Tiếng anh chuyên ngành Thiết bị dầu khí (Petroleum equipment)

Unit. Drilling Rigs
Rigs are generally categorized as onshore (land) or offshore (marine). Onshore rigs
are all similar, and many modern rigs are of the cantilevered mast, or "jackknife" derrick
type. This type of rig allows the derrick to be assembled on the ground, and then raised to
the vertical position using power from the drawworks, or hoisting system. These
structures are made up of prefabricated sections that are moved onto the location by
truck, barge, helicopter, etc., and then placed in position and pinned together by large
steel pins. Some cantilevered land rigs have their mast permanently attached to a large
truck to enhance their portability. Figure 1 shows a typical large land rig with a drilling
mast.

Figure 1: Drilling rig
Offshore drilling rigs fall into one of several categories, each designed to suit a
certain type of offshore environment:
• Barge rigs
• Submersible rigs
• Jack-up or self-elevating rigs
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• Semisubmersible rigs
• Drillships
• Structure rigs
BARGE RIG: The barge rig is most often a flat-bottomed vessel with a shallow
draft, equipped with a derrick and other necessary drilling equipment. It is usually towed
to the location and then has its hull filled with water, which allows it to rest on the
bottom, providing a solid support for drilling activities. Obviously, this type of rig is only
used in relatively shallow, swampy areas such as the river deltas of West Africa, the
inland waters of the Louisiana swamps, or the shallows of Lake Maricaibo, Venezuela.
Barge rigs are generally capable of drilling in water depths of less than 12 ft (3.7 m), or,
in the case of a posted barge, perhaps to 20 ft (6.1 m). A posted barge has a lower hull

that rests on the bottom and an upper deck that is sup ported by posts from the lower hull.
SUBMERSIBLE RIG: A submersible rig is a larger version of a posted barge, and
is capable of working in water depths of 18 ft to 70 ft (5.5 m to 2.14 m). Often the hull of
a submersible rig will have steel floats or "bottles" that can be filled with water (ball
lasted) to help stabilize the vessel on bottom.
JACK-UP RIG: This is a self-elevating drilling rig, illustrated in Figure 2 , designed
to operate in depths from 30 ft to 350 ft (9 m to 107 m). After being towed to the location
(or in some cases being self-propelled), the legs are lowered by electric or hydraulic jacks
until they rest on the seabed and the deck is level, supported perhaps 60 ft (18 m) above
the waves. Most jack-up rigs have three to five legs, and are either vertical or slightly
angled for stability. The legs may have steel feet, called "spud cans," or they may be
attached to a large steel mat. When moving to a location the legs are raised high above
the deck, creating a some what cumbersome vessel that must move at slow speeds and
only in good weather. The derrick, or mast, on a jack-up may be located over a drilling
slot indented in one side of the structure, or the drill floor may be cantilevered over the
side of the deck, allowing the rig to service wells on stationary platforms, or caissons,
offshore.
SEMISUBMERSIBLE RIG: Unlike the other offshore vessels, the semisubmersible
drilling rig does not rest on the seafloor. This rig is a floating deck supported by
submerged pontoons and is kept stationary by a series of anchors and mooring lines, and,
in some cases, position-keeping propellers
"Semis" can either move under their own power or must be towed to their location.
They have a water-depth-operating range of 20 ft to 2000 ft (6 m to 600 m), and differ
from each other principally in their hull configuration and their number of stabilizing
columns. Most types have a rectangular deck; others may be wedge shaped, pentagonal,


or even triangular. The two most usual hull arrangements are a pair of parallel pontoons
or an individual pontoon at the foot of each stabilizing column. The

columns

and

pontoons are ball lasted to provide a low center of gravity, adding to the semi's stability.
Although the semi can operate in deeper water than a jack-up, it is still limited by the
capabilities of the mooring equipment and the "riser" (the conduit that connects the drill
floor to the sub-sea equipment located at the borehole on the seafloor).
DRILLSHIPS: Drillships are most often utilized for extremely deep water drilling at
remote locations. A "floater" like the semisubmersible, a drillship must maintain its
position at the drilling location by anchors and mooring lines, or by computer-controlled
dynamic positioning equipment. A series of controllable pitch propellers, or "thrusters,"
shift position and speed to maintain the ship over the wellbore. The drilling slot, or
"moon pool," is through the ship's midsection, as shown in Figure 6 and Figure 7 . Most
drillships have greater storage capacity than other types of rigs, allowing efficient
operation at remote locations.
STRUCTURE RIGS: Structure rigs are mounted on a fixed drilling and production
platform, with all necessary auxiliary equipment secured on the deck. The derrick and
substructure are usually capable of skidding to different positions on the platform
structure; following the drilling and completion of multiple wells, the rig may be
dismantled and removed during the production phase of the program. Subsequent
remedial work on these platforms may require the rig to be replaced. In some cases, the
configuration of wells on the platform allows a jack-up rig to service the location.
Permanent drilling and production structures vary widely in design and capabilities. A
few of the most common designs are :
• piled-steel platforms
• concrete gravity structures
• caisson-type monopod structures
• guyed towers
• tension leg platforms

Each drilling rig operates four basic fuctions: hoisting, rotating, circulating, and
controlling that are corresponding to the four systems installed on the rig.


Unit. Hoisting system
I. Reading comprehension
The mast and the substructure it sits upon support the weight of the drillstem and
allow vertical movement of the suspended drillpipe. The substructure also supports the
rig floor equipment and provides workspace for its operation. The drillstring must be
removed from time to time; the length of drillpipe section that can be disconnected and
stacked to one side of the derrick is determined by the height of the mast. A joint of
drillpipe is about 30 ft (9.1 m) long, and a mast that will allow the pulling and stacking of
pipe, in three-joint sections (90 ft or 27.4 m), is about 140 ft (42.7 m) high.
The drawworks is a spool or drum upon which the heavy steel cable (drilling line)
is wrapped. From the drawworks, the line is threaded through the crown block at the top
of the mast and then through the traveling block, which hangs suspended from the crown
block ( Figure 1 ).

By reeling in or letting out drill line from the drawworks drum, the traveling block
and suspended drillstem can be raised or lowered. In order to safely

manage

the

movement of such a heavy load with precision, the driller relies on an electrical or
hydraulic brake system to control the speed of the traveling block and a mechanical brake
to bring it to a complete stop. The drawworks also features an auxiliary axle,
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or


"catshaft," with rotating spools on each end called "catheads." One spinning cathead is
used to provide power to tighten the drillpipe joints via a cable from the cathead to the
rotary tongs. The other cathead is for "breaking out" or loosening the pipe joints when the
pipe is being withdrawn in sections.
The wire rope drilling line that is spooled onto the drawworks drum undergoes a
certain degree of wear as the block is raised and lowered in the derrick. For this reason
the line is routinely "slipped" (moved onto the drawworks drum) and replaced with a new
section from the continuous spool on which it is stored. The line is clamped at the storage
spool end by a deadline anchor. The hook is attached to the traveling block and is used to
pick up the drillstem via the swivel and kelly when drilling, or with elevators when
tripping into or out of the hole.

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Unit. Rotating system
I. Reading comprehension
The swivel allows the drillstem to rotate while supporting the weight of drillstring
in the hole and providing a pressure-tight connection for the circulation of drilling fluid.
The drilling fluid enters the swivel by way of the "gooseneck," a curved pipe connected
to a high pressure hose. Connected to the swivel is the kelly, a three-, four-, or six-sided
40 ft (12.2 m) length of hollow steel, which is used to transmit the rotary movement of
the rotary table to the drillstring. (The term drillstem refers to the kelly and attached
drillpipe, drill collars, and bit. The term drillstring refers to the drillpipe and drill collars.
However, most folks in the oil patch disregard these rules and use whichever they
please!) The kelly cock is a special valve on the end of the kelly nearest the swivel,
which can be closed to shut in the drillstem. A lower kelly cock is also available on the

bottom end of the kelly to perform the same function when the upper kellycock is not
accessible. The flat sided-kelly fits through a corresponding opening in the kelly drive
bushing, which in turn fits into the master bushing set into the rotary table. The rotary
table is turned by the rig's power source, the table turns the bushings, the kelly bushing
turns the kelly, the kelly turns the drillpipe, and so on . . . down to the bit. Note that in
place of this conventional rotating system, many modern rigs have gone to the use of
power swivels and top-drive units.


Unit. Circulating system
I. Reading comprehension
Circulation of a drilling fluid to carry cuttings up the hole and cool the bit is an
important function of any rotary drilling rig. The heart of the circulation system is the
mud pump (or pumps), which is powered by the rig's prime power source, as are the
rotary table and drawworks. Mud pumps are positive displacement pumps that push a
volume of drilling mud through the system with each stroke of their pistons. The output
of a mud pump can be determined from the piston and cylinder sizes, the number of
strokes per minute, and type of piston arrangement. The mud pumps pump the drilling
fluid from the mud pit or tanks up the stand-pipe to a point on the derrick where the
rotary hose connects the standpipe to the swivel. This flexible, high-pressure hose allows
the traveling block to move up and down in the derrick while maintaining a pressure-tight
system. The circulating drilling mud moves through the swivel, kelly, drillpipe, and drill
collars, exiting through the bit at the bottom of the hole. The mud moves up the annular
space between pipe and hole (or casing), carrying the drilled rock in suspension.

At the surface, the mud leaves the hole through the return line and falls over a
vibrating screen called the shale shaker. This device screens out the cuttings and dumps
some of them into a sample trap and the rest into the reserve pit. Once cleaned of large
cuttings, the mud is returned to a mud tank, from which it can be once again pumped
down the hole. Fine particles are removed by centrifugal force by flowing the mud

7


through desanders, desilters, or a centrifuge. A degasser is used to remove small amounts
of gas picked up in the mud from the subsurface formations.

8


Unit. Controlling system
I. Reading comprehension
Controlling the subsurface pressures encountered while drilling is an important
part of the operation. One of the purposes of the drilling mud is to provide a hydrostatic
head of fluid to counterbalance the pore pressure of fluids in permeable formations.
However, for a variety of reasons the well may "kick"; that is, formation fluids may flow
into the wellbore, upsetting the balance of the system, pushing mud out of the hole, and
exposing the upper part of the hole and equipment to the higher pressures of the deep
subsurface. If left uncontrolled, this can lead to a "blowout," with the formation fluids
forcefully erupting from the well, often igniting, and endangering the crew, the rig, and
the environment.
The blowout preventers are a series of powerful sealing elements designed to close
off the annular space between the pipe and hole where the mud is normally returning to
the surface. By closing off this route, the well can be "shut-in" and the mud and/or
formation fluids forced to flow through a controllable choke, or adjustable valve. This
choke allows the drilling crew to control the pressure that reaches the surface and to
follow the necessary steps for "killing" the well and restoring a balanced system. Figure 1
shows a typical set of blowout preventers, including the annular preventer, which has a
rubber sealing element that is hydraulically squeezed to conform tightly to the drillpipe in
the hole.

Figure 1. BOP system
Also shown are ram type preventers. These include pipe rams, which close around
the pipe with rubber-lined steel sealing elements, and blind rams, which seal off the
wellbore when there is no pipe in the hole. Shear rams are a type of blind ram that can
crimp the pipe in two with a powerful hydraulic force to seal off the hole. Blowout
preventers are opened and closed by hydraulic fluid stored under 1500 to 3000 psi
(10,000 to 20,000 kPa) in an accumulator. The choke manifold houses the series of
positive and/or adjustable chokes that are usually controlled from a remote panel on the
rig floor. Often, a rig that is encountering frequent gas kicks will also have a mud-gas
separator, which saves the drilling mud that is expelled along with a large flow of
formation gas, and separates the gas for safe flaring at some distance from the rig.
When a kick (influx of formation fluid) occurs, rig operators or automatic systems
close the blowout preventer units, sealing the annulus to stop the flow of fluids out of the
wellbore. Denser mud is then circulated into the wellbore down the drill string, up the
annulus and out through the choke line at the base of the BOP stack through chokes (flow
restrictors) until downhole pressure is overcome. Once “kill weight mud” extends from
the bottom of the well to the top, the well has been “killed”. If the integrity of the well is
intact, drilling may be resumed. Alternatively, if circulation is not feasible it may be
possible to kill the well by "bullheading", forcibly pumping, in the heavier mud from the
top through the kill line connection at the base of the stack. This is less desirable because
of the higher surface pressures likely needed and the fact that much of the mud originally
in the annulus must be forced into receptive formations in the open hole section beneath
the deepest casing shoe.
Exploitable reservoirs of oil and gas are increasingly rare and remote, leading to
increased subsea deepwater well exploration and requiring BOPs to remain submerged
for as long as a year in extreme conditions. As a result, BOP assemblies have grown
larger and heavier (e.g. a single ram-type BOP unit can weigh in excess of 30,000
pounds), while the space allotted for BOP stacks on existing offshore rigs has not grown
commensurately. Thus a key focus in the technological development of BOPs over the

last two decades has been limiting their footprint and weight while simultaneously
increasing safe operating capacity.

10


Unit. Power Generation/Transmission system
I. Reading comprehension
Hoisting, rotating, and circulating equipment is supplied with power from a prime
power source, usually diesel engines. Engine capacity may range from 500 to 6000 Hp,
and power may be transmitted to the rig either mechanically or electrically. Mechanical
drive rigs have a combination of belts, sprockets, clutches, and pulleys, which transfer
power from the diesel engines to the drawworks, pumps, and rotary table. The more
modern diesel-electric rigs use their engines to drive generators that produce electricity.
This electricity is sent through cables to a switch and control house from which point it is
relayed to power the electric motors of each end user.

11


Unit. Casings and the casing head
I. Reading comprehension
Suppose an oil well were just a “hole in the ground,” with no protection. During
the drilling, soft earth or high formation pressures would probably make the well-bore
cave in, or collapse. Therefore, a well completed and produced without protection would
be very wasteful. In that unprotected well, oil and other reservoir fluids would leak, or
seep from the well-bore into other formations. In order to those phenomena, casing
strings are used to protect the well-bore during drilling. After the well is completed, the
casing strings continue to prevent cave-ins and leakage, or seepage from the well-bore.
1

Casing is a steel pipe ranging from less than 4 /2 inches OD to more than 20 inches OD.
Casing pipe put together with leakproof connections is called a casing string. Through
out the drilling, more than one casing string may be set in the well-bore.

Drilling

continues inside each casing string after it is set. So, The first casing string installed has
the largest OD.

Figure. Casings
The casing string that completes the well-bore to a producing formation is called
the production casing. The production casing has the smallest OD compared with other
casing strings in the well-bore. If the well is completed with only one casing string, that
string play the role of the production casing. Usually, the first string installed is the
surface casing. Hence, the surface casing is the casing with the largest OD. Sometimes, a
conductor casing is set before the surface casing.The first casing string installed is always
the shortest casing string in the well-bore. If no conductor casing is set, the shortest
casing string in the well-bore is the

surface casing. This first string of casing is held in


place with cement. If only one string of casing is used to complete the

well,

the

production casing is held by cement all the way to the producing formation. Normally , it
is the surface casing that is completely cemented in. At the bottom of the string, the

production casing, like the surface casing, is cemented in place. In a two casing-string
completion, the production casing is run inside the surface casing. To support the
production casing from the surface, a casing head is used.
The casing head has a bowl which supports the casing hanger. This casing hanger
supports the production casing. The casing head screws into or is welded onto the top of
the surface casing. Or, at the well head, the weight of the production casing is actually
supported by the surface casing.
Some wells are completed with three casing strings. An intermediate casing string
may be set inside the surface casing.
Then the production casing is set inside the intermediate casing. The intermediate
casing is longer than the surface casing but shorter than the production casing. It is used
when formation pressures and drilling depths make three casing strings necessary. When
an intermediate casing string is used, it is supported at the top by a casing head set on the
surface casing. Then, to support the production casing from the surface, a second casing
head is used. A well completed with three casing strings has two casing heads. The
uppermost casing head supports the production & intermediate casing. The lowermost
casing head sits on the surface casing and supports the cemented in place casing in a well
completed with three casing strings.
Finally, The surface casing is usually:
- supported by a casing head.
- cemented in place.


Unit. Fishing jobs
I. Reading comprehension
Sometimes, items of drilling equipment get lost in the borehole. When an item of
equipment is lost in the hole, it’s called a ‘fish’. A lost item is also called ‘junk’. Drilling
cannot continue until the fish or junk is recovered from the hole. To recover the lost item,
a fishing job is necessary. Special fishing tools are used for latching on to the fish and
hoisting it up to surface. There are many types of fishing tools. For example, there is a

type of fishing tool called a ‘junk basket’, and there is another type called a ‘spear’. Look
diagram below.
As you can see, these fishing tools are very different. The spear is used the bore of
the lost pipe. The diameter of the spear, therefore, must be smaller than the diameter of
the pipe in the hole. When the spear enter the pipe, its teeth pull out, and grip the inner
sides of the tightly. Then it is usually possible to hoist the fish out of the borehole.
The junk basket is used for latching on to smaller pieces of junk. It’s used for
recovering lost bit cutters, for example. The bottom part of the basket is a shoe with hardfaced teeth. The shoe has a hole in its centre. The fish is forced through the hole and enter
the barrel of the basket. Spring-loaded fingers prevent the fish from dropping out of the
barrel and falling back into the well.
Before a fishing job can begin, the string must be tripped out of the hole. First, the
kelly is broken out and is set in the rathole. Then the string is broken out in stands and the
stands are stood back on the rig floor. When all of the stands are stood back, the fishing
can begin. The toolpusher usually takes charge of the fishing operation.


Unit. Wellhead
I. Reading comprehension
A wellhead consists of pieces of equipment mounted at the opening of a well to
manage the extraction of hydrocarbons from an underground formation. It prevents the
leakage of oil or natural gas out of the well, and also prevents blowouts caused by high
pressure. Formations that are under high pressure typically require wellheads that can
withstand a great deal of upward pressure from the escaping gases and liquids. These
wellheads must be able to withstand pressures of up to 20,000 pounds per square inch
(psi). The wellhead consists of three components: the casing head, the tubing head, and
the 'christmas tree.’
The casing head consists of heavy fittings that provide a seal between the casing
and the surface. The casing head also serves to support the entire length of casing that is
run all the way down the well. This piece of equipment typically contains a gripping
mechanism that ensures a tight seal between the head and the casing itself.

The tubing head is much like the casing head. It provides a seal between the
tubing, which is run inside the casing, and the surface. Like the casing head, the tubing
head is designed to support the entire length of the casing, as well as provide connections
at the surface, which allow the flow of fluids out of the well to be controlled.
The 'christmas tree' is a piece of equipment that fits on top of the casing and tubing
heads, and contains tubes and valves that control the flow of hydrocarbons and other
fluids out of the well. It commonly contains many branches and is shaped somewhat like
a tree, thus its name, ‘christmas tree.’ The christmas tree is the most visible part of a
producing well, and allows for the surface monitoring and regulation of the production of
hydrocarbons from a producing well. A typical Christmas tree is about six feet tall.
When selecting a well, head the casing size, weight and thread must be known.
The inner string is tubing and most of the time will be 2 3/8" in diameter. The tubing
string must be suspended by slips or hangers and set in tension at the surface on all
standard RFI systems. The casing head pressure rating (2000 to 3000psig) must be
properly selected and the side outlets are most often 2" LP size and the packing material,
either nitrile or other seal/o-ring materials, must be properly selected.
The diagram below describes a typical DGWS (downhole

gas

and

water

separation) wellhead configuration. This configuration prevents excessive tubing pressure
build- up if a failure downhole occurs.



Unit. Packers

I. Reading comprehension
A production packer is an equipment used to provide a seal between the outside
of the production tubing and the inside of the casing, liner, or wellbore wall. It also
functions as a casing protection, a medium to separate multiple zones etc.,.
Based on its primary use, packers can be divided into two main categories:
production packers and service packers. Production packers are those that remain in the
well during well production and service packers are used temporarily during well service
activities such as cement squeezing, acidizing, fracturing and well testing etc.,.
In wells with multiple reservoir zones, packers are used to isolate the perforations
for each zone. In this situation, a sliding sleeve would be used to select which zone to
produce. Packers may also be used to protect the casing from pressure and produced
fluids, isolate sections of corroded casing, casing leaks or squeezed perforations, and
isolate or temporarily abandon producing zones. In waterflooding developments in which
water is injected into the reservoir, packers are used in injection wells to isolate the zones
into which the water must be injected.
A production packer is designed to grip and seal against the casing ID. Gripping is
accomplished with metal wedges

called

"slips."

These

components

have

sharpened, carburized teeth that dig into the metal of the casing. Sealing is accomplished
with large, cylindrical rubber elements. In situations where the sealed pressure is very

high (above 5,000 psi), metal rings are used on either side of the elements to prevent the
rubber from extruding.
A packer is run in the casing on production tubing or wireline. Once the desired
depth is reached, the slips and element must be expanded out to contact the casing. Axial
loads are applied to push the slips up a ramp and to compress the element, causing it to
expand outward. The axial loads are applied either hydraulically, mechanically, or with a
slow burning chemical charge.
Most packers are "permanent" and require milling in order to remove them from
the casing. The main advantages of permanent packers are lower cost and greater sealing
and gripping capabilities.
In situations where a packer must be easily removed from the well, such as
secondary recoveries, re-completions, or to change out

the

production

tubing,

a

retrievable packer must be used. To unset the tool, either a metal ring is sheared or a
sleeve is shifted to disengage connecting components. Retrievable packers have a more
complicated design and generally lower sealing and gripping capabilities, but
removal and subsequent servicing, they can be reused.

after


There are three types of packers: mechanical, hydraulic set and

permanent packer.

All packers fall into one or a combination of these.
Mechanical Set Packers: These are set by some form of tubing movement,
usually a rotation or upward /downward motion. They are used best in shallow low
pressure wells that are straight, and not designed to withstand pressure differences unless
a hydraulic hold down is incorporated.
Tension Set packers: set by pulling a tension on the tubing, slacking off releases
the packer. This type of packer is good for shallow wells with moderate pressure
differences.
Rotation Set packers: used to set the packer to mechanically lock it in; an left
hand turn engages and a right hand turn retrieves it.
Hydraulic Set packers: use fluid pressure to drive the cone behind the slips. Once
set they remain set by the use of either entrapped pressure or a mechanical lock. They are
released by picking up the tubing. They are good for used in deviated/ crooked holes
where tubing movement is restricted or unwanted. The tubing can be hung in neutral
tension.
Inflatable rubber/Balloon packers: Use fluid pressure to inflate a balloon and set
the packer. They can’t withstand high pressure differentials and are only used in specialty
applications and in wells where the casing or open holes are collapsed.
Permanent packers: Run and set on an electric wireline, drill pipe or tubing. They
are good in wells that have high pressure differentials or large tubing load variations and
can be set precisely. They can be set the deepest.
Cement packer : In this case the tubing is cemented in place inside the casing or
open hole. This type of packer is cheap.


Unit. Pumps and pumping system
I. Reading comprehension

Pumps are classified as either "kinetic" or "positive displacement" pumps. In a
kinetic pump, energy is added continuously to increase the fluid's velocity within the
pump to values in excess of those that exist in the discharge pipe. Passageways in the
pump then reduce the velocity until it matches that in the discharge pipe. From
Bernoulli's law, as the velocity head of the fluid is reduced, the pressure head must
increase. Therefore, in a kinetic pump, the kinetic or velocity energy of the fluid is first
increased and then converted to potential or pressure energy.
Almost all kinetic pumps used in production facilities are centrifugal pumps in
which the kinetic energy is imparted to the fluid by a rotating impeller generating
centrifugal force. In a positive displacement pump, the volume containing the liquid is
decreased until the resulting liquid pressure is equal to the pressure in the discharge
system. Most positive displacement pumps are reciprocating pumps where the
displacement is accomplished by linear motion of a piston in a cylinder. Rotary pumps
are another common type of positive displacement pump, where the displacement is
caused by circular motion.
A pump distinguishes from other pumps by its basic parameters. The basic pump
parameters to be considered belong to two groups of hydraulic and rotational variables.
The hydraulic variables consist of head, capacity (or flow), and efficiency. Head is
simply a pressure unit that is commonly used in hydraulic engineering that is expressed
in feet of pumped fluid (or in meter). That is to say, it is the pressure that is exerted from
the weight of a height of a given liquid; hence the unit of feet (meters in the metric
system of units). And It’s usually denoted as H. The capacity of a pump is the amount of
liquid conveyed per unit time. It is actually the volumetric rate of flow. Other common
terms for capacity are flow rate and discharge rate. The classical English unit is gallons
per minute (gpm). The metric equivalents are liters per minute (R/min) or cubic meters
per second (m³/sec). Capacity will be denoted as Q. Efficiency is a measure or indication
of the amount of loss. The term entropy is used to define unavailable or lost energy;
entropy is ever increasing. We must be careful when we discuss efficiency because there
are no less than four efficiencies involved in centrifugal pump systems. These are (1)
hydraulic efficiency, (2) mechanical efficiency, and (3) drive efficiency. The overall

pump operational efficiency (4) is the product of the three preceding efficiencies.
The rotational (maybe they should be referred to as mechanical) variables are
power, speed, and impeller diameter. In physics, power is defined as work per unit time.
In the field of engineering, power is defined as the ability to do work. Units for power are


the horsepower (hp) and the kilowatt (kw). With centrifugal pumps we deal with the
former; the unit of horsepower is commonly used interchangeably with, and taken to
mean the variable of power. Here again we must be careful. When we discuss
horsepower there exists no less than three different horsepowers involved in centrifugal
pump systems. These are (1) hydraulic horsepower, (2) brake horsepower, and (3) drive
or motor horsepower. Hydraulic horsepower, sometimes referred to as water horsepower
(WHP), is the power imparted to the liquid by the pump.
Rotational Speed Rotational speed is the scalar quantity of the dynamics term
known as angular velocity. Rotational speed is generally referred to simply as speed. The
unit of revolutions per minute (rpm) is used in conjunction with speed. And the last is
impeller Diameter, this is the simplest variable to define.
In order to make a selection of the pumps required for a specific installation, it is
necessary to first determine the purposes of pumps to be used, then the desired flow rate
or head. The NPSH (net possitive suction head) available should be determined, and if a
centrifugal selection is possible, a system head-flow-rate curve should be developed.
Usually, centrifugal pumps are used for production and transportation while possitive
displacement or piston pumps are mainly used for drilling operations basing on the
advantages and disadvantages of each type of pump.

20


Unit. Gathering center
I. Reading comprehension

After the crude has been brought to the surface, the next step is to process it into
the form in which it will be sent on to the refinery. Through the flowlines, production
from the various wellheads in the field is directed to the gathering centre. Offshore, for
reasons of space and cost, the gathering centre is the production platform itself. At the
gathering centre, the oil is treated to bring it up to pipeline and refinery specification.
Water and dissolved salts can seriously corrode chokes, valves and pipe walls, and must
therefore be removed from the crude before it is transported. Dehydration and
desalination can be accomplished by electrical precipitation, heating, and washing with
fresh
Reservoir crude also has to be treated to separate associated gas. Separation of the
gas may be a single-stage or a multi-stage operation, depending on the gas/oil ratio. In
single-stage separation, only one oil-gas separator is used. Separators can be vertical,
inclined, or horizontal.
Natural gas may also require treatment at the gathering centre, particulary if it
contains water vapour. When a high-pressure gas is expanded to a lower temperature,
considerable cooling takes place. If the gas contains water vapour, this cooling can cause
the formation of hydrates, and these may plug chokes, valves and pipelines. The gas is
dehydrated in a large steel vessel known as a ‘scrubber’, in which the water is removed
by the absorbing action of glycol. Natuaral gas frequently contains considerable amounts
of the corrosive and highly toxic acid gas H2S (hydrogen sulphide), and treatment must
be avaiable for this as well as for water vapour.
Trunk lines connect the gathering centre to the refinery or tanker terminal. Many
kilometres of large-diameter pipeline (eg, 26’’ or 32’’ OD) may be required. Problems
inside the lines must be prevented, or quickly corrected when they occur. The devices
which test, log, clean and unblock oil pipelines are know as ‘pigs’. Each type of pig is
usually reffered to by a special name. One type of rig, for example, is known as a
‘rabbit’. In product pipelines, pigs can be used to separate two or more different oil
products which are being sent at the same time through a single line.

Unit. Separators
I. Reading comprehension
The function of an oil production facility is to separate the oil well stream into three
components or “phases” (oil, gas, and water), and process these phases into some
marketable products or dispose of them in an environmentally accept-able manner. In
mechanical devices called “separators”, gas is flashed from the liquids and “free water” is
separated from the oil. These steps remove enough light hydrocarbons to produce a stable
crude oil with the volatility (i.e., vapor pressure) to meet sales criteria. An oil and gas
separator generally includes the following essential components and features:
1. A vessel that includes (a) primary separation device and/or section, (b) secondary “gravity”
settling (separating) section, (c) mist extractor to remove small liquid particles from the
gas, (d) gas outlet, (e) liquid settling (separating) section to remove gas or vapor from oil
(on a three-phase unit, this section also separates water from oil), (f) oil outlet, and (g)
water outlet (three-phase unit).
2. Adequate volumetric liquid capacity to handle liquid surges (slugs) from the wells and/or
flowlines.
3. Adequate vessel diameter and height or length to allow most of the liquid to separate from
the gas so that the mist extractor will not be flooded.
4. A means of controlling an oil level in the separator, which usually includes a liquid-level
controller and a diaphragm motor valve on the gas outlet.
5. A backpressure valve on the gas outlet to maintain a steady pressure in the
vessel.
6. Pressure relief devices.
Separators

work

on

the

principle

that

the

three

components

have

different densities, which allows them to stratify when moving slowly with gas on
top, water on the bottom and oil in the middle. Any solids such as sand will also settle in
the bottom of the separator. The functions of oil and gas separators can be divided into
the primary and secondary functions which will be discussed later on.
Separators are classified as “two-phase” if they separate gas from the total liquid
stream and “three-phase” if they also separate the liquid stream into its crude oil and
water components. The classification of oil and gas separators include :
- Classification by operating configuration : Oil and gas separators can have three
general configurations: vertical, horizontal, and spherical.
- Classification by function : The three configurations of separators are available for twophase operation and three-phase operation. In the two-phase units, gas is separated from
the liquid with the gas and liquid being discharged separately. In three-


phase separators, well fluid is separated into gas, oil, and water with the three fluids
being discharged separately
- Classification by operating pressure : Oil and gas separators can operate at pressures
ranging from a high vacuum to 4,000 to 5,000 psi. Most oil and gas separators operate in

the pressure range of 20 to 1,500 psi
- Cassification by application : separators may be classified as test separator, production
separator, low temperature separator, metering separator, elevated separator, and stage
separators (first stage, second stage, etc.).

There are several new concepts currently under development in which the fluids are
degassed upstream of the primary separator. These systems are based on centrifugal and
turbine technology and have additional advantages in that they are compact and motion
insensitive, hence ideal for floating production facilities. The methods listed are some of
the ways in which oil is separated from gas in separators : Density Difference (Gravity


Separation) ; impingement ; Change of Flow Direction ; Change of Flow Velocity and
Centrifugal Force.
Because of higher prices for natural gas, the widespread reliance on metering
of liquid hydrocarbons, and other reasons, it is important to remove all nonsolution gas
from crude oil during field processing. Methods used to remove gas from crude oil in oil
and gas separators are: settling , agitation, heat and centrifugal force.


Unit. Pipeline
I. Reading comprehension
The first pipeline was built in the United States in 1859 to transport crude oil.
Through the one-and-a-half century of pipeline operating practice, the petroleum industry
has proven that pipelines are by far the most economical means of large scale overland
transportation for crude oil, natural gas, and their products, clearly superior to rail and
truck transportation over competing routes, given large quantities to be moved on a
regular basic. Nowadays, offshore pipeline is the unique means of efficiently
transporting offshore fluids, i.e., oil, gas, and water.
Offshore pipelines can be classified into categories as follows:

-Flowlines transporting oil and/or gas from satellite subsea wells to subsea manifolds;
-Flowlines transporting oil and/or gas from subsea manifolds to production facility platforms;
-Infield flowlines transporting oil and/or gas between production facility platforms;
-Export pipelines transporting oil and/or gas from production facility platforms to shore;
-Flowlines transporting water or chemicals from production facility platforms, through
subsea injection manifolds, to injection wellheads.
The further the downstream from the subsea wellhead, as more streams commingle,
the larger the diameter of the pipelines. Of course, the pipelines are sized to handle the
expected pressure and fluid flow. To ensure desired flow rate of product, pipeline size
varies significantly from project to project. To contain the pressures, wall thicknesses of
the pipelines range from 3/8 inch to 11⁄2 inch.
Design of marine pipelines is usually carried out in three stages: conceptual
engineering, preliminary engineering, and detail engineering. During the conceptual
engineering stage, issues of technical feasibility and constraints on the system design and
construction are addressed. Potential difficulties are revealed and non-viable options are
eliminated. Required information for the forthcoming design and construction are
identified. The outcome of the conceptual engineering allows for scheduling of
development and a rough estimate of associated cost. The preliminary engineering
defines system concept (pipeline size and grade), prepares authority applications, and
provides design details sufficient to order pipeline. In the detail engineering phase, the
design is completed in sufficient detail to define the technical input for all procurement
and construction tendering.