140717 artificial lift

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Artificial Lift
Artificial Lift
PTRT 2325_Artificial Lift
Chapter 01_C
Source: WWW

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Types of Artificial Lift
• Introduction
• Beam Pumping – Sucker Rod Pumping
• Electric Submersible Pumps – ESP
• Subsurface Hydraulic Pumps
• Progressing Cavity Pumps – PCP
• Gas Lift
• Plunger Lift
• x
• sucker-rod (beam) pumping, ESP, gas lift, and reciprocating and
jet hydraulic pumping systems. Also, plunger lift and PCP are
becoming more common.
x
Source:
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Basics of Artificial Lift
• When the reservoir pressure falls below the pressure
that is necessary to bring petroleum fluids to the
surface sum form of artificial means must be employed
to bring fluids to the surface
• The process of bringing lower pressure fluids to the
surface is termed artificial lift
• x
• x
Source:
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Introduction to Artificial Lift
• Artificial lift is a method used to lower the producing
bottomhole pressure (BHP) on the formation to obtain a
higher production rate from the well.
• This can be done with a positive-displacement
downhole pump, such as a beam pump or a progressive
cavity pump (PCP), to lower the flowing pressure at the
pump intake.
Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems
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• It also can be done with a downhole centrifugal pump,
which could be a part of an electrical submersible pump
(ESP) system.
• A lower bottomhole flowing pressure and higher flow
rate can be achieved with gas lift in which the density of
the fluid in the tubing is lowered and expanding gas
helps to lift the fluids.
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• Artificial lift can be used to generate flow from a well in
which no flow is occurring or used to increase the flow
from a well to produce at a higher rate.
• Most oil wells require artificial lift at some point in the
life of the field, and many gas wells benefit from
artificial lift to take liquids off the formation so gas can
flow at a higher rate.
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• To realize the maximum potential from developing any
oil or gas field, the most economical artificial lift
method
must be selected
• The methods historically used to select the lift method
for a particular field vary broadly across the industry.
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• The manner utilized to select the best artificial lift
methods include
- operator experience
- what methods are available for installations in certain areas
of the world
- what is working in adjoining or similar fields
- determining what methods will lift at the desired rates and
from the required depths
- evaluating lists of advantages and disadvantages
- "expert" systems to both eliminate and select systems
- evaluation of initial costs, operating costs, production
capabilities, etc. with the use of economics as a tool of
selection, usually on a present-value basis.
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• When significant costs for well servicing and high
production rates are a part of the scenario, it becomes
prudent for the operator to consider most, if not all, of
the available evaluation and selection methods.
• If the "best" lift method is not selected, such factors as
long-term servicing costs, deferred production during
workovers, and excessive energy costs (poor
efficiency) can reduce drastically the net present value
(NPV) of the project.
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• Typically, the reserves need to be produced in a timely
manner with reasonably low operating costs
• Conventional wisdom considers the best artificial lift
method to be the system that provides the highest
present value for the life of the project
• Good data are required for a complete present-value
analysis, and these data are not always broadly
available.
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• In some situations, the type of lift already has been
determined and the task is to best apply that system to
the particular well
• The more basic question, however, is how to determine
the proper type of artificial lift to apply in a given field
for maximum present value profit (PVP)
• This chapter briefly reviews each of the major types of
artificial lift before examining some of the selection
techniques
• Some less familiar methods of lift also are mentioned
• Preliminary factors related to the reservoir and well
conditions that should be considered are introduced
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• Environmental and geographical considerations may be
overriding issues in the determination of the lift method
• Sucker-rod pumping is, by far, the most widely used
artificial lift method in onshore United States
operations
• However, in a densely populated city or on an offshore
platform with 40 wells in a very small deck area, sucker-
rod pumping might be a poor choice.
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• Deep wells producing several thousands of barrels per
day cannot be lifted by beam lift; therefore, other
methods must be considered
• Such geographic, environmental, and production
considerations can limit the choices to only one method
of lift
• Determining the best overall choice is more difficult
when it is possible to apply several of the available lift
methods.
• x
• x
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Artificial Lift
x
Beam Pumping
Source: PETEX_Fundamentals of Petroleum_5th
_Denehy
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Beam Pumping
• Beam pumping is the most common method of bringing
subsurface oil to the surface
• Beam pumping involves both surface and subsurface
equipment
• The pumping action is derived from the rotary motion of
a prime mover (electric motor) into an up-and-down
motion that actuates a below surface pump the forces
oil to the surface
• x
• xsucker-rod (beam) pumping, ESP, gas lift, and reciprocating and
jet hydraulic pumping systems. Also, plunger lift and PCP areSource: PETEX_Fundamentals of Petroleum_5th
_Denehy
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Pump Jack
Source: www
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Pump Jack
Source: www
Artificial Lift

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Pump Jacks
Source: www
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Pump Jack Oil Pumping System
Source: www
x
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Beam Pumping – Sucker Rod Pumping
Schematic of a beam-pumping system. (from Harbison-Fischer)
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• Sucker-rod pumping systems are the oldest and most
widely used type of artificial lift for oil wells
• x
• x
• x
• x
• x
• x
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• There are approximately 2 million oil wells in operation
worldwide
• More than 1 million wells use some type of artificial lift
• More than 750,000 of the lifted wells use sucker-rod
pumps
• In the U.S., sucker-rod pumps lift approximately 350,000
wells.
• x
• x
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• Approximately 80% of all U.S. oil wells are stripper wells
making less than 10 B/D with some water cut. (date???)
• The vast majority of these stripper wells are lifted with
sucker-rod pumps
• Of the nonstripper "higher" volume wells, 27% are rod
pumped, 52% are gas lifted, and the remainder are lifted
with ESPs, hydraulic pumps, and other methods of lift
• These statistics indicate the dominance of rod
pumping for onshore operations
• For offshore and higher-rate wells around the world, the
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• Sucker-rod pumping systems should be considered for
new, lower volume stripper wells because they have
proved to be cost effective over time
• In addition, operating personnel usually are familiar
with
these mechanically simple systems and can operate
them efficiently
• Inexperienced personnel also can operate rod pumps
more effectively than other types of artificial lift
• Sucker-rod pumping systems can operate efficiently
over a wide range of production rates and depths
• Most of these systems have a high salvage value
• x
Considerations for Use of Sucker Rod Pumping
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• Sucker-rod systems should be considered for lifting moderate
volumes from shallow depths and small volumes from intermediate
depths. It is possible to lift up to 1,000 B/D from approximately
7,000 ft and 200 bbl from approximately 14,000 ft. Special rods may
be required, and lower rates may result depending on conditions.
Most of the sucker-rod pumping system parts are manufactured to
meet existing standards, which have been established by the
American Petroleum Institute (API). Numerous manufacturers can
supply each part, and all interconnecting parts are compatible. Many
components are manufactured and used that are not API certified,
such as large-diameter downhole pumps extending to more than 6 in.
in diameter.
• x
Considerations for Use of Sucker Rod Pumping
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x
• x
• xThe sucker-rod string is the length of the rods from the surface to
the downhole pump, and it continuously is subjected to cyclic load
fatigue typical of sucker-rod pump systems. The system must be
protected against corrosion, as much as any other artificial lift
system, because corrosion introduces stress concentrations that can
lead to early failures. Frequent rod failures must be avoided for an
economical system operation.
• x
• x
• x
• x
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x
• x
• xSucker-rod pumping systems often are most incompatible with
deviated (doglegged) wells, even with the use of rod protectors and
rod and/or tubing rotators. However, deviated wells with smooth
profiles and low dogleg severity may allow satisfactory sucker-rod
pumping, even if the angle at the bottom of the well is large
(approximately 30 to 40°, up to 80°). Some high-angle hole systems
use advanced methods of protecting the tubing and rod string with
rod protectors and "roller-rod protectors," while other installations
with high oil cuts, smooth profiles, and lower angles of deviation use
only a few of these devices. Plastic-lined tubing has proven to be
effective in reducing rod/tubing wear.
• xSource: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems
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x
• x
• xSucker-rod pumping systems often are most incompatible with
deviated (doglegged) wells, even with the use of rod protectors and
rod and/or tubing rotators. However, deviated wells with smooth
profiles and low dogleg severity may allow satisfactory sucker-rod
pumping, even if the angle at the bottom of the well is large
(approximately 30 to 40°, up to 80°). Some high-angle hole systems
use advanced methods of protecting the tubing and rod string with
rod protectors and "roller-rod protectors," while other installations
with high oil cuts, smooth profiles, and lower angles of deviation use
only a few of these devices. Plastic-lined tubing has proven to be
effective in reducing rod/tubing wear.
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x
• x
• xOne of the disadvantages of a beam-pumping system is that the
polished-rod stuffing box, in which a polished rod with the rods hung
below enters the well at the surface through a rubber packing
element, can leak. This can be minimized with special pollution-free
stuffing boxes that collect any leakage. Good operations, with such
practices as "don’t over tighten" and "ensure unit alignment with
standard boxes," with standard boxes are also important.
Continuous production with the system attempting to produce more
than the reservoir will produce leads to incomplete pump filling of
the pump, fluid pound, mechanical damage, and low energy
efficiency. Many systems are designed to produce 120 to 150% more
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x
• x
• xIn general, sucker-rod pumping is the method of artificial lift that
should be used if the system can be designed without overloading the
prime mover, gearbox, unit structure, and the calculated fatigue
loading limits of the rods. This system should be considered very
carefully in the selection process and, in many cases, should be the
artificial lift system of choice.
• x
• x
• x
• x
x
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Beam Pumping
x
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Electrical Submersible Pumping
• xAs an example area in which ESPs are applied extensively,
THUMS Long Beach Co. was formed in April 1965 to drill, develop,
and produce the 6,479-acre Long Beach unit in Wilmington field,
Long Beach, California. It was necessary to choose the best method
to lift fluids from the approximately 1,100 deviated wells over a 35-
year contract period from four man-made offshore islands and one
onshore site. ESPs have been the primary system in this environment
for the contract period.
• x
• x
• x
• x
x
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Artificial Lift
x
_Denehy
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• x
• x
• x
• x
• x
• x
• x
• x
• x
• x
x
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• x
• x
• x
• x
• x
• x
• x
• x
• x
• x
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x
• x
• x
• x
• x
• x
• x
• x
• x
• x
• x
Source: www Schlumberger
Electric submersible pump system
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• x
• xMajor ESP Advantages. ESPs provide a number of advantages.
•Adaptable to highly deviated wells; up to horizontal, but must be set
in straight section.
•Adaptable to required subsurface wellheads 6 ft apart for maximum
surface-location density.
•Permit use of minimum space for subsurface controls and associated
production facilities.
•Quiet, safe, and sanitary for acceptable operations in an offshore and
environmentally conscious area.
•Generally considered a high-volume pump.Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems
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• x
• xMajor ESP Disadvantages. ESPs have some disadvantages that
must be considered.
•Will tolerate only minimal percentages of solids (sand) production,
although special pumps with hardened surfaces and bearings exist to
minimize wear and increase run life.
•Costly pulling operations and lost production occur when correcting
downhole failures, especially in an offshore environment.
•Below approximately 400 B/D, power efficiency drops sharply;
ESPs are not particularly adaptable to rates below 150 B/D.
•Need relatively large (greater than 4½-in. outside diameter) casingSource: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems
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• Long life of ESP equipment is required to keep production
economical. Improvements and recommendations based on
experience are in the chapter on ESP in this section of the Handbook
and in "ABB Automation Technology Products Presentation."[4]
• x
• x
• x
• x
• x
• x
• x
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Artificial Lift
x
Progressive Cavity Pumping – PCP
_Denehy
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PCP and the Electrical Submersible Progressive
Cavity Pump
• x
• xThe PCP and the Electrical Submersible Progressive Cavity
Pump
•Fig. 10.5 shows a schematic of a PCP with a rotating metal rotor
and a flexible rubber-molded stator. The stator forms a cavity that
moves up as the rotor turns. The pump is well suited for handling
solids and viscous fluids because the solids that move through the
pump may deflect the rubber stator but do not abrade, wear, or
chemically deteriorate the stator or rotor to any appreciable degree.
Most PCPs are powered by rotating rods driven from the surface with
a hydraulic or electric motor. The system shown in Fig. 10.5 has a
pump small enough that the entire pump can be inserted with rods.
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x
• x
• x
Introduced in 1936, the PCP is of simple design and rugged
construction. Its low (300 to 600 rev/min) operating speeds enable
the pump to maintain long periods of downhole operation if not
subjected to chemical attack or excessive wear or it is not installed at
depths greater than approximately 4,000 to 6,000 ft. The pump has
only one moving part downhole with no valves to stick, clog, or wear
out. The pump will not gas lock, can easily handle sandy and
abrasive formation fluids, and is not normally plugged by paraffin,
gypsum, or scale.
With this system, the rotating rods wear and also wear the tubulars.
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x
• x
• xTo alleviate problems inherent with the conventional rotating-rod
PCP systems, the ESPCP system is available. While the number
installed is still small, this is not a new system. It has been run in
Russia for a number of years and also was available from an ESP
vendor a number of years ago. The newer ESPCP system (Fig. 10.6)
has some advantages over the rotating sucker-rod systems.
• x
• x
• x
• x
x
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x
• x
• x
• x
• x
• x
• x
• x
• x
• x
• xFig. 10.6—Schematic of ESPCP system. (Courtesy of
Centrilift.)
x
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x
• x
• xThere is a problem of rotating the eccentric rotor with the motor
shaft because of possible vibration; therefore, a flexible connection is
used. There is a seal section, as in an ESP assembly, to protect the
underlying motor from wellbore fluids and to accommodate an
internal thrust bearing. Because the PCP usually rotates at
approximately 300 to 600 rev/min, and the ESP motor rotates at
approximately 3,500 rev/min under load, there must be a way of
reducing speed before the shaft connects to the PCP. Methods
available from various manufacturers include the use of a gearbox to
reduce the motor to acceptable speeds (less than approximately 500
rev/min). Another method is to use higher pole motors with lower
synchronous speeds to allow the PCP to turn at operational speeds inx
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x
• x
• xMajor PCP Advantages. PCPs have the following major
advantages.
•The pumping system can be run into deviated and horizontal wells.
•The pump handles solids well, but the coating of the rotor will erode
over time.
•The pump handles highly viscous fluids in a production well with a
looser rotor/stator fit.
•Several of the components are off-the-shelf ESP components for the
ESPCP.
•The production rates can be varied with the use of a variable-speedx
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x
• x
• xMajor PCP Disadvantages. PCPs have the following
disadvantages.
•The stator material will have an upper temperature limit and may be
subject to H 2 S and other chemical deterioration.
•Frequent stops and starts of the PCP pumps often can cause several
operating problems.
•Although it will not gas lock, best efficiency occurs when gas is
separated.
•If the unit pumps off the well or gas flows continuously though the
pump for a short period, the stator will likely be permanentlyx
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x
• x
• xProgressive Cavity Pump Summary. For a low-pressure well
with solids and/or heavy oil at a depth of less than approximately
6,000 ft and if the well temperature is not high (75 to 150°F typical,
approximately 250°F or higher maximum), a PCP should be
evaluated. Even if problems do not exist, a PCP might be a good
choice to take advantage of its good power efficiency. If the
application is offshore, or if pulling the well is very expensive and
the well is most likely deviated, ESPCP should be considered so that
rod/tubing wear is not excessive. There is an ESPCP option that
allows wire lining out a failed pump from the well while leaving the
seal section, gearbox, motor, and cable installed for continued use
• xx
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Artificial Lift
x
Gas Lift
_Denehy
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Gas Lift
• Gas lift is used extensively around the world and
dominates production in the U.S. Gulf Coast with most
these wells are on continuous-flow gas lift
• The principle of gas lift is that gas injected into the
tubing reduces the density of the fluids in the tubing,
and the bubbles have a "scrubbing" action on the
liquids
• Both factors act to lower the flowing BHP at the bottom
of the tubing
• Care must be exercised not to inject excess gas, or
friction will begin to negate the desirable effects of
injecting gas into the tubing.
• xx
Artificial Lift

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Continuous-Flow Gas Lift
• Continuous-flow gas lift is recommended for high-
volume and high-static BHP wells in which major
pumping problems could occur with other artificial lift
methods
• It is an excellent application for offshore formations that
have a strong waterdrive, or in waterflood reservoirs
with good PIs and high gas/oil ratios (GORs).
• If high-pressure gas without compression is available
or when gas cost is low, gas lift is especially attractive.
• Continuous-flow gas lift supplements the produced gas
with additional gas injection to lower the intake
pressure to the tubing, resulting in lower formation
pressure as wellx
Artificial Lift

53Schematic of a gas lift system. (photo from Schlumberger.)
Gas Lift
Artificial Lift

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• A reliable, adequate supply of good quality high-
pressure lift gas is mandatory
• This supply is necessary throughout the producing life
of the well if gas lift is to be maintained effectively
• In many fields, the produced gas declines as water cut
increases, requiring some outside source of gas
• The gas-lift pressure typically is fixed during the initial
phase of the facility design.
• x
• x
x
Gas Lift
Artificial Lift

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• Ideally, the system should be designed to lift from just
above the producing zone
• Wells may produce erratically or not at all when the lift
supply stops or pressure fluctuates radically
• Poor gas quality will impair or even stop production if it
contains corrosives or excessive liquids that can cut
valves or fill low spots in delivery lines
• The basic requirement for gas must be met, or gas lift is
not a viable lift method.
• x
• x
x
Gas Lift
Artificial Lift

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• Continuous-flow gas lift imposes a relatively high
backpressure on the reservoir compared with pumping
methods; therefore, production rates are reduced
• Also, power efficiency is not good compared with some
artificial lift methods, and the poor efficiency
significantly increases both initial capital cost for
compression and operating energy costs.
• x
• x
x
Gas Lift
Artificial Lift

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• Gas lift is the best artificial lift method for handling sand
or solid materials.
• Many wells produce some sand even if sand control is
installed
• The produced sand causes few mechanical problem in
the gas-lift system; whereas, only a little sand plays
havoc with other pumping methods, except the PCP
type of pump
• Deviated or crooked holes can be lifted easily with gas
lift. This is especially important for offshore platform
wells that are usually drilled directionally.
• xx
Gas Lift – Advantages
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• Gas lift permits the concurrent use of wireline
equipment, and such downhole equipment is easily and
economically serviced.
• This feature allows for routine repairs through the
tubing.
• The normal gas-lift design leaves the tubing fully open.
• This permits the use of BHP surveys, sand sounding
and bailing, production logging, cutting, paraffin, etc
• x
• x
x
Gas Lift - Advantages
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• High-formation GORs (gas/oil ratios) are very helpful for gas-lift
systems but hinder other artificial lift systems.
•Produced gas means less injection gas is required; whereas, in all
other pumping methods, pumped gas reduces volumetric pumping
efficiency drastically.
•Gas lift is flexible. A wide range of volumes and lift depths can be
achieved with essentially the same well equipment.
•In some cases, switching to annular flow also can be easily
accomplished to handle exceedingly high volumes.
•A central gas-lift system easily can be used to service many wells
or operate an entire field.
•Centralization usually lowers total capital cost and permits easier
well control and testing
• xx
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• x
• xA gas-lift system is not obtrusive; it has a low profile. The
surface well equipment is the same as for flowing wells except for
injection-gas metering. The low profile is usually an advantage in
urban environments. Well subsurface equipment is relatively
inexpensive. Repair and maintenance expenses of subsurface
equipment normally are low. The equipment is easily pulled and
repaired or replaced. Also, major well workovers occur infrequently.
Installation of gas lift is compatible with subsurface safety valves
and other surface equipment. The use of a surface-controlled
subsurface safety valve with a ¼-in. control line allows easy shut in
of the well. Gas lift can still perform fairly well even when only poor
data are available when the design is made. This is fortunate because
Fundamentals of Petroleum
x

61
• Relatively high backpressure may seriously restrict production in
continuous gas lift. This problem becomes more significant with
increasing depths and declining static BHPs. Thus, a 10,000-ft well
with a static BHP of 1,000 psi and a PI of 1.0 bpd/psi would be
difficult to lift with the standard continuous-flow gas-lift system.
However, there are special schemes available for such wells.
•Gas lift is relatively inefficient, often resulting in large capital
investments and high energy-operating costs. Compressors are
relatively expensive and often require long delivery times. The
compressor takes up space and weight when used on offshore
platforms. Also, the cost of the distribution systems onshore may be
significant. Increased gas use also may increase the size of necessary
flowline and separators.
x
Gas Lift - Disadvantages
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• Adequate gas supply is needed throughout life of project. If the
field runs out of gas, or if gas becomes too expensive, it may be
necessary to switch to another artificial lift method. In addition, there
must be enough gas for easy startups. Operation and maintenance of
compressors can be expensive. Skilled operators and good
compressor mechanics are required for reliable operation.
Compressor downtime should be minimal (< 3%). There is increased
difficulty when lifting low gravity (less than 15°API) crude because
of greater friction, gas fingering, and liquid fallback. The cooling
effect of gas expansion may further aggravate this problem. Also, the
cooling effect will compound any paraffin problem. Good data are
required to make a good design. If not available, operations may
have to continue with an inefficient design that does not produce the
well to capacity.
x
Gas Lift - Disadvantages
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Gas Lift
• x
• x This section addresses the following issues: Why
choose gas lift?; Where should continuous flow be used?;
and When should intermittent lift be selected?
• x
• x
• x
• x
• x
• x
• x
_Denehy
x
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Artificial Lift
x
Plunger Lift
_Denehy
Artificial Lift

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Plunger Lift
• Plunger lift is commonly used to remove liquids from
gas wells or produce relatively low volume, high GOR
oil wells.
• Plunger lift is important and, in its most efficient form,
will operate with only the energy from the well.
• A free-traveling plunger and produced-liquid slug is
cyclically brought to the surface of the well from stored
gas pressure in the casing-tubing annulus and from the
formation.
• In the off cycle, the plunger falls and pressure builds
again in the well.
• x
x
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66
Plunger Lift
• A new two-piece plunger (cylinder with ball underneath)
can lift fluids when the components are together
• But both components are designed to fall when
separate
• Use of this plunger allows a shut-in portion of the
operational cycle that is only a few seconds long,
resulting in more production for many wells.
• x
• x
x
Artificial Lift

67Schematic of a plunger lift installation.
Plunger Lift
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• There is a chamber pump that relies on gas pressure to
periodically empty the chamber and force the fluids to
the surface, which is essentially a gas-powered pump
• There are variations of gas lift and intermittent lift, such
as chamber lift
• The principles presented apply to the selection of all
methods that might be considered.
• x
• x
x
Plunger Lift
Artificial Lift

140717 artificial lift

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