Introduction The Origins, Migration and Trapping of Petroleum and Exploring For It Introduction 1.1 Revision No: A-0 / Revision Date: 03·31·98 CHAPTER 1 …the word “petroleum” is derived from the Latin words for “rock” (petra) and “oil” (oleum)… THE ORIGIN OF PETROLEUM During certain geologic ages, when the climate was suitable, petroleum began as organic material derived from plants and animals which grew in abundance. As these organisms went through their cycles of growing and dying, buried organic material slowly decayed and became our present-day fossil fuels: oil, gas, coal and bitumen. Oil, gas and bitu- men were dispersed in the sediments (usually clay-rich shales). Over millions of years, these organic-laden shales expelled their oil and gas under tremen- dous pressures from the overburden. The oil and gas migrated into permeable strata below or above them, then migrated further into traps that we now call reservoirs. It’s interesting to note that the word “petroleum” is derived from the Latin words for “rock” (petra) and “oil” (oleum), indicating that its origins lie within the rocks that make up the earth’s crust. These ancient petroleum hydrocar- bons are complex mixtures and exist in a range of physical forms — gas mix- tures, oils ranging from thin to viscous, semi-solids and solids. Gases may be found alone or mixed with the oils. Liquids (oils) range in color from clear to black. The semi-solid hydrocarbons are sticky and black (tars). The solid forms are usually mined as coal, tar sand or natural asphalt such as gilsonite. As the name “hydrocarbon” implies, petroleum is comprised of carbon atoms and hydrogen atoms bonded together; the carbon has four bonds and the hydrogen has one. The sim- plest hydrocarbon is methane gas (CH 4 ). The more complex hydrocar- bons have intricate structures, consist- ing of multiple carbon-hydrogen rings with carbon-hydrogen side chains. There are often traces of sulfur, nitrogen and other elements in the structure of the heavier hydrocarbons. THE MIGRATION AND TRAPPING OF PETROLEUM Sedimentary rocks. Oil is seldom found in commercial amounts in the source rock where it was formed. Rather, it will be found nearby, in reservoir rock. These are normally “sedimentary” rocks — layered rock bodies formed in ancient, shallow seas by silt and sand from rivers. Sandstone is the most common of the sedimen- tary rock types. Between the sand grains that make up a sandstone rock body there is space originally filled with seawater. When pores are inter- connected, the rock is permeable and fluids can flow by gravity or pressure through the rock body. The seawater that once filled the pore space is par- tially displaced by oil and gas that was squeezed from the source rock into the sandstone. Some water remains in the pore space, coating the sand grains. This is called the reservoir’s connate water. Oil and gas can migrate through the pores as long as enough gravity or pressure forces exist to move it or until the flow path is blocked. A blockage is referred to as a trap. Carbonate rock, limestones (calcium carbonate) and dolomites (calcium- magnesium carbonate) are sedimentary rocks and are some of the most com- mon petroleum reservoirs. Carbonate reservoirs were formed from ancient coral reefs and algae mounds that grew in ancient, shallow seas. Organic-rich source rocks were also in proximity to supply oil and gas to these reservoir rocks. Most limestone strata do not have a matrix that makes them per- meable enough for oil and gas to migrate through them. However, many limestone reservoirs contain
1. Introduction The Origins, Migration and Trapping of
Petroleum and Exploring For It Introduction 1.1 Revision No: A-0 /
Revision Date: 033198 CHAPTER 1 the word petroleum is derived from
the Latin words for rock (petra) and oil (oleum) THE ORIGIN OF
PETROLEUM During certain geologic ages, when the climate was
suitable, petroleum began as organic material derived from plants
and animals which grew in abundance. As these organisms went
through their cycles of growing and dying, buried organic material
slowly decayed and became our present-day fossil fuels: oil, gas,
coal and bitumen. Oil, gas and bitu- men were dispersed in the
sediments (usually clay-rich shales). Over millions of years, these
organic-laden shales expelled their oil and gas under tremen- dous
pressures from the overburden. The oil and gas migrated into
permeable strata below or above them, then migrated further into
traps that we now call reservoirs. Its interesting to note that the
word petroleum is derived from the Latin words for rock (petra) and
oil (oleum), indicating that its origins lie within the rocks that
make up the earths crust. These ancient petroleum hydrocar- bons
are complex mixtures and exist in a range of physical forms gas
mix- tures, oils ranging from thin to viscous, semi-solids and
solids. Gases may be found alone or mixed with the oils. Liquids
(oils) range in color from clear to black. The semi-solid
hydrocarbons are sticky and black (tars). The solid forms are
usually mined as coal, tar sand or natural asphalt such as
gilsonite. As the name hydrocarbon implies, petroleum is comprised
of carbon atoms and hydrogen atoms bonded together; the carbon has
four bonds and the hydrogen has one. The sim- plest hydrocarbon is
methane gas (CH4). The more complex hydrocar- bons have intricate
structures, consist- ing of multiple carbon-hydrogen rings with
carbon-hydrogen side chains. There are often traces of sulfur,
nitrogen and other elements in the structure of the heavier
hydrocarbons. THE MIGRATION AND TRAPPING OF PETROLEUM Sedimentary
rocks. Oil is seldom found in commercial amounts in the source rock
where it was formed. Rather, it will be found nearby, in reservoir
rock. These are normally sedimentary rocks layered rock bodies
formed in ancient, shallow seas by silt and sand from rivers.
Sandstone is the most common of the sedimen- tary rock types.
Between the sand grains that make up a sandstone rock body there is
space originally filled with seawater. When pores are inter-
connected, the rock is permeable and fluids can flow by gravity or
pressure through the rock body. The seawater that once filled the
pore space is par- tially displaced by oil and gas that was
squeezed from the source rock into the sandstone. Some water
remains in the pore space, coating the sand grains. This is called
the reservoirs connate water. Oil and gas can migrate through the
pores as long as enough gravity or pressure forces exist to move it
or until the flow path is blocked. A blockage is referred to as a
trap. Carbonate rock, limestones (calcium carbonate) and dolomites
(calcium- magnesium carbonate) are sedimentary rocks and are some
of the most com- mon petroleum reservoirs. Carbonate reservoirs
were formed from ancient coral reefs and algae mounds that grew in
ancient, shallow seas. Organic-rich source rocks were also in
proximity to supply oil and gas to these reservoir rocks. Most
limestone strata do not have a matrix that makes them per- meable
enough for oil and gas to migrate through them. However, many
limestone reservoirs contain
2. Introduction CHAPTER 1 Introduction 1.2 Revision No: A-0 /
Revision Date: 033198 fracture systems and/or interconnect- ing
vugs (cavities formed when acidic water dissolved some of the
carbon- ate). These fractures and vugs, created after deposition,
provide the porosity and permeability essential for oil to migrate
and be trapped. Another car- bonate rock, dolomite, exhibits matrix
permeability that allows fluid migra- tion and entrapment.
Dolomites also can have fracture and vugular porosity, making
dolomite structures attractive candidates for oil deposits. Salt
domes. A significant portion of oil and gas production is
associated with salt domes which are predomi- nately classified as
piercement-type salt intrusions and often mushroom shaped.
Piercement-type domes were formed by the plastic movement of salt
rising upward through more dense sediments by buoyant forces
resulting from the difference in density. The sur- rounding strata
(sand, shale and car- bonate) is deformed by this upward intrusion
of salt forming stratigraphic and structural traps (see Figure 2c).
These traps are formed around the flanks and under the overhang of
salt domes in the sandstone layers that were faulted and folded by
the movement of the salt. Being impermeable to oil and gas, salt
forms an excellent barrier for the accumulation of hydrocarbons.
Salt layers. Major oil and gas reser- voirs have been found in
recent years beneath horizontal salt beds. Until recently, it was a
mystery what was beneath these extruded salt layers called salt
sills, salt sheets and salt lenses. They could not be explored
economically by drilling, and seismic interpretation through
plastic salt was unreliable. Now, sub-salt formations can be
evaluated through modern three-dimensional seismic analysis to
identify potential reservoirs. Once likely formations are located,
wells are drilled through the salt layer to determine if oil and
gas deposits exist. Traps. Oil, gas and water slowly migrate
through permeable rocks, dri- ven by natural forces of gravity
(buoy- ancy) and pressure gradients. When they meet an impermeable
barrier, they can go no farther, so oil and gas accu- mulate. This
barrier is generally referred to as a trap. Varying densities make
the gas phase rise, while the water settles to the lowest point,
and the oil remains in the middle. Traps are categorized as
structural or stratigraphic. Structural traps result from a local
deformation such as folding and/or faulting of the rock layers.
Examples of structural barriers are anticline traps, fault traps
and traps associated with salt domes (see Figures 1a, 1b and 2c).
Stratigraphic traps are formed by geo- logical processes other than
structural deformation and relate to variations in rock properties
(lithology). The remains of an ancient limestone or dolomite coral
reef buried by impervious sedi- ments is an example. An ancient,
Structural Traps Figure 1a: Anticlinal trap. Figure 1b: Fault trap.
oil and gas accumulate in traps Formation containing saltwater
Formation containing saltwater Formation containing saltwater Sand
Clay or Limestone Oil Gas Saltwater shale Formation containing oil
Formation containing gas Formation containing oil Sand Clay or
Limestone Oil Gas Saltwater shale _______________________
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3. Introduction Introduction 1.3 Revision No: A-0 / Revision
Date: 033198 CHAPTER 1 sand-filled river bed that has been silted
out by clay is another type of stratigraphic trap. Sedimentary
layers may change laterally in lithology or may die out and
reappear elsewhere as a different rock type. Such changes can cause
a lateral decrease in porosity and permeability, creating a trap
(see Figure 2a). Another type of stratigraphic trap is an
unconformity. Unconformities occur where a succession of rock
strata, including the future oil reservoir, have been uplifted,
tilted, eroded and are subsequently overlain by sediments which
form an impermeable barrier. An unconformity represents a break in
the geologic time scale (see Figure 2b). EXPLORING FOR PETROLEUM
Locating petroleum: Knowing that petroleum traps exist is one
thing, but pinpointing traps far below the earths surface is quite
another. Then determining the likelihood of oil and gas in the
trapped region is yet another concern. Many methods have been used
to locate petroleum traps, but the most important methods are
aerial sur- veying, geological exploration, geo- physical (seismic)
exploration and exploratory drilling. Aerial and satellite. Surveys
from high altitudes give a broad picture of a geographic area of
interest. Major sur- face structures such as anticlines and faulted
regions can be clearly observed by these methods. This information
determining the likelihood of oil and gas in the trapped region
Figure 2c: Typical salt structure development (from Geology of
Petroleum, A. I. Levorson). Stratigraphic Traps Figure 2a:
Stratigraphic trap. Organic reef embedded in shale and wedging out
sand. Figure 2b: Unconformity trap. _______________________
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_______________________ _______________________ Formation
containing saltwater Formation containing oil Formation containing
saltwater Formation containing saltwater Formation containing
saltwater Formation containing oil Formation containing oil
Formation containing saltwater Formation containing oil Formation
containing oil Formation containing saltwater Surface Salt Surface
Salt Surface Salt Sand Clay or Limestone Oil Gas Saltwater shale
Sand Clay or Limestone Oil Gas Saltwater shale
4. Introduction CHAPTER 1 Introduction 1.4 Revision No: A-0 /
Revision Date: 033198 helps locate areas where more detailed study
is warranted. In the early years of petroleum exploration,
visualiza- tion from an aircraft or mapping river and creek
drainage patterns were suc- cessful surveying techniques. Modern
aerial and satellite surveying is more sophisticated allowing a
number of features to be evaluated, including thermal anomalies,
density variations, mineral composition, oil seepage and many
others. Surface geological exploration. Observations by trained
geologists of rock outcrops (where subsurface layers reach the
surface), road cuts and canyon walls can identify lithol- ogy and
assess the potential for hydro- carbon source rocks,
reservoir-quality rocks and trapping mechanisms in an area under
study. Much has been learned about ancient deposits from studying
modern river deltas, for exam- ple. Detailed geologic maps, made
from these observations, show the position and shape of the
geologic features and provide descriptions of the physical
characteristics and fossil content of the strata. Geophysical
exploration. Through the use of sensitive equipment and analytical
techniques, geophysicists learn a great deal about the subsurface.
Chief among these techniques is seis- mic exploration in which
shock waves, generated at the surface and aimed downwards, are
reflected back to the surface as echoes off the strata below.
Because rocks of varying density and hardness reflect the shock
waves at dif- ferent rates of speed, the seismologist can determine
depth, thickness and type of rock by precisely recording the
variances in the time it takes the waves to arrive back at the
surface. Modern 3-D seismic has improved the success rate of the
exploration process, espe- cially in areas beneath salt, as
discussed above. Continual improvements in seismic measurement and
the mathe- matical methods (algorithms) used to interpret the
signals can now give a clearer picture of subsurface forma- tions.
Other geophysical methods use variations in the earths gravity and
magnetic properties to detect gross features of subsurface
formations. seismic exploration in which shock waves DRILLING
METHODS When it has been established that a petroleum reservoir
probably exists, the only way to verify this is to drill. Drilling
for natural resources is not a new idea. As early as 1100 A.D.,
brine wells as deep as 3,500 ft were drilled in China, using
methods similar to cable tool drilling. Cable tool drilling. This
was the method used by pioneer wildcatters in the nineteenth and
early twentieth cen- turies and is still used today for some
shallow wells. The method employs a heavy steel drill stem with a
bit at the bottom, suspended from a cable. The tool is lifted and
dropped repeatedly. The falling steel mass above the bit provides
energy to break up the rock, pounding a hole through it. The hole
is kept empty, except for some water at the bottom. After drilling
a few feet, the drill stem (with its bit) is pulled out and the
cuttings are removed with a bailer (an open tube with a valve at
the bot- tom). The cable tool method is simple, but it is effective
only for shallow wells. Progress is slow because of the ineffi-
ciency of the bit and the need to pull the tools frequently to bail
out cuttings. Drilling for Petroleum _______________________
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6. Introduction CHAPTER 1 Introduction 1.6 Revision No: A-0 /
Revision Date: 033198 Rotary drilling. Rotary rigs are used for a
variety of purposes drilling oil, gas, water, geothermal and
petroleum- storage wells; mineral assay coring; and mining and
construction projects. The most significant application, however,
is oil and gas drilling. In the rotary method (introduced to oil
and gas drilling in about 1900), the drill bit is suspended on the
end of a tubular drillstring (drill stem) which is supported on a
cable/ pulley system held up by a derrick (see Figure 3). Drilling
takes place when the drillstring and bit are rotated while the
weight of the drill collars and bit bears down on the rock. To keep
the bit cool and lubricated, and to remove the rock cuttings from
the hole, drilling fluid (mud) is pumped down the inside of the
drillstring. When it reaches the bit, it passes through nozzles in
the bit, impacts the bottom of the hole and then moves upward in
the annulus (the space between the drillstring and the wellbore
wall) with the cuttings suspended in it. At the sur- face, the mud
is filtered through screens and other devices that remove the cut-
tings, and is then pumped back into the hole. Drilling mud
circulation brought efficiency to rotary drilling that was missing
from cable tool drilling the ability to remove cuttings from the
hole without making a trip to the surface. Equipment for rotary
drilling is illustrated in Figure 3. DRILL BITS A good place to
begin the description of rotary drilling equipment is where the
action takes place at the drill bit. As it rotates under the weight
of the drill- string, the bit breaks up or scrapes away the rock
beneath it. Early rotary bits were drag bits because they scraped
at the rock. Because they resembled the tail of a fish, they earned
the name fishtail bits. They were effective in drilling soft
formations, but their blades wore out quickly in hard rock. An
improved rotary bit was needed and in the early 1900s, the roller
cone bit was introduced. Roller cone (rock) bits. A roller cone bit
also known as a rock bit has either two or three cone-shaped
cutters that roll along as the bit is turned. The surface of the
rolling cone has teeth that contact most of the hole bottom as the
cones roll over the surface (see Figure 4a). These bits drill by
fracturing hard rock and by gouging softer rock. There is also some
scraping action because the cones axes are off-center compared to
the center of rotation. Weight on the bit, rotational speed, rock
hardness, differential pressure, and drilling fluid velocity and
viscosity affect how fast bits drill. Nozzles in the bits body give
the mud extra velocity, creating a jetting action as it exits
through the bit. This contributes to faster drilling. Rock bits are
classified according to the types of bearings and teeth they have.
Bearing types include (1) non- sealed roller bearings, (2) sealed
roller bearings and (3) journal bearings. When referring to bits by
the type of teeth they have, the terms: (1) milled tooth and (2)
Tungsten Carbide Insert (TCI) are used. Bearing design is important
to a bits service life; sealed bearings and journal bearings
provide longer life than unsealed bearings, but they are more
expensive. A rock bits teeth their shape, size, number and
placement are important to drilling efficiency in different
formations. Milled tooth bits have teeth that are machined from the
same metal billet as the cone (see Figure 4c). In some cases the
teeth have hard- facing applied for extra life. This type is
designed for soft to medium for- mations where long teeth can gouge
out the rock. The teeth on insert bits are actually tungsten
carbide studs keep the bit cool and lubricated, and to remove the
rock cuttings
7. Introduction Introduction 1.7 Revision No: A-0 / Revision
Date: 033198 CHAPTER 1 inserted into holes drilled into the cones
(see Figure 4a). TCI bits drill by gener- ating a crushing action,
for harder and more abrasive formations. Some insert bits are
enhanced with special inserts that feature a layer of
polycrystalline diamond applied over the tungsten car- bide. This
gives them an even longer service life than tungsten carbide alone.
Diamond and PDC bits. Fixed-cutter bits with diamond cutting
surfaces are used for drilling medium to hard for- mations, when
extra-long bit life is needed or for special coring operations.
Single-piece, fixed-cutter bits use either natural diamond chips or
man-made diamond wafers as cutters. Natural dia- mond bits use
industrial-grade, natural Types of Bits Figure 4a: Rock bit (TCI
type). Figure 4b: PDC bit. Figure 4c: Milled tooth rock bit. Figure
4d: Natural diamond core bit. _______________________
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8. Introduction CHAPTER 1 Introduction 1.8 Revision No: A-0 /
Revision Date: 033198 diamonds set in a steel matrix on the cutting
area, as shown on the natural diamond core bit in Figure 4d. During
rotation, the exposed natural dia- monds drag and grind out the
hole. Man-made diamond cutters, called Polycrystalline Diamond
Cutters (PDC), are configured so that the cutters shear the rock
beneath the bit producing large cuttings and high penetration rates
(see Figure 4b). PDC bits are in demand for drilling in many types
of rock, but especially for long sections of medium-hard
formations. PDC bits are very durable and efficient offering higher
penetration rates and long bit life. A variety of PDC bit designs
are manufac- tured to optimize drilling particular for- mations.
Typically PDC bits drill faster in shales than in sandstones and
are used most often to drill long shale sections. Both types of
diamond bits work in a manner similar to older style fishtail drag
bits because they scrape the rock. THE DRILLSTRING Starting at the
bottom, a basic drill- string for rotary drilling consists of the
(1) bit, (2) drill collars and Bottom-Hole Assemblies (BHAs), and
(3) drill pipe (see Figure 5). The BHA is located just above the
bit and consists of drill collars combined with one or more bladed
stabilizers (to keep the BHA and bit concentric), pos- sibly a
reamer (to keep the hole from becoming tapered as the bit diameter
wears down) and other tools. MWD tools and mud motors are generally
located low in the BHA, usually just above the bit. Sometimes, a
set of jars is located near the top of the BHA. Jars can free stuck
pipe by giving a hammering action when they are set-off by pulling
hard. Drill collars are thick-walled, heavy joints of pipe used in
the BHA to pro- vide weight to the bit. Usually, one of the collars
is made of non-magnetic metal so that a magnetic compass tool
(survey tool) can be used to determine the inclination of the lower
BHA and bit without interference from mag- netic metals. Each joint
of drill pipe is approxi- mately 30 ft long, and has a box (female
connection) welded onto one end and a pin (male connection) welded
to the other. These threaded couplings (tool joints) must be
strong, reliable, rugged and safe to use. They must be easy to make
up (connect) and break out (dis- connect). Outer diameters for
drill pipe range from 23 8 to 65 8 in. The hollow drillstring
provides a means for continuous circulation and for pumping
drilling mud under high pressure through the bit nozzles as a jet
of fluid. The blast of mud knocks rock cuttings from under the bit,
gives a new rock surface for the cutters to attack and starts the
drill cuttings on their trip to the surface. This transmis- sion of
hydraulic horsepower from PDC bits are very durable and
efficient
9. Introduction Introduction 1.9 Revision No: A-0 / Revision
Date: 033198 CHAPTER 1 the mud pumps to the bit is a very important
function of the mud. Coiled-tubing drilling. This method employs a
continuous string of coiled tubing and a specialized, coiled-tubing
drilling rig. Rather than drilling with separate joints of the
traditional, large- diameter, rigid drill pipe, the drillstring is
smaller-diameter, flexible tubing. Unlike drill pipe which is
screwed together to form the drillstring, and which must be
disconnected into stands that are racked in the derrick during
trips, the tubing comes rolled on a reel that unwinds as drilling
progresses and is subsequently rewound onto its spool during trips.
The coiled-tubing method greatly facilitates lowering and
retrieving the drilling assembly. Traditionally, coiled-tubing rigs
have been used for workover and completion operations where
mobility and com- pact size were important. With the development of
downhole mud motors which do not require the use of a rotat- ing
drillstring to turn the bit, coiled- tubing units are now
functioning as true drilling rigs. DRILL BIT ROTATION Regardless of
bit type, it must be rotated in order to drill the rock. There are
three methods used to turn the bit downhole: 1. The drillstring and
bit are turned by a rotary table and kelly. 2. The drillstring and
bit are rotated by a top-drive motor. 3. Only the bit is rotated by
a hydraulic mud motor in the drillstring. (The drillstring can be
held still or rotated while using a mud motor, as desired.) Rotary
table and kelly. A rotary table is a gear- and chain-driven
turntable mounted into the rig floor that has a large open center
for the bit and drill- string. The rotary table kelly bushing is a
large, metal donut with a 4-, 6- or 8- sided hole at its center.
This bushing can accept a special piece of 4-, 6- or 8-sided pipe,
called the kelly. The kelly, which is about 40 ft long, is turned
by the kelly bushing in the rotary table, just as a hex nut is
turned by a wrench. The kelly is free to slide up and down in the
kelly bushing so it can be raised while a 30-ft joint of drill pipe
(the topmost joint in the drillstring) is attached to its bottom.
The drill pipe is then lowered into the hole until the bit touches
bottom, and the kelly can be rotated. The driller starts the rotary
table, and as the bit drills down, the kelly moves down, too. When
the top end of the kelly is level with the bushing (at rig floor
level), the kelly is broken out from the drill pipe, raised while
another joint is added, and the process of drilling down is
repeated. In order for the drilling mud to get into Regardless of
bit type, it must be rotated Casing Mud flow out Mud flow in Cement
Annulus Open hole Drill bit Kelly Tool joint Drill pipe Drill
collar Mud Bottom-holeassembly Crossover sub Stabilizer Mud motor
MWD/LWD Stabilizer Figure 5: Drillstring components.
10. Introduction CHAPTER 1 Introduction 1.10 Revision No: A-0 /
Revision Date: 033198 the drillstring, a rotary hose and mud swivel
are attached to the top of the kelly to supply mud from the mud
pumps. The swivel is a hollow device that receives mud from the
stand pipe and rotary hose and passes it through a rotating seal to
the kelly and into the drillstring. One disadvantage of the
kelly/rotary arrangement is that while pulling pipe with the kelly
discon- nected, no mud can be pumped and pipe rotation is minimal.
Top drive. A top-drive unit has important advantages over a kelly/
rotary drive. A top-drive unit rotates the drillstring with a large
hydraulic motor mounted high in the derrick on a traveling
mechanism. Rather than drilling one 30-ft joint before making a
connection, top drives use 3-joint (90-ft) stands of drill pipe and
greatly reduce the number of connections and the time to make a
trip. One key advan- tage the driller can simultaneously rotate the
pipe while going up or down over a 90 ft distance in the hole and
circulate mud. This allows long, tight spots to be quickly and
easily reamed without sticking the pipe. Due to these advantages,
top drive units are being installed on most deep rigs and offshore
rigs. Mud motor. While the first two rotation methods involve
turning the drill pipe in order to turn the bit, this method is
different. In this case, there is a hydraulic motor (turbine or
positive-displacement mud motor) mounted in the BHA near the bit.
During drilling, hydraulic energy from the mud passing through the
motor turns the bit. This is achieved through the use of multiple
rotor/stator ele- ments inside the motor which rotate a shaft to
which the bit is attached. This offers several advantages. Mud
motors can achieve much higher bit rotational speeds than can be
achieved by rotating the entire drillstring. Less energy is
required to turn just the bit. The hole and casing stay in better
con- dition, as does the drillstring, when only the bit (and not
the pipe) rotates. Higher bit RPM results in improved Rate of
Penetration (ROP), and vibra- tion is less of a problem. Mud motors
are used extensively for directional drilling where it is essential
to keep an orienting tool positioned in the desired direction. MWD
AND LWD In the old days, when a driller wanted to check the angle
of a directional well, or when he wanted to log the well to obtain
certain downhole or formation- related information, he was faced
with only one course of action. He had to stop drilling and run
special measure- ment or logging instruments down into the
wellbore; sometimes this involved pulling the entire drillstring
before measurement could proceed. Higher bit RPM results in
improved ROP
11. Introduction Introduction 1.11 Revision No: A-0 / Revision
Date: 033198 CHAPTER 1 Today, there are sophisticated elec- tronic
instruments that can perform Measurement While Drilling (MWD) and
Logging While Drilling (LWD) functions while the drilling process
continues uninterrupted. The meas- urements they perform are
varied, and while they are important to the driller, there is
another factor that is more important to mud engineers. That is the
fact that both MWD and LWD instruments transmit their findings back
to the surface by generating pulse waves in the drilling mud col-
umn inside the drillstring. For that reason, mud conditions
(density, vis- cosity, gas entrainment, etc.) will be especially
important on rigs that are running MWD and LWD instruments.
DERRICKS HOISTING SYSTEM Drilling rigs must have tremendous power
to lift and suspend the weight of long drillstrings and casing
strings. This hoisting system must have the capacity to overcome
any resistance caused by tight spots in the hole and pull-on or jar
stuck pipe. While the weight of the equipment is suspended from the
top of the derrick, the lifting power comes from an engine or motor
operating the drawworks. The draw- works controls a reel of wire
cable which runs through a system of pulleys to reduce the
mechanical requirements. Heres an overview. A stationary block
(crown block) is mounted at the top of the derrick, and a movable
block (traveling block) is suspended by cable, also known as wire
rope. One end of this wire rope, the drum line, is wound around the
drum of the draw- works, and then it is passed between the sheaves
of the crown block and sheaves of the traveling block several
times. The dead end of the wire rope, dead line, is secured to the
base of the derrick. This multi-sheave block and tackle system
offers high mechanical advantage to the hoisting system. On the
bottom of the traveling block there is a large hook. During
drilling, a rotary swivel hangs from the hook on a bail. The swivel
provides a rotating pressure seal so that mud can flow under
pressure down the kelly and into the drillstring. The hook also
suspends the drillstring, which is being turned by the kelly.
Drawworks and tongs. While trip- ping, the swivel (with the kelly
attached) is set aside. Devices called elevators hang on the hook
to hoist the drillstring out of the hole. When making a trip,
three- joint stands (about 90 ft of drill pipe) are pulled. While a
stand is being unscrewed and placed back into the derrick, the rest
of the drillstring weight is supported from the rotary table by
pipe slips that grip the pipe below the tool joint. Tool joints are
made up tight or broken-out using pipe tongs (large pipe wrenches).
A spinning chain is used to rotate the joints together rapidly. A
mechanical cathead is the device that pulls the spin- ning chain
and pulls the pipe tongs. The friction cathead, with a rope around
it, allows the rig crew to perform various tasks, such as light
pulling and hoisting. The friction cathead and mechanical cathead
operate off the cat shaft. The drawworks has in it a large drum
hoist used to wrap and pull the wire rope (drilling line), as
mentioned earlier. On the drum is the main brake, which has the
ability to quickly stop and hold the weight of the drillstring.
When heavy loads are being lowered, the main brake is assisted by a
hydraulic or electric auxiliary brake, or retarder, to absorb the
great amount of energy developed by the mass of the traveling
block, hook assembly and drillstring. _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
12. Introduction CHAPTER 1 Introduction 1.12 Revision No: A-0 /
Revision Date: 033198 Drillers console. Located next to the
drawworks is the drillers control console. From this vantage point,
the driller controls the brake, catheads, rotary table (or top
drive), the rate at which the drillstring is pulled or low- ered,
mud pump speed, and other important functions. MUD CIRCULATION AND
SOLIDS REMOVAL A logical place to begin the discussion of a mud
circulation system is at the mud pumps (see Figure 6). These pumps
and the engines that power them, represent the heart of the mud
system just as the circulating mud is the lifeblood of the drilling
operation. Mud pumps are positive-displacement piston pumps, some
of which produce up to 5,000 psi. They are powered by diesel
engines or electric motors. To produce the required pressure and
flow rate for a specific set of drilling conditions, the correct
piston and liner sizes must be selected for the pumps and the right
nozzle sizes must be specified for the bit. This is called
hydraulics optimization, and its a key factor in efficient
drilling. After exiting the mud pump at high pressure, the drilling
fluid travels up the standpipe, a long, vertical pipe attached to
the derrick leg, then through the kelly hose (rotary hose), through
the swivel and down the kelly. The mud then travels down the
drillstring to the bit. A bit will usually have two or more nozzles
(jets) which accelerate the mud to a high velocity. This jet of mud
scours the bottom of the hole to keep the bit cutters clean and
keep a fresh rock surface for the bit to attack. From the hole
bottom, the mud moves upward in the annular space between the
drillstring and the wellbore, carrying the cuttings generated by
the bit. the driller controls the brake, catheads The mud then
travels down the drillstring to the bit. Standpipe Swivel Kelly
hose Suction line Mud pits Shale shaker Flow line Mud pump
Discharge line Mixing hopper Kelly Drill pipe Drill collar Bit
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ Figure 6: Mud circulating system.
13. Introduction Introduction 1.13 Revision No: A-0 / Revision
Date: 033198 CHAPTER 1 The mud and its load of cuttings flow out of
the bell nipple and through a large-diameter, sloping pipe (flow
line) onto one or more vibrating wire-mesh screens mounted on the
shale shaker. The idea is that the mud falls through the screens
and most of the cuttings (which are bigger than the screens mesh)
are separated from the circulating system. When the mud falls
through the screen, it drops into a settling pit. These pits are
large, rectangular, metal tanks with pipe or troughs connecting
them. The settling pit is not stirred so that any remaining larger
solids can settle out of the mud. From the settling pit, the mud
moves into stirred mud pits downstream where gas, sand and silt are
removed. After that, the mud moves to the suction pit where the
pumps pull it out for recirculation downhole. The suction pit is
also used for the addition of treating chemicals and mud
conditioning additives. A mud hopper with a venturi is used in this
pit for adding dry additives such as clays and weighting agents.
BLOWOUT PREVENTERS A drilling mud should have sufficient density
(mud weight) to prevent (hydro- statically) any gas, oil or
saltwater from entering the wellbore uncontrolled. Sometimes
however, these formation fluids do enter the wellbore under great
pressure. When this happens, a well is said to take a kick. It is
especially risky if the fluid is a gas or oil. To guard against the
dangers of such events, rigs are usually equipped with a stack of
Blowout Preventers (BOPs). Depending on the well depth and other
circumstances, there will be several BOP units bolted together and
then to the surface casing flange. One or more of these BOPs can be
engaged to seal off the wellbore if a kick occurs. Multiple BOPs in
the stack provide flexibility and redundancy in case of a failure.
At the top of the BOP stack is a bag- type preventer commonly
referred to as a Hydril. This unit contains a steel- ribbed,
elastomeric insert which can be expanded hydraulically to seal the
annulus. Below the bag preventers are the ram-type preventers with
hydrauli- cally driven rams that close against the pipe or against
themselves, thrusting in from opposite sides of the pipe. These
preventers can be pipe, blind or shear rams. Pipe rams have heads
with a con- cave shape to grip the pipe and form a seal around it;
they accomplish the same function as the bag preventer but are
rated at higher pressure. Blind rams come together over the hole to
form a fluid-tight seal against one another in the event the pipe
is not in the well or if it has parted and fallen down into the
wellbore. Shear rams sever the pipe before sealing together. Below
the blowout preventers is the drilling spool. It has an opening in
its side to allow drilling mud and the kick fluids to be pumped
out. A high-pres- sure choke line connects to the spool with a
special back-pressure valve (the choke) in the line. During
well-control procedures, the choke is used to hold back-pressure on
the annulus while heavier mud is pumped down the drill- string to
kill the kick. If the invading fluid contains gas, the gas must be
removed from the mud exiting the well. Gas-cut mud from the choke
is sent to a mud-gas separator vessel. The gas is flared and the
mud is returned to the pits for reconditioning. CASING AND LINER
When a well is being drilled, exposed formations must be
periodically cov- ered and protected by steel pipe. This is done
for several reasons to keep the hole from caving in, to protect the
for- mations being drilled and/or to isolate different geological
zones from each other. These protective pipes are called casings
and liners. Casing refers to pipe _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
14. Introduction CHAPTER 1 Introduction 1.14 Revision No: A-0 /
Revision Date: 033198 that starts at the surface or mud line and
extends down into the borehole. The term liner applies to pipe
whose upper end does not reach the surface or mud line but is
inside and overlaps the bottom of the last casing or liner. Casing
and liners are either totally or partially cemented in place.
Casing. Two, three or more casing strings may be run in a well,
with the smaller pipe being run inside the larger sizes, and the
smaller ones going deeper than the larger. The surface casing is
run and cemented at a depth to protect freshwater aquifers and to
avoid mud seepage into shallow sand and gravel beds; it might be
set at about 2,000 ft. The next string is the intermediate casing.
It is run and cemented when theres a need to change the mud to a
density that cant be tolerated by the exposed formations or by the
surface casing. Below the intermediate casing may be another string
of casing or a liner. Liners. It may not be necessary, eco- nomical
or practical to line the entire, already-cased hole all the way to
the surface just to protect the lower open hole. This is especially
true as the hole nears total depth and becomes smaller. So a liner
is run from the bottom of the hole, up into the casing, overlap-
ping it by several hundred feet. Liners are held in place inside
the casing by special tools called liner hangers. The practice of
running a liner protects the last open hole interval, which often
includes the reservoir section. CEMENTING After a string of casing
or a liner has been properly landed in the hole, a cement slurry is
mixed and quickly pumped down the inside of the cas- ing (or
liner). Pressure drives it out the bottom and up into the annular
space between the pipe and the hole wall. Cement is followed
downhole by just enough fluid to push all but the last part of it
out of the casing or liner. Once all the cement hardens, that small
quantity still inside the casing or liner is drilled out and the
hole proceeds into a few feet of new rock beyond the end of the
casing. Then the casing or liner is pressure-tested to see how much
mud weight it will be able to hold, for future reference. If it
fails the test, a remedial cement job (squeeze) may be required.
Once the cement job passes the pressure test, drilling can resume.
MUD LOGGING Several methods are used during the drilling of a well
to identify geological strata by age and type, and to look for
signs of oil and gas. Mud logging is one of these methods. It
involves examination of the cuttings for lithol- ogy and
fluorescence as evidence of oil called shows. By analyzing the
gases in the mud returning from downhole, the presence of
hydrocarbons is deter- mined. Depth, ROP and other parame- ters are
correlated with oil shows and lithologic changes. CORING AND CORE
ANALYSIS A valuable reservoir evaluation method is core analysis. A
core is a piece of the actual rock taken from the reservoir under
study. Cylindrical pieces of rock (cores) several feet long can be
obtained by drilling with a spe- cial coring bit attached to a core
barrel. The bit cuts only the outer circumfer- ence of the
formation, and the cylin- der of rock that remains is captured
inside the core barrel. Small sidewall cores can be obtained with
wireline logging equipment after a zone is drilled. Cores are
examined to some extent on the rig by a geologist, but they are
usually sent to a core analysis laboratory for full evaluation.
Labs can directly measure porosity, permeability, clay content,
lithology, oil shows and other valuable formation parameters.
Coring is expensive and is used only Several methods are used to
identify geological strata
15. Introduction Introduction 1.15 Revision No: A-0 / Revision
Date: 033198 CHAPTER 1 when necessary to have the best, direct data
about the formation. DRILL-STEM AND FORMATION-INTERVAL TESTING
Drill-Stem Testing (DST) and Formation-Interval Testing (FIT) are
two similar methods used to measure directly the production
potential of a formation, to capture samples of the fluids from the
zone tested, and to obtain pressure and temperature data. A DST is
a temporary completion through the drill pipe, using a retriev-
able packer/tester at the bottom of the string. The packer is set
to seal off the annulus, and the tester tool is opened to allow
flow from the open zone. Then the tester is closed, the packer is
unseated and the drillstring is pulled out of the hole. A sample of
fluid is captured. Instruments contained in the tool record the
pressure and temperature. An FIT is run into the hole on a wireline
rather than the drillstring. The tool seats itself against the side
of the hole. A fluid sample is taken, and pres- sure and
temperature are measured. The FIT is then pulled out of the well to
capture the sample under pressure. The sample can be transferred,
under pressure, to another container for ship- ment to a laboratory
for fluid analysis. WIRELINE LOGGING The most widely used method of
for- mation evaluation is wireline logging. Specialized tools run
into the wellbore measure the electrical, acoustical and/or
radioactive properties of the formations. An electrical cable
connects the tool to a recording unit on the surface where the
signals from the tool are amplified and recorded or digitized for
computer- ized analysis. Logs can be used to locate and identify
formations in the well and for geological correlations with nearby
wells. Various logs can indicate lithol- ogy, porosity,
permeability, fluid type (oil, gas, freshwater, saltwater), fluid
contacts and, to some extent, where to find the best part of the
reservoir. Logs measure downhole pressures, tem- peratures and the
hole size. Logs also check casing wear and the integrity of the
cement bond behind the casing. DIRECTIONAL DRILLING Until recently,
most wells were drilled vertically, but more and more, situations
today require an increasing number of wells to be drilled at high
angles or even horizontally (90 from vertical). In addi- tion to
high angles, radical changes in direction (azimuth) can now be made
up to 180. There are many and varied reasons for doing this, but
most of them are economic, environmental and/or technical. Deviated
wells can access more of the reservoir than would be reached if
holes were simply drilled ver- tically. Horizontal drainholes have
become a technical success and are steadily increasing in number.
In one application, the directional wellbore intersects several
adjacent, but isolated and discrete, vertical fractures with a
single drainhole (as in the Austin Chalk). In another, the
directional well exposes a longer producing section such as in a
thin or lens-type reservoir. Due to the enormous expense of off-
shore drilling, one platform usually serves as the launch pad for
several, highly deviated, long-reach wells to cover most or all of
a big reservoir. These wells constitute an extended- reach drilling
project such as is com- mon in the North Sea, Gulf of Mexico and
other areas. In some cases, the devi- ated hole may have changes in
azimuth direction and inclination, resulting in an S- or U-shaped
configuration. [Logs] measure the electrical, acoustical and/or
radioactive properties of the formations.
16. Introduction CHAPTER 1 Introduction 1.16 Revision No: A-0 /
Revision Date: 033198 _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________ WELL COMPLETION The
next step, after setting casings and liners, is the completion
phase of a well. Completion simply means making the well ready to
produce oil and gas under controlled pressures and flow rates.
Figure 7 shows the four common com- pletion techniques. In all
four, the cas- ing prevents the formations above the producing zone
from collapsing into the wellbore. If the producing formation is
strong enough, as in the case of limestone, a length of casing can
be cemented immediately above it, leaving the producing formation
unsupported. This is called an open hole completion. If the
reservoir rock needs support, other methods can be used: Perforated
casing or liner. In this method, casing or liner is run all the way
through the producing zone and cemented in place. Then, holes are
shot (by explosive charge) through the cas- ing and cement, into
the formation. These perforations are created with a perforating
gun that is lowered into the hole on a wireline. The gun is then
fired electrically, and powerful, shaped charges perforate the pipe
and the zone at predetermined intervals. Once the perforations have
been made, oil and/or gas can flow into the casing. Perforated or
slotted liner. In the second method, a pre-perforated or slotted
liner (with holes or slots that are level with the producing zone)
is hung from the bottom of the last string of casing. If the
producing for- mation is weak or poorly consoli- dated, sand and
other solids will be carried into the well as the oil or gas is
produced. To prevent this sand pro- duction,the slotted or
perforated liner may contain a wire-wrapped or a pre- packed-gravel
protective layer to keep the sand from entering the wellbore.
Gravel packing. Another approach that is helpful if the producing
forma- tion is weak (such as loose sand), and must be supported or
held back, is the conventional gravel pack. A gravel- packing
operation consists of circulat- ing and placing carefully sized
gravel into the annular space between the liner and the wellbore
wall. The pack forms a permeable layer to exclude any formation
particles from the wellbore that become loose during production.
PRODUCTION TUBING A string of pipe (tubing) through which oil and
gas are produced is a production string. It is hung inside the
casing or liner. Tubing sizes range between 3 4 and 41 2 in. in
diameter, with the most common sizes being 23 8, 27 8 and 31 2 in.
Because of its relatively high ratio of wall thickness to diameter,
tubing can withstand much more pressure than the Producing
Petroleum Figure 7: Bottom-hole arrangement of some types of
completions. casing prevents the formations from collapsing
Producing formation Casing to surface Cement Producing formation
Slotted liner Casing to surface Liner hanger and packer Cement
Producing formation Slotted liner Casing to surface Liner hanger
and packer Cement Gravel Producing formation Gun perforated holes
Casing to surface Cement (a) Open-hole completion (b)
Gun-perforated completion (c) Liner completion (d) Gravel-packed
liner
17. Introduction Introduction 1.17 Revision No: A-0 / Revision
Date: 033198 CHAPTER 1 casing, permitting high-pressure reser-
voirs to be safely controlled and pro- duced. In a high-pressure
completion, the casing/tubing annulus is sealed off near the bottom
with a tubing packer. (A packer is a sealing device which can
expand to seal an annular space between two concentric pipes.) With
a packer set and sealed, oil and gas flow into the cased hole below
the packer then into the tubing and up to the surface where
pressure and rate are controlled by surface valves and chokes. If a
well produces from two or more zones, a multiple-zone packer must
be used to accommodate production from different zones flowing into
a single tubing string. Another alternative is to complete the well
with multiple tubing strings and use multiple packers to direct oil
and gas production from each zone into separate tubing strings. A
stable, non-corrosive packer fluid is left static in the annular
space above the packer and surrounding the tubing. This fluid will
be left in place for years. Packer fluids are needed to help bal-
ance pressure and mechanical forces on the casing, tubing and
packer. PRODUCTION EQUIPMENT Once the well has been completed, it
is ready to be put on-line and start producing. At the surface, a
variety of equipment comes into play at this stage. This equipment
will vary from well to well and will change as a given well becomes
depleted. A fundamental consideration is whether the reservoir has
enough internal pressure to flow naturally or whether it must be
assisted. If the well flows without assistance, then only a
wellhead will be required. The wellhead (Christmas tree) is a
series of flow-control valves, chokes and gauges mounted on spools.
From the Christmas tree, the oil and gas move to a separator,
perhaps a heater/treater to break any emulsion and prepare the oil
for transfer to a storage tank or oil pipeline, and prepare the gas
for a pipeline. Gas may have to be compressed before being put into
a pipeline. PUMPING METHODS If reservoir pressure is too low to
force the oil, gas and water to the surface, some type of
artificial lift is needed. Pumping is an economical method of
lifting oil to the surface. The pump itself is located downhole,
below the level of standing oil. A reciprocating- type (plunger)
pump lifts oil on the upstroke and refills the pump on the
downstroke. A sucker rod from the pump up to the surface is
connected to a pump jack. Downhole electrical pumps are another
commonly used method for getting oil and water to the surface. They
are placed downhole and are powered by electricity supplied by a
cable. Another common method for lifting oil is gas-assisted lift
or simply gas lift. This method uses gas (from the same well or
another source) injected into the oil column downhole to lift the
fluids. Gas is injected under pressure into the casing/tubing
annulus through a series of gas-lift valves. Fluids (oil and water)
that are above the gas-inlet port are dis- placed upwards, becoming
less dense as they rise to the surface because of the gas thats
been injected into them. Gas, oil and water can be lifted this way
until it is no longer economical. _______________________
_______________________ _______________________
_______________________ _______________________
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_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________ Pumping is an
economical method of lifting oil
18. Functions Functions 2.1 Revision No: A-0 / Revision Date:
033198 CHAPTER 2 The objective of a drilling operation is to drill,
evaluate and complete a well that will produce oil and/or gas effi-
ciently. Drilling fluids perform numer- ous functions that help
make this possible. The responsibility for perform- ing these
functions is held jointly by the mud engineer and those who direct
the drilling operation. The duty of those charged with drilling the
hole including the oil company representa- tive, drilling
contractor and rig crew is to make sure correct drilling proce-
dures are conducted. The chief duty of the mud engineer is to
assure that mud properties are correct for the specific drilling
environment. The mud engi- neer should also recommend drilling
practice changes that will help reach the drilling objectives.
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ The duty of those charged with drilling the
hole Introduction Drilling fluid functions describe tasks which the
drilling fluid is capable of performing, although some may not be
essential on every well. Removing cuttings from the well and
controlling formation pressures are of primary importance on every
well. Though the order of importance is determined by well
conditions and current opera- tions, the most common drilling fluid
functions are: 11. Remove cuttings from the well. 12. Control
formation pressures. 13. Suspend and release cuttings. 14. Seal
permeable formations. 15. Maintain wellbore stability. 16. Minimize
reservoir damage. 17. Cool, lubricate, and support the bit and
drilling assembly. 18. Transmit hydraulic energy to tools and bit.
19. Ensure adequate formation evaluation. 10. Control corrosion.
11. Facilitate cementing and completion. 12. Minimize impact on the
environment. 1. REMOVE CUTTINGS FROM THE WELL As drilled cuttings
are generated by the bit, they must be removed from the well. To do
so, drilling fluid is circu- lated down the drillstring and through
the bit, entraining the cuttings and car- rying them up the annulus
to the sur- face. Cuttings removal (hole cleaning) is a function of
cuttings size, shape and density combined with Rate of Penetration
(ROP); drillstring rotation; and the viscosity, density and annular
velocity of the drilling fluid. Viscosity. The viscosity and
rheolog- ical properties of drilling fluids have a significant
effect on hole cleaning. Cuttings settle rapidly in low-viscosity
fluids (water, for example) and are difficult to circulate out of
the well. Generally, higher-viscosity fluids improve cuttings
transport. Drilling Fluid Functions
19. Functions CHAPTER 2 Functions 2.2 Revision No: A-1 /
Revision Date: 022801 Most drilling muds are thixotropic, which
means they gel under static con- ditions. This characteristic can
suspend cuttings during pipe connections and other situations when
the mud is not being circulated. Fluids that are shear- thinning
and have elevated viscosities at low annular velocities have proven
to be best for efficient hole cleaning. Velocity. Generally, higher
annular velocity improves cuttings removal. Yet, with thinner
drilling fluids, high veloci- ties may cause turbulent flow, which
helps clean the hole but may cause other drilling or wellbore
problems. The rate at which a cutting settles in a fluid is called
the slip velocity. The slip velocity of a cutting is a function of
its density, size and shape, and the viscosity, density and
velocity of the drilling fluid. If the annular velocity of the
drilling fluid is greater than the slip velocity of the cutting,
the cutting will be transported to the surface. The net velocity at
which a cutting moves up the annulus is called the transport
velocity. In a vertical well: Transport velocity = Annular velocity
slip velocity (Note: Slip velocity, transport velocity, and the
effects of rheology and hydraulic conditions on cuttings transport
will be discussed in detail in another chapter.) Cuttings transport
in high-angle and horizontal wells is more difficult than in
vertical wells. The transport velocity as defined for vertical
wellbores is not rele- vant for deviated holes, since the cut-
tings settle to the low side of the hole across the fluids flow
path and not in the direction opposite to the flow of drilling
fluid. In horizontal wells, cut- tings accumulate along the bottom
side of the wellbore, forming cuttings beds. These beds restrict
flow, increase torque and are difficult to remove. Two different
approaches are used for the difficult hole-cleaning situations
found in high-angle and horizontal wellbores: a) The use of
shear-thinning, thixo- tropic fluids with high Low-Shear- Rate
Viscosity (LSRV) and laminar flow conditions. Examples of these
fluid types are biopolymer systems, like FLO-PRO, and flocculated
ben- tonite slurries like the Mixed Metal Hydroxide (MMH)
DRILPLEXsystem. Such drilling fluid systems provide a high
viscosity with a relatively flat annular velocity profile, cleaning
a larger portion of the wellbore cross section. This approach tends
to sus- pend cuttings in the mud flow path and prevent cuttings
from settling to the low side of the hole. With weighted muds,
cuttings transport can be improved by increasing the 3 and 6 RPM
Fann dial readings (indi- cations of LSRV) to 1 to 11 2 times the
hole size in inches and to use the highest possible laminar flow
rate. b) The use of a high flow rate and thin fluid to achieve
turbulent flow. Turbulent flow will provide good hole cleaning and
prevent cut- tings from settling while circulating, but cuttings
will settle quickly when circulation is stopped. This approach
works by keeping the cuttings sus- pended with turbulence and high
annular velocities. It works best with low-density, unweighted
fluids in competent (not easily eroded) for- mations. The
effectiveness of this technique can be limited by a num- ber of
factors, including large hole size, low pump capacity, increased
depth, insufficient formation integ- rity, and the use of mud
motors and downhole tools that restrict flow rate. Density.
High-density fluids aid hole cleaning by increasing the buoyancy
forces acting on the cuttings, helping to remove them from the
well. Compared to fluids of lower density, high-density fluids may
clean the hole adequately even with lower annular velocities and
lower rheological properties. However, mud weight in excess of what
is needed The rate at which a cutting settles in a fluid The use of
shear- thinning, thixotropic fluids with high Low- Shear-Rate
Viscosity
20. to balance formation pressures has a negative impact on the
drilling opera- tion; therefore, it should never be increased for
hole-cleaning purposes. Drillstring rotation. Higher rotary speeds
also aid hole cleaning by intro- ducing a circular component to the
annular flow path. This helical (spiral- or corkscrew-shaped) flow
around the drill- string causes drill cuttings near the wall of the
hole, where poor hole-cleaning conditions exist, to be moved back
into the higher transport regions of the annulus. When possible,
drillstring rota- tion is one of the best methods for removing
cuttings beds in high-angle and horizontal wells. 2. CONTROLLING
FORMATION PRESSURES As mentioned earlier, a basic drilling fluid
function is to control formation pressures to ensure a safe
drilling oper- ation. Typically, as formation pres- sures increase,
drilling fluid density is increased with barite to balance pres-
sures and maintain wellbore stability. This keeps formation fluids
from flow- ing into the wellbore and prevents pres- sured formation
fluids from causing a blowout. The pressure exerted by the drilling
fluid column while static (not circulating) is called the
hydrostatic pressure and is a function of the density (mud weight)
and True Vertical Depth (TVD) of the well. If the hydrostatic
pressure of the drilling fluid column is equal to or greater than
the formation pressure, formation fluids will not flow into the
wellbore. Keeping a well under control is often characterized as a
set of condi- tions under which no formation fluid will flow into
the wellbore. But it also includes conditions where formation
fluids are allowed to flow into the well- bore under controlled
conditions. Such conditions vary from cases where high levels of
background gas are tolerated while drilling, to situations where
the well is producing commercial quantities of oil and gas while
being drilled. Well control (or pressure control) means there is no
uncontrollable flow of formation fluids into the wellbore.
Hydrostatic pressure also controls stresses adjacent to the
wellbore other than those exerted by formation fluids. In
geologically active regions, tectonic forces impose stresses in
formations and may make wellbores unstable even when formation
fluid pressure is bal- anced. Wellbores in tectonically stressed
formations can be stabilized by balanc- ing these stresses with
hydrostatic pres- sure. Similarly, the orientation of the wellbore
in high-angle and horizontal intervals can cause decreased wellbore
stability, which can also be controlled with hydrostatic pressure.
Normal formation pressures vary from a pressure gradient of 0.433
psi/ft (equivalent to 8.33 lb/gal freshwater) in inland areas to
0.465 psi/ft (equiva- lent to 8.95 lb/gal) in marine basins.
Elevation, location, and various geo- logical processes and
histories create conditions where formation pressures depart
considerably from these nor- mal values. The density of drilling
fluid may range from that of air (essentially 0 psi/ft), to in
excess of 20.0 lb/gal (1.04 psi/ft). Functions Functions 2.3
Revision No: A-0 / Revision Date: 033198 CHAPTER 2
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ _______________________
_______________________ Higher rotary speeds also aid hole
cleaning
21. Functions CHAPTER 2 Functions 2.4 Revision No: A-0 /
Revision Date: 033198 Often, formations with sub-normal pressures
are drilled with air, gas, mist, stiff foam, aerated mud or special
ultra- low-density fluids (usually oil-base). The mud weight used
to drill a well is limited by the minimum weight needed to control
formation pressures and the maximum mud weight that will not
fracture the formation. In practice, the mud weight should be
limited to the minimum necessary for well control and wellbore
stability. 3. SUSPEND AND RELEASE CUTTINGS Drilling muds must
suspend drill cut- tings, weight materials and additives under a
wide range of conditions, yet allow the cuttings to be removed by
the solids-control equipment. Drill cut- tings that settle during
static condi- tions can cause bridges and fill, which in turn can
cause stuck pipe or lost cir- culation. Weight material which
settles is referred to as sag and causes a wide variation in the
density of the well fluid. Sag occurs most often under dynamic
conditions in high-angle wells, where the fluid is being circulated
at low annular velocities. High concentrations of drill solids are
detrimental to almost every aspect of the drilling operation,
primarily drill- ing efficiency and ROP. They increase the mud
weight and viscosity, which in turn increases maintenance costs and
the need for dilution. They also increase the horsepower required
to circulate, the thickness of the filter cake, the torque and
drag, and the likelihood of differential sticking. Drilling fluid
properties that suspend cuttings must be balanced with those
properties that aid in cuttings removal by solids-control
equipment. Cuttings suspension requires high-viscosity, shear-
thinning thixotropic properties, while solids-removal equipment
usually works more efficiently with fluids of lower viscosity.
Solids-control equipment is not as effective on non-shear-thinning
drilling fluids, which have high solids content and a high plastic
viscosity. For effective solids control, drill solids must be
removed from the drill- ing fluid on the first circulation from the
well. If cuttings are recirculated, they break down into smaller
particles that are more difficult to remove. One easy way to
determine whether drill solids are being removed is to com- pare
the sand content of the mud at the flow line and at the suction
pit. 4. SEAL PERMEABLE FORMATIONS Permeability refers to the
ability of fluids to flow through porous formations; for- mations
must be permeable for hydro- carbons to be produced. When the mud
column pressure is greater than forma- tion pressure, mud filtrate
will invade the formation, and a filter cake of mud solids will be
deposited on the wall of the wellbore. Drilling fluid systems
should be designed to deposit a thin, low-permeability filter cake
on the for- mation to limit the invasion of mud fil- trate. This
improves wellbore stability and prevents a number of drilling and
production problems. Potential prob- lems related to thick filter
cake and excessive filtration include tight hole conditions, poor
log quality, increased torque and drag, stuck pipe, lost cir-
culation, and formation damage. In highly permeable formations with
large pore throats, whole mud may invade the formation, depending
on the size of the mud solids. For such situations, bridging agents
must be used to block the large openings so the mud solids can form
a seal. To be effective, bridging agents must be about one-half the
size of the largest opening. Bridging agents include cal- cium
carbonate, ground cellulose and a wide variety of seepage-loss or
other fine lost-circulation materials. Drilling muds must suspend
drill cuttings _______________________ _______________________
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22. Functions Functions 2.5 Revision No: A-0 / Revision Date:
033198 CHAPTER 2 Depending on the drilling fluid sys- tem in use, a
number of additives can be applied to improve the filter cake, thus
limiting filtration. These include bentonite, natural and synthetic
poly- mers, asphalt and gilsonite, and organic deflocculating
additives. 5. MAINTAIN WELLBORE STABILITY Wellbore stability is a
complex balance of mechanical (pressure and stress) and chemical
factors. The chemical composi- tion and mud properties must combine
to provide a stable wellbore until casing can be run and cemented.
Regardless of the chemical composition of the fluid and other
factors, the weight of the mud must be within the necessary range
to balance the mechanical forces acting on the wellbore (formation
pres- sure, wellbore stresses related to orienta- tion and
tectonics). Wellbore instability is most often identified by a
sloughing formation, which causes tight hole con- ditions, bridges
and fill on trips. This often makes it necessary to ream back to
the original depth. (Keep in mind these same symptoms also indicate
hole- cleaning problems in high-angle and difficult-to-clean
wells.) Wellbore stability is greatest when the hole maintains its
original size and cylindrical shape. Once the hole is eroded or
enlarged in any way, it becomes weaker and more difficult to
stabilize. Hole enlargement leads to a host of problems, including
low annular velocity, poor hole cleaning, increased solids loading,
fill, increased treating costs, poor formation evalua- tion, higher
cementing costs and inadequate cementing. Hole enlargement through
sand and sandstone formations is due largely to mechanical actions,
with erosion most often being caused by hydraulic forces and
excessive bit nozzle velocities. Hole enlargement through sand
sections may be reduced significantly by following a more
conservative hydraulics program, particularly with regard to impact
force and nozzle velocity. Sands that are poorly consolidated and
weak require a slight overbalance to limit wellbore enlargement and
a good-quality filter cake containing bentonite to limit wellbore
enlargement. In shales, if the mud weight is suffi- cient to
balance formation stresses, wells are usually stable at first. With
water-base muds, chemical differences cause interactions between
the drilling fluid and shale, and these can lead (over time) to
swelling or softening. This causes other problems, such as
sloughing and tight hole conditions. Highly fractured, dry, brittle
shales, with high dip angles, can be extremely unstable when
drilled. The failure of these dry, brittle formations is mostly
mechanical and not normally related to water or chemical forces.
Various chemical inhibitors or addi- tives can be added to help
control mud/shale interactions. Systems with high levels of
calcium, potassium or other chemical inhibitors are best for
drilling into water-sensitive formations. Salts, polymers,
asphaltic materials, gly- cols, oils, surfactants and other shale
inhibitors can be used in water-base drilling fluids to inhibit
shale swelling and prevent sloughing. Shale exhibits such a wide
range of composition and sensitivity that no single additive is
universally applicable. _______________________
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_______________________ _______________________ Wellbore stability
is a complex balance
23. Functions CHAPTER 2 Functions 2.6 Revision No: A-1 /
Revision Date: 022801 Oil- or synthetic-base drilling fluids are
often used to drill the most water- sensitive shales in areas with
difficult drilling conditions. These fluids pro- vide better shale
inhibition than water-base drilling fluids. Clays and shales do not
hydrate or swell in the continuous phase, and additional inhi-
bition is provided by the emulsified brine phase (usually calcium
chloride) of these fluids. The emulsified brine reduces the water
activity and creates osmotic forces that prevent adsorption of
water by the shales. 6. MINIMIZE FORMATION DAMAGE Protecting the
reservoir from damage that could impair production is a big
concern. Any reduction in a producing formations natural porosity
or perme- ability is considered to be formation damage. This can
happen as a result of plugging by mud or drill solids or through
chemical (mud) and mechani- cal (drilling assembly) interactions
with the formation. Frequently, formation damage is reported as a
skin damage value or by the amount of pressure drop that occurs
while the well is producing (drawdown pressure). The type of
completion procedure and method will determine which level of
formation protection is required. For example, when a well is
cased, cemented and perforated, the perfora- tion depth usually
allows efficient pro- duction, even if near-wellbore damage exists.
Conversely, when a horizontal well is completed with one of the
open- hole methods, a reservoir drill-in fluid specially designed
to minimize damage is required. While the effect of drilling fluid
damage is rarely so extensive that oil and/or gas cannot be
produced, consideration should be given to potential formation
damage when selecting a fluid for drilling potential reservoir
intervals. Some of the most common mecha- nisms for formation
damage are: a) Mud or drill solids invading the formation matrix,
plugging pores. b) Swelling of formation clays within the
reservoir, reducing permeability. c) Precipitation of solids as a
result of mud filtrate and formation fluids being incompatible. d)
Precipitation of solids from the mud filtrate with other fluids,
such as brines or acids, during completion or stimulation
procedures. e) Mud filtrate and formation fluids forming an
emulsion, restricting permeability. The possibility of formation
damage can be determined from offset well data and studies of
formation cores for return permeability. Drilling fluids designed
to minimize a particular prob- lem, specially designed reservoir
drill-in fluids or workover and completion flu- ids, all can be
used to minimize forma- tion damage. 7. COOL, LUBRICATE AND SUPPORT
THE BIT AND DRILLING ASSEMBLY Considerable frictional heat is
generated by mechanical and hydraulic forces at the bit and where
the rotating drill- string rubs against the casing and well- bore.
Circulation of the drilling fluid cools the bit and drilling
assembly, Protecting the reservoir from damageis a big
concern.
24. Functions Functions 2.7 Revision No: A-0 / Revision Date:
033198 CHAPTER 2 transferring this heat away from the source,
distributing it throughout the well. Drilling fluid circulation
cools the drillstring to temperatures lower than the bottom-hole
temperature. In addition to cooling, drilling fluid lubri- cates
the drillstring, further reducing frictional heat. Bits, mud motors
and drillstring components would fail more rapidly if it were not
for the cooling and lubricating effects of drilling fluid. The
lubricity of a particular fluid is measured by its Coefficient of
Friction (COF), and some muds do a better job than others at
providing lubrication. For example, oil- and synthetic-base muds
lubricate better than most water- base muds, but lubricants can be
added to water-base muds to improve them. On the other hand,
water-base muds provide more lubricity and cooling ability than air
or gas. The amount of lubrication provided by a drilling fluid
varies widely and depends on the type and quantity of drill solids
and weight material, plus the chemical composition of the sys- tem
pH, salinity and hardness. Altering mud lubricity is not an exact
science. Even after a thorough evalua- tion, with all relevant
factors consid- ered, application of a lubricant may not produce
the anticipated reduction in torque and drag. Indications of poor
lubrication are high torque and drag, abnormal wear, and heat
checking of drillstring compo- nents. But be aware that these prob-
lems can also be caused by severe doglegs and directional problems,
bit balling, key seating, poor hole cleaning and incorrect
bottom-hole assembly design. While a lubricant may reduce the
symptoms of these problems, the actual cause must be corrected to
resolve the problem. The drilling fluid helps to support a portion
of the drillstring or casing string weight through buoyancy. If a
drillstring, liner or casing string is sus- pended in drilling
fluid, it is buoyed by a force equal to the weight of the mud
displaced, thereby reducing hook load on the derrick. Buoyancy is
directly related to the mud weight, so an 18-lb/gal fluid will
provide twice the buoyancy of a 9-lb/gal fluid. The weight that the
derrick can support is limited by its mechanical capacity, a
consideration that becomes increasingly important with increased
depth as the weight of the drillstring and casing becomes
tremendous. While most rigs have sufficient capacity to handle the
drillstring weight without buoyancy, it is an important considera-
tion when evaluating the neutral point (where the drillstring is in
neither ten- sion nor compression). However, when running long,
heavy strings of casing, buoyancy can be used to provide a sig-
nificant benefit. Using buoyancy, it is possible to run casing
strings whose weight exceeds a rigs hook load capac- ity. If the
casing is not completely filled with mud as it is lowered into the
hole, the void volume inside the casing increases buoyancy,
allowing a signifi- cant reduction in hook load to be used. This
process is referred to as floating in the casing. 8. TRANSMIT
HYDRAULIC ENERGY TO TOOLS AND BIT Hydraulic energy can be used to
maxi- mize ROP by improving cuttings removal at the bit. It also
provides power for mud motors to rotate the bit and for Measurement
While Drilling (MWD) and Logging While Drilling (LWD) tools.
Hydraulics programs are based on sizing the bit nozzles properly to
use available mud pump horsepower (pressure or energy) to generate
a maxi- mized pressure drop at the bit or to optimize jet impact
force on the bot- tom of the well. Hydraulics programs are limited
by the available pump The lubricity of a partic- ular fluid is
measured by Hydraulic energy can be used to maximize ROP
25. Functions CHAPTER 2 Functions 2.8 Revision No: A-0 /
Revision Date: 033198 horsepower, pressure losses inside the
drillstring, maximum allowable surface pressure and optimum flow
rate. Nozzle sizes are selected to use the available pressure at
the bit to maximize the effect of mud impacting the bottom of the
hole. This helps remove cuttings from beneath the bit and keep the
cutting structure clean. Drillstring pressure losses are higher in
fluids with higher densities, plastic viscosities and solids. The
use of small- ID drill pipe or tool joints, mud motors and MWD/LWD
tools all reduce the amount of pressure available for use at the
bit. Low-solids, shear-thinning drilling fluids or those that have
drag- reducing characteristics, such as polymer fluids, are more
efficient at transmit- ting hydraulic energy to drilling tools and
the bit. In shallow wells, sufficient hydraulic horsepower usually
is available to clean the bit efficiently. Because drillstring
pressure losses increase with well depth, a depth will be reached
where there is insufficient pressure for optimum bit cleaning. This
depth can be extended by carefully controlling the mud properties.
9. ENSURE ADEQUATE FORMATION EVALUATION Accurate formation
evaluation is essen- tial to the success of the drilling opera-
tion, particularly during exploration drilling. The chemical and
physical properties of the mud affect formation evaluation. The
physical and chemical wellbore conditions after drilling also
influence formation evaluation. During drilling, the circulation of
mud and cut- tings is monitored for signs of oil and gas by
technicians called mud loggers. They examine the cuttings for
mineral composition, paleontology and visual signs of hydrocarbons.
This informa- tion is recorded on a mud log that shows lithology,
ROP, gas detection and oil-stained cuttings plus other important
geological and drilling parameters. Electric wireline logging is
performed to evaluate the formation in order to obtain additional
information. Sidewall cores also may be taken with wireline-
conveyed tools. Wireline logging includes measuring the electrical,
sonic, nuclear and magnetic-resonance proper- ties of the formation
to identify lithol- ogy and formation fluids. For continuous
logging while the well is being drilled, LWD tools are available.
Drilling a cylin- drical section of the rock (a core) for lab-
oratory evaluation also is done in target production zones to
obtain desired information. Potentially productive zones are
isolated and evaluated by per- forming Formation Testing (FT) or
Drill- Stem Testing (DST) to obtain pressure and fluid samples. All
of these formation evaluation methods are affected by the drilling
fluid. For example, if the cuttings dis- perse in the mud, there
will be noth- ing for the mud logger to evaluate at the surface.
Or, if cuttings transport is poor, it will be difficult for the mud
logger to determine the depth at which the cuttings originated. Oil
Accurate formation evaluation is essential to the success
26. Functions Functions 2.9 Revision No: A-0 / Revision Date:
033198 CHAPTER 2 muds, lubricants, asphalts and other additives
will mask indications of hydrocarbons on cuttings. Certain
electrical logs work in conductive fluids, while others work in
non-conductive fluids. Drilling fluid properties will affect the
measurement of rock properties by electrical wireline tools.
Excessive mud filtrate can flush oil and gas from the near-wellbore
region, adversely affect- ing logs and FT or DST samples. Muds that
contain high potassium ion con- centrations interfere with the
logging of natural formation radioactivity. High or variable
filtrate salinity can make electrical logs difficult or impossible
to interpret. Wireline logging tools must be run from the surface
to bottom, with the actual measurement of rock properties being
performed as the tools are pulled up the hole. For optimum wireline
log- ging, the mud must not be too thick, it must keep the wellbore
stable and it must suspend any cuttings or cavings. In addition,
the wellbore must be near- gauge from top to bottom, since exces-
sive bore enlargement and/or thick filter cakes can produce varying
logging responses and increase the possibility of sticking the
logging tool. Mud for drilling a core is selected based on the type
of evaluation to be performed. If a core is being taken only for
lithology (mineral analysis), mud type is not a concern. If the
core will be used for waterflood and/or wet- tability studies, a
bland, neutral-pH, water-base mud without surfactants or thinners
will be needed. If the core will be used for measuring reservoir
water saturation, a bland oil mud with minimal surfactants and no
water or salt is often recommended. Many cor- ing operations
specify a bland mud with a minimum of additives. 10. CONTROL
CORROSION Drillstring and casing components that are in continual
contact with the drilling fluid are susceptible to various forms of
corrosion. Dissolved gasses such as oxygen, carbon dioxide and
hydrogen sulfide can cause serious cor- rosion problems, both at
the surface and downhole. Generally, low pH aggravates corrosion.
Therefore, an important drilling fluid function is to keep
corrosion to an acceptable level. In addition to providing
corrosion pro- tection for metal surfaces, drilling fluid should
not damage rubber or elastomer goods. Where formation fluids and/or
other downhole conditions warrant, special metals and elastomers
should be used. Corrosion coupons should be used during all
drilling operations to monitor corrosion types and rates. Mud
aeration, foaming and other trapped-oxygen conditions can cause
severe corrosion damage in a short period of time. Chemical
inhibitors and scavengers are used when the cor- rosion threat is
significant. Chemical inhibitors must be applied properly.
Corrosion coupons should be evalu- ated to tell whether the correct
chemi- cal inhibitor is being used and if the amount is sufficient.
This will keep the corrosion rate at an acceptable level. Hydrogen
sulfide can cause rapid, catastrophic drillstring failure. It is
also deadly to humans after even short periods of exposure and in
low concentrations. When drilling in high H2S environments,
elevated pH fluids, combined with a sulfide-scavenging chemical
like zinc, should be used. 11. FACILITATE CEMENTING AND COMPLETION
The drilling fluid must produce a well- bore into which casing can
be run and cemented effectively and which does not impede
completion operations. Cementing is critical to effective zone
isolation and successful well comple- tion. During casing runs, the
mud must remain fluid and minimize pressure surges so that
fracture-induced lost Dissolved gassescan cause serious corrosion
problems _______________________ _______________________
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27. Functions CHAPTER 2 Functions 2.10 Revision No: A-0 /
Revision Date: 033198 circulation does not occur. Running casing is
much easier in a smooth, in- gauge wellbore with no cuttings, cav-
ings or bridges. The mud should have a thin, slick filter cake. To
cement casing properly, the mud must be completely displaced by the
spacers, flushes and cement. Effective mud displacement requires
that the hole should be near- gauge and the mud must have low vis-
cosity and low, non-progressive gel strengths. Completion
operations such as perforating and gravel packing also require a
near-gauge wellbore and may be affected by mud characteristics. 12.
MINIMIZE IMPACT ON THE ENVIRONMENT Eventually, drilling fluid
becomes a waste product, and must be disposed of in accordance with
local environmen- tal regulations. Fluids with low envi- ronmental
impact that can be disposed of near the well are the most
desirable. In most countries, local environmen- tal regulations
have been established for drilling fluid wastes. Water-base, oil-
base, non-aqueous and synthetic-base fluids all have different
environmental considerations, and no single set of environmental
characteristics is accept- able for all locations. This is