Offshore Drilling and Production Platforms/Units 159
FIGURE 3.40
Drillship. (Courtesy of Cliff/Wikimedia Commons/CC-BY-SA-2.0.)
A subsequent increase in ‘rig downtime’ or ‘lost’ time occurs. Because of this
there is a bigger demand for the use of compensation devices.
Drillships similar to the semisubmersibles are held on location either by
conventional mooring system or by dynamic positioning. However, there is
one additional system that has been developed on a drillship and that is the
‘turret’ system.
Briefly then, drillships have many advantages like proven deepwater capa-
bility, capacity to transport much larger loadings of drilling supplies, faster
travel time to remote locations, self-propelled and hence no need for tug, but
the disadvantage is that it should only be considered for use in areas of small
wave heights and low wind velocities.
3.3.2.2 Floating Production Unit
Once offshore operations extended beyond practical fixed platform lim-
its, the production engineers borrowed concepts devised by the drilling
engineers. They in turn had responded to the needs of the explorers with
semisubmersibles and drillships as they moved out of shallow water. Thus,
floating production units (plus, in many cases, the subsea completions) now
160 Offshore Petroleum Drilling and Production
provide the viable options in deepwater. Figure 3.32 shows different types of
floating units used for oil and gas production.
Floating production units come in many sizes and shapes. Some provide
more functions than others. In every case, they differ from fixed units by
what holds them up – the buoyancy of displaced water, not steel understruc-
ture. Such units have four common elements:
Hull – the steel enclosure that provides water displacement. Floating
unit hulls can be in ship shapes, pontoons and caissons, or a large
tubular structure called a spar.
Topsides – the deck or decks have all the production equipment used
to treat the incoming well streams plus pumps and compressors
needed to transfer the oil and gas to their next destinations. Some
have drilling and workover equipment for maintaining wells. Since
almost all deepwater sites are somewhat remote, their topsides
include living accommodations for the crew. In most cases, export
lines connect at the deck as well.
Mooring – the connection to the seabed that keeps the floating units in
place. Some combine steel wire or synthetic rope with chain, some
use steel tendons. In some cases, they make a huge footprint on the
seabed floor. This is discussed in detail in a subsequent chapter.
Risers – steel tubes that rise from the sea floor to the hull. A riser trans-
ports the well production from the sea floor up to the deck. The line
that moves oil or gas in the other direction, from the deck down to
pipeline on the sea floor, uses the oxymoron export risers.
3.3.2.2.1 Tension Leg Platforms (TLP)
The semisubmersible, used for years only for drilling, begat TLPs. By similar
design, the buoyancy of a TLP comes from a combination of pontoons and
columns. Vertical tendons from each corner of the platform to the sea floor
foundation piling hold the TLP down in the water. Vertical risers connected
to the subsea wells heads directly below the TLP bring oil and gas to dry
trees on the deck.
Dry trees on the deck of the TLP control the flow of oil and gas production
coming up through the conductor pipes. However, like other floating sys-
tems, it can receive production from risers connected to remote subsea wet
tree completions. Most TLPs have subsea riser baskets, structural frames that
can hold the top end of risers coming from subsea completions. Figure 3.41
shows a TLP used for production.
3.3.2.2.2 Monocolumn TLP/Mini-TLP
In shallower water or for smaller deposits in deepwater, and where no more
drilling is planned, some companies use a smaller variation of the TLP
called a mini-TLP, a monocolumn TLP, or sometimes a SeaStar (Figure 3.42).
Offshore Drilling and Production Platforms/Units 161
FIGURE 3.41
Tension leg platform. (Courtesy of Derk Bergguist, South Carolina, Department of Natural
Resources.)
The names monocolumn and SeaStar (a proprietary label) come from the
underwater configuration of the floatation tanks, a large central cylinder
with three star-like arms extending from the bottom. The cylinder measures
about 60 ft in diameter and 130 ft in height. The arms reach out another 18 ft.
As with other TLPs, tendons secure the substructure to the sea floor, in
this case two from each arm. The mooring system, risers and topsides are
similar to any other TLP, except for the modest sizes. The absence of drilling
equipment on board helps lower the weight of the topsides and allows for
this scaled-down version.
3.3.2.2.3 Floating Production Storage and Offloading (FPSO)
This refers to a ship-shaped structure with several different mooring systems.
From 400 yards away, most FPSOs are indistinguishable from oil tankers. In
fact, while many FPSOs are built from scratch, the rest are oil tankers converted
to receive, process and store production from subsea wells. FPSOs do not pro-
vide a platform for drilling wells or maintaining them. They do not store natu-
ral gas, but if gas comes along with the oil, facilities are onboard and the FPSO
separates it. If there are substantial volumes, they are sent back down a riser for
reinjection in the producing reservoir or some other nearby consumer.
162 Offshore Petroleum Drilling and Production
FIGURE 3.42
Mono column TLP.
The industry has found scores of remote or hostile environments that call
for the FPSO design:
• At sea where no pipeline infrastructure exists
• Where weather is no friend, such as offshore Newfoundland or the
northern part of the North Sea
• Close to shore locations that have inadequate infrastructure, market
conditions, or local conditions that may occasionally not encourage
intimate personal contact, such as some parts of West Africa
There are four principal requirements that drive the size of a typical FPSO:
1. Sufficient oil storage capacity to take care of the shuttle tanker turn-
around time
2. Sufficient space on the topsides for the process plant, accommoda-
tion, utilities and so on
Offshore Drilling and Production Platforms/Units 163
3. Sufficient ballast capacity to reduce the effects of motions of process
plant and riser systems
4. Space for the production turret (bow, stern or internal)
As an FPSO sits on a station, wind and sea changes can make the hull
want to weathervane, turn into the wind like ducks on a pond on a breezy
day (Figure 3.43). As it does, the risers connected to the wellheads, plus
the electrical and hydraulic conduits, could twist into a Gordian knot. Two
approaches deal with this problem, that is, the cheaper way and the better
way, depending on the ocean environment.
In areas of consistent mild weather, the FPSO moors, fore and aft, into
the predominant wind. On occasions, the vessel experiences quartering or
broadside waves, sometimes causing the crew to shut down operations.
In harsher environments, the more expensive FPSOs have a mooring sys-
tem that can accommodate weathervaning. Mooring lines attach to a revolv-
ing turret fitted to the hull of the FPSO. As the wind shifts and the wave
action follows, the FPSO turns into them.
The turret (Figure 3.44) might be built into the hull or cantilevered off the
bow or stern. Either way, the turret remains at a permanent compass setting
as the FPSO rotates about it.
The turret also serves as the connecting point between the subsea systems
and the topsides production equipment. Everything between the seabed and
the FPSO is attached to the turret-production risers, export risers, gas rein-
jection risers, hydraulic, pneumatic, chemical and electrical lines to the sub-
sea wells, as well as the mooring lines.
Turrets contain a swivel stack, a series of fluid flow and electronic continu-
ity paths that connect the seaside lines with the topsides. As the FPSO swings
around the turret, the swivels redirect fluid flows to new paths, inbound
Anticlockwise
l
sse
Ve
Clockwise
FIGURE 3.43
‘Weathervane’ concept.
164 Offshore Petroleum Drilling and Production
Bearing
Outer rotating part
Seal
Fluid passage
Inner fixed part
FIGURE 3.44
Turret of an FPSO.
or outbound. Other swivels in the stack handle pneumatics, hydraulics and
electrical signals to and from the subsea systems.
In some designs, the FPSO can disengage from the seabed (after shut-
ting in the production at the wellheads) to deal with inordinately rough
seas, or other circumstances that might worry the ship’s captain, like an
approaching iceberg. A spider buoy, the disconnectable segment of the tur-
ret with the mooring, the riser and the other connections to the subsea
apparatus, drops and submerges to a predesignated depth as the vessel
exits the scene.
After the oil moves from the reservoir to the FPSO via the turret, it goes
through the processing equipment and then to the storage compartments.
Shuttle tankers periodically must relieve the FPSO of its growing cargo.
Some FPSOs can store up to 2 million barrels on board, but that still calls for
a shuttle tanker visit every week or so. Mating an FPSO to the shuttle tanker
to transfer crude oil calls for one of several positions.
• The shuttle tanker can connect to the aft of the FPSO via a mooring
hawser and offloading hose. The hawser, a few hundred feet of ordi-
nary marine rope, ties the shuttle tanker to the stern of the FPSO and
the two-vessel weathervane together about the turret.
• The shuttle tanker can moor at a buoy a few hundred yards off the
FPSO. Flexible lines connect the FPSO through its turret to the shut-
tle buoy and then to the shuttle tanker (Figure 3.45).
• Some shuttle tankers have dynamic positioning, allowing them to
sidle up to the FPSO and use their thrusters on the fore, aft and
Offshore Drilling and Production Platforms/Units 165
Tanker-offloading
buoy
FPSO Drilling platform
Injection lines
Existing well centers
FIGURE 3.45
Offloading of an FPSO. (Courtesy of WikiDon/Wikimedia Commons/CC-BY-SA-3.0.)
sides to stay safely on station, eliminating the need for an elaborate
buoy system. The shuttle tanker drags flexible loading lines from the
FPSO for the transfer.
Oil then flows down a 20-in. (or so) offloading hose at about 50,000 bar-
rels per hour, giving a turnaround schedule for the shuttle tanker of about
one day.
3.3.2.2.4 Floating, Drilling, Production, Storage and Offloading (FDPSO)
Inevitably, the attributes of an FPSO plus a drillship or a semisubmersible
come together in the form of a floating drilling production storage and
offloading (FDPSO) to do it all in deepwater. The crucial technologies for this
union, still in the nascent stage, are motion and weathervane compensation
systems for the drilling rig.
3.3.2.2.5 Floating Storage and Offloading (FSO)
This specialty vessel stores crude from a production platform, fixed or float-
ing, where no viable alternatives for pumping oil via pipeline exist. FSOs
almost always had a former life as an oil tanker and generally have little or
no treating facilities onboard. As with the FPSO, shuttle tankers visit peri-
odically to haul the produced oil to market.
3.3.2.2.6 Floating Production System (FPS)
In theory, an FPS can have a ship shape or look like a semisubmersible or TLP,
with pontoons and columns providing buoyancy. Either way, the FPS stays
166 Offshore Petroleum Drilling and Production
moored on station to receive and process oil and gas from subsea wet trees,
often from several fields. After processing, the oil and gas can move ashore
via export risers, or the gas can go into reinjection and the oil to an FSO.
At a typical operation, the Shell-BP Na Kika project in the Gulf of Mexico,
the FPS is designed to handle six oil and gas fields, some several miles away
(Figure 3.46). Production arrives at the FPS from subsea completions through
flexible and catenary risers and goes through treating and processing before
it leaves via export risers toward shore. The FPS provides a home for the sub-
sea well controls that are connected via electrical and hydraulic umbilicals.
3.3.2.2.7 Spar
Even though the name spar comes from the nautical term for booms, masts
and other poles on a sailboat, spars exhibit the most graceless profile of the
floating systems. An elongated cylindrical structure, up to 700 ft in length
and 80–150 ft in diameter, the spar floats like an iceberg – it has just enough
freeboard to allow a dry deck on top. The mooring system uses steel wire or
polyester rope connected to chain on the bottom. The polyester has neutral
buoyancy in water and adds no weight to the spar, eliminating having to
build an even bigger cylinder. Because of its large underwater profile, the
huge mass provides a stable platform with very little vertical motion. To
ensure that the centre of gravity remains well below the centre of buoyancy
(the principle that keeps the spar from flipping), the bottom of the spar usu-
ally has ballast of some heavier-than-water material like magnetite iron ore.
Host platform
Herschel
Ariel field field
Kepler field Coulomb field
Fourier field
E. Anstey field
FIGURE 3.46
A typical FPS designed to handle six sub-sea fields (Na Kika Project). (Courtesy of Shell Oil Co.)
Offshore Drilling and Production Platforms/Units 167
Because of the large underwater profile, spars are vulnerable not only to
currents but also to the vortex eddies that can cause vibrations. The char-
acteristic strakes (fins that spiral down the cylinder) shed eddies from these
ocean currents, although the strakes add even more profile that calls for
additional mooring capacity.
Drilling rigs operate from the deck through the centre of the cylinder.
Wells connect to dry trees on the platform by risers, also coming through
this core. Risers from subsea systems and export risers also pass through
the centre.
Spars have evolved through several generations of design. The original
concept had a single 600-ft steel cylinder below the surface.
Three types of production spars (Figure 3.47) have been built to date: the
‘classic’ spar, ‘truss’ spar and the third generation ‘cell’ spar. The basic parts
of the classic and truss spar include:
1. Deck
2. Hard tank
3. Midsection (steel shell or truss structure)
4. Soft tank
Hard
tank Ballast tanks
Strakes
Fairlead
Mid
section
Soft tank Mooring lines
Steel catenary riser Top-tensioned riser
Classic spar Truss spar Cell spar
FIGURE 3.47
Types of production spar.
168 Offshore Petroleum Drilling and Production
The topsides deck is typically a multilevel structure to minimise the can-
tilever requirement. For decks up to about 18,000 tons, the deck weight is
supported on four columns, which join the hard tank at the intersection of
a radial bulkhead with the outer shell. Additional columns are added for
heavier decks.
The hard tank provides the buoyancy to support the deck, hull, ballast
and vertical tensions (except the risers). The term ‘hard tank’ means that
its compartments are designed to withstand the full hydrostatic pressure.
The profile is shown in Figure 3.47. There are typically five to six tank levels
between the spar deck and the bottom of the hard tank, each level sepa-
rated by a watertight deck. Each level is further divided into four compart-
ments by radial bulkheads emanating from the corner of the center well. The
tank level at the waterline includes additional cofferdam tanks to reduce the
flooded volume in the event of a penetration of the outer hull from a ship
collision. Thus, there are up to 28 separate compartments in the hard tank.
Typically, only the bottom level is used for variable ballast, the other levels
being void spaces.
The midsection extends below the hard tank to give the spar its deep draft.
In the early ‘classic’ spars, the midsection was simply an extension of the
outer shell of the hard tanks. There was no internal structure, except as
required to provide support for the span of risers in the midsection. Later
spars replaced the midsection with a space frame truss structure. This ‘truss
spar’ arrangement resulted in a lower weight, less expensive hull structure.
Also, the truss has less drag and reduces overall mooring loads in high cur-
rent environments.
The soft tank at the bottom of the spar is designed to provide floatation
during the installation stages when the spar is floating horizontally. It also
provides compartments for the placement of the fixed ballast once the spar is
upended. The soft tank has a centre well and a keel guide which centralises
the risers at that point.
The truss spar has three sections: a shortened ‘tin can’ section; below
that, a truss frame (saving weight); and below that, a keel or ballast
section filled with magnetite. The truss section has several large, hori-
zontal, flat plates that provide dampening of vertical movement due to
wave action. Like the original, the cylindrical tank provides the buoy-
ancy for the structure and contains variable ballast compartments and
sometimes tanks for methanol, or antifreeze used to keep gas lines from
plugging.
The third generation, the cell spar, is a scaled down version of the truss spar
and is suitable for smaller, economically challenged fields. The design takes
advantage of the economies of mass production. It uses more easily fabri-
cated pressure vessels, what refineries and gas plants call bullets, that are
used to handle volatile hydrocarbons. Each vessel is 60–70 ft in diameter and
400–500 ft long. A cell, a bundle of tubes that looks like six giant hot dogs
clustered around a seventh, makes up the flotation section extending below
Offshore Drilling and Production Platforms/Units 169
the decks. Structural steel holds the package together, extends down to the
ballast section and can include heave plates. This design embodies a new
construction technique using ring stiffened tubulars assembled in a hex-
agonal formation to form a spar. The first cell spar is designed for wet trees
only. Because of the length of a spar, the spar hull cannot be towed upright.
Therefore, it is towed offshore on its side, ballasted to a vertical attitude and
then anchored in place. The topside is not taken with the hull and is mated
offshore once the spar is in place at its site. The mooring cables are connected
with predeployed moorings.
3.3.3 Buoyancy and Stability
Any seaworthy vessel must obey all the laws of hydrodynamics for the safe
operation of drilling and production as well as during movement from one
location to the other. Thus ‘buoyancy’ and ‘gravity’ become two very impor-
tant factors which play a big role in determining the ‘stability’ of a floating
unit.
3.3.3.1 Theory and Analysis
3.3.3.1.1 Buoyancy
Buoyancy is the apparent loss of weight of a body immersed in a fluid.
It was Greek scientist Archimedes (287–212 B.C.) who discovered that the
weight of a body floating in a fluid equals the weight of the volume of the
fluid displaced by the body. In precise terms, Archimedes’ principle is stated
as follows:
A solid body wholly or partially submerged in a fluid is buoyed up by a
force (mbg) equal to the weight (ρwV) of the fluid displaced.
Referring to Figure 3.48, mb is the mass of the fluid displaced by a ship of
mass in air equal to mo, V is the volume of water of constant density ρw dis-
placed by the ship of weight in air mog.
Thus, the upward pressure of the displaced water, that is, buoyant force
m b g = ρw V. (3.1)
In Naval terminology, Vρw, that is, the weight of the volume of water below
the waterline which is occupied by water is known as ‘displacement.’ It is to be
noted that dimensionally this is not the length but weight.
Now the above buoyant force (mbg) acts at a point B (known as the
‘centre of buoyancy’) of the ship in a vertical direction opposite to that
of gravitational force (mog), which acts at a point G (known as ‘centre of
gravity’).
