Heriot-Watt University, EGIS School, Institute of Petroleum Engineering

CHAPTER 6: DRILLING

TABLE OF CONTENT

1. INTRODUCTION
2. DRILLING TECHNIQUES
3. PREPARATORY WORKS
4. RIG COMPONENTS
4.1 Power System
4.2 Hoisting System
4.3 Rotating System
4.4 Circulation System
4.4.1 Circulating Equipment
4.4.2 Circulating Fluid (Drilling Mud)
5. CASING
6. CEMENTING
7. FORMATION AND WELL PRESUURE CONTROL
8. SPECIAL DRILLING CONSIDERATIONS
8.1 Drilling Different Hole Sections
8.2 Hole Direction
8.3 Fishing
9. OFFSHORE DRILLING
10. DIRECTIONAL DRILLING
11. CORING
11.1 Coring Criteria
11.2 Coring Operating Parameters
11.2.1 Rate of Circulation
11.2.2 Rotary Speed
11.2.3 Weight on Corehead
11.2.4 Stabilisation
12. REFERNCES (AND SUGGESTED READING)

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LEARNING OUTCOMES

Having worked through this chapter the student will be able to:
• Name and describe briefly different drilling techniques.
• Have an understating of the required preparatory work prior to drilling operation.
• Name and describe briefly different rig components, i.e. the objectives of power, hoisting, rotating,
circulating and their main components.
• State different mud types, mud functions and properties required to perform its functions.
• Describe briefly casing operation and its main objectives.
• Describe briefly cementing operation and its main objectives.
• Describe briefly the kick, blow-out and lost circulation problems and ways to control them.
• Name and describe briefly different blow-out preventers.
• Name and describe briefly different hole sections requiring different drilling considerations.
• Define the under and over balance drilling including their main objectives and advantages.
• Describe briefly the term fish.
• Name and describe briefly different reasons that lead to stuck pipe and ways to fish stuck pipe.
• Describe briefly the similarities and differences between onshore and offshore drilling.
• Name different fixed and mobile offshore rig types.
• Describe briefly different reasons that lead to directional drilling.
• Describe briefly coring operation, its main objectives & criteria & different coring parameters.
• State the information that can be obtained from a core.
• Perform simple volumetric calculations on the preparation and delivery of the cement as
exemplified in the model exam and also tutorials at the end of the notes.

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 Heriot-Watt University, EGIS School, Institute of Petroleum Engineering
CHAPTER 6: DRILLING

1. INTRODUCTION
The aim of drilling a well is to provide a flow path to conduct the hydrocarbons from the reservoir
to the surface where they can be sent for processing. The drilling process today involves the
participation of a number of specialist functions, which together have enabled the depths reached to
be extended to many times the depths attained by earlier techniques. The location of the drill site is
chosen by the operating company who has the license to explore. The location is chosen by
consideration of several factors amongst which are:
• Favourable geological conditions
• Economic and legal factors - the capital to drill a well, the right to drill the site.
The sites themselves are basically onshore and offshore. There has been a development of
drilling equipment and techniques from land based sites through shallow lakes and lagoons to deep
sea locations. The wells are generally classified as exploration or development wells.
An exploration well (wildcat) is drilled with limited information on the subsurface formations or
the possible presence of hydrocarbon. It proves the presence of hydrocarbon (and information on the
geological conditions of all the strata through which the drill has passed) if it passes through a
reservoir. A development well augments the information on a reservoir, which has been found by an
exploration well. It delineates the reservoir and allows tests on the conductivity of the reservoir
formation. As development wells are drilled in areas proven by the exploration wells, the drilling
costs are reduced as full use is made of the exploration well information.

2. DRILLING TECHNIQUES
The development of modern oil well drilling started many years ago with a simple percussive
technique; i.e. Cable-tool drilling whereby a tool similar to a chisel was lowered on a cable down the
hole. Behind the chisel were weights, Figure 1. At the surface, the cable was repeatedly picked up
and released which allowed the chisel, or bit, to impact the bottom of the hole, breaking new ground.
From time to time, drilling was stopped and appropriately shaped tools lowered on the cable to pick
up the broken rock. Only shallow depths were drilled. The percussive technique and the associated
tools, although an efficient method of breaking rock, have limitations. The development of Rotary
drilling technique allowed the bit to be held on bottom and rotated, Figure 1. The rotation is imparted
from the surface by solid drill pipe, which also allows drilling mud to be pumped downhole to the
bit. The mud has several functions which enhance the drilling process, among them the ability to
remove the cut rock as drilling proceeds.

(a) (b)
Figure 1: (a) Cable tool and (b) rotary drilling.
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3. PREPARATORY WORKS
Before the final choice is made to drill a well, the operating company must review the geological
and geophysical data, the land rights, access rights to any potential site, and any environmental and
safety implications associated with a prospective site. Then the site selected must be prepared for the
drilling rig and associated equipment. Land sites are prepared according to local geographical
features (roads built, reserve pits dug for the storage of drilling mud and cuttings, etc). Offshore,
problems such as water depth, subsea features and weather are significant. Land rigs are designed to
be dismantled into sections and transported by road where possible. If roads do not exist or cannot
be built, more expensive methods of transport are used, i.e. helicopters and aeroplanes. The seasonal
climate may impose restrictions on the scheduling of drilling in that a road on frozen mud in winter
may be inaccessible in summer.
For land rigs, once on location they must be assembled. Rigging up involves reassembling the
transported sections of the rig. The substructure is positioned over the hole and assembled. It supports
the derrick, the drill pipe as it is run in and out of the hole, the draw-works which winches the drill
string, and depending on type, the engines for power. With the draw-works etc. in place the derrick
is built. Modern rigs have a mast which is not disassembled and which is merely hoisted into the
vertical. The rest of the rig is assembled including mud pumps mud tanks, shale shakers and the
electrical power and compressed air lines are hooked up.
Offshore, equipment and techniques are similar to drilling on land except for the appearance of
rigs and some specialised drilling methods to deal with the problems that marine environment
presents as discussed later in a separate section.

4. RIG COMPONENTS
Making hole with a rotary drill rig requires equipment, which can be divided into four sections:
power, hoisting, rotating and circulating.

4.1 Power System

The power system is generally a series of diesel engines with a power output of up to 300 hp.
The greater the depth required of a rig, the more power required. The transmission system is usually
electrical, but can be mechanical on older rigs. Each diesel engine is shafted to a generator. The
electrical output is switched and regulated to each of the rig components, e.g. the draw-works and
mud pumps. The system allows the diesel engines to be located farther from the rig, and also avoids
problems associated with the alignment of mechanical power systems.

4.2 Hoisting System

This comprises the draw-works, the derrick, the crown block, the travelling block and wire rope,
Figure 2. The main body of the draw-works consists of a large drum onto which is spooled one end
of the drilling line. The draw-works itself is essentially a series of winches. There are gears for speed
and direction selection and a main (a hydraulic or electric) brake to stop the drum turning. This is a
significant control mechanism used by the driller.
The drilling line is made of wire rope ranging in diameter from 1.125 to 1.5 inches in diameter.
The rope is constructed of strands of steel wire wrapped together to produce the correct combination
of flexibility and strength. The rope must be strung up to the crown block at the top of the derrick
and the travelling block to which the drill string is attached. The rope is reeved through the crown
and travelling blocks on a number of sheaves (pulleys) depending on the depth and therefore the load
expected. One end of the drilling line is wound around the draw-works and is termed the live (or fast)
line. The other end of the drilling line is passed through the drill floor to an anchor. This line is termed
the deadline and therefore, the deadline anchor. The remainder of the line is held on the spool on
which it was transported. The rope is regularly advanced off the spool, around the blocks to the draw-
works to limit the exposure of sections of the line to the combination of heavy load and flexure around
sheaves. A spring and hook are attached to the travelling block to allow the drill string to be

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suspended. Offshore, an additional piece of equipment is attached to the travelling block. This is a
motion compensator which allows the drill string to remain almost static relative to the heave of the
floating rig. It is also required when logging the hole.
The derrick, which is steel tower supporting hoisting components, must be strong enough to bear
the load of several thousands of feet of drill pipe and casing. The derricks are rated in terms of vertical
loads carried (0.25 - 1.5 million pounds) and wind speed (100 - 130 miles per hour).

Figure 2: Different components of the hoisting system.

4.3 Rotating System

Rotating Equipment consists of a swivel, the kelly, the rotary table, the drill string and the bit.
This is collectively termed the drill stem, Figure 3.
The swivel sustains the weight of the drill string, permits rotation of the string and gives a
rotating; pressure-tight seal and conduit for the drilling mud to be pumped down the inside of the
drill pipe. It is attached to the travelling block hook by a large bail.
The kelly hose is attached to the side of the swivel. The kelly is attached to the swivel. It is a
hexagonal piece of pipe, which conducts the drilling mud from the swivel to the drill pipe and imparts
rotary motion from the kelly bushing to the drill string. The master bushing sits in the rotary table
and transmits its torque through studs on the bottom of the kelly bushing to the kelly bushing. The
kelly is about 40 feet in length and is free to pass through the kelly bushing.
The rotary table is connected to an electric motor, which drives it. It accommodates the master
bushing and allows the use of slips to hold the drill pipe when making or breaking connections. The
slips is a device which essentially consists of three wedges, linked to each other, which wrap around
drill pipe and allow it to be suspended in the hole when the kelly is removed or when sections of drill
pipe are disconnected from each other, i.e. tripping in or out of the hole.
The drill string is made up of sections of drill pipe and drill collars. Both are made of steel pipe
through which mud is pumped. The drill collars are thicker and therefore more massive than drill
pipe. Drill collars are placed near the bit to supply weight to the bit and are thick enough to have the
threads cut directly onto them without the need of joints. The operating company specifies the grade
and weight of drill pipe, but the formation and other factors determine the number of drill collars to
be used. Drill pipe comes in lengths of about 30 feet. Both ends have tool joints welded to them.
These are characteristic bulges on the ends of the drill pipes. One joint has internal threads and is
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termed the box, the other end has external threads and is termed the pin. The pipe is made up by
stabbing the pin of one section into the box of the section held in the slips. Great care is taken to
maintain the integrity of the threads. The drill floor has an area beside the rotary table where stands
of drill pipe are held. A stand is usually three drill pipes connected together, which obviously means
less time spent making and breaking joints when tripping in or out of the hole.

Figure 3: Different components of the rotating system including various types of bits.

The bit is connected to the bottom of the drill string. These are complex devices, which are
designed to break rock by the most suitable method. Some rocks are brittle and break by impact, other
rocks fail by shearing. The bit must also distribute the drilling mud to cool the bit, clear the teeth of
cuttings and by design of the jet nozzles in the bit, remove the cut rock from the bottom of the hole.
The main types are roller cone, rock, and diamond bits. The roller cone and rock bits have usually
three cones fixed to the body of the bit. The design of the bearing and lubrication system of the cones
is critical to the performance of the bit in different types of formation. The cones rotate as the bit
rotates, and their azimuths are slightly offset relative to the centre of the bit. The path followed by
each cone is therefore slightly different on each rotation of the bit, ensuring that the teeth do not fall
on the same spot each time. The teeth are either cut from the steel of the cone or are buttons made of
tungsten carbide inserted into the cone. Diamond bits do not have roller cones, but are made from
several diamonds embedded into the bottom and sides of the bit. Diamond is the hardest natural
material and is therefore able to cut very hard formations.

4.4 Circulation System

Circulating system gets the mud down the hole and back to the surface. It consists of circulating
equipment and circulating fluid (drilling mud).
4.4.1 Circulating Equipment
The drilling fluid (mud) is circulated around the well by mud pumps, Figure 4. These draw mud
from the mud pits and force it through a standpipe mounted vertically on one leg of the derrick to the

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flexible kelly hose. The kelly hose is connected to the swivel and from there the mud is pumped
through the kelly, the drill string, the bit and is then forced back to the surface through the annulus
between the drill pipe and the wall of the hole.

Figure 4: Different components of the circulating system.

At the surface the mud leaves the hole through the mud return line and flows to a series of
equipment, which removes the rock cuttings. The cutting process produces cuttings which have a
wide range of sizes, therefore different principles of removing the material must be used.
The first piece of equipment is the shale shaker, which has series of vibrating screens to separate
the largest sizes of cuttings. Onshore the cuttings go to the reserve pits and the mud continues on its
cleaning cycle. Offshore, the cuttings are dumped in the sea or may be dumped on a barge for
transport to a land site for disposal.
The mud may go straight back to the mud pits, ready to be pumped around the wellbore again,
but usually, further beneficiation is required to bring the mud back to the required standard for
optimum performance. Usually desanders and desilters are installed in the flow train to remove sand
and silt sized particles, which alter the flow characteristics of the mud and which erode downhole
equipment. These pieces of equipment operate on the principle of the cyclone using the difference in
centrifugal forces to separate particles of different masses. There may be other pieces of equipment,
which essentially remove finer and finer particles. There is an optimum setting, since the material
specifically added to the mud will start to be removed and lost. It is also important to remove any
small amounts of gas, which may have entered the mud from the formation, using the degasser. The
gas decreases the density of the mud, therefore the pressure exerted by it and could lead a kick, which
refers to flow of formation fluid into the wellbore whenever hydrostatic pressure of mud falls below
formation pressure.
The mud is kept mixed in the mud pits by agitators, and there are flow loops to hoppers where
solids may be added to the mud. Large quantities of the mud constituents are held in dry conditions
in the mud house. The mud is made up and conditioned for several hours before being used for
drilling. The properties are continually assessed by analysing samples of mud in the mud laboratory.
The density (usually expressed in pounds per gallon), pH, filter volume, cation exchange capacity,
viscosity, yield point etc. are measured and reported. During drilling, the mud is also checked
regularly at less frequent intervals.
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4.4.2 Circulating Fluid (Drilling Mud)
Drilling fluid (mud), is a mixture of water or oil with clay, weighting material and quantities of
chemicals to alter some of its properties including the compatibility of the mud and the formation.
The mud serves as a transport medium to carry the rock cuttings to the surface. It cools, cleans
and lubricates the bit and provides a back pressure against the pressure of the formation fluids.
Sometimes it is used for powering the drill bit (turbine drilling).
The column of mud should exert an appropriate fluid pressure against the side of the hole and
the fluid within the formation. In other words, the well is drilled with a slight overbalance pressure,
compared to the formation pressure, to ensure that no formation fluids are allowed to flow out of the
formation. Therefore, the mud density is adjusted by adding quantities of weighting materials, usually
barite to ensure the required over-balance is achieved. This overbalance also means that the drilling
mud flows into the formation. Clay is, hence, added to the mud that allows the formation of a mud
cake on the well wall. The development of a mud cake reduces the mud invasion into the formation
and also provides stability to the sides of the hole.
The mud should have an optimum viscosity that is high enough to transfer cuttings but also
pumpable with reasonable pressure drop, filtration rate that ensures formation of an efficient wall
cake and gelling that avoids suspended materials settling out. The mud should be stable at both high
pressure-high temperature bottom hole and surface conditions. The mud is designed to optimize the
drilling process, taking account of these many functions expected of it.
Water based muds could affect the stability of certain clay minerals within the shales, causing
them to expand and break off into the hole, which cause problems. This can largely be alleviated
using the oil based mud or very rarely synthetic mud fluids. However, there are greater environmental
problems with these systems, which are also very expensive, especially noting that large quantity of
mud is required. The mud type would vary during the drilling of a hole. For example, waterbased
mud maybe used to drill the initial sections of the hole, and then oil based mud is used for the
remaining reservoir section. The mud constituents may be changed as unforeseen problems are
encountered downhole, or as the formation changes.

5. CASING
Normal drilling operations involve keeping a sharp bit on bottom and drilling as efficiently as
possible; adding new joints of pipe as the hole deepens; tripping the drill string out of and into the
hole to change drill bits and running casing and cementing. In drilling, the following typical
procedures are followed: Enough collars and drill pipes are made up and lowered in until the bit is
almost to bottom. The kelly is made up and the mud pumps and rotary table are started and the driller
slowly releases the brake of the draw-works to lower the rotating string to the bottom of the hole.
The driller continues to lower the string to develop the appropriate amount of weight on the bit for
drilling. A weight indicator shows the total weight of the string, and by reference to it, the amount by
which it is reduced is the amount supported by the bit. Constant use of the brake lowers the drill
string to maintain the weight on the bit as drilling proceeds and the hole becomes deeper..
The hole, which is drilled is successively lined with protective steel tubes (casing), set at certain
depths. In other words, after reaching to a certain depth, the next operation is to set a casing. Casing
are usually applied to achieve the following main objectives: it prevents
• collapse of the wellbore during drilling
• the flow of formation fluid into the wellbore
• The excessive flow of mud into the formation (i.e. lost circulation)
Casing sometimes serves other purposes such as acting as a flow conduit for non-corrosive fluids
and a support for other equipment e.g. blow-out preventers, subsequent casing strings.
Casing basically involves setting large diameter pipes (Figure 5a), using special elevators, slips
and casing tongs. Before placing the casing, each section is measured and the internal diameter and
threads are checked. The bottom of the casing has a guide shoe fitted to allow easy passage down the
well. Two or three joints from the bottom, a float collar is fitted. This is a valve to prevent back flow

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of cement once it has been placed around the outside of the casing. Attached to the outside of the
casing joints are centralizers and scratchers. The scratchers remove mud cake from the wall of the
hole as the casing is run in to make a good bond with the hole and the cement.
Sometimes a liner instead of a casing is put in place especially when reaching to the productive
formation. Liners are suspended from the bottom of the previous casing and do not extend to the
surface. Thus they are less expensive than a full string of casing back to the surface.

(a) (b)
Figure 5: (a) Casing and (b) cementing.

6. CEMENTING
The next operation is cementing (Figure 5b) the casing. In addition to providing axial support
for the casing, cementing protect casing from corrosion by formation fluids, prevents fluid movement
through the annular space between the formation and casing from one formation into another and
close an abandoned portion of the well. There are different classes of cements depending on the
operating conditions and formation depth. Bulk cement is held in tanks and mixed with water and
additives to check the setting time. Special cement pumps pump the cement slurry to the cementing
head. This is a valve assembly, which incorporates two plugs. The bottom plug is released to travel
in front of the cement. A top plug is released after the volume of cement has been pumped, and this
separates the cement from the drilling mud which follows. The bottom plugs seats on the float collar
and a passageway opens through it by the pressure in the following cement. Thus the cement is
pumped through the plug and up the annulus. The top plug bumps the bottom and an increase in
pressure indicates that the pumps should be shut down. The top plug ensures the dense cement slurry
does not U tube back up the drill pipe. Several hours are allowed for the cement to gain sufficient
strength to allow drilling to continue. The cement is designed based on the information gained during
drilling. Quality assurance tests are done on the cement, additives and makeup water. When hardened,
tests may be done to ensure a good cement job.
The next bit to be run must pass through the newly set casing. It is made up as before with the
appropriate drill collars, however, the drill string must be tripped into the hole to get to the bottom.
If the bit must be changed, a round trip must be made to pull the drill string, change the bit and run
the drill string back in the hole. Depending on the casing program design, several strings of casing
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may be run before the final casing through the reservoir is set. The setting procedures are the same.
Throughout the drilling process, a mud logger records various parameters. These include the
standpipe pressure, the gas cut of the mud, the weight-on-bit, the torque, penetration rate, etc. These
data are of use in determining the efficiency of the drilling process. The cuttings from the shale shaker
are also examined for traces of oil (the oil reacts to ultraviolet light). The cuttings are also used to
produce geological logs of the formations. In development wells, the well may be cored in sections
to provide large samples for further laboratory analysis. Between bit runs, the well is also be logged
as described in the logging chapter. This information is used by the operator to decide if the well is
tested for hydrocarbons. A useful technique is the drill stem test. This involves a special tool run on
the end of the drillpipe. The tool has the ability to set a rubber packer against the hole thereby sealing
the drillpipe from the annulus. Valves within the tool allow the mud to be displaced and the formation
to flow up the drill pipe to the surface. Pressure gauges on the tool record the bottom hole pressure
continuously when the formation flows and when it is shut in. Analysis of the pressure record can
determine the amount of oil and the permeability of the formation. The produced fluids are metered
at the surface. The oil produced are flared through flare booms.

7. FORMATION AND WELL PRESUURE CONTROL

When formation fluid enters the hole, it is termed a kick, which is undesirable. If no action is
taken, the formation fluid rises to the surface and expands as the hydrostatic pressure drops,
producing large volumes of gas and/or oil, which can wreck the rig, and if it is gas, will probably
explode, which is termed as blow out. The kick produces anomalies in the normal circulating system,
such as mud pit levels greater than normal or flowing mud even when the pumps are shut down,
although these anomalies are not always readily detectable. The mud is the first line of defense
especially against kicks by changing the density of mud.
As mentioned earlier, blowouts represent complete loss of control of the well, and the greatest
effort is involved in designing the drilling program to minimize their occurrence. Remotely controlled
valves termed blowout preventers are placed that are closed to contain the fluid in the well. They
provide a pressure tight seal and are regularly tested during the drilling program. On land rigs and
platforms, these are located at the top of the well beneath the rig floor. On floating rigs the blowout
preventers are attached to the well on the sea floor.
Two basic types of blowout preventers are annular and ram. Usually the annular preventer is
located above two or three ram preventers which constitute the BOP stack. The annular preventer
seals the annulus between the drill pipe or kelly and the hole. It can also seal off an open hole. The
seal is provided by a very stiff annulus of rubber, which is deformed by a ram such that the internal
faces of the annulus meet and seal.
Ram type preventers are made to seal either against themselves, when there is no drill string or
other tubing (blind rams), or against drill pipe (pipe rams) restricting flow in the annulus between the
outside of the drill pipe and wellbore. These rams are large blocks of steel with rubber face which
are forced against each other or against the pipe. The rubber faces deform and seal the pipe. Other
rams (shear rams) completely block the hole by shearing through any pipe in the hole.
Two lines called the choke and kill lines are connected to the hole via the BOP stack. They are
used to displace the formation fluid from the well once control has been regained by the use of the
BOP. The choke line is controlled by a choke manifold on the rig. This allows the kick to be circulated
out by pumping heavy mud downhole, while controlling the flow rate of the return mud and kick to
maintain enough back pressure to prevent further entry of formation fluid.
A condition that large quantities of mud are lost to a formation that contains caverns or fissures
or is coarsely permeable is termed as lost circulation. Loss of mud lowers the pressure in the hole,
which could allow the formation pressure to overcome the mud pressure. Drillers can drill this kind
of formation by controlling mud properties to have a better mud cake but may want to case off and
cement so that they do not cause problem later.

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8. SPECIAL DRILLING CONSIDERATIONS
8.1 Drilling Different Hole Sections
The sections of hole must successively be of smaller and smaller diameter to allow the bit to pass
through the cased sections. The first section of hole is large in diameter and is usually lined with
conductor pipe of typically 30" diameter. After the conductor or 30 inch casing has been set, a bit of
smaller diameter (typically 17.5 inch) is used to fit through the 30 inch casing and so on.
Usually three hole sections are identified, i.e. top, intermediate (middle) and reservoir. Rate of
penetration is usually high at the top hole section as it deals with unconsolidated sediments. A surface
casing is cemented to prevent the hole collapse and protect flow from shallow aquifers. Rate of
penetration is usually lower for the intermediate hole as it deals with consolidated rocks. An
intermediate casing is usually set above the reservoir to prevent hole collapse, fluid flow (water) from
formation and lost circulation. Drilling the reservoir section is the prime objective, so great care
should be taken to minimise the formation damage for instance by using oil based mud and under
pressure drilling. That is, it was mentioned above that usually the mud is water based, which when
invades the formation could react with formation rock and reduce its ability to flow. The flow of mud
into the formation happens as mud pressure is kept slightly above the formation pressure during over-
balance drilling to minimize the risk of flow of formation fluid into the wellbore, which could lead
to losing the well due to blowout. However, when drilling the reservoir section, the mud pressure is
kept slightly lower than formation pressure. This under-balance drilling operation is planned mostly
for production wells of a developed field with known pressure and minimum risk of losing the well
due to unexpected high flow rate of formation fluid into the wellbore.

8.2 Hole Direction

Generally, the shortest distance between two points is a straight line; any variation from this line
will cost more in terms of time and materials. If deviation is severe and/or sudden, it can lead to
expensive time consuming problems. In other words, unless directional drilling that is described in
the next section is not planned, for exploration, appraisal and producing wells on land, straight holes
are usually called for. However, all holes are deviated to some extent, i.e. there is no such a thing as
a ‘straight hole’. The contract could involve penalties if overall deviation excess 3° - 5°. Deviation
per 1,000’ is sometimes specified, this Figure being allowed to increase as the target depth is
approached. In other words, the operator wants to keep the hole as straight as possible for various
reasons, which eventually come down to economy.
The deeper the formation, the harder the rock is likely to be, so for optimum penetration heavier
weights on bit must be utilised, however, this will increase the tendency to deviate. The operator is
placed in a dilemma - should he decrease the weight on bit, which in turn would decrease the
deviation and rate of penetration thus increase completion time and total costs - or should he increase
the weight on bit, and run the risk of high deviations. The latter decision is favoured by the fact that
deviation near the bottom of the well causes less problems than deviation at the top. The formation
dip also affects hole deviation especially when where the structures are hard, at high angle and of
different composition from layer to layer. Where these conditions are present, the bit tend to drill ‘up
dip’ and hence the surface location is situated ‘down dip’.
The bending characteristics of the bottom hole assembly obviously have the biggest effect on the
‘straightness’ of the hole. Bending characteristics are affected by, weight on bit and drill collar
diameter. If drill collars were the same size as the hole, no deviation problem would occur. We have
to get as near as possible to this situation, without affecting the annular velocity too drastically.
Relatively large diameter collars for hole size - in some cases square drill collars and stabilisers are
used to reduce bending characteristics or ‘stiffen up the bottom hole assembly’.
To sum up; to keep deviation to a minimum the correct balance of weight on bit and stabiliser
placement must be used for each formation angle. Field experiments have proved the most effective
combinations and tables are available in the toolpushers manual giving this information.

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8.3 Fishing
A fish can be anything from part or all of the drill stem stuck or lost in the hole to small pieces
of equipment (junk), such as bit cones, hand tools, pieces of steel, or any other item that can not be
drilled out. One of major issues is stuck pipe, which can occur due to (i) Collapse or deformation of
the borehole. Shale or clay can suck water of the mud and expand into the hole. Debris can also fill
the hole leading to a stuck pipe. (ii) Excessive pressure differential. In this case, mud pressure is
much higher than formation pressure, creating thick mud cake and when the drill stem is not rotating
(e.g. when a connection is being made) it may rests against one side, the mud pressure force it into
the thick cake jamming the drilling stem. (iii) Dogleg or key seat. A key seat is a small side hole
created during rotation of the drill pipe as it leans against the side of dogleg. When the drill stem is
pulled out wider section of drill pipe can jam into this side hole. Several simple and then sophisticated
methods are used to fish the stuck pipe. These include circulating lubricant (spot oil), Striking very
heavy upward or downward blow on the stuck pipe with a special device (Jar the drill stem) and
application of explosive charge to bang the stuck pipe (String shot).

9. OFFSHORE DRILLING
Offshore, equipment and techniques are similar to drilling on land except for the appearance of
rigs and some specialised drilling methods to deal with the marine environment problems.
Offshore the choice of rig depends, in general if it is an exploration or development well. Due to
high risk and cost of fixed platforms, they are usually used for development wells. Fixed platforms
are fixed to the sea floor bottom and divided into Rigid and Compliant platforms. These massive
structures are built onshore and are floated out to location and anchored to the sea bed. In North Sea
they have been incorporated with the production facilities, but sometimes development wells are
drilled by floating rigs before the production platform is installed.
Mobile rigs are divided into Bottom-supported units and Floating units. A part of the structure
the bottom-supported units is in contact with the sea floor, and sub-divided into Submersibles and
Jackups. The Floating units, floats on or slightly below the water’s surface and sub-divided into Drill
ships, Ship-shaped barges, and Semisubmersibles.

10. DIRECTIONAL DRILLING

Sometime it is desirable to design and control the inclination and azimuth of the drill bit to
achieve deviated wells, Figure 6. There are microelectronics sensors, which transmit information on
the bit direction (and other information) as the bit cuts through the rocks. The information is used to
alter the weight on bit to change the inclination of the drilling assembly. Deviated holes are started
by the use of special substitute drill pipe with small bends in them. Below the bent subs, mud motors
use the power of the circulating mud to rotate the drilling assembly, while the rest of the drill string
remains stationary. This forces the bit to drill away from the vertical to "bend" the hole towards a
pre-set target. Deviated wells are usually drilled from fixed platforms where some sort of spread of
the wells is needed to penetrate the reservoir over all of its areal extent.
Directional drilling is particular attractive in offshore environment because it allows drilling
from an offshore production platform, Figure 6a, to make the operation more economic as offshore
drilling cost including transportation are considerably higher. In such cases, directional drilling can
also reduce the risk of oil spills and save local fishing industry (especially if drilled from land),.
Deviated wells may also be necessary in other situations (Figure 6b) when:
• Local conditions dictate that the rig cannot be sited directly above the target (A, B).
• Straight hole misses the reservoir (D, E, C).
• Drilling through a fault plane would create a risk of the formation slipping thereby
shearing casing or otherwise causing damage (C).
• Drilling a relief well to control a blowout (F).
• Deviating around a salt done to eliminate expensive mud and hole problems (H).

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 Institute of Petroleum Engineering
• It is impossible to drill ahead because of fish in the hole, and too expensive to respond,
the well is ‘side-tracked’.
• Increasing the recovery due to better reservoir reach and larger contact area. In this
context, horizontal wells are of particular interest especially for exploitation of very low
permeability unconventional assets.
The main considerations are how to force the bit to build an angle, choice of a suitable mud as
longer wells require less viscous mud (reduce pressure drop) and selection of proper drill pipe as
lighter but more rigid drill pipes are to needed to avoid buckling due to weight and angle.

(a) (b)
Figure 6: Directional drilling.

11. CORING
The best source of geological information is found from cutting and retrieving from the well a
vertically continuous column of the rock. Provided good recovery of the core is made accurate
geological correlation and reservoir data can be derived such as porosity, permeability, fluid type and
saturation, accurate rock description (e.g. lithology). The core can also be used to perform tests to
determine recovery factor, core computability with injection fluids and etc.

(a) (b)
Figure 7: (a) coring assembly and (b) cylindrical cores sections.
The basic coring operation involves drilling out of a cylinder of rock using a special assembly
comprising a corehead (Figure 7a), and a hollow core barrel, which accepts and retains the cylinder
core for retrieval at surface. Core bit can be visualised as a hollow cylinder with cutters on outside,
which cut a groove into the formation, intact cylinder of the rock moves into the inner core barrel as
coring process progresses. After completion of coring, the core is locked inside the core barrel and
brought to the surface for analysis in the laboratory. Core diameters vary between 3” to 7” in diameter

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 Chapter 7: Drilling
and 25 to 60 ft in length (Figure 7b) but Smaller plugs (1-2” diameter) are cut for core analysis. Cost
of coring consists of equipment, rig time and follow up investigation in laboratory.

11.1 Coring Criteria

The decision to pull a bit and run a core barrel will be generally governed by criteria given in the
drilling program. Some of the interia are specific and some leave room for a judgement to be made
on the wellsite. Some of the criteria are:
• Specific depth given by geological prognosis for the well.
• Increase in penetration rate indicating the top of a porous reservoir zone which is to be cored.
• Hydrocarbon indications either from the cuttings fluorescence and oil or gas cut mud.
• Cuttings show the transition from a cap rock say to a reservoir rock, e.g. anhydrite to limestone.
It should be noted that sometimes this is not easy to recognize, e.g. when using diamond drilling
with a turbine where the cuttings are finely ground.

11.2 Coring Operating Parameters

11.2.1 Rate of Circulation
The circulation rate of the fluid is important not only to provide cooling and lubrication of the
corehead but also to clean the face of the corehead and prevent cuttings settling in the annulus. Low
circulation rates will cause inadequate cleaning and cooling which may result in low penetration rates
or burning of the diamonds. High rates will cause excessive annular velocities and may cause the bit
to lift and bounce on the bottom of the hole. It also depends on the weight of the mud, i.e. for the
same prevailing conditions, higher mud weight results in/requires lower rate of circulation.

11.2.2 Rotary Speed

In general, penetration rate increases as a straight line function with increasing rotary spedd in
round per minute (RPM). However, uneven operation in certain formations due to high torque
created for example in sticky shales can often reduce penetration rate. Coreheads are generally
operated with lower RPM than the corresponding diamond bit to avoid damaging the core.

11.2.3 Weight on Corehead

Bit should have appropriate contact with the formation to achieve the maximum (optimum)
penetration rate without damaging the core. The maximum penetration is achieved by maintaining
the diamond stones in contact with the formation. However, the drill string should always be
maintained in tension.

11.2.4 Stabilisation
It is essential to correctly stabilise a core barrel to provide sufficient rigidity to the string and
eliminate ‘whipping’ or cyclical stress during rotation. The following advantages accrue from using
a properly stabilised string. 1. faster penetration rate. 2. reduced shock loading on corehead face and
reduced diamond costs. 3. improved core recovery. 4. reduced possibility of core barrel failure.

12. REFERNCES (AND SUGGESTED READING)

1. Dyke, K. V.: “Fundamental of Petroleum”, Univ of Texas at Austin Petroleum, 4th edition,
Jun. 1997. Some of the Figures are taken from this book.

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