND ITS SALINITY

The amount of produced water expected and its dissolved solids content are two of the
critical and basic input parameters used to design a hydrate inhibition program. More
needs to be said about them, because some past program designs have been based on
unrealistic assumptions regarding water salinity and rates.
Gas wells always produce a small amount of water vapor, some of which may condense
out somewhere in the well flow stream. This water existed in the gas phase with the
hydrocarbon gas in the reservoir, and so it contains no salt or other dissolved solids.
This water, whether in vapor or liquid phase, will readily form hydrates with light
hydrocarbon gasses under the conditions shown in Figure 13.26 (based on the
gas-condensed water system).

Hydrate Formation Condition

GOM Diana Field

10000

Hydrates Possible
Pressure (PSI)

1000

No Hydrates

100
40 45 Figure
50 13.26 -55
Hydrate Formation
60 Graph
65 70 75 80
Temperature (Deg. F)

The good news here is that the gas in the reservoir can only carry a very limited amount
of water vapor with it, but if it condenses it is fresh water, which form hydrates very
easily in the deepwater environment. The exact amount depends on reservoir
temperature and pressure (it can be calculated), but it will vary from about 0.6 Bbl
to 2.5 Bbl of water per MMscf of gas.

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It should be noted here that this 0.6 to 2.5 Bbl water might never condense out in the
separator. It may go out with the gas outlet to the flare line. Even though liquid water is
never measured in the separator, the flow stream may need to be inhibited.
Gas above a GOC or with no GWC may contain no water vapor at all. But for purposes
of designing the hydrate control program, it should be assumed that the gas may contain
water vapor, but certainly limited to the amounts just discussed (0.6 to 2.5 Bbls/MMscf).
Of course, if the gas well is
completed near a GWC, or the
formation evaluation is not clear
cut for mobile water saturations,
the completion may produce
formation water along with the
gas. If it were produced, this
formation water would likely be
produced in much greater
quantities than the gas-associated
water vapor discussed above.
However, this water will likely
contain varying amounts of salt,
which is a natural hydrate
inhibitor, as shown in
Figure 13.27. This figure shows
the effect of salt on hydrate
suppression parallels its effect on
freezing point suppression. A salt
concentration of 10% (or 100,000
ppm) by weight in water will
reduce the hydration temperature Figure 13.27 - Hydrate Depression Curve
by about 10F.
This water salinity of 10% is in the
ball park or low for most
deepwater reservoirs. The actual salinity of the formation water should be well known to
the project log analyst, as this parameter is a cornerstone for determining hydrocarbon
saturations in the reservoir. This information must be used to properly design the hydrate
inhibition program. For a rank wildcat, salinity information may be completely unknown.
Hydrate inhibition programs in the past were designed assuming that large amounts of
formation water might be produced with the gas, and that it would have no salinity. But
available salinity data should be taken into account. Those setting up the case study for
th e h yd ra te p re ve n tio n p ro g ra m n e e d to a sk th e te st c lie n ts fo r th e b e st e stim a te s o f
water salinity, and how much water production would be tolerated before the test is
terminated. The best available answers to these two questions should reduce excessive
predictions of methanol requirements.

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TO RECAP THESE POINTS:

1. A gas well can only produce very limited amounts of condensed reservoir
water vapor.
2. If an oil or gas well produces formation water, it will probably have some salinity,
which can act as a very good gas hydrate inhibitor, and should be taken into
account.
3. For deepwater locations, where costs are high and hydrate problems can result in
major problems, extreme care should be taken to ensure that uninhibited water
never contacts gas near or around the mudline.
There is one more point to make concerning water. Completion fluids and cushion fluids
are at least partially inhibited against hydrate formation due to their salt or calcium
chloride content. If they are not, they should be.

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13.13.7 PREDICTING LOCATIONS AND TIMES FOR HYDRATES

IN THE WELL TEST SEQUENCE

Determining the required temperature and pressure (i.e., constructing a hydrate

m a p a s sh o w n in Figure 13.26 for hydrates is straightforward once the hydrocarbon
composition, presence of water, and the amount of dissolved solids (e.g. salinity
primarily) in the water are known. Most reservoir fluid property prediction (PVT)
programs will generate this map.
Predicting pressures and especially temperatures along the entire flow path during the
well test sequence is not straightforward. For fixed reservoir fluid conditions, the flow
stream pressure and temperature will vary with location and time along the flow path.
Computer simulation programs, such as NODAL and WELLTEMP, have been used to
model the flow path. They require many input parameters, especially in the heat transfer
area, that may not be well defined for deepwater. And to date, the flow stream has not
been instrumented for temperature and pressure measurements in the possible
h yd ra te -critica l zo n e s to ca lib ra te th e m o d e ls.
The model work has been very helpful, and has been relied on to plan the hydrate
inhibitor injection program. It gives very good direction on answering two very important
q u e stio n s, H o w d e e p in th e te st strin g ca n h yd ra te s o ccu r a n d h o w m u ch w a te r
production ca n b e to le ra te d b e fo re th e te st m u st b e e n d e d ? T h e se a re th e m o st critica l
for pre-planning and determining special equipment requirements.
WELL STARTUP
Before the well is opened for flow, the lower test string temperature profile is determined
by the geothermal gradient below the mudline. This means that the upper part of the
lower test string, below the BOP stack, can sometimes be in the hydrate region before
flow starts.
The temperature profile in the landing string is determined by the seawater temperature
gradient. This means that a major part of the landing string in a deepwater well will
almost always be in the hydrate region before flow starts.

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Figure 13.28 shows the results of flow stream temperature predictions at the wellhead
and mudline versus time prediction for a specific reservoir at one flow rate. The upper
curve represents the flow stream temperature response at the mudline. The simulation
shows that the well is in danger of hydrating below the mudline (i.e., below 71F) during
the first hour of flow, at the far-left side of the plot, therefore inhibition is required below
the mudline at test startup.
This is a good case to illustrate some real world complications that are difficult to
replicate in the model. The first is that there will actually be a 6 to 12 hour period in
which the rate is slowly ramped up during cleanup to the 25 MMscf/d in the case study.
The others are that the well may be loaded with a naturally inhibited cushion (base oil or
diesel), and later produce completion fluid, also inhibited. So the decision to go with
sub-mudline inhibitor injection is not clear cut.

Flow Back Temperature

GOM Diana Field: Water Depth ~4200 ft
110

25 MMscf/d, 135 F BHT

100

90

80
Temperature (Deg F)

70
1 hour at risk: Mudline
Mudline Temperature
60 Surface Temperature
Hydrate Temperature = 71 F

50

40

30

20
Figure
0 13.28
5 - Flow
10 Stream
15 Temperature
20 Prediction
25 30 35 40 45 50
Time (hours)

T h e tie b re a ke r h e re is th a t if th e re is a n y p o in t in th e te st strin g w h e re yo u d o n t w a n t
hydrates to be formed, sticking and building up, its in the SSTT area. Hence, for gas
well tests in deepwater, it is most prudent to utilize sub-mudline injection equipment
(especially with DP rigs, where the chance for emergency disconnect is higher than
for a moored rig).

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WELL FLOWING

Once the well starts flowing, the flow stream carries the deeper geothermal heat up to
the mudline, as shown in Figure 13.28, and in this simulation, the hydrate zone below
the mudline disappears within the hour. Caution is in order here. When kicking off the
well, often completion brine will be produced with the oil/gas mixture, flow rates will be
relatively low (little warming effects), temperatures at/near the mudline will be low, and
mudline pressures will be high. All these factors combine to make hydrate formation
very likely.
Once the mudline is reached, flowing well stream will start cooling quite dramatically in
deepwater well test, even at high flow rates. There is usually little or no effective
insulation from the very cold seawater, having a temperature of 30 to 35F. As a result,
flow stream temperatures at the rig floor in water depths over 4000 ft have been as low
as 55F for oil wells, and 50F for gas wells at high flow rates.
Note: The model predicts a wellhead temperature of 75 to 80F after warm up, whereas
the observed values are usually about 15 to 20F lower. This discrepancy may be due to
the fact that the model does not consider Joule Thompson cooling effects of the
expanding gas, or the heat transfer coefficients in the sea leg are too low. In this case,
the hydrate injection program must be adjusted to honor actual observed conditions of
temperature and pressure at the wellhead.
Another observation with deepwater tests has been that the flow stream temperatures at
the surface dropped with increasing production rates for both oil wells and gas wells.
At first thought, this is the opposite of what is expected! But for oil wells at least, this is a
sure indication that the flow stream cooled rapidly to a minimum temperature, lower than
the sea surface temperature, and was actually being re-warmed by the near surface
waters.
As a result, inhibitor injection at the SSTT in the BOP stack will be necessary in all
deepwater gas wells and sub-mudline injection is highly likely. The inhibitor volume
requirements will usually be higher than for injection below the mudline, because of the
much lower temperatures in the landing string. So two injection systems are necessary
unless the lower line can handle the total requirements. Even then, a second line may be
desired for backup.
Also, the warming trend with time shown for the wellhead temperature in Figure 13.28
was not observed on deepwater tests. Again, evidence that the sea has excess cooling
capacity, and does not heat up appreciably, even in the riser. So, inhibitor injection at the
SSTT in the BOP stack will usually be continued throughout the test in all deepwater gas
wells, unless there is no water production. The need for inhibitor injection below the
mudline may fade when the well warms there.

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SHUTTING THE WELL IN

There is another period in the testing sequence when the production string is very
susceptible to gas hydrate formation. This would be in the main pressure buildup period,
when the tubing pressure would be at its highest and the temperature at its lowest. This
was a serious problem until the bottom hole shut-in valve or tester valve came into use
in deepwater testing. Now, the well is shut-in at the tester valve, and tubing pressure is
bled off through the surface facilities to some low pressure.
As added insurance, methanol inhibitor can be pumped into the tubing. If this is done
very early in the buildup (as it should be), the effect on the bottomhole pressure gauge
data below the tester valve is negligible, especially if the gauges are hanging free in a
tailpipe below the packer.
Often hydrate mitigation actions take precedence over data collection. The test should
be conducted safely, or not conducted at all.

13.13.8 METHANOL IS THE BEST INHIBITOR

The conventional method used to prevent hydrates in the flowstream is to inject an

inhibitor into the flowstream UPSTREAM of the first problem area. Methanol is the most
e ffe ctive in h ib ito r in co m m o n u se to d a y. E xp e rim e n ta l w o rk h a s b e e n d o n e w ith m icro
inhibitors, which are reputed to be effective in the p p m co n ce n tra tio n ra n g e , b u t th e yve
not been tested under deepwater testing conditions. Obviously, failure here would be a
heavy burden.
Glycol is mentioned in some references as a viable alternative, but it has at least five
important disadvantages for injection applications. Compared to methanol, it is less
effective, seven times as expensive, more viscous and harder to pump. It will not
dissolve pre-existing hydrates, and sometimes causes the formation of a heavy second
hydrocarbon-rich phase (that makes 4 total phases) in water-gas-oil systems, causing
separation, sampling, and metering problems.
Methanol is more flammable than glycol, but not extremely so (closer in flammability to
diesel than to gasoline). It has a flash point of 52F, but for refere n ce , g a so lin e s fla sh
point is -50F. It is poisonous, but so is glycol. Probably the worst that can be said of
methanol is that it burns with an almost invisible flame. This is a problem and can be
partly remedied by spreading salt under methanol line connections and other possible
leak areas. The salt will make any methanol fire visible should a methanol leak occur
and be ignited. Methanol is also hard on pump seals and rubber goods. Thus, the
surface injection equipment needs to be in good working order, and backup equipment
should be available.

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HYDRATE INHIBITOR INJECTION

In deepwater gas wells hydrate inhibitor injection is usually required downhole, at least
as low as the BOP stack, and in some cases, below the BOP. Additional lines, surface
pneumatic pumps and injection subs will be required. The inhibitor injection line is run
with the SSTT control lines on the landing string.
Of course, injection below the BOP will require that a specially ported slick joint be
employed to get the inhibitor past the sealing pipe rams in the BOP. This slick joint has a
p o rt b o re d in its w a ll lo n g itu d in a lly to a cco m p lish th is. T h e in je ctio n lin e e n te rs th e
p o rte d slick jo in t a t th e to p , a b o ve th e se a lin g ra m s, a n d e xits a t th e b o tto m , b e lo w th e
sealing rams. Also, the SSTT is specially ported to handle the injection lines, so a
disconnect and reconnect can be done, and injection capability be re-established without
a trip of the landing string. Methanol is normally the inhibitor of choice, and 0.25-in.
minimum ID lines will be the minimum required. Early on, line crushing and subsequent
leakage has been a major problem, especially below the BOP. More recently, an
armored line is used that is much stronger and resistant to crushing. One example of this
improved line looks like Romex electric wire, but about five times the size. It is more or
less flat in shape, and each edge is embedded with a cable. The flow line is in the
center, protected in all dimensions.
Surface pumping equipment usually consists of low-rate high-pressure pumps, capable
of delivering several gal/min at 10,000 psi. For higher methanol injection needs, highly
specialized pumps and larger diameter (or special) umbilicals would be deployed.
This is generally a long lead-time item, and often has to be manufactured (including the
sub-mudline injection equipment and ported fluted hanger).
TOO MUCH INHIBITOR CAN CAUSE PROBLEMS
In the case of a gas well producing only condensed water vapor, an excess of inhibitor
causes no problems beyond waste, contaminating samples needlessly, and perhaps
inhibitor-water mixture disposal problems.
However, for any case in which moderate to high salinity water is being produced, care
must be taken because the common inhibitors (methanol and glycol) reduce the
solubility of salt in water. If sufficient inhibitor is injected into a flowstream containing
formation water with moderate to high salinity, salt will precipitate out in the tubing, and
possibly plug or restrict it. Again, a good hydrate prevention plan will incorporate the
best formation water salinity data available, and provide techniques for checking
methanol and salt concentrations in the produced water to verify that inhibition is
adequate. When producing a reservoir bounded by a salt dome, expect high salinity
water if any is produced.
INHIBITORS ARE NOT RECOVERED
Inhibitors that are injected into the flow stream are not recoverable. Methanol will be
distributed mainly in any water in the flow stream, then oil. A slight amount may be in the
gas. Methanol in the small quantities normally used should not cause any disposal (or
sales, in the case of oil) problems as it mixes and burns well. Large quantities of
methanol will dissolve water in oil.

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INHIBITORS CONTAMINATE SEPARATOR SAMPLES

Methanol (or any other inhibitor) will contaminate any samples taken downstream of the
injection point. The amount of methanol used should be trimmed back as conditions
permit. Well before the test, in the program planning stage, it would be advisable to get
an opinion from the in-house and laboratory PVT experts on how much methanol can be
tolerated in the samples.
In some cases, such as the water cut falling to zero in an oil well after cleanup, injection
can be stopped. In other cases, it can be stopped for a short time before sampling if
hydrate indicators are watched carefully, and resumed after sampling. But time must be
allowed for the separator to flush out, and perhaps drain out the water leg. Methanol in
dry gas samples may not be a big problem.

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13.13.9 CAN GAS HYDRATES BE A PROBLEM IN OIL WELLS?

The short answer is yes. The same conditions that determine formation in gas wells
apply to oil wells. But normally hydrates are not as big a problem as in gas wells. If the
o il is 1 0 0 % d ry, th e n h yd ra te s ca n t fo rm . B u t th is u su a lly isn t kn o w n p rio r to te stin g .
Other hydrate problems can be self-induced. Gas/brine mixtures usually occur during
initial clean up. In addition, water/brine knowingly or inadvertently introduced into the
tubing has caused serious hydrate problems (i.e. water used to test the wireline
lubricator flowed down to the mudline after the lubricator valve was opened, completely
plugging the tubing with hydrates).
Most oil flow streams will contain dissolved gas (methane, ethane, possibly CO2, H2S,
etc.). Most oil flow streams will contain at least some mix of formation and completion
water during cleanup, and small amounts afterwards for a day or so. So, at first glance,
all the factors are there for hydrate formation.
While laboratory studies have shown us that gas hydrates can indeed form in oil, they
fo rm q u ite slo w ly, re q u irin g fro m a n h o u r to a d a y o r so . M a ss tra n sfe r lim its th e ra te o f
hydrate formation in oil. This means that the hydrate forming components, methane and
water have to diffuse through the liquid oil phase to the mutual hydrate nucleation sites,
and this slows the formation. Once they do form in the oil phase, the hydrate crystals
tend to form as isolated flakes, or a loose mush or slurry, rather than a sticky,
mechanically competent mass capable of complete plugging. Another factor contributing
to making hydrates less of a problem in oil wells is that water produced with oil is a mix
of cushion fluid, completion fluid and water formation water and will usually have
inhibiting properties due to its salt or CaCl2 or other dissolved solids content.
Past conservative approaches to gas hydrate prevention in deepwater oilwell tests have
treated oil wells like gas wells. Subsea injection of methanol (up to several thousand feet
below the BOP in some cases) was employed if the hydrate formation map and tubing
pressure and temperature so indicated. But experience has borne out the observations
in the preceding paragraph. They explain why sub-mudline injection of inhibitor in oil
wells has not been necessary under conditions encountered to date.
Once above the mudline, the flow stream will get much cooler, and stay that way for a
relatively long time, so injection of inhibitor at the SSTT may be indicated in an oil well.
Therefore, sub-mudline injection of inhibitor in oil wells seems unnecessary because:
1. The load fluid is usually an inhibitor (or at least dry, in case of base oil cushion).
2. Produced water may be inhibited (dissolved salts).
3. Hydrates form slowly in oil, and will move above the SSTT injection point before
they can form prlblems.
4. The well will warm up below the mudline.

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WATER SALINITY INFORMATION IS CRITICAL TO OILWELL INHIBITOR

INJECTION PROGRAM
It is very important not to load up a saline formation water with inhibitor to the point
where salt precipitates out of the water. This situation is not as bad as hydrate plugging,
but it can restrict flow and W/L tool entry. The water will be properly inhibited even if the
calculated amount of methanol can be added due to salt dropping out. Saline water
re q u ire s le ss in h ib ito r, a n d if sa lt is d ro p p in g o u t th e syste m , it is b e in g o ve r in h ib ite d .
The group doing the gas hydrate prevention study must have the best formation water
salinity data available, and be aware of how methanol reduces salt solubility. In the final
analysis, onsite observations and analysis of produced water samples will be critical.
Sometimes salt precipitation can be detected at the choke manifold by a pinging noise
(like sand particles make), or by inspection of the choke block housing when a choke is
changed. Salt precipitate in oil looks a lot like sand in oil. But unlike sand, it will dissolve
in fresh water.

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13.13.10 RULE-OF-THUMB FOR METHANOL INJECTION INTO

GAS WELLS

After all of this, a drop back position is o ffe re d a s a ru le -of-th u m b . T h e syste m is

sufficiently inhibited if the produced water contains about 30% to 35% by volume
methanol, and the water vapor is inhibited. This assumes low salinity water. If water
is moderate to high salinity, methanol injection must be reduced or it will precipitate out
salt. The salinity of the formation water is very important parameter in designing a
hydrate prevention program. It impacts whether on not inhibitor is needed, and if so, how
much. The project log analyst will have the best information on formation water salinity.
For rank wildcats, no information may be available until after logging.

ESSENTIALS STEPS IN A HYDRATE INHIBITION PROGRAM FOR A

DEEPWATER PRODUCTION TEST (1)
1. Consult project log analyst and client reservoir engineer for formation water
salinity, expected water production, reservoir pressure and temperature. Define
the hydrocarbon system, water salinity, expected reservoir pressure and
temperature. Obtain seawater temperature profile, surface to mudline, and
mudline to reservoir temperature profile.
2. Employ URC to generate a hydrate map for the possible temperature and
pressure ranges for the hydrocarbon-water (salinity) system using (PROPSIM
or other URC Facilities Design software). This analysis should consider specific
well dimensions, tubing, casing configurations, temperature and pressure profiles
along entire tubing string, from completion to surface flowhead, as a function of
flow time, for a realistic range of :
a) Water rates and salinities (both most critical).
b) Production rates.
c) Bottomhole conditions.
d) Hydrocarbon rates.
e) Tubing sizes (especially for gas wells).
f) IDs of tool string elements.
g) Sub-mudline and sea leg temperature profiles.
h) Heat transfer coefficients in sea leg and sub-mudline.

Ideally, this study would model the entire well test (all flow and shut-in periods).

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Comments: The flow stream pressure and temperature profiles will probably be
calculated with WELLTEMP, perhaps with NODAL as a backup. The water rate is
usually given a wide range to URC. This is OK, if salinity is high, but water rates higher
than those or low salinities would cause drilling to call for the test to be ended. These
causes must be considered, as the drilling engineer must know the parameters that
could cause the test to be halted.
3. Find all of the hydrate prone areas in the test string as a function of time using
the hydrate map and the temperature and pressure profiles generated in Step 2,
above.
4. Design a subsurface hydrate inhibition system, the critical elements of the design
being:
a) The location(s) of injection of inhibitor.
b) The maximum rate of inhibitor, giving due consideration to fact that com-
pletion and cushion fluids are normally good hydrate inhibitors at start up.
Comments: The KEY decision to be reached here is whether or not inhibitor injection is
needed below the mudline. Sub-mudline injection complicates the system significantly.
Usually, this is not a close call for oil wells (because well heats sooner, hydrates form
more slowly, less likely to plug). For most deepwater gas wells, sub-mudline inhibitor
has been recommended to prevent hydrates in the near mudline (and critical
SSTT) area, especially during well startup. This is the worst possible place to have
a hydrate problem.
Sub-mudline injection requires a special ported slick joint to convey the inhibitor through
the BOP, as well as high-strength lines, and added pump capacity. Special protection
and precautions need to be taken to prevent the line being crushed in the annulus when
the APO tools are being operated. The injection sub, located perhaps 500 to 1500 ft
below the mudline, is often specially manufactured and not readily available.
5. From the modeling results, develop a rule-of-thumb on how the effectiveness and
need to adjust the methanol injection program can judged using field observable
parameters, such as:
a) WH temperatures and pressures.
b) Water cut, methanol content and salinity.
c) Signs of plugging, hydrate formation, such as:
- Quick drop in WHP and especially WHT.
- Loud, banging noises when a partial plug breaks loose.
d) Flow rate and elapsed time
6. In practice, we are limited by injection rate capacity (line size, pump pressure),
and may have less capacity than required for the high water rate case (which
URC usually includes). These high water rates are sometimes higher than drilling
would tolerate. Thus, we pump what we can, coordinate methanol injection with
water rates, consider salinities (we do not want to precipitate salt), monitor WHP
and WHT and remain alert for signs of hydrates.

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Comments: When water rate goes down, we can reduce methanol injection rate, but
normally maintain a rate sufficient to keep about 30-35 volume % methanol (another
rule-of-thumb) in the water, unless water has salinity. Then we can back off some,
how much depends on salinity.
7. Remember, there will usually be water vapor in a gas well flow stream, so even if
the separator is not making liquid water some methanol is probably needed, but
only approximately 0.25 to 2 Bbl. Per MMscf of gas. The exact maximum amount
of water vapor that the gas can carry can be calculated from reservoir
temperature and pressure. Note that this water is essentially fresh, and is the
best type for forming hydrates. Formation water is another matter that must be
considered.

GENERAL OBSERVATIONS
1. Hydrate calculations are based on thermodynamic equilibrium, which does not
consider rate of formation.
2. Hydrate formation rate in gas is quite rapid, so kinetics are simpleco n sid e r
th e m fo rm e d .
3. Hydrate formation rate in gas dissolved in oil is much slower, sometimes taking
several hours to a day to form.
4. H yd ra te s fo rm e d in flo w in g o il d o n t stick a n d p lu g re a d ily, b u t te n d to flo a t a lo n g
as isolated crystals, or at worst, fo rm m u sh , w h ich d o e s flo w b u t w ith so m e
added resistance. The Blackback well, offshore Australia (circa 1995)
demonstrated this.
5. Because hydrates require water, and form slowly in oil, they usually are not a
problem in shut-in oil wells, except in the gas cap at the subsea wellhead area.
There usually is a gas cap there. So the well must be treated like a shut-in gas
well. Examples are Tierra del Fuego Salmon, circa 1970 (W/L entry blocked
after shut-in), and Xikomba-1 in Angola, circa 1999 (wireline samples stuck due
to hydrates in wellhead caused by water use to test the lubricator).
6. To mitigate hydrate formation problem in shut-in wells, we normally shut-in at
bottom and bleed off pressure above the tester valve, then pump a barrel or two
of methanol at the SSTT.
7. Observations may indicate the oil flow stream reaches its minimum temperature
quickly after it reaches the mudline, and is slowly warmed as it approaches
the rig by the near surface waters. Therefore, minimum depth for injection should
be at the SSTT.

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DIANA 2 PRODUCTION TEST CASE STUDY

H o w lo n g d o e s it ta ke to e lim in a te h yd ra te risk, ju st b y p ro d u cin g , n o in je ctio n ?

Gas Rate BHT=110 F BHT=122F BHT=135F
2 Mscf/D Mudline: hrs Mudline: hrs Mudline: hrs
Surface: hrs Surface: hrs Surface: hrs
5 Mscf/D Mudline: >12hrs Mudline: 8hrs Mudline: 4hrs
Surface: hrs Surface: hrs Surface: > 96hrs
25 Mscf/D Mudline: 4hrs Mudline: 4hrs Mudline: > 1hr
Surface: hrs Surface: hrs Surface: 24 48 hrs
35 Mscf/D Mudline: ~ 4hrs Mudline: >1hr Mudline: ~ 1hr
Surface: hrs Surface: >48 hrs Surface: 24 hrs
These results are from the same study than generated Figure 13.28 for a planned test
for Diana 2, a gas well. Even the uncertainty range in BHT is high, but is typical when
estimating BHTs from logging runs in deepwater wells.
Model results to the contrary, field data from other wells indicate that the sea leg
portion of the flow stream never gets out of the hydrating region. The flow stream
comes up colder than predicted, and gets colder with higher rates perhaps due to
Joules-Thompson effect.
It would take some sort of insulated tubing or insulation on the riser to get out of the
hydrate region. Evacuation of the riser, filling it with a foamy gel or low heat conducting
mixture, and insulated tubing have been employed to preserve flow stream heat to
prevent hydrates. Insulated tubing works very well as a foolproof, passive hydrate
preventer, but the costs, supply logistics, and unwieldy nature of this special tubing
seem to be prohibitive. It was used on the Cooper test (GOM, circa 1991) and was very
successful for the hydrate prevention standpoint, with wellhead temperatures 30 to 35F
higher than typical.

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APPENDIX A - PERSONNEL RESPONSIBILITY

ESSO EXPLORATION

PERSONNEL RESPONSIBILITIES

ESSO OPERATION SUPERVISOR

a) Has overall responsibility for all operations during production test.
b) Ensures all aspects of testing and rig operations are carried out safely.
c) Communicates test results/status to EEPNL Lagos Office as required.
d) Gathers pertinent information from Exploration Test Engineer and Drilling
Engineer and prepares daily DRS report.
e) Verifies that appropriate fishing equipment (overshots/grapples) are on board.

ESSO DRILLING ENGINEER

a) Prepares "Well Test Program."
b) Verifies required equipment is available and functioning properly.
c) Verifies that equipment has been measured and recorded prior to RIH.
d) Witnesses pressure and function tests of equipment.
e) Supervises perforating, make up and running of test string.
f) Calculates required space outs.
g) Consults with Exploration Test Engineer regarding required flow rates, lengths of
flow tests and lengths of buildup periods.

ESSO EXPLORATION TEST ENGINEER

a) Prepares "Production Test Protocol" specifying the test objectives.
b) Responsible for gathering production test data onsite.
c) Evaluates test data to determine whether same is adequate.
d) Specifies flow rates, lengths of flow periods, and lengths of buildup periods.
e) Supervises separator operations.
f) Supervises sampling operations and determines whether samples are adequate.
g) Evaluates bottom-hole pressure data to determine whether same are adequate.
h) Communicates test data as required to EMEC.
i) Provides test information to be included in the Daily Drilling Report.
j) Observes calibration of the separator flowmeter.
k) Specifies pressure gauge requirements and programming.

SERVICE COMPANY REPRESENTATIVES

a) Ensure equipment required for operations is available and in safe working
condition.
b) Ensure that all offshore skids, baskets, and lifts have been inspected in the last
12 months for lifting safety, and that lifting certificates are available.
c) Provide personnel sufficient in number and skill to perform as required.
d) Measure and record dimensions of all tools to be run downhole (OD, ID, Length)

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APPENDIX B - READINESS CHECK LIST

ESSO EXPLORATION

PRE-JOB CHECK LIST

PURPOSE: The purpose of this document is to provide a query-style checklist for test
equipment to ensure a safe and successful operation. It is divided into 2 sections:
Items performed in the shop prior to load-out and items performed on the rig prior to
RIH. By writing directly on this list, complete each section of the checklist, sign/date it,
and provide a copy of Section 1 to ESSO representative on completion of the loadout,
and Section 2 on completion of RIH. If a particular item does not apply to the test at
h a n d (i.e g ra ve l p a ck vs. e xclu d e r), p le a se w rite N /A b e sid e th is ite m .

ITEMS PERFORMED PRIOR TO LOAD-OUT:

GENERAL WELL INFORMATION
1. Do you have all the information needed from ESSO in order to properly plan
the job? If not, contact the ESSO Engineer immediately.
2. Do you have a draft or final copy of the testing procedure?
3. Is the well directional and do you have a copy of the directional survey?
4. Do you the information from the rig contractor regarding the BOP stack and
ram spacing?
5. Is the perforation interval known? If not have they agreed with the ESSO
Engineer on the amount of guns to load and bring to the rig?
6. Do you know the planned setting depth for the production packer?
7. Do you know the weight and type of the completion fluids to be used?
8. Do you understand the SSTT injection requirements and are chemical injection
pumps available to meet the requirements?
9. Have the tools to be used in the DST string been determined and are they
(Primary and Backup) in country, available, pressure and function tested?
10. A re a ll n e e d e d cro sso ve rs a va ila b le fo r h o o kin g u p to rig s p ro d u ctio n te st
and air lines?
11. Have personnel that will run the job obtained visas to enter the country, and
are they here?
12. Are all chicksan connections that are loaded out compatible so that the possibility
of connecting pressure mismatched connection is eliminated?
13. Have stack-up drawings been prepared and provided to the ESSO Engineer for
the DST string, the landing string, the BOP space out and the TCP diagram, on
both paper and in Excel format?
14. Have copies of all sling certifications been provided to ESSO?
15. Have copies of the maintenance records for the DST tools to be used been
provided to ESSO?

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DOWNHOLE TOOL STATUS AT LOADOUT

1. Are lifting devices in the baskets for all of the downhole test tools?
2. Have all tools been drifted to 2.215 in. in the shop?
3. Have all tools been calipered, measured, function and pressure tested (low and
high) in the shop?________. Will this be repeated at the rig site prior to RIH?
4. Have all the connection threads been verified to match the tool string schematic?
In other words, will all tools make up as planned?
5. Have you discussed the point(s) at which yo u r e q u ip m e n t m a ke s u p to B a ke rs,
and is it understood who will provide necessary crossovers? Have they been
physically screwed together?
6. Have all tools that will pass through the bore of the packer been calipered to
ensure that they will pass through the ID of the packer and sealbore extension?
7. Have you loaded out any fishing equipment for downhole tools?
8. Are all required crossovers (and backups) in the baskets? (See perforating string,
DST string & landing string diagrams and equipment tables in testing program for
list of XOs).
9. Have threads on crossovers been verified (visually inspected and physically
made up)?
10. Have crossovers been marked for reference in the tool string diagram and tubing
tally to ensure proper space out?
11. Are backups available for downhole tools?
12. Are the backup DST tools of the same tool type, or are they different type/model?
If different, have the differences been discussed and approved by ESSO?
13. If applicable, are couplings for tools that will pass through the packer beveled?
14. Are torque values for all threads available?

DOWNHOLE TOOL STATUS AT LOADOUT

PERFORATING GUNS
1. Have sufficient guns been loaded out to accommodate the planned perforation
Interval?
2. Are the charge types in accordance with the program?
3. Have the perforation performance sheets been provided to the ESSO Engineer?
4. Has a preliminary detonation pressure for hydraulic firing heads been calculated
independently by Schlumberger and Esso and compared?
5. Is an adequate selection of rupture disks available and have rupture disk
calculations been performed and provided to the Esso Engineer?
6. Has the length from the lubricator sub landing point to the top shot been
measured? _____________

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TUBING TESTER VALVE (TFTV)

1. Have all of the valve functions been tested and verified on both the primary and
backup tools?
2. Are the primary and backup tools identical, or are they different types or models?
If different, explain.
3. Has the rupture disk valve been checked and agreed on by Esso and
Schlumberger?
4. Are the correct rupture disks available for the tool and loaded out?
5. Have the tool joints been inspected?
6. Has the tool body been pressure tested (both low and high) in the shop prior to
Load out?
7. Has the tool been pressure tested (both high and low) from above prior to
loadout?
8. Do you know if the bypass ports are to be plugged or left open?

IRIS OPERATED DUAL VALVE (IRDV)

1. Have both of the valves (Circulating & Testing valves) been function tested on
the primary and, if applicable, the backup tool?
2. Are the primary and backup tools identical, or are they different types or models?
If different, explain.
3. Has the correct rupture disk for the manual override been installed?
4. Have the primary and backup tools been inspected and redressed since their last
use? Have the tool joints been inspected for wear and corrosion?
5. Has the tool been pressure tested (both high and low) in the shop prior to
loadout?
6. Has the Tester Valve been pressure tested from below (both low and high)?
7. Have the batteries been tested prior to loadout? Are spares available?
8. Do you have the needed equipment to be able to utilize the IRDV with the
Datalatch System (ported below then tester valve)?

DOWNHOLE SAMPLING TOOL (SCAR-A)

1. Is a backup tool available?
2. Are the primary backup tools identical, or are they different types or models?
If different explain.
3. Are the slots in the tool configured in accordance with the Test Engineers
Requirements?
4. Has the rupture disc valve been checked and agreed on by Esso and
Schlumberger?
5. Is the tool configured for all chambers to be activated by one rupture disk, or are
separate rupture disks/settings used for the chambers?
6. Are needed rupture disks and backups available and loaded out?
7. Have the tool joints been inspected?
8. Are handling subs available and loaded out?
9. Have you checked the quality of the Nitrogen supply for the samplers to ensure it
meets quality specs? What is the % O2?

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DOWNHOLE SHUT-IN VALVE (PCT) WITH PRESSURE OPERATED

REFERENCE TOOL (PORT) AND HOLD OPEN (HOOP) FEATURE
1. Prior to loadout, were the primary and backup tools fully function tested?
2. Are the primary and backup tools identical, or are they different types or Models?
If different, explain.
3. Prior to loadout, were the HOOP functions tested on both primary and backup?
4. Has nitrogen been loaded out? _____________ Has the pressure in the nitrogen
bottles been verified prior to loadout? _______ Has the quality of the nitrogen
been tested to verify that it meets your quality specs (0.5% 02)?
5. Have the primary and backup tools been pressure tested from both above and
below at both low and high pressures prior to loadout?
6. Have the tools/joints been inspected?
7. Have all needed rupture disks been loaded out?
8. Do you know if the bypass ports are to be plugged or left open?
9. Do you have needed equipment to be able to utilize the PCT with the
DATALATCH System (ported below the tester valve)?

CIRCULATING VALVE (MCCV)

1. Prior to loadout, were the primary and backup tools fully function tested through
at least 2 cycles of the tool using differential pressures equal to those to be used
during the job?
2. Are the primary and backup tools identical, or are they different types or models?
If different, explain.
3. Prior to loadout, were the primary and backup tool bodies pressure tested (both
low and high) in the shop?
4. Were the tools joints inspected?
5. Is the tool configured as 12 cycle or 6 cycle?

SINGLESHOT HYDROSTATIC REVERSING VALVE

1. Prior to loadout, were the primary and backup tools fully function tested?
2. Are the primary and backup tools identical, or are they different types or models?
If different, explain.
3. Were the tool joints inspected?
4. Prior to loadout, were the primary and backup tool bodies pressure tested (both
low and high) in the shop?

JARS
1. Prior to loadout, were the primary and backup tools fully function tested?
2. Are the primary and backup tools identical, or are they different types or models?
If different, explain.
3. What is the force needed to stroke the jars both up and down (both primary and
backup tools)?
4. What is the stroke of the jars (primary and backup)?
5. Were the tool joints inspected?
6. Prior to loadout, were the primary and backup tool bodies pressure tested (both
high and low) in the shop?

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SUBSEA TEST TREE & TOOLS

FLUTED HANGER
1. Is a backup fluted hanger available and has it been loaded out?
2. Are both the profile on the primary and backup fluted hangers identical to the
profile?
3. On the dummy hanger?
4. Is the fluted hanger compatible with the 10-3/4 in. wear bushing in the hole?
5. Will we make a dummy run with the same fluted hanger that will be run during
the well test?
6. Have the tools joints been inspected?

SUBSEA TEST TREE (SSTT)

1. Is a primary and backup tool available and have both been loaded out?
2. Are the primary and backup SSTTs identical, or are they different types or
models? If different, explain.
3. For both the primary and backup, have the tools been serviced since the
last job (i.e. have they been completely broken down, all seals been
checked/changed, ball valve checked for scoring, metal sealing surfaces
checked for pitting/scoring)?
4. Have they been function tested and timed (through the hose reel) in the shop
prior to loadout? Has the time been provided to the Esso Engineer?
5. Time to open valve: __________________.
6. Time to disconnect: __________________.
7. Time to close valve: __________________.
8. Was this disconnect test performed by starting o u t w ith p re ssu re o n th e A lin e
to more closely simulate actual disconnect time? __________________.
9. Have they been pressure tested from below at both high and low pressures?
10. Have the dimensions of the SSTT been closely checked to ensure it will fit in
BOP stack between the shear rams and MPRs?
11. Has a preliminary copy of the SSTT space out within the BOP stack been
provided to both the Esso Engineer and to the rig contractor?
12. Are shear screws for mechanical release set to shear at approximately
4000 ft-lbs?
13. Have centralizers been measured to ensure they will pass through the riser and
will enter the BOP stack?
14. Is a backup hose reel available?
15. Has the hose reel been pressure tested, and are critical spare parts available
(i.e. swedging tool and couplings)?
16. What fluids are in the lines of the reel pack at present?
17. Has the SSTT chemical injection line been tested with the chemical injection
pump(s) that are to be used (pump through reel pack with water)? _________
What rate was achieved? __________________.
18. Have the dimensions and material specifications of the shear joint been
communicated to Esso and has it been determined that the shear rams will shear
it? Has the rig contractor agreed?

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19. Have the ram sizes been checked to determine if they will seal on the slick joint?
20. Is the thickness of the ram blocks known and is it shown on the space out check?
21. Will the space out allow dual or single ram closure?
22. Is the SSTT pump through capable and has been function tested in the shop
prior to loadout?

RETAINER VALVE
1. Is a primary and backup tool available and have both been loaded out?
2. Are the primary and backup tools identical, or are they different types or models?
If different explain:
3. Is the retainer valve fail open or fail closed
4. Has the tool been serviced since the last job (ie: has the tool been broken down,
all seals been checked/changed, ball valve checked for scoring, metal sealing
surfaces checked for pitting/scoring)?
5. Has the retainer valve been function tested in the shop through the hose reel?
Time to close valve __________. Time to open valve ___________.
6. Was the body of the Retainer Valve pressure tested (LP and HP) in the shop
prior loadout?
7. Was the body of the Retainer Valve pressure tested (LP and HP) from above in
the shop prior loadout?
8. If used in conjunction with a bleed-off valve, has the bleeder valve been
function tested?
9. Have the tool joints been inspected?
10. If type RETV-DA is used (primary or BU), is the space out such that the spanner
joint is correctly located across an annular preventer? Are umbilical jumpers
available to reach from the RETV-DA to the SSTT?

SURFACE TEST VALVE

LUBRICATOR VALVE
1. Is a primary and backup tool available and have both been loaded out?
2. Are the primary and backup tools identical, or are they different types or models?
If different explain.
3. What is the length of the control hoses that were loaded out, and is this sufficient
considering the placement of the valve in relation to the rig floor?
4. Has the tool been serviced since the last job (i.e. has the tool been broken down,
all seals been broken down, all seals been checked/changed, ball valve checked
for scoring, metal sealing surfaces checked for pitting/scoring)?
5. Have the lubricator valves been function and pressure tested (LP and LP) from
both directions prior to loadout?
6. Has the pump-through capability of the valve been tested in the shop? At what
pressure and flow rate?
7. Is the injection port open or plugged?

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SURFACE TEST TREE (STT)

1. Has the body of the STT been pressure tested (LP and HP) prior to loadout?
2. Have HP and LP pressure tests been performed each way against the master
valve, flowline valve and kill valve prior to load-out?
3. Does the STT have a check valve on the upstream of the kill valve? If so, can it
be locked open?
4. Are stiff joints and XOs available to run immediately below the STT and are
necessary XOs loaded out?
5. Have the remote ESD stations been loaded out?
6. Does the logging company understand the connection type on top of the STT
so that connection can be made to the wireline BOP/Lubricator?
7. Is a crossover from the STT to the cement line available?
8. Have needed coflexip hoses been loaded out?

DATALATCH SYSTEM
1. Is the equipment needed to provide SRO of pressure below the SI valve?
2. Is the OD of the Powerline running tool small enough to allow it pass through all
then DST string components to reach the LCDA?
3. Do you have the needed equipment to splice the running tool onto the wireline
(including back- ups)?
4. Have you tested the SRO surface computer interface to ensure it is working
properly?

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ITEMS PERFORMED ON THE RIG

GENERAL INFORMATION
1. Are Lifting devices onsite for all of the downhole test tools?
2. Were all DST tools drifted to 2.125 in. on the rig prior to RIH?
3. Were all tools calipered and measured, on the rig prior to RIH?
4. If any of the dimensions differed from those on the DST stack-up sketches, were
the new dimensions provided to Esso representative so that space out
corrections could be made?
5. Were all tools function and pressure tested on the rig prior to RIH?
6. Were emergency procedures (yellow and red alarms) reviewed and understood
between Driver and the SSTT operator(s)?
TUBING TESTER VALVE (TFTV)
Unless otherwise indicated, provide information regarding the Primary tool.
1. Was the tool body pressure tested (both low and high) on the rig prior to RIH?
2. Was the flapper pressure tested (both high and low) from above prior to RIH?
3. Were all of the valve functions tested and verified to be in correct position for
RIH?
4. Are auto-fill ports open and functioning or are they plugged?
5. Has the rupture disk value been checked and agreed on by Esso and
Schlumberger?
6. What is the status of the backup tool?

DOWNHOLE SAMPLING TOOL (SCAR-A)

Unless otherwise indicated, provide information regarding the primary tool.
1. Was the tool configured in accordance with the Test Engineers requirements?
2. Were rupture disk values checked and agreed on by Esso and Schlumberger?

IRIS OPERATED DUAL VALVE (IRDV)

1. Was the IRDV function tested prior to running? Was the ball valve pressure
tested both ways on the rig prior to running?
2. Were the correct rupture settings verified with the Esso Engineer and were the
correct disk(s) installed?
3. Was the tool run with 12 available dumps remaining in the atmospheric
chamber?

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DOWNHOLE SHUT-IN VALVE (PCT) WITH PRESSURE OPERATED

REFERENCE TOOL (PORT) AND HOLD OPEN (HOOP) FEATURE
Unless otherwise indicated, provide information regarding the Primary tool.
1. Is the nitrogen precharge in the PCT Valve set to operate (normal operation)
at the prescribed pressure (______ psi surface pressure + _____ ppg brine
hydrostatic at _____m TVD RKB)?
2. Was the tool function tested on the rig prior to RIH?
3. Was the tool pressure tested from both above and below at both low and high
pressures on the rig prior to RIH?
4. Was is the status of the backup tool?

CIRCULATING VALVE (MCCV)

Unless otherwise indicated, provide information regarding the Primary tool.
1. Has a diagram showing the cycle of tool positions been given to Driller,
Toolpusher, and Esso personnel?
2. Was the tool function tested on the rig prior to RIH?
3. Was the tool pressure tested (low and high pressure) on the rig prior to RIH?
4. What is the status of the backup tool?

SINGLESHOT HYDROSTATIC REVERSING VALVE

Unless otherwise indicated, provide information regarding the Primary tool.
1. Is the rupture disk rated to ____psi (____psi surface pressure + ____ ppg brine
hydrostatic at _____ m TVD RKB)?
2. Rupture disk rating minimum: _________________,maximum: _____________
3. Was the tool redressed on the rig prior to RIH?
4. Was the tool body pressure tested on the rig prior to RIH?
5. What is the status of the backup tools?

SUBSEA TEST TREE & TOOL

FLUTED HANGER
Unless otherwise indicated, provide information regarding the Primary tool.
1. Did Esso, Schlumberger and the rig contractor all agree on the final SSTT/BOP
space out?
2. Was the fluted hanger set on the threaded mandrel in accordance with the
dimensions that all parties agreed to?
3. Was the SSTT /FLUTED hanger assembly measured immediately prior to RIH to
ensure consistency with requirements?

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SUBSEA TEST TREE (SSTT)

Unless otherwise indicated, provide information regarding the Primary tool.
1. Has the SSTT specialist communicated with the Driller regarding disconnect
timing and pick-up needed for the SSTT to clear the LMRP disconnect point?
2. Was the SSTT measured immediately prior to RIH to ensure consistency with
dimensional requirements?
3. Was a complete function and pressure test performed on the rig prior to
picking it up?
4. Were the SSTT valve open, valve close and disconnection functions tested
through the hose reel and timed on the rig floor immediately prior to RIH?
Open time: _________ Close time: ________ Disconnect time: ___________
5. W a s th is d isco n n e ct te st p e rfo rm e d b y sta rtin g o u t w ith p re ssu re o n th e A lin e
to more closely simulate actual disconnect time? _________________
6. What are the shear screws for mechanical release set to? ________ ft-lbs.
7. Was the OD measured to ensure it would pass through the riser?
8. Was the hose reel pressure tested on the rig and are critical spare parts
available?
9. Was the injection line on the reel pack displaced to the correct fluid (or at least
had the fresh water displaced out) prior to circulating down the base oil/diesel
cushion?
10. What is the injection rate capability of the as the SSTT chemical injection line?
______gal/min.
11. Will the final space out allow dual or single ram closure?
12. What is the status of the backup SSTT?

RETAINER VALVE
Unless otherwise indicated, provide information regarding the Primary tool.
1. Was the Retainer Valve function and pressure (LP and HP) tested on the rig
through the hose reel? Time to close valve ____________________
2. What is the status of the backup tool?
3. If type RETV-DA, is the space out such that the spanner joint is correctly located
across an annular preventer?

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WELL TESTING OPERATIONS

SURFACE TEST TOOLS

LUBRICATOR VALVE
Unless otherwise indicated, provide information regarding the Primary tool.
1. Was the Lubricator valve function and pressure tested (LP and HP) from both
directions on the rig prior to picking it up?
2. What is the status of the backup tool?

SURFACE TEST TREE (STT)

1. Was the STT space out about as predicted?
2. Were all of the STT valves pressure tested both ways (LP and HP) on the rig
prior to picking it up?
3. Is the correct top tension being held on the compensator?
4. Were the remote ESD stations tested on the rig following landout?

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WELL TESTING OPERATIONS

APPENDIX C - EXAMPLE SPACE OF LANDING STRING

Figure 13.29 Example

Space of Landing String

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REFERENCES

Chorneyko, David M., Simmons, A. Barlow, Patel, Harshad N., and Vela, Saul, The
ExxonMobil Exploration Company Well Testing Operations Manual, C o p yrig h t 2 0 0 0 ,
Chapter 11, pages 11-3 through 11-16), available on CD-ROM from EMEC Technology,
Formation Evaluation Group
C ra w fo rd , G a ry E ., P ie rce , A a ro n E ., E xp lo ra tio n W e ll T e stin g M a n u a l, Exxon
Production Research Company, July 1997, Section 11, Data Forms.
ExxonMobil Development Drilling, Drilling OIMS Manual, Second Edition, Section 3-10,
January 2002.

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SUBSEA COMPLETIONS

14
Section

14.0 SUBSEA COMPLETIONS

OBJECTIVES
This section will focus on some of the major attributes of subsea completion that differ
from typical offshore platform operations with the goal to gain a basic understanding of
the critical systems. The most significant differences between land or platform based
completion operations and subsea completion operations involve:

Subsea tree system.

Downhole well control system.

Riser connection back to surface.

Associated vessel motions.

A number of aspects of deepwater completions are quite similar to platform or shallow
water operations. These may include fluid selection and handling, sand control selection
and implementation, tubing string and associated hardware. These topics are common
to all completion operations and therefore will not be specifically covered in this review.
This section will focus on the completion operations from the wellhead to the surface and
does not provide information on the downhole completion operations since they are
generally not unique to floating operations.
Upon completion of this section, you will be able to:

Describe the differences and advantages/disadvantages between Horizontal and

Vertical Trees.

Describe the difference between single concentric and dual bore eccentric Vertical
Trees.

D e scrib e th e d iffe re n ce b e tw e e n P a rtia l a n d F u ll d rillin g H o rizo n ta l T re e s.

Describe the application of a subsea tubing hanger and how it is oriented.

List the different types of completion risers.

Identify the major components of a subsea test tree from a schematic.

Describe the functions of the subsea test tree.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION
SUBSEA COMPLETIONS

List the different types of subsea control systems and the application for
each system.

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SUBSEA COMPLETIONS

CONTENTS Page
14.0 SUBSEA COMPLETIONS .................................................................................................... 1
OBJECTIVES ........................................................................................................................ 1
14.1 OVERVIEW OF A SUBSEA COMPLETION ......................................................................... 4
14.1.1 PLANNING.............................................................................................................. 4
14.2 TREE SELECTION - HORIZONTAL VS. VERTICAL TREE ................................................. 6
14.2.1 SUBSEA TREE SELECTION ................................................................................. 6
14.2.1 VERTICAL TREES ................................................................................................. 7
14.2.3 E C C E N T R IC D U A L B O R E V E R T IC A L T R E E .................................................... 8
14.2.4 C O N C E N T R IC M O N O B O R E V E R T IC A L T R E E .............................................. 10
14.2.5 HORIZONTAL TREES .......................................................................................... 14
14.2.6 PARTIAL DRILLING HORIZONTAL TREE .......................................................... 15
14.2.7 FULL DRILLING HORIZONTAL TREE. ............................................................... 17
14.2.8 TREE SELECTION SUMMARY ............................................................................ 21
14.3 TUBING HANGER INSTALLATION ................................................................................... 23
14.3.1 TUBING HANGER ORIENTATION. ..................................................................... 23
14.3.2 ACTIVE HANGER ORIENTATION ....................................................................... 23
14.3.3 PASSIVE HANGER ORIENTATION..................................................................... 25
14.4 COMPLETION RISER ......................................................................................................... 26
14.4.1 DUAL BORE COMPLETION/WORKOVER RISER FOR
ECCENTRIC VERTICAL TREES ......................................................................... 26
14.4.2 ECCENTRIC VERTICAL TREE BARRIERS ........................................................ 29
14.4.3 MONO-BORE COMPLETION RISER FOR CONCENTRIC VERTICAL TREE .... 30
14.4.4 MONO-BORE COMPLETION RISER FOR HORIZONTAL TREES ..................... 30
14.4.5 LIFT FRAME ......................................................................................................... 31
14.4.6 RISER SUMMARY ................................................................................................ 33
14.5 SUBSEA TEST TREE CONTROLLED DISCONNECT ...................................................... 35
14.6 SUBSEA TREE CONTROL SYSTEMS .............................................................................. 38
14.7 SUBSEA TREE PREFERENCES ....................................................................................... 41
14.7.1 CASE STUDY TREE SELECTION FOR DEEPWATER GOM PROJECT ........ 42
14.8 REFERENCES .................................................................................................................... 44
14.9 WELL FLOWBACK SCHEMATIC FOR HORIZONTAL TREE............................................................ 45
14.10 BATCH SUBSEA TREE INSTALLATION ...................................................................................... 46

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SUBSEA COMPLETIONS

14.1 OVERVIEW OF A SUBSEA COMPLETION

The subsea environment poses significant technological challenges unlike anything
encountered in platform or land based developments. Development strategies must
consider the complexities of the offshore environment including water depth, weather,
currents, geothermal gradient, rig type, equipment reliability and logistics, just to name
a few.
One aspect of subsea completions that quickly becomes clear is how critical it is to
effectively manage the numerous interface issues. Effective integration of these
interfaces, to a large degree, will directly impact completion success. Subsea completion
technology is so advanced and specialized that a large number of subject matter experts
are required to properly address the many details of the installation. The entire system is
highly intertwined and few people in the process have the opportunity to fully grasp all of
the interdependencies. It is therefore imperative for those individuals leading the
completion operation to properly coordinate and facilitate the timely and effective
interchange of information. The Management of Change System plays a key role in
this interchange.

14.1.1 PLANNING
Due to complexity and required operational features of the total subsea development
project, preplanning must start prior to procurement of the subsea tree and its related
equipment. It is important to ensure that all operational features of the tree and its
control system are identified and specified as early as possible. These must include:
All interfaces between the landing string, tubing hanger, subsea tree and control
system, and production tubing string must be evaluated. These may also include
control line requirements for the safety valve and chemical injection systems,
encapsulated conductors for downhole pressure/temperature monitoring
systems, intelligent completion components, and provisions for annular well
access and monitoring.
Rig related issues such as deck space, load capacity and equipment lay-out
plans need to be addressed as early as possible (oftentimes, even before the rig
is selected). This is mainly to ensure enough rig capacity and flexibility to perform
safe and efficient subsea operations under all anticipated environmental
conditions.
Operational envelopes for heave, pitch and roll and riser alignment for all critical
drilling and completion phases.
Prior to initiating offshore installation operations, a Systems Integration Test (SIT)
will generally be conducted. The functionality and operability of all related subsea
systems will be thoroughly tested at this time.
Batch Setting Plans (also reference appendix B)
Batch setting is an operational technique where multiple horizontal trees are run and set
at a given drill center to take advantage of operational efficiencies. Implementation of
this technique requires pre-investment in an extra conductor, referred to as a parking

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SUBSEA COMPLETIONS

stump. Additionally, all trees must be completed and delivered upon commencement of
drilling operations versus commencement of completion operations. As such, batch
setting requires substantial acceleration of the tree delivery schedule, therefore,
coordination among the Drilling and the Subsea Teams procuring trees is essential.
Batch setting benefits from learning curve acceleration because a procedure is repeated
many times over a short time frame and saves BOP trip time. The savings become more
and more significant as water depth increases.
Conductors are batch set on all wells at the subsea drill center plus one additional
parking stump. Trees are then run on drill pipe and landed on all conductors except the
conductor that is the initial drilling site. The BOP stack is then run, and drilling
commences. At the appropriate time for tree installation, the stack is disconnected from
the drill well and latched onto the tree from the adjacent conductor (the location of the
next drill well). The tree is then landed on the drill well to be completed. The process
eliminates a BOP round trip. This technique was used on the Diana, Marshall and Mica
developments. Estimated savings were approximately $1.2M per well.

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14.2 TREE SELECTION - HORIZONTAL VS.

VERTICAL TREE

14.2.1 SUBSEA TREE SELECTION

The decision to select the subsea tree concept usually occurs early in the project due to
long delivery times. It is typical for this phase of the project to occur 18 to 24 months
prior to the start of drilling operations. Also, the contract commitment for the trees can be
one of the first large CAPEX expenditures for a new project. Therefore, it is imperative
that the subsea tree concept has been fully integrated into the overall conceptual well
plan and that potential well control risks identified with each option have been
considered.
The subsea tree selection process is typically led by the Subsea Group of the
Development Company, but critical input and endorsement from Drilling is required.
Decisions made during this development phase have significant implications on almost
every aspect of the well plan and completion installation (specifically the completion riser
type). Early integration of drilling, completion and subsea expertise during the concept
selection phase of the project enhance the planning and execution phases of deepwater
subsea developments.
There are two fundamental subsea tree concepts available to industry V ertical Trees
(VT) and H o rizo n tal Trees (HT). Essentially all of the subsequent completion
discussions are predicated on the type of tree selected.
VERTICAL TREE
The Vertical Tree concept is defined as having a vertical flow though the tubing hanger.
The master and wing valves in the tree body are located vertically above the tubing
hanger. The tubing hanger is landed in the subsea high-pressure (HP) wellhead. This
concept allows retrieval of the tree body with pulling the tubing hanger.
HORIZONTAL TREE
The Horizontal Tree is defined as diverting flow horizontally at the tubing hanger. The
master and wing valves in the tree body are located in the horizontal plane to the tubing
hanger. The tubing hanger is landed in the horizontal tree. This concept allows retrieval
of the tubing hanger with pulling the tree body.
The remainder of this section describes the attributes of both tree concepts.

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14.2.1 VERTICAL TREES

The nomenclature for these two tree concepts evolved from the tubing hanger design,
depending on the direction of the production flow stream relative to the tubing hanger
(e.g., either vertical or horizontal). With either subsea tree concept, the vertical
production flow from the wellbore is eventually diverted horizontally to enter the subsea
flowline system. For the vertical tree concept, the flow stream is diverted horizontally
above the tubing.
The production tubing is run through the drilling BOP and landed in the 18-3/4 in. subsea
wellhead or in the tubing hanger spool. The drilling BOP must be pulled before the VT
can be run. A special completion riser is used to run the tubing/TH and the VT (Figure
14.1).
The vertical tree concept can be further defined as E ccen tric or C o n cen tric based
on whether the production flow is routed eccentrically (resulting in a dual bore
configuration) or concentrically (a single bore configuration) through the tubing hanger.
These differences will be further discussed in this section.

Figure 14.1 Zinc Project Dual Bore Vertical Tree

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14.2.3 E C C E N T R IC D U A L B O R E V E R T IC A L T R E E
T h is tre e co n ce p t, a lso kn o w n a s a d u a l b o re V T , h a s tw o ve rtica l b o re s th ro u g h th e
tree body and tubing hanger as illustrated in Figure 14.2. In the Eccentric Vertical Tree
concept, the dual bore tubing hanger is eccentric and lands in the subsea wellhead
body. The eccentric design requires accurate orientation of the tubing hanger (TH) and
the tree. A detailed discussion of the TH orientation can be found in section 14.3.1.
The larger bore in the TH is for the production tubing which is suspended below the
hanger, and the smaller bore allows access to the production casing annulus. The
eccentric design does limit the production bore through the tubing hanger (typically a
5-1/2 in. x 2-3/8 in. bore when run in conjunction with 10-3/4 in. production casing).
Note: Some regulatory agencies require an annulus safety valve when dual bore trees
are utilized.
The annulus bore provides access to the production casing annulus and facilitates fluid
circulation and well control during tubing running or pulling operations when there are no
downhole mechanical barriers. The tubing hanger lands and seals in the subsea
wellhead body. This makes the tubing hanger independent from the VT itself.
The Eccentric Vertical Tree concept has a minimum of two subsea tree valves
(e.g. master and swab valves) located vertically above each bore (e.g., the production
tubing bore and production casing annulus bore). It is also common for the tubing
hanger spool to have a crossover connection between the production and annulus bore,
separated by an X-over valve (XOV).
This design provides vertical access through the vertical tree body to run or pull wireline
plugs that land into dedicated profiles in the dual bore tubing hanger. These wireline
plugs provide mechanical isolation to the tubing and production casing annulus for well
control. This becomes important during BOP removal/tree installation and during
workover operations. The Eccentric Vertical Tree concept has the production wing valve
outlet in the tree body at 90o to the production bore above the master valve. This diverts
the production flow stream horizontally, through the choke and mated connector to the
subsea flowline system.

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SUMMARY OF ECCENTRIC VT
Two eccentric vertical bores through tubing hanger.
Tubing hanger lands in subsea wellhead (active alignment).
Flow diverted horizontally after master valve.
Tree installed with dual bore completion riser (open water).
Through tubing workovers no plugs to pull.

The typical steps to run the tubing and Eccentric VT are as follows:
1. Production tubing/TH is run via a dual bore completion riser and landed in the
subsea wellhead. This system will be run through the drilling riser/BOP.
2. Flow barriers (wire line plugs) are run and set in the tubing hanger. The
completion riser and drilling riser/BOP are pulled.
3. The VT is run via a dual bore completion riser/BOP.
4. The flow barriers are removed, and either the well is allowed to flow back to
surface via the completion riser, or the tree cap is run and the well flows through
the subsea manifold/pipeline.

The Eccentric VT concept was used for the following projects:

Zinc (ExxonMobil GOM)
Girossol (Total Fina Elf - Block 17 Offshore Angola)
Balder (ExxonMobil North Sea Norway)
Blackback (ExxonMobil Austraila)

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4.2.4 C O N C E N T R IC M O N O B O R E V E R T IC A L T R E E
The Concentric VT concept uses a mono bore tubing hanger that is concentric and sets
in a tubing hanger spool landed above the subsea wellhead. The concentric design does
not limit the production bore through the tubing hanger, therefore a larger tubing string
can be used. For this tree concept, the flowpath for the production casing annulus is
around the concentric tubing hanger through side outlets machined in the tubing hanger
spool below and above the hanger as shown in Figure 14.3. The tubing hanger lands
and seals in the subsea wellhead body. This makes the tubing hanger independent from
the VT itself.
The Concentric Vertical Tree concept has a minimum of two subsea tree valves
(e.g. master and swab valves) for both the production tubing and casing.
This design provides vertical access through the vertical tree body to run or pull wireline
plugs that land into dedicated profiles in the mono bore tubing hanger. These wireline
plugs provide mechanical isolation to the production tubing only. The production casing
is isolated with a valve in the tubing spool body. This becomes important during BOP
removal/tree installation and during workover operations. The Concentric Vertical Tree
concept has the production wing valve outlet in the tree body at 90 degrees to the
production bore above the master valve. This diverts the production flow stream
horizontally, through the choke and mated connector to the subsea flowline system.

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SUMMARY OF CONCENTRIC VT
Single concentric bore through tubing hanger.
Tubing hanger lands in tubing hanger spool (passive alignment).
Flowbase design allows tree retrieval without pulling jumper.
Tree installed with mono bore completion riser (open water).
Additional permanent leak path (tree/tubing hanger spool).

The typical steps to run the tubing and Concentric VT are as follows:
1. Flow barriers (wire line plugs) are run and set in the production casing.
2. The drilling riser/BOP is pulled.
3. The tubing hanger spool is run with DP.
4. Once the spool is landed the DP is pulled.
5. The drilling riser/BOP is run and the flow barriers are removed.
6. Production tubing/TH is run via a mono bore completion riser and landed in the
tubing spool. This system will be run through the drilling riser/BOP.
7. Flow barriers (wire line plugs) are run and set in the tubing hanger.
8. The completion riser and drilling riser/BOP are pulled.
9. The VT is run via the mono bore completion riser/BOP with a hose or small string
of tubing to maintain access to the production annuals.
10. The flow barriers are removed and either the well is allowed to flow back to
surface via the completion riser or the tree cap is ran and the well flows through
the subsea manifold/pipeline.

The Concentric VT concept was used for the following projects:

Bongo (Shell Nigeria)
Mensa (BP GOM)
Crazy Horse (BP GOM)
Macaroni (Shell GOM)

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VERTICAL TREE SUMMARY

The main differences between the Eccentric and Concentric Vertical Tree concepts are:
The Concentric VT body lands on a tubing hanger spool while the Eccentric VT
body land on the 18-3/4 in.subsea wellhead.
The Concentric VT uses a mono bore tubing hanger. Therefore, the production
annulus access is around the tubing hanger (i.e. through the tubing hanger
spool).
Although the Concentric VT system is designed to capture many of the advantages of
both Eccentric VT and Horizontal Tree concepts, this concept has some significant
limitations to be considered during subsea tree concept screening.
The key limitations include:
A separate trip in critical path (with a single derrick MODU) is required to install
the tubing hanger spool located between the subsea wellhead and vertical tree
body which results in additional installation costs and another potential leak path.
More potential leak paths due to additional connections.
The trees are substantially taller which will impact the size of MODU required for
the project.
Both the Eccentric and Concentric VT concepts allow the operator to pull and repair the
vertical tree body without pulling the tubing hanger or disconnecting the subsea jumper.
Both the Concentric and Eccentric VT use a dual vertical bore through the tree body.

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VT Body

Manifold/Template
Connection
Tubing
Hanger

Flow Base 18 3/4"Subsea Wellhead

Figure 14.2 - Eccentric Dual Bore

VT

Tree/Flow Base VT Body

Connection
`

Tubing Hanger
Manifold Spool
Connection

Flow Base
18 3/4" Subsea Wellhead
Tubing Hanger

Figure 14.3 - Concentric VT Concept & Tubing Hanger

Spool

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14.2.5 HORIZONTAL TREES

As previously noted, the Horizontal Tree (HT) concept diverts the production flow stream
out a side outlet in the tubing hanger through production flow valves located 90 degrees
from the vertical run of the tree. The tubing hanger lands in the body of the HT. The
centered bore of the tubing hanger allows use of larger tubing (7 in.) as compared to a
comparably sized vertical tree. The HT uses a hydraulically actuated connection to
connect to the high pressure wellhead. The HT also has a profile on top of the tree that
allows the drilling BOP stack to connect to the tree. Therefore, the HT concept allows the
operator to pull and repair the tubing without pulling the tree. On the other hand, a
problem that requires pulling the tree would also involve pulling the tubing string since
the tubing/TH is landed in the tree.
The tubing hanger for this HT concept has an intersecting outlet at 90 degrees to the
production bore. This diverts the production flow stream through the production master
and wing valves. These valves may be either integral to the HT body or bolted on the
side of the HT body. Access to the production casing annulus is provided by a valved
side outlet configuration that exits below and re-enters above the tubing hanger as
shown in Figures 14.5. and 14.6.
To secure the well for production operations, a permanent wireline plug must be installed
in the vertical bore of the tubing hanger above the flow outlet. Then, an internal tree cap
is run and landed in the tree above the tubing. A second permanent wireline plug is then
run and landed in the internal tree cap to fully isolate the vertical flow path. This plug
allows future vertical access without pulling the internal tree cap.
Recent experience with this tubing hanger/tree cap design identified problems
associated with setting both the internal tree cap and tree cap plug. The tight clearances
associated with this design have proved to be very intolerant of any well debris that may
settle on top of the tubing hanger plug. Extra care and operational steps are required to
ensure riser and stack cleanliness. Based on this knowledge, a number of
manufacturers are promoting new tree designs that incorporate the tubing hanger and
internal tree cap into a single element. This upgrade will help to avoid some of the
problems experienced on the Diana and Mica subsea developments.
Since the tubing hanger lands in the HT body and not the subsea wellhead, as with a
dual bore vertical tree, the interface between the subsea wellhead and subsea tree is
less critical than with a Vertical Tree concept. This allows the drill team greater flexibility
to more easily use different vendor designs for the subsea wellhead or utilize an existing
exploration well that is temporarily suspended.
The H T co n ce p t ca n b e fu rth e r d e fin e d a s P a rtia l D rillin g o r F u ll D rillin g a s sh o w n in
Figures 14.5 and 14.6. Both horizontal tree concepts utilize a concentric, mono bore
tubing hanger. Tubing hanger orientation is still required, due to mating of all control
line connectors.

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14.2.6 PARTIAL DRILLING HORIZONTAL TREE

This concept (concentric vertical bore through the hanger and the production flow) is
diverted into an intersecting horizontal bore against a permanent wireline plug in the
tubing hanger. A fixed helix in the tree body provides passive tubing hanger alignment.
Access to the tubing by production casing annulus is around the tubing hanger through
the tree body shown in Figure 14.5 This tree is typically run and landed using drill pipe.
Once the HT is installed, it is not possible to land casing hangers in the 18-3/4 in.
subsea wellhead. However, since the HT is run after setting a full string of 9-5/8 in.
production casing, it is possible to run a drilling bore protector and drill or sidetrack in
an 8-1/2 in. hole through the HT. One of the key advantages of this concept is that
production tubing may be used as the completion riser. This eliminates the need to have
a costly dedicated completion riser.

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SUMMARY OF PARTIAL DRILLING HT

Concentric vertical and intersecting horizontal bore in hanger.
Tubing hanger lands in HT body (passive alignment).
Tree installed on drill pipe.
Drill 8-1/2 in. hole with HT installed using a bore protector.
Production tubing used as completion riser.

The typical steps to running the Partial Drilling HT are as follows:

1. Run and cement the production casing.
2. Test the casing and install storm packer for well bore isolation.
3. The drilling riser/BOP is pulled.
4. The HT is run with a drill pipe landing string.
5. The HT coupled to the connection on top of the wellhead.
6. The drilling riser/BOP is run and coupled to the connection on top of the HT.
7. The storm packer is removed.
8. The production tubing/TH is run with a subsurface test tree (SSTT) and a mono
bore completion riser or landing string. This system will be run through the drilling
riser/BOP.
9. The well is flowed back to surface via the completion riser (landing string), or the
internal tree cap is run and the well flows through the subsea manifold/pipeline.
10. Pull the subsurface test tree (SSTT) and a mono bore completion riser or landing
string.
11. Pull the drilling riser/BOP.
12. Run the external tree cap on drill pipe.

The Partial Drilling HT concept was used for the following projects:
Diana, Marshall, Madison (ExxonMobil GOM)
Mica (ExxonMobil GOM) (Figure 14.4)
Kizomba (ExxonMobil Angola)

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14.2.7 FULL DRILLING HORIZONTAL TREE

This Full Drilling HT concept is based on combining the existing 16-3/4 in. subsea
wellhead and 18-3/4 in. HT tree designs. The concept is to manufacture a 16-3/4 in.
subsea wellhead system with an 18-3/4 in. hub. This would permit an 18-3/4 in. HT
system to be run on drill pipe immediately after running and cementing the subsea
wellhead on 20 in. conductor casing. Or in the case of the slim hole design, 13-3/8 in.
with a crossover to 20 in. casing and an 18-3/4 in. hub is run. The 18-3/4 in. BOP stack
would then be run and landed on top of the 18-3/4 in. HT. A drilling wear bushing would
be run to protect the HT bore. Then drilling and casing running operations would be
conducted through the 18-3/4 in. HT body (see Figure 14.6).
The Full Drilling HT concept eliminates the need to pull the 18-3/4 in. BOP stack by
allowing the 9-5/8 in. casing string to be run through the HT body. Even though this
concept can save a BOP trip on a single well basis, much of its incentive is lost if batch
installation of trees is done.
One key advantage of this concept is the use of a flow base which allows the tree body
to be pulled without disconnecting the jumper between the flowbase and the manifold.
The tubing hanger spool is typically run & landed using drill pipe, while the tree body is
usually installed with a mono bore completion riser in open water. However, a separate
trip is required to install the tubing hanger spool, and another permanent leak path is
introduced.

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SUMMARY OF FULL DRILLING HT CONCENTRIC VERTICAL AND INTERSECTING

HORIZONTAL BORE IN HANGER
Tubing hanger lands in HT body (passive alignment).
Tree installed on drill pipe.
Drill 12-1/4 in. and 8-1/2 in. hole with HT installed using a bore protector
(slim hole design).Production tubing used as completion riser.

The typical steps to running the Full Drilling HT are as follows:

1. Run and cement the surface casing. Test the casing and install storm packer for
well bore isolation. The drilling riser/BOP is pulled.
2. The tubing spool is run on mono bore completion riser.
3. The HT is run with a mono bore completion riser, and the HT is coupled to the
tubing spool.
4. The drilling riser/BOP is run and coupled to the connection on top of the HT.
5. The storm packer is removed.
6. The remaining hole sections are drilled.
7. The production tubing/TH is run with a subsurface test tree (SSTT) and a mono
bore completion riser or landing string. This system will be run through the drilling
riser/BOP.
8. The well is flowed back to surface via the completion riser (landing string) or the
internal tree cap is run, and the well flows through the subsea manifold/pipeline.
9. Pull the subsurface test tree (SSTT) and a mono bore completion riser or landing
string.
10. Pull the drilling riser/BOP.
11. Run the external tree cap on drill pipe.

The Full Drilling HT concept was used for the following projects:
Dalia (Total Fina Elf Block 17 Offshore Angola)
Ross (Talisman Energy North Sea UK)

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Figure 14.4 Mica Partial Drilling Horizontal Tree

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External Tree Cap

Internal Tree Cap

Tubing Hanger HT Body

Production Casing Access

Permanent
Wireline Plug

Manifold
Connection

Production Outlet
18 3/4" HP Wellhead

9-5/8 C asin g H an g er
Figure 14.5 Partial Drilling HT

External Tree Cap

Tubing Hanger Internal Tree Cap

HT Body
Production Casing Access

Permanent
Wireline Plug

Manifold
Connection
Production Outlet

18-3/4 x 20x 13-3/8

HP Wellhead 9-5/8 C asin g H an g er

Figure 14.6 - Full Drilling HT

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14.2.8 TREE SELECTION SUMMARY

Since the cost of VT and HT tree components are very close, the key driver for the
subsea tree selection process becomes the cost, availability, and operation of the
completion/workover riser system during initial installation. Certain assumptions for well
intervention versus subsea tree failures can also contribute to the subsea tree selection
process. If it is assumed that more tubing pull workovers would be required due to
downhole completion failures, the HT concept becomes more attractive
The subsea trees have generally proved more reliable than the overall downhole tubing
and sand face completion. Thus, ExxonMobil has preferred horizontal trees for recent
deepwater developments to capture the operational and financial benefits associated
with installation efficiencies and to eliminate the need for a dedicated completion riser
system.
A significant advantage of the vertical tree is that routine interventions into the wellbore
can be accomplished without the risks associated with pulling and resetting wireline
plugs, but a dedicated completion riser system is needed. The major advantage of the
horizontal tree is that the production tubing can be pulled from the wellbore without
pulling the HT body, (using the MODUs well control system, e.g. no dedicated
completion riser system is needed). In many development areas this is a significant
driver to the tree selection decision.
A qualitative and quantitative, development specific, intervention study will be needed to
determine the frequency of the expected intervention operations. This exercise will help
highlight which tree concept is most cost effective for a given scope of intervention work.
In general, if tree failures are the source of the majority of interventions, then vertical
trees tend to offer substantial benefits. If downhole failures have the higher potential,
then horizontal trees have inherent benefits.
For example, a quantitative intervention study for a particular development may
determine that artificial lift is required and/or the risk of sand control failure is high. In that
case, the project will likely benefit from the use of a horizontal tree that allows tubing
string removal without the cost of subsea tree removal.
In contrast, a development of naturally flowing wells with no sand control requirement
and little risk of downhole mechanical failure could likely benefit from use of a vertical
tree. This is because the relative frequency of tree related intervention with respect to
downhole intervention is likely greater. A major failure of a vertical tree requiring a pulling
operation could be conducted without pulling tubing. With a horizontal tree, the tubing
must be pulled prior to pulling the tree.
Other considerations are driven by rig selection and rig availability issues. The deck
space, variable deck load constraints and moonpool size/height under the rig floor is a
critical aspect of handling trees and completion equipment. The VT is typically taller than
the HT and so requires more height clearance under the rig floor. The HT is typically
wider than the VT and therefore requires a large moonpool area. If a dedicated
completion/workover riser is utilized, the drilling riser would likely need to be offloaded
between wells. These size constraints and riser issues will dictate the type of MODU
(Fourth or Fifth Generation) is capable of conducting the operation.

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For deepwater operations, horizontal trees provide a number of key advantages over
vertical trees.
When cleaning up and testing a subsea well to a Mobile Offshore Drilling Unit
(MODU), two independent well control systems are fully functional. First, the
subsea test tree with shut-in and disconnect functions, provides the primary well
control system. Second, the rig blowout prevention stack (BOP) provides
shearing and disconnect capabilities in the event of a subsea test tree failure.
As a result, well control risk is substantially reduced.
Horizontal trees can be batch set on the subsea wellhead before
commencement of completion operations; thus reducing overall installation
times, equipment costs and complexities of vertical trees.
T o d a te , in d u stry h a s p rim a rily u tilize d th e P a rtia l D rillin g H T co n ce p t. H isto rica lly, th e
"Full Drilling" HT concept has only been used for slim hole casing programs in single,
subsea well developments. This is because much of the savings potential of the full
drilling horizontal (elimination of stack pulling operations) is quickly offset by the
efficiencies gained by batch drilling and setting the trees at a particular drill center.
The following sections focus on the tubing hanger installation and the completion riser.

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14.3 TUBING HANGER INSTALLATION

Tubing hanger installation is a critical subsea tree operation from a well control
perspective. Landing the tubing hanger without downhole isolation to the completion is a
well control risk that should be considered.

14.3.1 TUBING HANGER ORIENTATION

The two methods used to orient the tubing hanger are called "active" and "passive"
orientation. Tubing hanger orientation is required to properly interface with downhole
electrical/hydraulic functions and production bores.

14.3.2 ACTIVE HANGER ORIENTATION

The eccentric vertical tree concept uses
active orientation requiring at least three
critical alignment steps with a low Alignment Helix
tolerance for error. The tubing hanger With Vertical
must be aligned with the flowline jumper Slot
when the vertical tree body is landed.
This is accomplished by using a helix
on the Tubing Hanger Running Tool Tubing Hanger
(THRT) and a remotely actuated pre- Running Tool
Tubing Hanger
installed pin in the drilling BOP stack.
This pin is placed in one of the side
outlets of the drilling BOP stack. As Alignment Pin
shown in Figure 14.7, an alignment pin
located within the BOP stack
(simulated) is used to orient the TH.
The drilling BOP must be aligned
relative to the Completion Guide Base
(CGB) which is attached to the subsea CGB
wellhead and contains the flowline
jumper hub. An alternative to the CGB
is the subsea template concept.
When landing the tubing hanger, an
ROV is used to verify the BOP pin
position. Good visual indicators are
required on the BOP pin to accurately
observe movement of the pin against
the THRT body. To facilitate this, a
close-up camera is often required on
the ROV to gain access to the pin outlet
on the BOP Figure 14.7-S im ulated B O P/T H R T D ry R un

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The TH is automatically rotated to the correct position when the orientation pin is
engaged into the Alignment Helix. Once in the correct position, the orientation pin will
drop into a vertical slot in the THRT body. Indication of correct position of the pin is
monitored using an ROV. Once oriented and landed, the TH integrity can be pressure
tested through kill/choke line, with the annular preventer closed against the THRT body.
Minimizing riser ball joint angle is important during this installation due to the tight
clearances between the marine riser/BOP and THRT/TH. Typically, the maximum
allowable riser ball joint angle is1.5. Rig heave is also important and should be limited
to ~1.5 m (5 ft). During landing and orientation operations, the heave compensation
system should be engaged.
Due to interface and alignment issues between the subsea wellhead, tubing hanger and
subsea tree, operators typically select the same vendor to provide the subsea wellhead
a n d su b se a tre e w h e n u sin g th e E cce n tric V e rtica l T re e o r d u a l b o re co n ce p t.
Examples are the Zinc, Balder, and Blackback projects. ExxonMobil and its affiliates
have mixed subsea wellhead and tree vendors successfully with the Eccentric Vertical
Tree concept on the Zafiro project in Equatorial Guinea, but not without additional cost
and time to develop and approve the orientation system.

Tubing Hanger

THRT

Riser Slips Tubing

S p id er Hanger

Tubing
Slips

Figure 14.8 - Tubing Hanger and THRT for the Zinc Eccentric Vertical
Tree

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SUBSEA COMPLETIONS

14.3.3 PASSIVE HANGER ORIENTATION

For the HT concept, the tubing hanger lands in the HT body that has a fixed helix in the
bore body. A solid key on the tubing hanger enters this helix and rotates the hanger to
the required orientation. Examples are the Diana, Mica, and Marshall/Madison projects.
Pre-checking and verification of correct alignment is normally done in a dry stack-up test.
A similar helix design is used on the tubing hanger spool for the Concentric Vertical Tree
concept. There is no need for a Completion Guide Base or alignment of the BOP stack
to the subsea wellhead. Operations personnel prefer this simpler more reliable
approach.

Stack-Up Test
d ry ru n

THRT
THRT

Quad
Penetraters

Tubing Hanger

Tubing
Hanger

False
Rotary

Figure 14.9 - Tubing Hanger and THRT for Mica Partial Drilling Horizontal Tree

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14.4 COMPLETION RISER

There are two basic riser options to install the tubing hanger assembly. They are:
1. A dual bore completion riser and
2. A mono-bore completion/workover riser.
But keep in mind that the tree design will dictate the available riser options. The
nomenclature for a "mono-bore completion riser" can mean several different riser
designs discussed below.

14.4.1 DUAL BORE COMPLETION/WORKOVER RISER FOR

ECCENTRIC VERTICAL TREES
A dual bore completion/workover riser (Figure 14.10), rated to full working pressure, has
typically been used to install the Eccentric Vertical Tree where the dual bore tubing
hanger lands in the subsea wellhead. This riser configuration, with one string providing
tubing access and the second string providing annular access, is used to run and land
the tubing hanger without pulling the 18-3/4 in. BOP stack. The riser is also equipped
with a protected groove for the internal installation workover control system umbilical, so
it can be securely strapped onto the riser. These completion/workover systems are
typically made up using non rotating riser system connectors and designed for a specific
water depth rating. They are generally dedicated to a specific subsea project for both the
initial completion and future workover requirements. Due to availability concerns, many
operators have purchased this riser as part of their "completion/workover" or "well
intervention" system.

Figure 14.10 Dual Bore Completion Riser Connection

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The riser has a separate stress joint installed on the bottom of the string, as well as
tension joint and protected landing joint used at surface. The landing joint needs to be
properly spaced out to allow heave related rig movements. A separate riser tensioning
system is connected to the tension joint.
For production testing purposes, a dual bore surface tree is also required. This tree is
equipped with top lubricator connectors for wireline access through either bore
(Figure 14.11).

Lift Frame
Annular Wing Valve
Swab Valves

X-Over Valve
Prod. Wing Valve

Dual Bore Surface Tree

Umbilical

Rotary Table
Riser Connection

Umbilical

Dual Bore Riser

EDP

Swab Valves
LMRP

X-Over Valve

Sheer Rams

Gripper Rams

WH Connector

Eccentric Dual Bore VT VT Body

Manifold/Template
Connection

Tubing
Hanger

Flow Base 18 3/4"Subsea Wellhead

Figure 14.11 Figure

Dual Completion
14.11 RiserRiser
Dual Completion andand
Surface
Surface Tree
Tree

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SUBSEA COMPLETIONS

This same dual bore completion/workover riser system is used to run the Eccentric
Vertical Tree body after pulling the 18-3/4 in. BOP stack. The significant components of
the completion/workover system are the Lower Marine Riser Package (LMRP) and the
Emergency Disconnect Package (EDP). The LMRP includes a small bore workover BOP
stack providing coil tubing and wireline shear rams, a master valve and a crossover
valve. See Figure 14.12.
When perforating or gravel packing a subsea well having a vertical tree, operators
typically run an additional downhole barrier prior to running the tubing hanger assembly
and pulling the BOP stack to install the vertical tree. The three common methods used
are:
1. Installation of another production packer with an isolation string across the
completion interval,
2. Some type of downhole tubing plug, or
3. A full bore isolation valve.

Figure 14.12 - Running Vertical Tree on Completion Riser Zinc VT

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14.4.2 ECCENTRIC VERTICAL TREE BARRIERS

After testing the downhole barrier for the Eccentric Vertical Tree concept and landing the
dual bore tubing hanger in the 18-3/4 in. subsea wellhead, wireline plugs are run through
the dual bore completion riser and set in the machined profiles of the tubing hanger
(Figure 14.13). These plugs isolate the production tubing and production casing
annulus. The 18-3/4 in. BOP stack is then pulled and the Eccentric Vertical Tree body is
run on the completion/workover riser. The 18-3/4 in. BOP stack is not normally used
during the well clean-up operations.

Retainer Valve ANN.

ANN
ANN.

Shear Sub

SHEAR/
Flapper Valve SEAL

VBR

Sen Tree 7
Lower Ball Valve PIPE

Slick Joint
VBR

THRT

Tubing Hanger

Figure 14.13 - Tubing Hanger Installation: Partial Driling HT

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Typically, well clean-up is performed after the production tree has been installed.
Primary well control at the seafloor is provided by the LMRP, a small bore workover
BOP installed on top of the vertical tree body. Additionally, the two master and two swab
valves in the vertical tree body for the production tubing and production casing annulus
can provide additional barriers.
One of the concerns with the eccentric vertical tree system is that during operations
when hydrocarbons are surfaced, drilling operations personnel will be relying on a
completion riser system that they may have little experience with. Therefore, it is
important to train the drilling operations personnel for these vertical tree installations.
Another concern with this concept is that these completion/workover systems may suffer
from lack of maintenance after the initial installation operations are completed. Proper
maintenance and inspection of the riser system and its connectors is essential.

14.4.3 MONO-BORE COMPLETION RISER FOR CONCENTRIC

VERTICAL TREE
A mono-bore completion riser, rated to full working pressure and designed to withstand
open water loads, is used to install both the tubing hanger and the vertical tree body in
the Concentric Vertical Tree concept. Additionally, the Concentric Vertical Tree requires
that an external umbilical attached to the riser to provide annulus access. The tubing
hanger lands in the tubing hanger spool. Variations of mono-bore completion risers
include large ID drill-pipe or production tubing with easy make and break connections.
The mono-bore completion riser system for the Concentric Vertical Tree concept
requires the tree vendor to supply dedicated EDP & LMRP as with the Eccentric Vertical
Tree concept in order to have access to the well bore after the upper tree body is
installed. This drives the mono-bore completion riser design and cost since it must be
reusable for the life of the project. The design criteria for use in open water and riser
connection fatigue are the primary cost drivers for this dedicated mono-bore riser.

14.4.4 MONO-BORE COMPLETION RISER FOR HORIZONTAL

TREES
The primary option for running the tubing hanger in the horizontal tree concept is a large
bore Subsea Test Tree (SSTT) run on a mono-bore completion riser (generally referred
to as a production tubing landing string). The subsea test tree with its shut-in and
disconnect functions, provide the primary well control system for the horizontal tree. It
incorporates two mechanical barriers in the event of an emergency disconnect incident
as shown in Figure 14.13. Also, the upper retainer valve on the SSTT can isolate
hydrocarbons in the landing string prior to disconnecting the SSTT. The rigs BOP
system provides redundant emergency well control capabilities. As a result, well control
risk for a horizontal tree is substantially reduced.
The large diameter tools associated with the subsea test tree dictate that riser ball joint
angle be less than ~0.75 degrees while landing the hanger. Rig heave and pitch must be
closely monitored during these critical operations. During landing operations, it is
advisable to go from passive to active heave compensation.

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14.4.5 LIFT FRAME

A tension lift frame is used to facilitate
tubing landing operations on subsea
wells when subsequent coil tubing or
wireline intervention operations are Lift Frame
planned (Figure 14.14). Because of
vessel motions on floating operations,
u se o f th e rig s m o tio n co m p e n sa tio n
system is necessary during this
critical landing phase. Additionally,
once the tubing hanger is landed at
the seafloor, the landing string is
generally hung on the blocks, not set
in the slips, with the motion Tension Lift Frame
compensator engaged.
CT Injector
The lift frame is used to provide a
means to rig up and run coil tubing or
wireline equipment on top of the flow
head (Figure 14.15). Because the lift
frame supports all loads, there is no
differential motion between the BOPs
landing string and the coil tubing
equipment. A large winch located at
the top of the lift frame is used to
pick-up and support the wireline Elevators
BOPs or the coil tubing BOPs and
injector head.
It is important to anticipate the need
for coil tubing or other through tubing
intervention in the planning stages of
the completion. If the lift frame is not FlowHead
picked up when the flow head is
initially picked up, it becomes very
difficult and/or expensive to
subsequently install the lift frame. The
steps to pick-up the lift frame will Figure 14.14 Typical Rig up of WL Lubricator,
generally include disconnecting the inside Lift Frame during TH landing.
landing string from the tubing hanger,
laying down the flow head, changing out the bails, picking up the lift frame and the flow
head, and then re-connecting to the tubing hanger.

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Schlumberger
7-3/8 10k Flowhead

1 0 -3 /4 H and lin g
Sub

Hydraulic Operated
Coflex Swab Valve
Support

Failsafe
Actuator Failsafe Actuator

Production
Kill Line Line #1

Dynamic Swivel

Hydraulic Operated
Master Valve

Figure 14.15 Flow Head

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14.4.6 RISER SUMMARY

When selecting a subsea tree concept, the intangibles of the riser installation system
should be considered. Cost is an important driver but safety is paramount, and drilling
personnel should have an understanding of the well control system used during well
clean-up operations. This is extremely important to mitigate a well control incident and
protect the environment.
With the VT concept, the workover/completion riser systems are typically custom
designed for a specific project based on water depth. Also, operators usually end up
purchasing or entering into a long term lease on the system to ensure availability. During
well clean-up operations, training is essential for drilling operations personnel since this
riser system includes a workover BOP that replaces the 18-3/4 BOP stack they have
been trained to use. Also, operator-owned riser systems may suffer from lack of
maintenance after initial use in a salt water environment. Poor maintenance could impact
the reliability of some components during future workover operations.
The HT concept utilizes the drilling contractor owned riser and BOP stack. The
production tubing riser inside the drilling riser is run with a subsea test tree to provide
primary well control during well clean-up operations (Figure 14.16).
Both riser systems in the Figure 14.16 depict the emergency disconnect mode during
well clean-up operations with hydrocarbons to the surface. The HT concept utilizes the
drilling contractor owned riser and BOP stack. The production tubing riser inside the
drilling riser is run with a subsea test tree to provide primary well control during well
clean-up operations. Just above the SSTT is a shear joint that can be sheared by the
BOP stack if for some reason the SSTT fails to function properly. Thus, two independent
well control systems are used with the HT concept. Also, drilling personnel are familiar
with SSTT operation based on experience using SSTTs for exploration well testing.
One key well control issue for the HT is a connection leak so that gas leaks from the
production tubing riser above the SSTT inside of the 21 in. drilling riser. This would
require diverter operations to keep gas from the rig floor. This risk can be mitigated by
using new production tubing with premium connections for each subsea completion and
by placing a special insert in the diverter housing. The production tubing riser can then
be run as production tubing below the tubing hanger on the next well, after re-inspection,
to reduce overall completion cost. The following summarizes the riser system
considerations:
Completion/Workover Riser System (VT)
Dedicated to specific project and water depth rating.
Operator/vender owned (availability concerns).
Drilling rig personnel experience (training required).
Lack of maintenance years after initial operations.
Completion/Workover Riser System (HT)
Drilling contractor owned riser and BOP stack.
Subsea test tree (SSTT) + shear joint.
Connection leak in tubing riser (diverter operations).
Mitigate by using new tubing + premium connections.

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Concentric VT Partial Drilling HT

Mono Bore 21 D rillin g R iser

Completion
Riser

Production Tubing
(landing string)

ANNULAR
Emergency
ANNULAR
Disconnect
Emergency Package
Disconnect BLIND SHEAR

Package
BLIND SHEAR

SUPER SHEAR

4 Ram 18-3/4 B O P
PIPE PIPE

3-Ram BSR
Workover BOP PR
VBR PIPE
Subsea Test Tree
PSR
VBR PIPE

THRT
VT Body

Tubing
Spool HT Body

Figure 14.16 - Emergency Disconnect Concentric VT (left) Partial Drilling HT (right)

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14.5 SUBSEA TEST TREE CONTROLLED

DISCONNECT
Under extreme environmental conditions, certain
emergency conditions, or positioning system
malfunctions, it is possible that the dynamic positioning
system may not be able to maintain station, and a drive
off occurs. If any of these cases were to occur after
landing the tubing string, a disconnect would be required. Lubricator Valve
Industry guidelines currently require that a complete
disconnect of the landing string and BOPs be completed
within 60 seconds for a dynamically positioned vessel and
4 minutes for a moored vessel.
Prior to disconnecting from the well, all flow must be shut- Control System
in, both ends of the disconnected landing string must be
sealed, and no hydrocarbons must enter the sea.
Additionally, once the operation again becomes safe,
Bleedoff
connection to the well must be reestablished to resume
Valve
operations.
Retainer Valve
Special tools, known as subsea test trees (SSTT) have
been developed by a limited number of service
companies to perform these critical tasks. These tools are
not permanently fixed to the seafloor like subsea trees but
rather run in conjunction with the tubing, tubing hanger,
and landing
string. All of this equipment is run inside the drilling riser
and BOP stack.
The SSTTs combine two primary features: Latch Connector

A series of full bore valves and latches that provide

downhole well control and disconnect capabilities.
A control system, tied back to the surface via an Flapper Valve
umbilical, facilitates activation of all valves and
latches. Note that this system is completely
independent of either the MODU BOP stack control Ball Valve
system or the horizontal tree control system (External
Intervention WorkOver Control System).
The primary components of the shut-off are a tubing
hanger running tool, a slick joint, a ball valve, a flapper
valve, a latch, a shear joint, and a retainer valve as shown Figure 14.17
in Figures 14.17 and 14.18. Schlumberger SenTree 7

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Packoff Sub

Retainer Valve

Shear Joint

Latch Connector

Flapper Valve

Ball Valve

Slick Joint

Tubing Hanger
Running Tool

Figure 14.18 - Schlumberger SenTee 7 Installation During A Well Test In GOM

Dimensional stack-u p o f th is la rg e d ia m e te r a sse m b ly (1 8 .5 6 in . fo r S ch lu m b e rg e rs

SenTree 7) is critical, as all of this equipment will be within the BOP stack when the
tubing hanger is landed. The slick joint below the lower ball valve is positioned across
from the lower subsea BOP pipe ram providing a means for riser isolation. A shear joint
is positioned across from the shear ram, to provide a means for emergency pipe
disconnect in the event of a subsea test tree latch failure.
The lower ball valve should be designed for wireline and coil tubing cutting capability, in
the event that conditions require a disconnect.
Subsea test trees consist of standard modules that must be precisely adapted to suit
project specifications driven by BOP dimensions, shear capability and tubing hanger
dimensions.

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The design of the subsea completion and test tree centers on the ability to perform a
controlled disconnect. To ensure hydrocarbon fluid isolation, the subsea test tree valves
operate in a very specific order:
1. The lower ball valve and then the flapper valve close shutting off the flow from
the wellbore.
2. The retainer valve above the latch closes to contain fluid in the landing string.
3. The small amount of fluid trapped between the flapper and retainer valve is bled
off into the drilling riser.
4. The latch disconnects allowing the upper section to be pulled clear of the BOP
stack.
5. If the drilling riser is also going to be disconnected, the BOP blind rams will then
close and the drilling riser disconnected.
6. The vessel can then move off location leaving the well fully controlled.
For subsea tree concepts that utilize a 21 in. drilling riser during well clean-up
operations, a key well control issue is a connection leak where gas escapes from the
landing string into the riser. Diverter operations would be required in water depths where
the gas could expand significantly as it rises to the surface. This risk can be mitigated by
using new production tubing with premium connectors for the landing string of each
subsea well or by conducting a thorough inspection between wells. The tubing selected
must be specifically qualified for service as a mono-bore completion riser. Vendor
provided mono-bore risers can also considered, but since the connections would need to
be designed for use on multiple wells and have a longer useable life, the cost of this
option may not be economically justified.

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14.6 SUBSEA TREE CONTROL SYSTEMS

In general, two separate and independent control systems are required during
completion and tree installation:
1. There is a control system that operates the subsea tree. This umbilical is often
referred to as the External IWOCS or External Intervention WorkOver Control
System. This system is run outside of the drilling riser and is used for installation
and landing of the tree. It contains all of the operational systems necessary for
valve operation and tree connect/disconnect activation.
2. There is the control system that facilitates tubing hanger running and landing
operations. This umbilical is referred to as the Internal IWOCS or Internal
Intervention WorkOver Control System and is used to land and lock the tubing
hanger and contains the operational systems needed for the subsea test tree
operation.
These two systems should be installed and incorporated in the rig emergency plan prior
to operation. Placement and access to the control systems are important. It is therefore
recommended that these systems be installed as close to the rig floor as possible.
The following discussion will focus on the Internal IWOCS used to control and operate
the subsea test tree.
INTERNAL IWOCS
Control systems for the subsea test tree are specifically engineered according to
environmental and operational requirements and the type of rig being used. This system
is referred to as the Internal IWOCS (Internal Intervention Workover Control System).
Figure 14.19 illustrates the IWOCS being clamped to the tubing on a GOM well. The
time available for disconnection depends on the vessels mooring system capabilities,
water depth, currents and wave heights.
Subsea test trees are designed to unlatch under full tension and at an angle greater than
can be physically achieved in the BOP stack, to ensure that controlled unlatching is
possible in all conditions. In water depths up to 5000 ft, from a moored vessel, the
acceptable disconnect time is 120 seconds or less. The disconnect time for moored
vessels is longer because the vessel is anchored and does not rely on dynamic
positioning to stay in place. In these cases, the control system is a direct hydraulic
system. The signal open or close a valve or to disconnect is sent through hydraulic lines
to so le n o id va lve s in th e to o ls co n tro l syste m th a t h yd ra u lica lly a ctiva te th e va lve s a n d
latches.
Note: Due to the behavior of fluids and the control lines, the time required for the
hydraulic signal to travel to the subsea tool increases with depth. In water depths greater
than 5,000 ft, it is necessary to enhance the system through the use of pressure
accumulators in the subsea hydraulics.

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Gooseneck

IW O C S (3 .3 5 O D )
being clamped to the
tubing landing string.

Umbilical Control Reel

Figure 14.19 - S chlum bergers S enT ree 7 T est T ree A nd C om m ander H ydraulic C ontrol System
Provides 120 Second Response Time

In operations from dynamically positioned vessels, disconnection must be achieved in

15 seconds or less. A hydraulic system alone, over the distance involved, functions far
too slowly. An electro-hydraulic system is required in these cases to improve response
time. The combination of an electrical and hydraulic system allows a fast electrical signal
to activate the hydraulically controlled flow shutoff and initiate the disconnect sequence.
These systems (Figure 14.20) are known as electrohydraulic control systems. The
surface systems send a direct electric signal on an electrical cable to the solenoid valves
of the downhole control system. These valves control the tree functions of shutoff,
pressure vent and unlatch.

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SenTree 7
Accumulator Module

Hydraulic Power Unit

Surface Control Unit

SenTree 7 Subsea Control Module

Figure 14.20 Sen Tree 7 test tree and Commander telemetry control system providing a 15
second response time.

S ch lu m b e rg e rs S e n T R E E 7 su b se a te st tre e u tilize s a m u ltp le x co n tro l syste m th a t

performs 24 functions. These include opening and closing the four downhole valves,
latching and unlatching, locking and unlocking the tubing hanger, injecting chemicals
and monitoring temperature and pressure. This system is far too complex to operate by
direct electrical signal, so a multiplexed signal (MUX) is sent down a logging cable, then
interpreted by a subsea electronics module in the control system. This, in turn, activates
the tool functions. In addition, the electrical system provides feedback on the pressure,
temperature, status of the valves, and other diagnostics as required, providing two-way
communication between the tool and the surface.

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14.7 SUBSEA TREE PREFERENCES

The Eccentric Vertical Tree is the most field proven system employed by industry today
simply due to the number of installations worldwide. Most of these Eccentric Vertical
Tree installations are in less than 1,000 feet of water. Perceived subsea tree reliability
can be a driver for selecting a subsea tree concept. Eccentric Vertical Tree's are
a lso re fe rre d to a s co n ve n tio n a l subsea trees which implies that Vertical Trees are
more reliable.
Since both subsea tree concepts utilize the same basic technology for subsea tree
valves, actuators, connectors, chokes, and control systems, it can be argued that the
number of subsea tree valves and control lines determine subsea tree reliability. By
inference, the horizontal tree concept would be more reliable since it has fewer subsea
tree valves and control lines. However, the consequence of a HT failure should also be
considered since the well must be secured in order to pull the tubing. In contrast, the
vertical tree can be recovered without pulling the tubing. Although the horizontal tree
concept offers additional flexibility, they have not gained universal acceptance by some
operators due to perceived reliability concerns. The potential to eliminate the costly
completion riser system however, is helping industry to move away from vertical trees
and towards horizontal trees.

Figure 14.21 Typical Subsea

System Configuration

The subsea tree is only one part of a larger subsea system as shown in Figure 14.21
that includes subsea templates or manifolds, subsea flowlines and pipelines, as well as
subsea control systems. The budget for design and procurement of subsea trees is
usually part of the overall budget for the subsea system, which is managed by the
subsea or facilities group within a project team. The budget for installing the subsea
trees is usually part of the drilling and completion budget. Consequently, the focus of the
drilling and completion group has been to install the subsea tree and related equipment
safely and efficiently.

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14.7.1 CASE STUDY TREE SELECTION FOR DEEPWATER

GOM PROJECT
Horizontal trees were selected for all of the recent deepwater Gulf of Mexico subsea
developments (Diana, Marshall, Madison and Mica Figures 14.22 and 14.23). The
basis for the recommendation was a single well comparison of an Eccentric Vertical Tree
versus a Partial Drilling Horizontal Tree. The time motion analysis of the vertical tree
versus HT installation sequence showed that the HT concept would take about 2 days
more of rig time than the vertical tree concept. However, the lower leased cost of the
SSTT more than offset the higher cost of a leased dual bore completion/workover riser
system.

Figure 14.22 - Installation of MICA Horizontal Tree in Gulf of Mexico

Additionally, the future availability of the leased completion/workover riser system for
workovers was identified as a concern. Purchase of a dual bore completion/workover
riser system for the small number of wells in the development could not be justified. The
analysis suggested that selection of the Horizontal Tree would result in an average
savings of about $800k/well.
Even though the horizontal tree concept had not previously been used at the required
water depth (~4,650 feet of water), the drilling organization supported the HT
recommendation, since it appeared that it had greater potential to reduce completion
installation time and costs.

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Use of the Eccentric Vertical Tree concept and dual bore completion/workover riser
system could expose operations to potential weather delays if offloading of the drilling
riser was required due to deck space limitations on MODU. Drilling estimated that
weather delays offloading or loading riser could add $1.0M per well if sufficient boats
were not available to conduct these operations out of critical path.
Actual installation times for horizontal trees installed at the Diana field were compared to
the vertical trees installed at the Zinc field. This comparison showed an average savings
of 6.7 days per well for horizontal trees using a single derrick MODU. Minimizing tripping
of the BOP stack and batch installation operations were key drivers to this savings in
time achieved at Diana. Additionally, the elimination of the completion/workover riser
system by using the MODUs drilling riser increased available deck space for other
completion equipment and decreased overall cost.
The HT concept provided future flexibility by being able to use existing drilling risers from
many different MODUs. Assumptions for well intervention can also contribute to the
subsea tree selection decision. The ability to sidetrack and re-drill through the HT further
reduces costs since sidetracks can be performed without pulling the HT. One sidetrack
re-drill through the horizontal tree has already been performed at Diana, and the
development plan anticipates future sidetrack re-drill opportunities. Drilling operations
personnel also preferred the SSTT system and the MODU BOP stack for well control
instead of a specialized completion/workover riser system that included a workover BOP
and EDP. The decision to use the production tubing as the landing string also provided
additional cost savings to the project.

FMC 10K- GLL HXT

Mica:
2 T rees, 4350 W D

Marshall-Madison:
3 T rees, 4600 W D

2000 / 2001

Figure 14.23 Mica Horizontal Tree with ROV access.

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14.8 REFERENCES
1. Towns, T. K., Deeken, D. G., Derby, L. M.,ExxonMobilDevelopment Company,
D ia n a S u b se a T re e S e le ctio n a n d In sta lla tio n R e su lts in 4 ,6 5 3 F e e t o f W a te r D e e p
Offshore Technology held in Rio de Janeiro, Brazil, October 17-19, 2001.
2. Moyer, M.C., Barry, M.D., Tears, N.C., "Hoover-Diana Deepwater Drilling and
Completions", OTC 13081, Offshore Technology Conference, Houston, Tx, May
2001.
3. S e n T R E E S u b se a W e ll C o n tro l S e rvice s S ch lu m b e rg e r, A p ril 2 0 0 1
4. S u b se a S o lu tio n s, S ch lu m b e rg e r, W in te r 1 9 9 9 /2 0 0 0

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SUBSEA COMPLETIONS

14.9 WELL FLOWBACK SCHEMATIC FOR HT

Figure 14.24 - Well Flowback Schematic Using Typical Horizontal Tree

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SUBSEA COMPLETIONS

14.10 BATCH SUBSEA TREE INSTALLATION

U ncle J ohn
Figure S upport
14.25 V essel
Uncle Subsea
John SupportTree Batch
Vessel Installation
Subsea LayoutInstallation Layout
Tree Batch

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ABANDONMENT OPERATIONS

15
Section

15.0 ABANDONMENT OPERATIONS

OBJECTIVES
On completion of this section, you will be able to:

List the key elements of a temporary or permanent abandonment operation.

Identify the equipment required for an abandonment operation.

Describe the differences between abandonment operations from a floating rig and
fixed structure.

Describe the process required to handle trapped gas when retrieving a seal
assembly from the wellhead.

Describe the various methods to cur and retrieve the structural and conductor casing
strings, wellheads, and guidebases.

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ABANDONMENT OPERATIONS

CONTENTS Page

15.0 ABANDONMENT OPERATIONS ...................................................................................................... 1

OBJECTIVES .................................................................................................................................... 1
15.1 INTRODUCTION ............................................................................................................................... 3
15.2 GOVERNMENTAL ABANDONMENT REGULATIONS ................................................................... 3
15.3 EXXONMOBIL ABANDONMENT GUIDELINES .............................................................................. 4
15.4 GENERAL GUIDELINES .................................................................................................................. 5
15.5 ISOLATING ZONES IN OPEN HOLE ............................................................................................... 6
15.5.1 OPEN HOLE BALANCED CEMENT PLUG(S) .................................................................. 6
15.6 ISOLATION OF OPEN HOLE AT CASING SHOE ........................................................................... 8
15.6.1 BALANCED CEMENT PLUG ............................................................................................. 8
15.6.2 MECHANICAL PLUG ......................................................................................................... 8
15.6.3 WIRELINE OPERATIONS .................................................................................................. 9
15.6.4 TESTING SHOE PLUG..................................................................................................... 10
15.7 PLUGGING ACROSS LINER TOPS ............................................................................................... 11
15.8 PLUGGING OF ANNULAR SPACES ............................................................................................. 12
15.8.1 SEAL ASSEMBLY RETRIEVAL ...................................................................................... 14
15.8.2 CASING CUTTING OPERATIONS ................................................................................... 17
15.9 PLUGGING OR ISOLATING A PERFORATED CASING ANNULUS ......................................... 22
15.10 SURFACE PLUGS .......................................................................................................................... 23
15.11 SUBSEA WELLHEAD REMOVAL .................................................................................................. 24
15.11.1 CUTTING MULTIPLE CASING STRINGS........................................................................ 24
15.11.2 CUTTING CASING WITH A MARINE SWIVEL ................................................................ 26
15.11.3 MOST WELLHEAD RETRIEVAL TOOL .......................................................................... 27
15.12 RETRIEVAL OF TEMPORARY GUIDEBASE ................................................................................ 30
15.13 TEMPORARY ABANDONMENTS .................................................................................................. 31
15.14 SEABED INSPECTION ................................................................................................................... 32
15.15 REFERENCES ................................................................................................................................ 33

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ABANDONMENT OPERATIONS

15.1 INTRODUCTION
Offshore exploration and many appraisal type wells are normally plugged and
abandoned following a formation evaluation program. The abandonment is necessary to
permanently isolate all hydrocarbon and permeable abnormally pressured water zones
to prevent communication between zones. The abandonment also prevents potential
migration of wellbore fluids to the seafloor and escaping into the ocean. All
abandonments should be conducted under the assumption that ExxonMobil will remain
re sp o n sib le fo r th e w e lls co n d itio n long after the abandonment and terms of the lease
expire. Methods to either temporarily or permanently abandon a wellbore will be dictated
b y lo ca l g o ve rn m e n ta l re g u la to ry a g e n cie s, b u t in g e n e ra l te rm s, E xxo n M o b ils g o a l is to
ensure that the wellbore is securely plugged and isolated.

15.2 GOVERNMENTAL ABANDONMENT

REGULATIONS
Successfully plugging any well involves following all applicable government regulations.
This will often include:
Isolation of any open hole.
Isolation of perforated intervals and liner tops.
Cutting all casing strings some distance below the mud line.
Setting plugs atop casing stubs.
Pressure testing annuli.
Clearing all equipment from the seafloor.
Confirming a clean seafloor.
Some of the more stringent and specific regulations on well abandonment are required
in the United States, Australia, and countries bordering the North Sea.
In the United States, and in most foreign countries, abandonment cannot commence
without prior approval of the appropriate government agency. Before an abandonment
procedure is finalized and approved by ExxonMobil management, the plan is typically
submitted to the appropriate government agencies for approval. For example, in the
U.S., this plan is called Notice of Intent to Abandon Well and is submitted for approval to
the MMS District Supervisor in whose district the well is being drilled. Exceptions to
regulations are typically included in the plan to abandon a well that is submitted to the
government agency.
In ultra-deepwater, plug and abandonment plans have been approved that allow the
subsea wellheads to remain in place on the seafloor since they do not provide a danger
to marine and fishing operations.

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ABANDONMENT OPERATIONS

15.3 EXXONMOBIL ABANDONMENT GUIDELINES

As well as meeting all applicable government regulations, ExxonMobil has developed a
series of general guidelines for abandoning wells. Consistent with local regulations, the
following shall apply:
1. Critical abandonment plugs that will isolate hydrocarbon and injection zones from
freshwater aquifers must be verified by tagging with open ended drill pipe and/or
pressure testing.
2. During each phase of the plug and abandonment operation, a means of
performing well control is to be maintained. This is valid until casing with a non-
sealed outer annulus (generally surface casing) is to be cut or perforated.
3. When conducting plug and abandonment operations, all mud returns are to be
analyzed by the mud logging unit in order to detect any formation fluid influx
which might occur.
4. Consideration should be made to treat mud left between cement plugs inside the
casing with a corrosion inhibitor and/or a bactericide.
5. During each phase of the plug and abandonment operation, the mud left in the
hole above a cement and/or a mechanical plug is to have a weight sufficient to
withstand, together with the plugs, any pressure which may develop in the well.
Assume only zones above the last tested cement plug will flow.

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15.4 GENERAL GUIDELINES

Many options exist to properly plug and abandon a wellbore. Planning should consider
regulatory and company requirements, availability of equipment tools and service
personnel and efficiency. Abandonment procedures should be researched and reviewed
while planning the well to ensure, where possible, that drilling plans coincide with
requirements for abandonment. As an example, the primary cement may be adjusted to
seal the annulus between two casing strings thereby meeting the requirements for a
permanent abandonment and allow the casing and wellheads to remain in place.
Items to consider during P&A planning:
18-3 /4 1 0 K o r 1 5 K W e llh e a d
Will the well be permanently or 3 0 L o w P re ssu re W e llh e a d
temporarily abandoned? Housing

If the well is in deepwater, can the

wellheads be left in place? In nearly all Structural Casing
cases, leaving the wellhead in place will
be less costly for the initial P&A, but the
Company may be responsible to remove 2 0 C a sin g
the wellhead at a later date.
Are mechanical plugs to be used, or will
the wellbore be isolated with cement only?
Plugging the well with cement may allow 13-3 /8 C a sin g
several plugs to be set on one-trip out of
the hole, but will require waiting on
cement time. Setting a mechanical plug
will require an additional trip or wireline to
set the plug. Other options to consider
when deciding whether to use a cement
plug or a mechanical plug are, whether
9-5 /8 C a sin g
the mechanical plug sets high or if the
cement cannot be squeezed through the
plug, will additional regulatory approval be
required to leave the plug at the
premature setting depth or whether the 7Liner

mechanical plug can be left with any Liner
cement below the plug? Hydrocarbon Zone

How will the reduction in mud weight be

handled (i.e., dilute back the weight or
replace the mud)? In deepwater, volumes
can be in excess of 3000+ bbls. If the mud Figure 15.1
weight is reduced, will it still maintain Pre-Abandonment Wellbore Sketch
hydrate suppression?
Is specialized equipment available to cut and recover the wellheads?
Figure 15.1 is an example of an exploration wellbore that is to be abandoned. All further
discussions on abandonment will refer to this example as each type of plug is set and
tested, and the casing is recovered.

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ABANDONMENT OPERATIONS

15.5 ISOLATING ZONES IN OPEN HOLE

In uncased portions of the hole, cement plugs shall be spaced to extend from 150 ft
below the bottom to 150 ft above the top of any oil, gas, or freshwater zone(s) to be
isolated Figure 15.2. Cement pilot tests should be performed for all cement plugs with
actual temperature data obtained from the well.

15.5.1 OPEN HOLE BALANCED CEMENT PLUG(S)

Open hole cement plugs are typically 18-3 /4 1 0 K /1 5 K W e llh e a d
set using a stinger run on the bottom of
3 0 L o w P re ss W e llh e a d
drill pipe. Typical sizes for cement
stingers are 2-7/8 in. for 6-1/2 in. hole
sizes and smaller, 3-1/2 in. tubing for 8-
Structural Casing
1/2 in. holes, and 5 in. of 12-1/4 in. hole
sizes and larger. In cases where
adequate space between the internal
diameter of the hole and drill pipe tool 2 0 C a sin g
joint OD is sufficient to allow cement to
fall around the connection, drill pipe is
commonly used as the cement stinger.
In operations where the wellbore fluid 13-3 /8 C a sin g
lacks adequate viscosity to suspend the
cement, the stinger is run below the
setting depth of the cement plug and a
hi-vis pill set that will help support the
cement slurry once it is in place. This
may be especially important if the top of
the cement plug must be tagged to
9-5 /8 C a sin g
verify the depth above a required
zone for isolation.
When more than one plug is required to 7 L in e r
isolate a zone, it is typical to set multiple
plugs on top of each other with only the
top plug tagged to confirm the depth.
T O C 1 5 0 a b o ve H yd ro ca rbons
Since floating rigs are always subject to
movement (heave, offset), the cement
head or pump-in sub is typically Hydrocarbon Zone
spaced-out above the rig floor to
provide adequate clearance for rig B O C 1 5 0 b e lo w H yd ro ca rb o n s
heave.
During cementing operations, the pipe Figure 15.2
should be suspended from the block Isolating Open Hole Zones
instead of setting in the slips so that
tension created by the rig heave can be measured by the weight indicator. For balanced
plugs, the use of the motion compensator is generally
not required.

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ABANDONMENT OPERATIONS

When operating from a dynamically positioned rig, it is important to determine the

location of the tool joint prior to the cementing operation to confirm that the tool joint is
positioned above the hang-off ram and adequate pipe stick-up above the rig floor is
available to allow the Driller to slack-off and hang-off the drill pipe prior to an Emergency
Disconnect (EDS). Information on EDS can be found in Section 11.
Testing of open hole plugs is usually confirmed by tagging the plug with the drill string to
confirm the top of cement depth. When tagging cement with open-ended tubing or drill
pipe, the cement will usually require considerable set time due to the small cross
sectional area of the tube that is used to tag the plug. On waiting a sufficient time for the
cement to reach adequate compressive strength, open hole plugs are typically tagged
with 10K lb. to 15K b. weight with slow circulation against the plug (ExxonMobil
guideline) to reduce the possibility of plugging the tubing.

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15.6 ISOLATION OF OPEN HOLE AT CASING SHOE

Where there is open hole below the casing, the casing shoe shall be plugged off from
the open hole Figure 15.3. Three methods are generally acceptable:
1. Placing a balanced cement plug across the casing shoe;
2. Setting a bridge plug in the casing near the shoe and spotting no less than 50 ft
of cement above it; or
3. Setting a cement retainer near the shoe, squeezing cement below it, and spotting
50 ft of cement above it.

15.6.1 BALANCED CEMENT PLUG 18-3 /4 1 0 K o r 1 5 K W e llh e a d

3 0 L o w P re ssu re
To isolate the shoe with a balanced cement plug, Wellhead
the stinger is placed at depth in the open hole, and
drilling fluid is circulated to ensure that mud
densities within the wellbore are balanced prior to Structural Casing
cementing. If required, a high viscosity mud spacer
may be spotted in the open hole to support the
cement plug. 2 0 C a sin g

15.6.2 MECHANICAL PLUG

If the shoe is to be isolated with a bridge plug or a
cement retainer, the plug can be run on drill pipe 13-3 /8 C a sin g

with a mechanical setting tool, or on electric wireline

with a wireline setting tool. Placement of the cement
retainer or bridge plug is typically set between 50
and 100 ft above the casing shoe. This plug should
not be run below the landing collar or float collar
unless a casing scraper run is made through the
shoe track.
9-5 /8 C a sin g
When the cement retainer is run on drill pipe,
surges caused from rig heave have caused T O C m in im u m o f 5 0
retainers to set prematurely. If the retainer is run on above cement retainer
drill pipe, trip speeds should take into account the 7 L in e r
additional surges caused by the rig heave.
Caution should also be taken to prevent setting the
bridge plug or cement retainer in a casing collar.
Hydrocarbon Zone

Figure 15.3
Isolating Casing Shoe

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ABANDONMENT OPERATIONS

15.6.3 WIRELINE OPERATIONS

Setting the cement retainer on wireline is a two-stage process where the retainer/bridge
plug is run and set on wireline, and a stinger is run on drill pipe to squeeze/spot cement.
When setting cement retainers/bridge plugs, the maximum temperature to which the
setting tool will be exposed should be determined and the cylinder oil level checked
before installing the piston. A slow-set power charge should be run for critical and large
diameter retainers/plugs. During wireline operations that include an explosive, all safety
procedures for radio and electrical equipment should be followed until the tools are
below the BOP stack/mudline.
After setting a retainer or bridge plug, it should be pressure tested prior to cementing to
establish pressure integrity of the seal and baseline for future test.
Wireline operations on a floating rig may also be impacted by the rig heave and may
require the use of the motion compensator. As shown in Figure 15.4, the motion
compensator can be configured to operate during wireline operations by attaching a
cable from the block (motion compensator) to the outer barrel of the slip joint (outer
barrel is fixed to the riser not compensated). Since the wireline is attached at two
points, the deck of the rig and the wellbore, the motion compensator cable should be
attached to the outer barrel of the slip joint and run through a sheave above the wireline
sheave and back to the deck. This is necessary to maintain a one-to-one travel between
the wireline and the compensator. Therefore, the distance between the hook and outer
barrel of the slip joint does not change as the rig heaves up and down.

Compensator strokes up and

down maintaining tension on
fixed line as rig heaves.

Fixed Length

Heave

Figure 15.4 Typical Rig-up for Wireline with Motion Compensator

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ABANDONMENT OPERATIONS

When cementing through a retainer, the cement is typically circulated into drill string with
the retainer setting tool/stinger unstung from the retainer. While circulating the cement
into the drill string, sufficient backpressure must be held on the annulus to prevent the
cement from U-tubing out of the drill string and up into the annulus. On floating rigs, this
is typically done with the annular preventer closed while taking returns through a
choke/kill line to the choke manifold. The backpressure to prevent U-tubing is maintained
by adjusting a choke on the choke manifold. Due to the friction pressure in the long
choke/kill lines, the actual pressure held on the annulus will be increased by an amount
equal to the Choke Line Friction Pressure (CLFP).

15.6.4 TESTING SHOE PLUG

Testing the shoe plug is critical since it provides a baseline for all subsequent pressure
tests and provides a barrier to allow the mud weight to be reduced. Test pressures are
usually calculated to exceed the leak-off pressure of the casing shoe by 1000 psi to
ensure that the shoe plug, and not the formation, is being tested.

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ABANDONMENT OPERATIONS

15.7 PLUGGING ACROSS LINER TOPS

Deepwater subsea wells can typically
18-3 /4 1 0 K o r 1 5 K W e llh e a d
contain several liners due to the short
open-hole intervals caused by the thin 3 0 L o w P re ssu re
Wellhead
margin between the pore pressure and
overburden pressure. To ensure that the
liner annulus is securely sealed, the top Structural Casing
of the liner is covered with a cement plug
to provide an additional barrier to the liner
top packer and/or annulus cement. Even 2 0 C a sin g
though the liner lap was pressure tested
prior to conducting drilling operations, the
quantity and quality of the cement is
unknown due to the small annulus
volume available to provide the seal. In 13-3 /8 C a sin g
addition, liner lap seals for drilling liners
may not have been differentially tested to
verify sealing capacity from below. During
the plug and abandonment, it is important Balanced Plug
above and below
to ensure that the liner top will not leak top of liner
from below, since the mud weight will be
reduced as the P&A progresses.
The cement plug is typically placed to 9-5 /8 C a sin g
extend from at least 150 ft above to
150 ft below the point of suspension
Figure 15.5.
Pressure testing or tagging of this 7 L in e r
measurement is typically not required,
but the liner top should be tested at some
time during the P&A operations.
Hydrocarbon Zone

Figure 15.5
Isolating Liner Tops

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ABANDONMENT OPERATIONS

15.8 PLUGGING OF ANNULAR SPACES

Annular spaces between casing string on subsea wells are commonly left uncemented
during the primary cement job since the subsea wellhead does not provide annulus
access.
The benefits of the open annulus during drilling are:
Minimizes the possibility of collapsing the previous string of casing during BOP
testing should the seal assembly leak.
Provides for casing backup pressure during casing design,.
Allows for thermal expansion of annulus fluid during production and/or well test
operations (thermal expansion in a closed annulus will impose collapse/burst loads
to the adjacent casing strings).
Simplifies the primary cement job.
Prior to plugging back the annulus of each casing string, it will be necessary to reduce
the mud weight to prevent fluid loss after exposing the formation in the casing annulus.
Mud weights are typically reduced to the density of the mud that was in the hole when
the casing was set and cemented.
On floating rigs, the process of mud weight reduction during the P&A is more
complicated and expensive than on surface stack operations due to the large volume of
mud contained in the riser. A well with a surface BOP stack and 9-5/8 in. casing set at
12,000 ft would have a volume of approximately 900 bbls whereas a well in 5000 ft of
water with 9-5/8 in. casing set at 12,000 ft would have a hole volume of approximately
2500 bbls.
Diluting a system this large can be time consuming, expensive (due to the chemicals
required to maintain adequate mud properties) and require a large surface pit volume.
This is another example of a synthetic-base mud system which can be extremely
expensive to dilute. An alternative to diluting is to swapout the mud system to a cheaper
water-base mud system. This method may be advantageous, but large pit volumes or
mud storage on the supply vessel will be required.

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ABANDONMENT OPERATIONS

During the P&A process, each annular space between casing strings within the wellhead
should be tested for communications with the open hole. Any annulus in communication
with the open hole should be sealed with a mechanical plug and/or cement and tested.
In most cases, this will mean cutting and pulling an inner string of casing to get access to
the annulus. Removal of the casing will also allow access to the outer casing that will
also need to be cut and recovered. Figure 15.6 depicts a wellbore where the 9-5/8 in.
casing has been cut and removed and the annulus sealed with cement. Since the
9-5/8 in. and 13-3/8 in. annulus are both unsealed, each casing annulus must be
plugged and abandoned separately.

18-3 /4 1 0 K o r 1 5 K W e llh e a d

3 0 L o w P re ssu re W e llh e a d

Structural Casing

2 0 C a sin g

Balanced plugs are set across

casing cuts with a minimum of
1 0 0 o f ce m e n t se t a b o ve th e
stub
13-3 /8 C a sin g

9-5 /8 C a sin g

7 L in e r

Hydrocarbon Zone

Figure 15.6
Plugging Annular Spaces

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ABANDONMENT OPERATIONS

15.8.1 SEAL ASSEMBLY RETRIEVAL

The principal steps for casing removal are:
Retrieve the wear bushing.
Retrieve the seal assembly.
Cut the casing.
Retrieve the casing.
Depending on the wellhead manufacturer and the type of P&A tools used, this process
can be accomplished in two to four trips.
To gain access to the seal assembly and hanger, the wear bushing must be retrieved
from the wellhead. The wear bushing is retrieved independently with a dedicated wear
bushing retrieval tool. While retrieving the wear bushing, a wash sub is typically run
below the tool and the wellhead washed before and after recovering the wear bushing to
ensure that the profiles for the retrieval tools are unobstructed.
Seal assemblies can either be locked to the wellhead or to the hanger depending on the
wellhead manufacturer. If the seal assembly is locked to the wellhead [Vetco Figure
15.7, Dril Quip is optional], a separate trip will be required for retrieval. If the seal
assembly is only locked to the hanger, it can be retrieved when the casing and hanger
are retrieved.

Released gas that was

trapped below seal
assembly

Seal Assembly
Released Position

Seal Assembly
Latched to wellhead Casing Hanger

Trapped Gas below

seal assembly

Figure 15.7 Vetco Seal Assembly Retrieval Tool Latched into seal and pulling seal free

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ABANDONMENT OPERATIONS

In either case, the seal assembly can be retrieved either before or after the casing has
been cut. The advantage to retrieving the seal assembly before cutting the casing is that
trapped gas, if present, can be handled separately and not be a concern while cutting
the casing.
The process to remove the seal assembly is complicated by the possibility that trapped
gas may have built up under the seal assembly over time. To prevent release of the
trapped gas into the riser, removal of the seal assembly must be done very carefully,
taking into account well control and the possibility of hydrates forming in the BOP stack.
To retrieve the seal assembly, a seal assembly retrieval tool is run to the wellhead on
drill pipe, and a BOP is closed to prevent accidental release of any trapped gas into the
riser as the seal is pulled free. Typically, an annular preventer is used during the seal
removal to simplify stripping the drill pipe up through the BOPs. If a side outlet is not
directly below the annular, a pipe ram should be considered to minimize the volume of
gas that may be trapped in the BOP stack afterwards. Since a BOP will need to be
closed while the seal assembly is retrieved, drill pipe should always be placed
immediately above the retrieval tool so that drill pipe will be across the BOP stack
during the retrieval.
After latching the retrieval tool into the seal assembly Figure 15.8, valves to the choke
and kill line outlets below the closed preventer on the stack are opened to monitor for
pressure and circulate across the stack. This removes any trapped gas that may have
be released. After the seal is pulled free Figure 15.9, the stack should be swept by
pumping down one line, across the stack, and up the other line to the gas buster. After
sweeping the stack, the preventer is opened, and the riser is circulated to remove any
residual trapped gas in the stack or that may be released into the riser. After circulating
the riser, the seal assembly can be recovered to the surface.
To minimize the possibility of hydrates forming in the BOP stack or choke/kill lines when
the seal is released, an inhibited fluid should be considered to sweep the BOP after the
seal is released. If using a water-base mud, a concentration of mud and glycol can be
mixed to sweep the BOP stack.

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Mud circulated down

kill line and across BOP
Returns up choke line

Annular Closed

Upper choke and kill

valves are open and the
lower choke and kill
valves are closed.

Seal assembly pulled free

Seal retrieval tool latched
into seal assembly

Figure 15.8 Seal Retrieval Tool Figure 15.9 Seal Assembly Pull Free with
Latched into Seal Assembly Annular Closed. Circulating Across BOP
Stack

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ABANDONMENT OPERATIONS

15.8.2 CASING CUTTING OPERATIONS

Cutting and removal of th e ca sin g ca n b e a cco m p lish e d w ith a o n e -trip syste m w h e re
th e ca sin g cu tte r a n d sp e a r a re ru n to g e th e r, a tw o -trip syste m w h e re th e ca sin g cu tte r
and spear are run on separate trips.
During casing cutting operations, it is important to compensate for rig motion and to
prevent vertical movement of the casing cutter. Vertical movement of the cutter can
cause a window to be cut (extending the cutting time), or cause damage to the knives
from excessive down weight or overpull. If heaves are greater than one foot, the motion
compensator is typically used in conjunction with a marine swivel (to apply setdown
weight) or a spear (to apply overpull) while cutting the casing.

ONE-TRIP SYSTEM
O n th e o n e -trip syste m , th e ca sin g cu tte r is sp a ce d o u t b e lo w th e spear to place the
cutter at the cut point when the spear lands in the hanger. The advantage of this system
is that the cut can be confirmed immediately after it is made, and the additional trip to
ru n th e sp e a r is sa ve d . T h e d isa d va n ta g e to th e o n e -trip system is that a packoff
cannot be run with the spear since it would prevent circulation while cutting the casing.
The use of a packoff with the spear allows the casing-by-casing annulus to be circulated
to free the casing or remove contaminated mud. When pulling out of the hole with the
one-trip system, the casing is landed in the rotary and the cutting assembly is pulled
from the casing while working with a false rotary. Tripping pipe with a false rotary can
add several hours to the normal trip time required to pull the cutting assembly from
the wellbore.

TWO-TRIP SYSTEM
O n a tw o -trip syste m , th e ca sin g cu tte r is ru n o n th e first trip to cu t th e ca sin g , a n d th e
spear is made-up and run to the wellhead on the second trip to recover the casing. The
advantage of this system is that a packoff can be run with the spear to allow the casing
annulus to be circulated to remove contaminated mud and assist in freeing the casing.
The disadvantage to this system is that an additional trip is required to spear the casing,
and the cut cannot be confirmed until the second trip with the spear. If well control is a
concern while recovering the casing, the two-trip method offers the most protection since
a packoff can be run and a double string (drill pipe inside casing) of pipe is not across
the BOP stack.
In w a te r d e p th s le ss th a n 1 ,0 0 0 ft, th e tw o -trip syste m m a y b e p re fe rre d sin ce th e trip
times to the wellhead are relatively short and quick and outweigh the additional handling
time required to make-u p th e o n e -trip system, and also outweigh the additional time
required to simultaneously pull out of the hole with the cutting assembly and casing.

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CASING CUTTER
Depending on the size of casing to be cut, a casing cutter body is selected that will
provide the necessary sweep of the blades to cut the casing. Table 15.1 shows cutter
arm lengths for various casing sizes. Blades Figure 15.10 are dressed with tungsten
carbide on the cutting surfaces. When cutting casing that is 16 in. or smaller, the motion
compensator on most rigs can adequately compensate for rig heave. If the motion
compensator cannot adequately keep the pipe stationary, a marine swivel can be run
and landed out in the wellhead.

Cutter Body Casing Size Length of Max. Cutter Pump Est. Time to
O.D. (inches) (inches) Cutter Arms Diameter Pressure (psi) Make Cut
(inches) (inches) (minutes)
8 3 /8 9 5 /8 3 12 1200 5
8 3 /8 10 6 18 1200 5
8 3 /8 11 6 18 1200 10
11 1 3 3 /8 7 19 100 200 15
11 16 7 19 100 200 15
11 20 15 36 200 400 20
11 30 23 52 400 600 30
11 36 23 52 400 600 45
11 48 31 69 600 120
11 60 31 69 600 180

Table 15.1 - Typical Casing Arm Sizes and Operating Data0

Unused tungsten carbide Wear Indication from Casing Cut

Figure 15.10 Used Casing Cutter Arm (Blade, Knife)

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 ABANDONMENT OPERATIONS

Figure 15.11 details the major components of a casing mill cutter. The casing cutter is a
simple hydraulic tool with a piston that is forced downward by pump pressure that
extends a set of knives outward against the casing. The top drive is engaged, and a slow
rotary speed is set for maximum torque to be maintained until the casing is cut, usually
only a few minutes Figure 15.12 for casing sizes 13 3/8 in. and smaller. Once the casing
is cut through, it is important that the fluid level in the hole be maintained for losses, in
the event there is a void behind the casing.
In our example of removing a string of 9-5/8 in. casing, an 8-1/4 in. body casing cutter is
used dressed with knives to open wide enough to assure that the casing is cut cleanly as
shown in Figure 15.9.

9 5 /8 C asing

13 3 /8 C asing

Casing Cutter

Figure 15.11 Typical Mechanical Cutter Figure 12 C utting 9 5 /8 Casing

Another consideration when selecting knife length is preventing the cutter from
inadvertently cutting the outer single of casing. If possible, the knife should be selected
with appropriate length to cut the inner string of casing, but not long enough to cut the
outer string of casing.
Another important component of the cutting assembly is the stabilizer used to centralize
the cutting tool. All internal cutters operate more efficiently turning true in the hole rather
than being slightly offset. To combat this offset, at least one stabilizer should always be
run immediately above the cutter or 30 to 60 ft above in all-casing sizes larger than
16 in. The use of one or more drill collars should also be considered.

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CASING SPEAR
The casing spear used for P&A operations on a floating rig is the same as that used on a
rig with a surface BOP stack. The casing spear is typically run with a spear stop and set
in the casing hanger. A sp ear sto p is important when operating from a floating rig
since rig heave could reset the spear deeper in the casing with each upward heave.
To provide a seal inside the casing at the spear, a pack-off can be run to allow
circulation up the backside of the casing. Circulation may be required to free stuck
casing or prevent swabbing while retrieving casing with a small annulus clearance.
W h e n a o n e -trip cu t a n d p u ll syste m is u se d , th e p a cko ff ca n n o t b e ru n w ith th e sp e a r
since it would prevent circulation while cutting the casing.
When retrieving the casing hanger/spear up through the BOP stack, the motion
compensator should be unlocked and overpressured to prevent severe overpull on the
drill pipe should the casing hanger hang up in a ram cavity. The retrieval of the casing
hanger with a spear leaves the flat shoulder on the casing hanger exposed and prone to
falling into a ram cavity. The casing hanger is also prone to hanging up on the bottom of
the inner barrel of the slip joint when tripping out of the hole and requires the use of the
motion compensator to prevent over-tensioning the drill string.
A spear should be selected that is beveled on the top side to minimize the possibility of
the spear hanging up in the BOP stack.

Spear Stop

G rapple latch ed into 9 5 /8 casing

9 5 /8 C asing Previously Cut

13 3 /8 C aing

Figure 15.13 Typical Casing Spear

show n latched into 9 5 /8 C asing

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ABANDONMENT OPERATIONS

ISOLATING ANNULUS WITH CEMENT

To isolate the annulus after the casing has been recovered with a balanced cement plug,
a cement stinger or open-ended drill pipe is run 100 ft into the casing stub, and a
balanced plug is pumped. The balanced cement plug should have sufficient volume to
squeeze a minimum of 100 ft of cement into the annulus leaving 100 ft of cement above
the casing stub. After the balance plug is set, the pipe is pulled a safe distance above
the balance plug and a preventer closed to squeeze the cement into the annulus.
If operating from a D/P rig or a moored rig with substantial heave, the drill string would
typically be hung off on a pipe ram to prevent pressure surges caused by the vessel
heave. To verify the annulus seal, a pressure test of 500 psi over formation leakoff at the
shoe is conducted.

ISOLATING ANNULUS WITH MECHANICAL PLUG

The annulus can also be plugged by setting a cement retainer above the casing stub
and squeezing a sufficient volume of cement through the retainer to place a minimum of
100 ft of cement in the annulus between the casing strings. When setting the retainer,
the guidelines listed in section 15.6.2 and 15.6.3 should be reviewed.
Set a cement retainer in the casing just above the casing stub and squeeze enough
cement through the retainer to place 100 ft in the annulus and leave 50 ft of cement
above the retainer.
Perforate the casing and set a cement retainer Figure 15.14 within 50 ft of the
perforation and squeeze cement through the perforations into the casing by casing
annulus. The casing would then be cut above the retainer and pulled, then a
balanced plug set across the stub.

TESTING PLUG(S)
These plugs shall be tagged and/or pressure tested to at least 500 psi in excess of the
formation leak-off pressure, or to the working limit of the weakest exposed casing string,
whichever is less (ExxonMobil guideline).

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ABANDONMENT OPERATIONS

15.9 PLUGGING OR ISOLATING A PERFORATED

CASING ANNULUS
In some cases it may be necessary to isolate the annulus between two casing strings
before casing is cut and recovered. In this case, the casing may be perforated and
cement squeezed into the perforation. In wells where the annulus needs to be sealed
following casing perforations (i.e., to seal 18-3 /4 1 0 K o r 1 5 K W e llh e a d
hydrocarbon or gas zone, well tests,
3 0 L o w P re ssu re W e llh e a d
remedial work, etc.), the following are
acceptable methods of isolating
perforated intervals Figure 15.14. Structural Casing
Consideration should be given to well
control prior to performing the following T O C m in im u m 5 0 a b o ve
above retainer
two steps since trapped gas may be 2 0 C a sin g
present in the casing annulus.
B o tto m o f re ta in e r 5 0 to
1. After the well is perforated and an n o t m o re th a n 1 0 0 a b o ve
13-3 /8 C a sin g perforations
injection rate is established (10 to 25
bbls to ensure that the cement can
squeezed through perforations), a
balanced cement plug placed Cement in annulus shall extend
a m in im u m 1 0 0 b e lo w p e rfs
opposite all open perforations,
extending 150 ft above and through
the bottom of the perforated interval.
9-5 /8 C a sin g
The cement may be squeezed in
place by closing the annular.
2. After the well is perforated and an
injection rate established, a cement 7 L in e r
retainer with effective back pressure
control is permanently set above the
perforated interval. Cement is then
pumped and squeezed into the Hydrocarbon Zone
perforations. Placement of the
retainer will be subject to local
regulations, but typically the cement
retainer should be set not less than Figure 15.14
50 ft and no more than 100 ft above Isolating Perforated Intervals
the top of the perforated interval. The
calculated volume of cement pumped shall extend to 100 ft below the bottom of the
perforated interval with a minimum of 50 ft of cement dumped onto the top of the
retainer as the running tool is pulled from the packer.
In wells where a production test has been performed and the casing has been
perforated, the perforation may be isolated and plugged using the same guidelines listed
above. This plug shall be tagged with a minimum of 15,000 lbs. circulating against the
plug and a pressure test to a differential pressure across the plug of at least 500 psi in
excess of the formation breakdown pressure (injection pressure), or within the working
limits of the weakest exposed casing string, whichever is less.

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15.10 SURFACE PLUGS

A surface cement plug of at least 18-3 /4 1 0 /1 5 K W e llh e a d
150 ft in length must be placed
3 0 L P W e llh e a d
in the smallest string of casing
that extends to the seafloor
Figure 15.15. Surface Plug Structural Casing
This balanced plug, placed
across the previously cut casing
stub of the largest casing
2 0 C a sin g
recovered prior to wellhead
removal, will often serve as the
surface plug. In those instances
where this is not possible, a 150
ft balanced plug set through a 3- 13-3 /8 C a sin g

1/2 in. stinger, or open ended

drill pipe will be placed such that
the top of the plug is within 100
ft of the mud line.
Setting the surface plug on a
floating rig is identical to setting
any other balance plug, except 9-5 /8 C a sin g
that, due to the proximity of the
BOP, it is critical that pipe
measurements are correct to
prevent cement from entering 7 L in e r
the stack. This uncertainty in
pipe measurement may occur
while the drill pipe is laid down
between plugs to facilitate the
stability during the upcoming rig Hydrocarbon Zone
move. The problem is
compounded by the fact that the
stack may be 5000 to 6000 ft
from the rotary. Figure 15.15
This plug shall be tagged with Surface Plug
10 to 15K lbs. to verify its top in
relation to the seafloor.

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ABANDONMENT OPERATIONS

15.11 SUBSEA WELLHEAD REMOVAL

The permanent abandonment of a well will typically include the removal of all wellhead
equipment from the seafloor. This will require the structural casing (38, 36, or 30 in.) and
conductor casing (26 or 20 in.) to be cut at a depth of at least 15 ft below the seafloor
and retrieved, in order to leave the drilling location in its natural environmental state.
Since the high-pressure wellhead and the low-pressure housing are locked together, a
multiple cut on the structural and conductor are always performed.
There are two methods for removal of the wellhead equipment: explosives and
mechanical cutting. The most common method to remove the wellheads is to
mechanically cut since the use of explosives can require special environmental
approval. The use of explosives can also be difficult due to the handling requirements,
host country regulations, and required transportation permits.
Since the use of mechanical cutting tools is the most common method for recovering the
wellhead equipment, this section will focus on the mechanical cutting tools and
procedures.

15.11.1 CUTTING MULTIPLE CASING STRINGS

Cutting multiple strings at once can
create problems not associated
with single cuts, the main problem
being the lack of centralization
resulting in an eccentric positioning
of the strings Figure 15.16.
Not knowing how eccentric the
casing strings are in relation to one
another, it is important that the
knife length be selected for the
maximum cutting diameter.
Table 15.2 shows examples of
casing sizes and blade lengths
necessary to cut multiple casing
strings in two or more trips in the
hole. Casing strings are very rarely
concentric, and knives are typically
selected assuming the largest
offset.

Figure 15.16 Eccentric Diameters

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ABANDONMENT OPERATIONS

Casing Combinations Eccentric Casing Combinations Eccentric

Diameter Diameter
Size A Size B Size C Size A Size B Size C
9 5 /8 13 3/8 20 27.881 1 3 3 /8 26 36 55.873
9 5 /8 16 20 27.916 16 20 30 40.290
9 5/8 16 26 38.874 16 20 36 52.290
10 16 20 26.791 16 24 30 41.248
10 16 24 33.749 16 24 36 53.248
1 3 3 /8 20 26 34.915 16 26 30 41.248
13 3/8 24 30 42.915 20 24 30 37.248
13 3/8 24 30 43.873 20 24 36 49.248
13 3/8 24 36 55.873 20 26 36 49.248

Table 15.2 Eccentric Diameters for Various Casing Sizes

Figure 15.17 shows that the

degree of centralization plays
an important part in the cutting
operation. On the left, the three
strings are centralized. Using
the 16 in. arms requires that
0.6 cubic ft of steel be
removed.
On the right, the strings have
the maximum eccentricity and
must be cut using 22 in. arms
requiring that 1.4 cubic ft of
steel be removed to complete
the cut. If it is known that the
well will be abandoned after
the hole is evaluated,
centralizing the casing strings
when they are run in the area
where the cut is to be made
will significantly improve cutting
operations. This is particularly
important in the upper portions
of the hole where conductor Figure 15.17 Cutting Uncentralized Casing
and structural casing strings
with large wall thickness and
cemented annuli are to
be cut. Figure 15.17 Cutting Uncentralized
Casing

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ABANDONMENT OPERATIONS

15.11.2 CUTTING CASING WITH A MARINE SWIVEL

When performing a multiple cut, it is critical to ensure that the knives are stationary and
not affected by rig heave. Since the cuts on the wellheads will be performed in open
water after the BOP stack has been retrieved, a landout point in the wellhead is required
to provide a passive point of resistance for the motion compensator. Removing the
heave component from the drill string while cutting the casing ensures that the space-out
from the wellhead to the cut remains the same, thereby reducing the window that is
being cut and the time required to make the cut, and reducing the possibility of
damaging the cutter knives.
The marine swivel Figure 15.18, when used is positioned
in the cutting assembly to land-out in the wellhead and Rotating Stem
position the casing cutter at the proper cut location. When
the marine swivel seats in the wellhead, it provides
passive resistance for the motion compensator to act
against to provide heave compensation.
Thrust Bearing
Marine swivels are equipped with a support ring to land-
out in the wellhead and a thrust bearing that allows
rotation of the inner stem and the drill string. Typical tool
sizes are from 10.5 in. to 14.0 in. with support rings from
12.0 in. to 35.0 in.. Bearing Stationary Sleeve
capacity ranges from 45 to 250 kips.
With the marine swivel landed-out in the wellhead, the
casing can be cut with either the rotary/top drive or with a
mud motor using a large casing cutter equipped with extra
long knives. After cutting the casing, the cutting assembly
would be tripped and a casing spear or wellhead running
tool used to retrieve the casing, wellheads and
assemblies.

If a spear is used to catch the 18- in. wellhead, the

grapple will typically catch in the sealing area of the
wellhead requiring considerable repair or potentially Figure 15.18 Typical
junking the wellhead. Marine Swivel

If the wellhead running tool is used, it will require make-up into the wellhead with
left-h a n d ro ta tio n . B e fo re ru n n in g th e w e llh e a d ru n n in g to o l, a ll o rin g se a ls sh ould be
removed to facilitate stab-in and make-up. During make-up of the running tool into the
wellhead, the torque limit switch to the top drive should be set to a minimum and surface
rotation should be matched with drill string rotation at the tool with the ROV. When high
overpull or jarring is required to free the wellheads and casing from the mud line, the
wellhead-running tool will provide a more secure catch than the large spear or the
external catch tool (Weatherford MOST tool).
A Marine swivel can also be used when cutting smaller casing with the BOP and
riser in place.

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15.11.3 MOST WELLHEAD RETRIEVAL TOOL

A cutting assembly, as depicted in Figure
15.19, is run in conjunction with the
retrieval tool that externally latches to the
18-3/4 in. high-pressure wellhead housing.
The common type of tool used for this Mud Motor
operation is the Weatherford Drilling &
In te rve n tio n S e rvice s M e ch a n ica l O u tsid e MOST
Single Trip tool (commonly referred to as a Tool
MOST tool). The Weatherford MOST tool
is run in conjunction with a mud motor and
casing cutter to latch onto the external
wellhead profile. The MOST can be run
with the cutter spaced out to either cut with
weight set down on the wellhead or while
pulling tension on the wellheads.
Removal of the structural casing and
conductor casing is performed after the
BOP stack is pulled and is considered a
freewater operation without the support of
the drilling riser. All cutting is performed Non-Rotating
with seawater with returns being taken to Stabilizer
the seafloor and monitored with an ROV.
Large bodied casing cutters are employed
that have full knife sweeps up to 47.5 in.
which can cut through the conductor
casing, annular cement and structural
casing in a single cutting operation. Casing Cutter
The advantages of the MOST are:
Confirming the cut without tripping
the pipe (especially important in
deepwater where trip time can
be substantial). Figure 15.19 - MOST Tool Assembly
Minimizing any internal damage to
the wellhead (for reuse) since it
latches externally instead of using an internal grapple.
High capacity (600,000 tension) allows the casing to be cut in tension.

As depicted in Figure 15.19, a downhole mud motor is placed above cutter allowing the
casing to be cut without pipe rotation. Without the support of the drilling riser, it is
preferable to use a mud motor to prevent the necessity of having to rotate the drill string
in open water, particularly at deeper water depths.
Once the MOST tool is set onto the wellhead, circulation is begun and the pressure
forces a piston down, opening the knife blades against the casing, and the cutting is
begun. An increase in pump pressure will indicate that the cut has been made.

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ABANDONMENT OPERATIONS

The pumps are shut down, and the MOST tool is picked-up to engage the wellhead, and
a pull is taken to determine if the conductor casing, structural casing and PGB/mud mat
are free. Figure 15.20. If so, then the entire assembly is pulled to the surface and laid
down.
Prior to cutting the conductor and structural casing, the exact location of the casing
connectors should be determined and the cutters spaced out to avoid cutting the casing
across a connector. It is also preferable to cut above any connections on the conductor
pipe since the rotation and torque of the cutter knives may back off the connection above
the cut. When running the conductor casing, all locking tabs/devices should be utilized
on any connections that may be above the cut location. If the casing is cut below a
connection and the joint backs off, rotation of the joint will prevent the knives from
continuing to cut/mill the conductor casing which will prevent the knives from reaching
the opening width required to cut the structural casing.

Figure 15.20 MOST Tool Latch

Profile Shown with CIW Wellhead

When attempting to pull the casing, wellheads and mud mat free from the mud line, it is
essential that the casing be completely cut. If only a small section on one side of the
casing remains uncut, it is nearly impossible to pull apart the uncut section. In addition,
when the casing parts, the sudden loss in tension can cause the MOST tool to release
from the wellhead and leave the wellheads leaning at an angle that makes it difficult to
re-latch the tool.
The wellheads and casing can also be difficult to pull free from the mud line due to the
cuttings and cement accumulation on top of the mud mat and/or guidebase(s). The

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ABANDONMENT OPERATIONS

cuttings and cement accumulate on the mud mat and guidebase while the conductor
hole is drilled and as a result of the excess conductor casing cement.

In Figure 15.21, the MOST tool is landed on the wellhead with the casing cutter spaced
at the desired location to cut the conductor and structural casing. In Figure 15.22, the
conductor and structural casing have been cut, the MOST tool latched onto the wellhead
and the casing and wellhead are being lifted from the seafloor.

The MOST tool is a highly reliable system whose grapples are available to retrieve
various manufactured wellheads, including Vetco, Cameron, National, and Dril-Quip

Cuttings and Excess Cement

from Conductor Hole Drilling
& Cementing

Figure 15.21 Cutting Conductor & Figure 15.22 Wellheads & Conductor/
Structural Casing with MOST Tool Structural Casing being Retrieved with MOST
Tool

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ABANDONMENT OPERATIONS

15.12 RETRIEVAL OF TEMPORARY GUIDEBASE

If a temporary guidebase is used, it will require retrieval from the seafloor during
permanent plug and abandonment. The temporary guidebase can be retrieved by
one of the following methods:
The guidebase running tool can be run on drill pipe and made-up into the guidebase
with left-hand rotation. Even though the makeup of the tool will typically only require
one-quarter turn for makeup, this method can be difficult since the guidebase will
typically be at an angle, and simultaneous engagement of the running tool into the
four j-slots will be hampered.
Pull the guidebase on the guide wires with the guideline tensioners and tuggers.
This method is hampered by the cutting and cement build possibly present on the
guidebase. After breaking the guidebase free from the mud line, the guidelines must
be reeled in simultaneously to prevent the guidebase from overturning.
Attach the temporary guidebase to the permanent guidebase and retrieve with the
wellheads. When the temporary guidebase is run, 10 to 12 ft wirerope pigtails are
attached to the guidebase and secured to the guidelines. After the structural
casing and PGB are run, the ROV is used to attach the pigtails to the PGB with
preinstalled hooks.

CABLES OR CHAINS
CONNECTED BY
ROV AT TIME OF P&A

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ABANDONMENT OPERATIONS

15.13 TEMPORARY ABANDONMENTS

Temporary abandonment differs from
Corrosion Cap
permanent abandonment in that all
casing strings and wellhead equipment
seals remain intact for future re-entry
Figure 15.23. No holes can be punched 3 0 L o w P re ssu re W e llh e a d
in the casing except as required for
production testing, and these 9-5 /8 B rid g e P lu g
perforations must be properly plugged
Structural Casing
and isolated. Any open hole or liner lap
is plugged off the same as for
permanent abandonment. The top plug
usually consists of either a cement or 2 0 C a sin g
mechanical bridge plug.
To protect the casing from corrosion, an
inhibiting fluid is typically displaced into
the wellbore after setting the last plug
13-3 /8 C a sin g
below the surface plug.
If a PGB or GRA are installed on the
wellhead, they may be retrieved to
reduce obstruction height above the
Balanced Plug
seafloor. The PGB or TGB are retrieved above and below
by running a special retrieval tool top of liner
furnished by the wellhead manufacturer
that latches onto the guidebase and
releases them from the wellhead. 9-5 /8 C a sin g
An ROV is required to assist stabbing
and make-up of the running tool.
The wellhead seal area is protected by
installing a corrosion cap. For long
7 L in e r
abandonment periods, the wellhead
area may additionally be protected by
displacing the mud in the seal area with
inhibiting fluid via the ROV pump, and
by attaching sacrificial anodes.
Hydrocarbon Zone
If the well is planned to be temporarily
abandoned for a long time, the wear
bushing should be retrieved to prevent
corrosion between dissimilar metals.
Local government regulations may Figure 15.23
require that the wellhead and guidebase Temporary P&A Wellbore
be inspected at a determined
frequency.

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15.14 SEABED INSPECTION

A seabed survey is typically performed with the rig ROV within a radius of 300 ft from the
w e llh e a d u sin g th e R O V s ca m e ra a n d so n a r to sca n th e se a flo o r fo r a n y d e b ris th a t m a y
have been accidentally dropped from a boat or the rig during the course of drilling the
well. An affidavit signed by the ROV Supervisor and a video of the seafloor survey is
typically retained for proof of a clear seafloor at the location. If any debris is found, it
should be recorded and recovered by the ROV, or noted, and permission granted from
the local regulatory body to leave it in place.

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15.15 REFERENCES
E xxo n P ro d u ctio n R e se a rch C o m p a n y; S u b se a W e llh e a d R e m o va l E P R .1 8 P R .8 4 ,
February 1984

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