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Artificial Lift Artificial Lift

When the reservoir pressure is insufficient to overcome the surface & hydrostatic pressure in a In some gas production applications, water

well, the reservoir fluid will not flow to the surface naturally regardless of the amount of liquid in the enters the wellbore, develops a hydrostatic head opposing

reservoir. It is then necessary to adopt artificial lift methods to recover the petroleum. gas flow, and interferes with gas production. This

impediment to gas flow may be overcome by using artificial

Stated simply, artificial lift involves methods of transmitting energy to the bottom of a well
lift to remove water from a wellbore in an operation called
(but never into the reservoir) to supplement natural energy in pushing liquids to the surface.
dewatering.
Artificial lift must be used: when liquids will not flow to the surface naturally, however, it may
The decision to use artificial lift must be based
also be used when the natural flow rate is not as high as desired. Thus artificial lift can also be used to
on economic factors. The cost of equipment used for
increase flow rate.
artificial lift is high, but this cost may be more than offset
The purpose of all artificial lift methods is to lower the tubing intake pressure below the natural
by the increased production rates possible. In fact,
flow conditions, thus increasing production.
artificial lift is often used so that the production rate can

be increased when a well is still capable of flowing.

Artificial lift must be used: Artificial Lift

when liquids will not flow to the surface naturally,

Several types of artificial lift methods are prevalent in the petroleum industry,
Also be used when the natural flow rate is not as high as desired, that is to increase
including
flow rate.
Gas Lift,
To dewater the gas wells

Plunger lift & Chamber lift,

Sucker Rod Pumping (SRP)

The purpose of all artificial lift methods is to lower the tubing intake pressure below the natural Electrical Submersible Pumping (ESP)
flow conditions, thus increasing production.
Hydraulic pumping – Piston type hydraulic pump, Jet pumping, Hydraulic

submersible pumping (HSP)

Progressive Cavity Pumping (PCP),

Artificial lift is often used so that the production rate can be increased when a well is still
Turbine Pump etc.
capable of flowing.

ARTIFICIAL METHODS IN NORTH

ARTIFICIAL LIFT METHODS WORLD WIDE
AMERICA

ESP
PCP

Plunger Lift

Gas Lift SRP

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Artificial Lift
STATUS OF WELLS IN OIL INDIA LTD

PURPOSE of artificial lift is to maintain a reduced producing BHP so that the formation can give

up the desired reservoir fluids. Initially, the well may be capable of performing this task under its own
2% 0.5%
power.

In the latter stages of a well’s flowing life and particularly after the well dies, a suitable means

42% 42% of artificial lift must be installed so that the required BHP can be maintained.
58% 58% 55%
Maintaining the required flowing BHP is the basis for the design of any artificial lift installation.

If a predetermined pressure drawdown can be maintained, the well will produce the desired fluids. This is

true regardless of the type of artificial lift installed.

Self Flowing Gas Lift

Artificial Lift Self Flowing
SRP ESP

Gas Lift Gas Lift

Gas Lift is a commonly used form of artificial lift today. It is means of producing fluid whereby energy in the form of compressed gas is transmitted to
the bottom of the well.
It is means of producing fluid whereby energy in the form of compressed gas is transmitted to
the bottom of the well. The compressed gas lifts the fluid by one or combination of the following three processes:

The lifting of fluid using compressed gas is achieved by one or combination of the following Expansion of the compressed gas
three processes:
Aeration (lightening) of the fluid column
Expansion of the compressed gas
Displacement of the oil by the compressed gas.
Aeration (lightening) of the fluid column
Gas under high pressure from a compressor station is supplied to a number of wells.
Displacement of the oil by the compressed gas.
Gas lift system can be adopted for single well or for a number of wells, and may be installed
Gas under high pressure from a compressor station is supplied to a number of wells. It requires either during initial completion or during later workover operations.
injection of gas down the tubing-casing annulus which subsequently enters the tubing through pressure
Gas lift can be used in many oil wells, and is often used to dewater gas wells.
operated gas lift valves.
Gas lift is usually used when the reservoir pressure is still high & when a significant volume of
The compressed gas either lifts the oil mechanically or aerates fluid from the point of gas
gas is available.
injection to the surface so that the well can flow more or less naturally.

Gas lift system can be adopted for single well or for a number of wells, and may be installed
either during initial completion or during later workover operations.

Gas Lift
Gas lift can be used in many oil wells , and is often used to dewater gas wells.

Gas lift is usually used when the reservoir pressure is still high & when a significant volume of
gas is available.

Fig shows a typical Gas lift networks & facilities. On the surface, gas-lift infrastructure
includes compressors, separators, manifolds, field flowlines & export pipelines, which are closely related to
subsurface equipment operation & performance.

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Fig: Typical gas lift network

Compressor
station
Gas export
pipeline Oil storage

Injection gas Produced

gas Oil
Producing export
wells pipeline

Injection gas Produced Oil

entering fluids
Water
Gas & oil
separator
Metering and Production
control manifold Water
disposal
well

Wellhead tubing &

casing pressure

Gas Lift Network system

Sub Surface Equipments of a Gas Lift system

1. Tubing:

The gas liquid mixture is lifted from the bottom to the wellhead along the tubing
column. As the pressure differential across the tubing can sometime be great, it may be necessary to use
high-yield tubing.

2. Packer:

A packer is placed between the tubing & casing which helds te annulus gas off the
formation. It is used to isolate the annular pressure from the bottom hole pressure.

3. Standing Valve:
Tubing

During the process of gas lift operation, the pressure inside the tubing can be very Packer
Casing
high. A standing valve is placed in the bottom of the tubing to keep from pushing lift gas & liquids back into
the formation. However, when the tubing pressure drops, the standing valve opens & allows fluid to enter
the tubing. Standing
Valve Gas lift
4. Gas Lift Valves: valves

A well on gas lift is often equipped with several valves, attached to the tubing, that
are used for unloading the annulus or to gas lift the required producing rate from a required depth.

Fig.: Sub Surface Equipments of a Gas Lift system

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Application of Gas Lift

Gas lift is usually used when the reservoir pressure is still high and when a significant volume of gas is
Advantages of Gas Lift
1. The initial cost of gas lift equipment is less than that of any other type of artificial lift equipment
available. It is often used as a means of assisting the natural flow of a well by aerating the fluid column
particularly for deep lift, provided high pressure gas is available for lifting the well.
to decrease its hydrostatic.
2. The gas lift is probably the most flexible of all types of artificial lifts. The design of a gas lift
To artificially lift oil wells to depletion.
installation can be modified to handle changing well conditions such as production rates and depth of
To kick off wells that later will flow naturally.
lift. The same installation can be designed for lifting from a depth near the surface initially and lifting
To unload water from gas wells.
from near total depth for depletion. Gas lift installation can be designed for lifting thousand of barrels
Gas lifting has been widely applied in oilfields with high gas production rates where other artificial
per day to less than one barrel per day. The installation is sufficient flexible to allow a continuous flow
methods are plagued with frequent failures or cannot be used at all.
from a relative high injection point, then permit an intermittent operation from the bottom as required
Gas lift is especially suited to the offshore environment where extremely high volumes have to be
reliably lifted. Recently there is a case where a liquid rate of 40,000 bpd is achieved from a 10,800 ft by the decline in BHP.

deviated wells through 7” tubing. 3. In contrast to most other artificial lift methods, gas lifting offers a high degree of flexibility. This

Gas lifting can produce any well during the whole lifespan of the well till its abandonment. Higher liquid means that any gas installation can very easily be modified to accommodate extremely great changes in

rates, usually associated with early production times, are achieved by continuous flow. Later, as liquid production rates.

formation pressure and liquid rates gradually decrease, continuous flow can be converted into 4. Gas lift can be used throughout the productive life of the wells, till depletion.

intermittent gas lift to ensure that production goals are met. Close to abandonment, chamber lift can 5. In fields where wells produce substantial amounts of formation gas, many times gas lifting is the only

be applied (again with a minimum of conversion costs), providing the production of the well with choice.

extremely low formation pressures. 6. The surface wellhead equipments of gas lift installation is not complex and requires little space.

Limitations of Gas Lift

Advantages of Gas Lift contd..

1. Natural Gas must be available. In some instances air, exhaust gases and nitrogen have been used
7. Abrasive material in the produced fluid does not effect the operation of gas lift equipment in most
but these are generally more expensive and more difficult to work with than locally produced
installation. The gas lift system is one of the best methods for handling sand producing wells.
natural gas.
8. Gas lift wells is not adversely effected by deviation of the wellbore.
2. Needs high pressure gas source and lines. It requires high capacity gas handling separator.
9. Gas lift is ideally suited to supplement formation gas for the purpose of artificially lifting wells where
3. Usually, a sufficient amount of formation gas production throughout the life of the field is
moderate amounts of gas are present in the produced fluid.
required to maintain the normal operation of the gas lift system.
10. The relatively few moving parts in a gas lift system give it a long service life when compared to other

forms of artificial lift.

11. Operating costs for gas lift installations are usually significantly less than other types of artificial

lifts.

12. The producing rate of gas lift can be controlled at the surface.

13. The major item of equipment (gas compressor) in a gas lift system is installed at the surface which can

be easily inspected, repaired and maintained. The equipment can be driven by either gas or electricity.

Open Installation Production out

Types of Gas Lift Installation
In this type of installation, a tubing string is suspended into

the well with neither packer nor a standing valve.

In general, the type of installation is influenced by a number of factors:
Gas In
Gas is injected down the casing-tubing annular space and
1. Whether the well is to be placed on Intermittent Lift or Continuous Lift.
fluids are removed out of the tubing.
2. Well conditions: High or low PI, High or low BHP
This type of installation leaves communication between the
3. Type of completion: Open or cased hole completion exist.
casing & tubing.
4. In addition conditions such as possible sand production & water or gas coning etc.
This type of installation are suitable for wells on continuous
These are some of the vital points influencing the design of gas lift installation.
lift.
Basically, there are three typical types of gas lift installation.
An open hole installation is not normally recommended, as it
i. Open Installation
carries various disadvantages.

ii. Semi-closed Installation

However, there are instances where a packer cannot be run
iii. Closed Installation for some reason, like corrosion, bad casing or internal upset casing etc.,

open hole installation will do a satisfactory job in that case.

This type of installation is very inefficient on an intermittent

installation where gas is likely to blow around the bottom of the tubing.

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Semi-Closed Installation Production out Production out

Closed Installation
This type of installation is similar to the open

installation, except that a packer is added to pack off between the tubing

& casing. Gas In This type of installation is similar to the semi-closed Gas In

This type of installation is suitable for both continuous & installation, except that a standing valve is placed in the tubing string.

intermittent flow. Although the standing valve is normally placed at the bottom

of the well, it may be placed directly below the bottom gas lift valve.
This type of installation offers several advantages over an

open installation: (a) Once the well has been unloaded there is no way for The standing valve prevents the injected gas pressure from

the fluid to come back into the casing-tubing annulus; since all the gas lift acting on the formation.

valves are run with a reverse check. (b) No fluid can leave the tubing & go
A standing valve should be run on intermittent gas lift
into the casing space. (c) The packer prevents any fluid from coming
installation especially when the reservoir pressure is very low.
around the bottom of the tubing and into the casing.

This type of installation is also used for intermittent gas lift.

Although the installation prevents casing gas pressure from

acting on the formation, there is no provision to keep the tubing gas

pressure from acting on the formation through the tubing string, which

occur for intermittent gas lift.

Types of Gas Lift Types of Gas Lift

There are two types of gas lift system used in the oil industry, namely
There are two types of gas lift system used in the oil industry, namely
1. Continuous Flow 2. Intermittent Flow

1. Continuous Flow 2. Intermittent Flow

Continuous Flow Gas Lift
Continuous Flow Gas Lift
In this method, a continuous volume of high pressure gas is introduced into the tubing string to
aerate to lighten the fluid column until reduction of the bottom hole pressure will allow a sufficient
In this method, a continuous volume of high pressure gas is introduced into the tubing string to
pressure differential, causing the well to produce at the desired rate of flow.
aerate to lighten the fluid column.
To accomplish this, a flow valve is used that will permit the deepest possible one point injection
of available gas lift pressure in conjunction with a valve that will act as a changing or variable orifice to Continuous gas lift method is used in wells
regulate gas injection at the surface.
with a high PI & a reasonably high BHP.
Continuous gas lift method is used in wells with a high PI & a reasonably high BHP relative to well
depth. In this type of well, fluid production can range from

In this type of well, fluid production can range from 200-20,000 B/D through normal size tubing
200-20,000 B/D through normal size tubing strings.
strings. On casing flow it is possible to lift in excess of 80,000 B/D.

On casing flow it is possible to lift in excess of 80,000 B/D.

Continuous Flow Gas Lift contd.. To separator

Thus, in a continuous flow gas lift

Choke
process, relatively high pressure gas is injected downhole
Injected
into the fluid column joining the formation gas, which Gas

comes out of solution of fluid as the fluid travels upward

to the surface, to lift the fluid to the surface by one or

more of the following processes:

(a) Reduction of the fluid density and

Valve Closed
the column weight so that the pressure differential

between reservoir and wellbore will be increased, leading

to higher inflow of reservoir fluids.

(b) Expansion of the injected gas so Operating Valve Open

(Point of gas injection)
that it pushes liquid ahead of it which further reduces the

column weight, thereby increasing the differential

between the reservoir & the wellbore.

Fig below illustrates continuous flow gas lift.

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Continuous Flow Gas Lift

Applications of Continuous Flow Gas Lift:
Continuous flow gas lifting involves a continuous injection of lift gas into the wellstream at a
predetermined depth, usually from the casing-tubing annulus to the tubing.
Gas lifting uses natural gas compressed at the surface and injected in the wellstream at some
Injection of a proper amount of gas significantly decreases the flowing mixture’s average
downhole point. In addition to the general applications of all gas lift techniques, continuous flow gas lift is
density above the injection point.
used to:
Thus the whole tubing’s resistance to flow is reduced, allowing the available pressure at the
bottom of the well to move the well fluids to the surface. • Produce high to extremely high liquid rates from any depth.

Therefore, with all other conditions unchanged, the well that was dead before will start to
• Lift sand or solid-laden liquids because sand settling problems in the flow string are negligible.
produce, whereas flowing wells will produce much higher fluids than before.

The basic mechanism of continuous flow gas lifting : Due to the continuous injection of lift gas from a • Increase the liquid rate of otherwise flowing wells.

outside source, the flow resistance of the well tubing is reduced, allowing reservoir pressure to move
• Produce large volumes of water for waterflooding operations.
the well fluids to the surface.

• Back flow water injection wells.

In most other types of artificial lift, especially those utilizing some kind of downhole
pump, formation gas is either harmful or completely detrimental to the operation of the production
equipment.

Gas lifting can be considered as the sole kind of artificial lift completely using the formations
natural energy stored in the form of dissolved gas.

Advantages of Continuous Flow Gas Lift:: Limitations of Continuous Flow Gas Lift:

• As the well’s liquid rate decreases due to the depletion of the formation, continuous flow gas
The basic advantages of continuous flow gas lifting can be summarized as follows:
lifting cannot be applied until the abandonment of the well.
• Continuous flow gas lift, in contrast to intermittent gas lifting, fully utilizes the energy of the
• In case of continuous flow gas lift, the Flowing Bottom Hole Pressure (FBHP) required to lift
formation gas.
well fluids to the surface is considerably high. If the FBHP is less than the minimum pressure required at
• Since gas injection and production over rates are relatively constant, neither the gas supply nor
the bottom of the flow string, the well cannot be produced by continuous flow.
the gathering station are overloaded, if properly designed.
Therefore, in contrast with artificial lift methods utilizing a subsurface pump, FBHPs cannot be
• Within its application ranges, continuous flow gas lifting is relatively flexible to accommodate
decreased sufficiently to produce the well. Thus, a sufficiently high reservoir pressure is a basic
varying well conditions.
requirement for the application of continuous flow gas lifting.

• The fairly constant bottom hole pressure means ideal flow conditions at the surface.

• Surface injection gas control is simple, usually a choke on the injection line is sufficient.

Intermittent Flow Gas Lift To separator

A well having a low reservoir pressure or a very low producing rate, is a candidate for the
TCC
intermittent flow.
Injected
Gas
As its name implies, this system produces intermittently or irregularly and is designed to

produce at the rate at which fluid enters the well bore from the formation.

In the intermittent flow system, fluid is allowed to accumulate and build up in the tubing at the

bottom of the well. At regular intervals determined manually or automatically with a surface Time Cycle
Controller (TCC), an injection gas valve at the surface opens. A slug of gas at high pressure and high volume Valve Closed

is injected into the tubing through gas lift valve very quickly underneath the column of liquid and the liquid

column is pushed rapidly up the tubing to the surface with a maximum velocity to minimize slippage or

controlling liquid fall back. As the injection continues, liquid is pushed to the surface.

Gas injection is stopped by closing the surface valve; and the standing valve which was Operating Valve
(Point of gas injection)
closed, when the gas lift valve was open, now allows fluid to enter the tubing.

The cycle is repeated often enough to lift as much fluid as enters the tubing.

The intermitted lift is used in wells that have the following characteristics:

High or Low PI with low BHP

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Intermittent Flow Gas Lift contd..

In Fig A, the controller on the injection gas line and the operating valve are closed. The standing
Mechanism of Operation:
valve is open, and the fluid from the formation is accumulating in the tubing above the operating valve
Intermittent gas lift, although uses compressed gas from the surface too, works on a principle
to a desired starting slug length.
completely different from continuous flow gas lift.

Lift gas, periodically injected into the flow string at a depth close to the perforations is used to In fig B, the controller and operating valve are open. Injection gas is entering the tubing through

physically, displace a solid liquid column that was allowed to accumulate above the operating gas lift valve. the operating valve and displacing the liquid slug towards the surface. The standing valve is closed, thus

If proper amount of lift gas is injected below the accumulated liquid column, the liquid slug is preventing injection gas pressure from being exerted against the formation.
propelled up to the wellhead and into the flowline.
In fig C, the controller has closed but the operating valve remains open. The liquid slug is
Well production, therefore, is done in periodically repeated cycles, with the basic mechanism of
fluid lifting being the physical displacement of the liquid slugs by the high-pressure lift gas. entering the flow line and the casing pressure is decreasing to the closing pressure of the operating

valve. The standing valve remains closed until the tubing pressure above it is less than the formation

Description of Intermittent Lift Cycle of Operation: pressure.

One complete cycle of intermittent gas lift operation is illustrated in the Fig. 3.6. In Fig D, the controller and operating valves are closed. Injection gas under the slug has entered

A complete injection gas cycle for intermittent lift operation is defined as the duration of time the flowline and the wellhead pressure has decreased to the separator pressure. The standing valve is
between two successive times that the operating valve opens.
open and the formation fluid is entering the tubing. When the starting slug length is reached, the cycle

repeats.

Applications of Intermittent Lift:

Intermittent gas lift is the natural choice in gas lifted fields when formation pressure and fluid
rates drop to such low levels that continuous flow is inefficient due to the great injection rates required.

Approximate minimum liquid rates below switching from continuous flow to intermittent lift is
necessary are:

100-150 bpd for 2 3/8”, 200-300 bpd for 2 7/8”, & 300-400 bpd for 3 ½” tubing sizes.

Conversion of wells on continuous operation to intermittent lift is easy and involves little
additional costs.

Generally, intermittent gas lift is applied in wells producing low to very low liquid
rates, specifically

In low-productivity wells with relatively high formation pressures.

In wells with low formation pressures and high productivities, where the application of Chamber
Lift is usually recommended.

Instead of pumping ( in low producers with relatively high gas rates), the preferred method is
(A) Immediately before gas injection (B) During gas injection (C) During displacement of slug (D) After gas injection
plunger-assisted intermittent lift.

Advantages of Intermittent Lift:

Intermittent Flow Gas Lift
The basic advantages of intermittent gas lifting can be summarized as follows:
There four categories of wells to be considered in gas lift applications:
For low liquid producers, intermittent gas lift is quite flexible to accommodate changes in well
inflow parameters. 1) High PI & High BHP wells

It can be used to the well’s final abandonment by changing the installation type from closed to 2) High PI & Low BHP wells
the chamber installation. 3) Low PI & High BHP wells
Capital costs, especially for deep, low fluid level wells are lower than for pumping applications. 4) Low PI & Low BHP wells

Wells having a PI of 0.50 or less are classified as low productivity wells, and those with a PI
Limitations of Intermittent Lift: greater than 0.50 are classified as high productivity wells.

The basic advantages of intermittent gas lifting can be summarized as follows: High BHP will support a fluid column equal to 70% of the well depth and low BHP will support a
fluid column of less than 40% of the well depth.
The energy of formation gas is wasted and is not utilized for fluid lifting.
Wells with a high BHP and a high PI are normally designed for semiclosed or open continuous
Available liquid production rates are limited.
flow.
High fluctuations in the producing bottom hole pressure associated with intermittent lift can
Wells with a high BHP and low PI are designed for semiclosed intermittent flow.
present serious sand production problems in unconsolidated formations.
Wells with low BHP and a high or low PI are usually designed for closed intermittent flow.

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Classification of Gas lift Valves

GAS LIFT VALVES
(A) Based on their control of operation, all gas lift valves can be classified into one of the following groups:
The heart of the gas lift installation is the gas lift valve, since it provides the necessary control
Pressure operated valves, which are opened or closed by injection &/or production pressures.
of well production rates and its performance determines the technical and economic parameters of fluid
lifting. The type of valve used in practically all gas lift installations are the pressure operated gas lift valve. Mechanically controlled from the surface ( by wireline, drop bar, etc.)

Pressure operated means that the valve behavior is controlled by injection pressure, production Other control methods include flow velocity, specific gravity etc.
pressure or both. These gas lift valves are easily controlled by changing the surface injection pressure.
(B) According to their application, gas lift valves can be used for unloading or as an operating valve, as
All pressure operated gas lift valves are provided with a reference pressure or force that comes follows:
from a gas-charged dome, a spring or a combination of both. By properly setting these references at the
Unloading valves are used for the startup of gas lift operations and are usually closed during
surface (with the right amount of pressure charge or spring force), the valve can be made to open and
normal production. All upper valves which are used to unload a well to desired point of gas
close according to the actual requirements of gas lift installation.
injection are called unloading valves.
The purposes of gas lift valves are:
Operating valves ensure normal gas lift operation and inject the right amount of gas into the well.
1. To unload a gas lift installation to a required depth of lift (point of gas injection). The operating valve is the deepest valve which opens each cycle in an intermittent gas lifting or
the valve at the point of gas injection in a continuous flow installation.
2. To gas lift the required producing rate from point of gas injection with the available
operating injection gas pressure. (C) Gas lift valves can also be classified according to the method they are run into the well, as
follows:
3. To permit deeper injection depths.
Conventional valves are attached to the outside of the tubing in special mandrel and can be run
4. To lower producing gas oil ratios.
and retrieved along with the tubing string only.

Classification of Gas lift Valves contd…

contd… Classification of Gas lift Valves contd…
contd…

Retrievable valves require special mandrel with inside pockets to receive the valve. Such valves Pilot valves contain two sections: a pilot and a main valve. The gas pilot controls the operation of
are run on wireline tools inside the tubing string and can be retrieved without the need to pull the the main valve and the co-operation of the two sections provides the desired results.
tubing.
Flexible sleeve valves etc.
Concentric valves are special subs in the tubing string and can be run and retrieved with the
(E) Finally, gas lift valves can be classed according to the place fluid flow occurs in the well (in the tubing
tubing string only.
or in the casing annulus).
Pack-off valves combine the advantages of concentric and wireline-retrievable valves. They are
Tubing flow valves inject gas from the casing-tubing annulus into the tubing string, whereas
run and set inside the tubing where holes in the tubing were previously made.
Casing flow valves allow the injection from the tubing string to the well’s annular space.
Pump-down valves, Coiled tubing valves. etc.

(D) Constructional features can also be used for distinguishing different valves:

Differential valves usually contain a single spring, the force of which determines the pressure
conditions under which the valve opens & closes.

Bellows valve contain a metal bellows charged with a predetermined gas pressure. The
subdivisions of these valves include the following:

- Single element valves having only the bellows as a source of control force.

- Valves utilizing a spring in addition to the gas-charged bellows.

- Valves with a spring as the only control force with an uncharged bellows.

BASIC COMPONENTS OF GAS LIFT VALVES

Includes:
Lift gas injected from the surface enters the valve inlet ports. Depending on pressure
a. Dome: The dome is normally charged with Nitrogen gas
conditions, the valve stem opens or closes the flow of injection gas through the valve port. Valves are
prior to attaching the gas lift valve to the tubing, The
usually equipped with reverse flow check valve having their own seats and closing devices (dart or disk).
dome pressure is chosen to cause the valve to open at
a specific combination of annular & tubing pressure.
The gas dome is connected to the metal bellows Core valve & tail plug:
b. Bellows with or without springs: The bellows of the gas The dome of the gas lift valves is charged to a predetermined gas pressure at the surface. To
lift valve provide an area of influence for upstream facilitate charging, core valve & tail plug are used at the top of the dome body. A Dill core valve is used
pressure i.e. the injection casing pressure. The bellows which provides filling of and release of gas from the dome. The tail plug provides sealing.
allows the movement of the valve stem.

Many valves have, in addition to the bellows charge, a

Gas Charge:
spring providing a supplement control force. The spring
is of a compression type, its normal force being set at In early gas lift valves the dome was charged with natural gas. However, today most gas lift

the surface before the valve is run in the well. valves are charged with Nitrogen gas because of its availability and other beneficial features:

Fig.: Valve parts of a single-element bellows valve N2 gas is inexpensive, inflammable & non-corrosive & more reliability.
c. Stem & port: The stem is attached to the bellows. The equipped with a reverse flow check valve.

stem tip sits on the port, and is in fact larger than the

port. The port is opened or closed by the stem tip.

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Bellow Assembly: Check Valves:

The most important function of the reverse flow check valves (or check valves) attached to the
The bellows is the heart of the gas lift valve. The bellows perform the most important function
gas lift valves, either separately or as an integral part of the valve assembly, is to prevent the re-entry of
of the gas lift valve by allowing the valve stem tip to move on & off the seat while maintaining the dome-
well fluids, after initial unloading, into the space reserved for gas injection (either the casing-tubing
charged pressure.
annulus or the tubing). This ensures that a constant fluid level is maintained above the operating valve and
The bellows compress and stretches many times during its life span and should therefore be of
no unloading is necessary after the well is shut down.
good quality and well protected against adverse conditions to ensure a long working life.

VALVE MECHANICS
Formerly, when classifying gas lift valves, the terms “casing pressure operated” and “tubing
Spring:
pressure operated” were used to denote valves that are more sensitive to casing or tubing
Many gas lift valves include a compression spring providing an additional force to keep the valve
pressure, respectively. These terms are correct if a tubing flow installation is used where casing pressure
closed. In an unloading valve string, even if the bellows fails, the spring force keeps the valves closed. The
automatically means injection gas pressure and tubing pressure reflects to be the pressure of the produced
spring force is unaffected by temperature, unlike the gas charged in the dome, whose pressure increases
fluid. For casing flow installation, however, the previous terms can be misleading because gas is injected
with depth as the temp. increases.
through the tubing string and fluid production occurs in the annulus. This is the reason why the previous
terms seem to be outdated and are being gradually replaced by the expressions “Injection pressure
operated (IPO)” and “Production pressure operated (PPO)”.
Ball and seat:
Unbalanced valves:
Gas lift valves inject lift gas into the wellstream through their main port, and the operation of
A gas lift valve is called unbalanced if its (a) Opening or (b) Opening and closing pressures are
the valve depends heavily on the proper seal between the valve seat and the stem tip. The stem tips are
influenced by production pressure. This means that the opening or closing conditions of the valve depend on
usually metal balls attached interchangeably to the valve stem. The size of the ball must fit the port size
the prevailing production (or tubing) pressure, whereas balanced valves open & close at the same injection
and generally, balls 1/16” larger in diameter than the port inside diameter are used.
pressure.

Injection Pressure Operated (IPO), Single Element Valves Injection Pressure Operated (IPO), Single Element Valves contd..

A single element valve means that the valve uses only a gas charge in its dome to control the As seen from the opening equation, the injection pressure required to open the valve in the
valve’s operation, there is no spring. In the closed position, injection pressure Pi acts on a much larger area closed position depends not only on the dome-pressure Pd but on the production pressure Pp as well. The
than the production pressure, Pp. This is why the valve is designated as Injection Pressure Operated (IPO). higher the production pressure, the lower the injection pressure necessary for opening the valve. At a
In the closed position, dome charge pressure, Pd, acting on the net area of the bellow Ab constant production pressure, as soon as the injection pressure is reached, the valve starts to open . It is
provides a sufficiently large closing force to keep the stem tip on the port. Thus, here assumed that as soon as the valve opens, the valve stem completely lifts off the seat and the full area
Closing force, Fc = Pd . Ab of the port is opened for injection gas flow.

All other forces acting on the valve stem work in the other direction trying to open the valve. If the valve is fully open, a new balance of forces acts on the valve stem. A general assumption is

The greater opening force comes from the injection pressure Pi acting on the bellow assembly from below that the pressure on the valve stem tip is equal to the injection pressure. Thus, the injection pressure acts

on an area equal to the net bellow area minus the valve port area, (Ab-Ap). A much smaller force arises on on the total bellows area and tries to keep the valve open. Closing force comes from the dome charge

the valve stem tip coming from production pressure Pp. pressure. Now the balance of forces results in the following equation.

Opening force, Fo = Pi.(Ab-Ap) + Pp.Ap Pd . Ab = Pi . Ab

Solving for the injection pressure at which the valve closes, we find the valve’s closing equation:
At the instant the valve opens, the closing force must be in equilibrium with the opening forces.
Pic = Pd -------------------------- (2)
Pd . Ab = Pi.(Ab-Ap) + Pp.Ap
Where, Pic = closing injection pressure at valve setting depth, psi; Pd = dome pressure at valve temp., psi
The injection pressure necessary to open the valve:
By comparing the opening & closing equations of the unbalanced gas lift valve [equ. (1) & (2)], we
Pio = Pd / (1-Ap/Ab) - Pp . (Ap/Ab) / (1-Ap/Ab)
find that the valve opens when injection pressure exceeds dome charge pressure but closes when injection
For simplification introducing the term, R = Ap/Ab
pressure drops below dome charge pressure.
Pio = Pd / (1-R) – Pp. R/ (1-R) ----------------- (1)
The valve dome pressure can be determined if the surface injection pressure and the production
Where, Pd = Dome pressure at valve temp., psi; Pio = Opening injection pressure at valve setting depth, psi; Pp
pressure at valve setting depth are specified.
= Production pressure at valve setting depth, psi; R = Geometrical constant

Injection Pressure Operated (IPO), Single Element Valves contd..

Injection Pressure Operated (IPO), Single Element Valves contd..

From valve opening equn (1): Pio = Pd / (1-R) – Pp. R/ (1-R) ----------------- (1)
From valve opening equation (A)
The second term of RHS of this equation is the Production Pressure Effect (PPE). It represents the
Pd = Pio (1-R) + Pp . R
contribution of the production pressure, Pp to the valve’s opening injection pressure.
Where, Pio has to be calculated from the surface injection pressure.
PPE = Pp. R/ (1-R)
Production Pressure Effect Factor (PPEF) = R/ (1-R) = (Ap/Ab) / (1-Ap/Ab)
"Test Rack Opening Pressure" (TROP) test is a test done at the surface to determine the
PPEF is a geometrical constant for a given valve with a given port size and represents the drop in
valve’s performance. TROP indicates the injection pressure at which the valve opens when the production
the valve’s opening injection pressure for a unit increase in production pressure. In tubing flow installation,
pressure is equal to the atmospheric pressure i.e. Pp is atmospheric pressure or Pp = 0 psig
production pressure equals tubing pressure, PPEF may therefore be called tubing effect factor (TEF), a
From equn (1): TROP = Pd’ / (1-R)
formerly widely used term. For a given valve, as the port size increases, the PPEF increases.
where, Pd’ = dome pressure at 60 0F, psig
Valve spread is defined as the difference between the opening and closing pressure of a gas lift
Valves are charged with high-pressure gas at the surface at a standard temp. of 60 0F. When
valve. The difference is caused by the fact that different pressure act on the valve port when the valve is
the valve is run in the well, the temp. of the valve and the gas charge assumes the well’s flowing temp. valid
in the open and when in the closed positions. Spread is a function of the valve geometry, dome charge
at the given depth. Since the well temperature are greater then the valve’s surface charging temp., actual
pressure, and production pressure and is defined as
pressure in the valve dome will always be greater than at charging conditions.
Spread = Pio – Pic
Unbalanced gas lift valves are characterized by two widely used parameters:
= (Pd– Pp. R)/ (1-R) - Pd
(a) Production Pressure Effect (PPE), earlier known as Tubing Pressure Effect,
= [R / (1-R)] . (Pd – Pp)
& (b) Valve Spread.
= PPEF . (Pd – Pp)

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Injection Pressure Operated (IPO), Double Element Valves Injection Pressure Operated (IPO), Double Element Valves contd..

Double element valve means that in addition to the bellows charge, a spring is also used to If the valve is fully open, a new balance of forces acts on the valve stem. A general assumption is
provide a closing force in an unbalanced gas lift valve. The spring can ensure that an unloading valve with a that the pressure on the valve stem tip is equal to the injection pressure. Thus, the injection pressure acts
rupture bellows does not stay open and inject gas unnecessarily. on the total bellows area and tries to keep the valve open. Closing force comes from the dome charge
The spring force is usually represented by an equivalent pressure term Psp which is assumed to pressure. Now the balance of forces results in the following equation.
act on the area (Ab – Ap). Pd . Ab + Psp . (Ab – Ap) = Pi . Ab
The force thus generated tries to close the valve and helps the dome charge pressure. Solving for the closing injection pressure at which the valve closes:
In contrast to the force caused by the dome pressure, the spring force is insensitive to Pic = Pd + Psp . (1-R) -------------------------- (4)
temperature, so the same value can be used for surface and downhole conditions. Where, Pic = closing injection pressure at valve setting depth, psi; Pd = dome pressure at valve temp., psi;
In the closed position, Psp = spring force effect, psi
Closing force, Fc = Pd . Ab + Psp . (Ab – Ap) In case opening injection pressure and production pressures are specified, equn (3) permits the

Opening force, Fo = Pi.(Ab-Ap) + Pp.Ap calculation of the required dome charge pressure:

At the instant the valve opens, the closing force must be in equilibrium with the opening forces. Pd = (Pio – Psp). (1-R) + Pp . R
Similarly,
Pd . Ab + Psp . (Ab – Ap) = Pi . (Ab-Ap) + Pp.Ap
TROP = Pd’ / (1-R) + Psp
The injection pressure necessary to open the valve:
where, Pd’ = dome pressure at 60 0F, psig
Pio = Pd / (1-R) – PPEF . Pp + Psp ----------------- (3)
SPREAD = PPEF . [Pd – Pp – Psp . (1-R)]
Where, Pd = Dome pressure at valve temp., psi; Pio = Opening injection pressure at valve setting depth, psi;
Pp = Production pressure at valve setting depth, psi; PPEF = Production Pressure Effect Factor = R / (1-R);
Psp = spring force effect, psi

Unloading Process Unloading Process of Continuous Flow Gas Lift Well

Gas Lifting is possible only if the injected lift gas reach down to the operating valve with no The figures show a well with semi closed installation and three gas lift valves, out of which the
liquid column existing above the valve in the well’s annulus. upper two are unloading valves, where bottom one is the operating valve.
After the initial completion of the well or after any workover operation, this requirement is The well’s tubing and annulus is almost completely filled up with kill fluid. The annular fluid is to
seldom met and the conditions will be as shown. be unloaded by the continuous flow gas lift operation.
Fig shows a theoretical case of a dead well, where the kill fluid level in both the tubing string All the gas lift valves are open because of the high pressure acting on them, consisting of the
and in the annulus, is quite close to the surface. injected gas pressure plus the pressure of the liquid column.
The gas lift valve is open due to the hydrostatic pressure of the liquid column above it, allowing As soon as gas is injected into the casing tubing annulus, the annular kill fluid is U-tubed through
communication between the tubing and the annular volume. the gas lift valve into the tubing and up to the surface.
Starting up well production requires the removal of kill fluid from the annulus. This can be Because of the high pressure exerted on the well bottom, no pressure drawdown across the
accomplished in two ways: formation occurs and all the fluid produced to the surface comes form the annulus.
a) By a procedure called Swabbing, where liquid is removed from the tubing As gas is continuously injected, the liquid level in the annulus is depressed until the valve #1 is
string, allowing the annulus liquid level to drop. uncovered, when it starts to inject gas into the tubing string. (Fig B).
b) Instead of swabbing, the liquid removal also called well unloading, can be done by Valve #1 inject gas into the tubing string; aerating the liquid column above the valve setting
utilizing the gas lift pressure and the unloading valves run at designed depths above the operating valve. depth thereby decreasing the tubing pressure at the first valve level.
These unloading valves allow a step wise removal of the kill fluid from the annulus. As gas injection into the annulus continues, the liquid level in the annulus lower/depress until
In the unloading operation using gas lift procedure, the lift gas is injected into the casing-tubing valve #2 is uncovered, and this valves now starts injecting gas into the tubing.
annulus, the injected gas exert pressure on top of the fluid column in the annulus, with the result that the This is a critical moment in the unloading process because two valves admit gas into the tubing.
annular kill fluid is U-tube through the open gas lift valves into the tubing and up to the surface. As a result The unloading valves are set and designed in such a way that valve #1 will close just after

the liquid level in the annulus is depressed/lowered; continuous injection of lift gas causes further lowering injection through valve #2 has begun.

of the liquid level in the annulus until the operating valve is uncovered. With valve #1 closed, gas is injected through the second valve alone. Fig D.

Unloading Process of Continuous Flow Gas Lift Well contd.. Intermittent Flow Unloading Process
Now gas injection occurs through valve #2, which brings about a decrease in the tubing pressure Fig 1, illustrates a dead well with kill fluid both in the annulus & tubing close to the
at second valve’s setting depth which in turn, forces the liquid level in the annulus to drop further. surface, which is to be unloaded by the Intermittent lift unloading sequence using a surface TCC.
As gas injection into the annulus continues, the liquid level in the annulus lowers/depress until When the controller opens, gas is injected into the casing tubing annulus. The injected gas
valve #3 is uncovered, and this valves now starts injecting gas into the tubing. exert pressure on top of the fluid column in the annulus, with the result that the annular kill fluid is U-tube
It is to be noted that this is the operating gas lift valve, and it is imperative that valve #2 will through the open gas lift valves into the tubing and up to the surface. This annular fluid level is lowered as
be forced to close just after injection has started through valve #3. a result until the 1st gas lift valve is uncovered. The injection gas then enters the tubing through the first
By this time the objective of the unloading process have been met, as gas injection takes place GLV, lifting the first liquid slug to the surface. The controller is then closed and the casing pressure drops
through valve #3 only. to the closing pressure of the top GLV. The standing valve remains closed during this operation due to the
At one point of time during the unloading process, FBHP drops below the formation pressure and hydrostatic head of the liquid in the tubing.
inflow of formation fluid to the wellbore starts. From that moment on, the well starts to produce well During the next cycle when the controller opens, the injected gas again enters the annulus and
fluids to the surface , in addition to the kill fluid from the annulus. the casing pressure builds up to opening pressure of the top valve. When its opens, the injection gas enters
Diagrams; book the tubing and displaces the liquid slug above this valve to the surface. The controller then closes and the
casing pressure decreases to the closing pressure of the top valve. When the tubing pressure decreases
following the surfacing of the slug, fluid from the annulus again U-tubes into the tubing through the open
GLVs below the fluid level. The annular fluid level lowers as a result. After a slug has accumulated above the
top valve, the TCC is opened and the process is repeated until till the second valve is uncovered.
Now when the TCC opens during the next cycle, the injected gas enters the tubing through
the second valve, the top GLV now being closed. The liquid slug accumulated above the second valve is
displaced to the surface. The controller then closes and the casing pressure decreases to the closing
pressure of the 2nd valve.

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Intermittent Flow Unloading Process

INTERMITTER LIFT CYCLE
When the tubing pressure decreases following the surfacing of the slug, fluid from the
Wells placed on intermittent gas lift produce in cycles, a complete injection gas cycle for
annulus again U-tubes into the tubing through the open GLVs below the fluid level. The annular fluid level
lowers as a result. After a slug has accumulated above the second valve, the TCC is opened and the process intermittent lift operation is defined as the duration of time between two successive times that the
is repeated until the third. valve is uncovered.
operating valve opens.
The standing valve remains closed during this operations due to the hydrostatic head of the
The cycle can be divided into three distinct phases: The Liquid Accumulation period, The Slug
liquid in the tubing.
In this way the process is repeated till the operating valve is uncovered. Lifting Period, & the Pressure Blow-down or Afterflow period.
As the tubing pressure decreases below the formation pressure, the standing valve opens and
Accumulation Period
the formation fluid enters the tubing through the standing valve. When the required slug of liquid build up
Liquid accumulation in the tubing above the operating GLV starts as soon as the standing valve
above the operating valve, the controller opens and the accumulated liquid slug is surfaced by the injection
gas. In this way the intermittent gas lift operation continues. opens and well fluids start to enter the tubing. At this moment, a liquid slug length equivalent to the liquid

volume that did not reach the surface in the previous cycle is present above the GLV. Starting from

this, the length of the liquid slug continuously increases due to the inflow from the formation and reach the

static fluid level corresponding to the well’s SBHP.

The well’s daily liquid production is the product of the liquid volume per cycle and the number

of cycles per day.

Accumulation of a long slug requires a long time which, in turn, reduces the number of cycles

per day, whereas a shorter slug means a greater number of cycles per day.

INTERMITTER LIFT CYCLE contd..

contd..
INTERMITTER LIFT CYCLE contd..
contd..

During the whole lifting period, the length of the upward rising liquid slug is continuously
In practice, Starting Slug Length, i.e. the length of liquid column above the operating valve at
reduced due to Injection Gas Breakthrough & Liquid Fallback.
the time of gas injection into the tubing, is taken to be about 40-50% of the static liquid column is used.
As the liquid slug is lifted by the high pressure gas, gas continuously penetrates the bottom of
Along with the rising of liquid level in the tubing string, the casing pressure at valve depth
the slug due to the high buoyancy force acting on it.
increases due to the gas injection into the casing-tubing annulus at the surface.
Gas breakthrough results in a loss of slug length because part of the liquid from the gas-
The operating GLV will open at a time when actual tubing & casing pressures satisfy its opening
penetrated bottom of the slug falls down.
equation, then the valve starts to inject gas below the liquid slug.
As the slug moves to the surface, there is a thin layer of liquid retained by the tubing wall.
Slug Lifting Period
This liquid is not that required for wetting, but a liquid of small incremental thickness moving at near zero
The lifting of the liquid slug starts as soon as the operating valve opens and lasts till the slug
velocity on the tubing wall. When the gas velocity in the tubing decreases, gravitational force cause the
has completely moved into the flowline. This period can further be divided into three distinct phases:
liquid to fall back and accumulate above the operating valve. It is virtually impossible to completely
Phase A where the liquid slug is accelerated

Phase B of a constant rising velocity eliminate liquid fall back in an intermittent installation. Liquid fall back can prevent unloading an

Phase C during which the slug enters the flowline. intermittent installation.

Throughout this period, the standing valve that had closed as soon as gas injection through Liquid Fallback is defined as the liquid above the operating valve which is not produced during

the operating valve started stays closed, sealing the formation from the high pressure of the lift gas. the cycle. The length received on the surface is less than the starting slug length, due to the combined

effect of gas breakthrough and liquid fall back.

Factors that effect injection gas breakthrough and liquid fall back are: Depth of lift, tubing
RULES OF THUMB for Intermittent Lift
size, slug velocity, port size of operating valve, restriction in the tubing and wellhead, pressure differential

across when operating valve opens etc.

A minimum slug velocity of 1000 ft/min should be attained to minimize liquid

Injection gas breakthrough is a function of the depth of lift. Injection gas breakthrough fallback.

increases with depth for a given slug velocity and tubing size. The shorter the time required for the slug to For normal conditions the liquid fallback is about 5-7% per 1000 ft of lift.
surface, the less time the injection gas has to breakthrough the liquid slug. Practice has shown that a slug Minimum cycle time is 3 min per 1000 ft of lift. The maximum number of daily
velocity of about 1000 ft/min gives a minimum of liquid fallback
cycles is easy to find from the approximation.
The maximum producing rate of an intermittent installation is limited by the maximum number
To ensure proper operation and a minimum of fallback, the starting tubing load
of injection gas cycles per day (maximum injection gas cycle frequency) and the volume of liquid produced
(the hydrostatic pressure of the starting slug length plus WHP) should be
per cycle. The maximum number of injection gas cycles per day decreases with depth – deeper the well, the

fewer the cycles.

selected as 50-75% of the operating valve’s opening pressure at valve depth.

Time to complete one cycle = 3 minutes per 1000 feet of lift. The injection gas requirement of intermittent lift can be approximated as:

The actual time required to complete may vary between installation, but majority of intermittent 200 – 400 scf/bbl per 1000 ft of lift for conventional installations.
installation require approximately 3 minutes per 1000 feet of lift. 200 – 300 scf/bbl per 1000 ft of lift for chamber installations
If the operating valve is at a depth of 5000 ft, the estimated time required to complete a

cycle would be 15 minutes and the maximum injection gas cycle frequency would be 96 cycles per day.

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Slug Lifting Period contd..

contd.. Slug Lifting Period contd..
contd..

The first phase of the slug lifting period starts after the GLV opens and last until the slug’s Afterflow Period

velocity has reached a constant value. In order for the liquid slug to reach the proper rising velocity in a The afterflow period starts after the flow of the liquid slug completely into the flowline,

short time, the operating valve must open quickly and must have a large port because then a sufficiently when the tail of the liquid slug leaves the wellhead. The tubing string now contains a high-pressure gas

large gas bubble can develop below the liquid slug. column with entrained liquid droplets.

Phase B of the slug lifting period involves a constant rising velocity of the liquid slug and lasts

until the top of the slug reaches the wellhead. During this phase, gas is continuously injected through the

open GLV into the tubing and the expansion of this gas lifts the liquid column up towards the wellhead. The

length of the liquid slug decreases due to gas breakthrough and liquid fall back, the total amount of loss

being proportional to the time spent by the slug in the tubing string.

During the final phase of the lifting period, the slug enters the flowline and lasts until the tail

of the surfacing slug leaves the wellhead and is completely transferred to the flowline.

CHAMBER LIFT

If the formation pressure in a well placed on intermittent lift drops to a low level, two

unfavorable phenomena occur that can severely decrease the efficiency of fluid lifting.

1) First, the slug volume that accumulates in the tubing string during one cycle considerably decreases

and the well’s production rate declines accordingly.

2) Second, the injection GLR inevitably increases since the same amount of injection gas is filled below

the liquid slug, no matter what the actual starting slug length is.

These are the reasons why intermittent gas lifting in a closed or semi-closed installation can

turnout to be very inefficient for low to very low formation pressures, i.e. in wells near their abandonment.

In chamber installation, well fluids accumulate in a downhole accumulation chamber of a

greater capacity than the tubing string. If the same starting slug LENGTH is allowed to accumulate, then

the cycle volume is much greater in the chamber installation than in a conventional intermittent installation.

For example, if a 2 3/8 in. tubing and a 7 in. casing is used, the capacity of the tubing is 3.87 x

10-3 bbl/ft, whereas that of the casing-tubing annulus is 3.28 x 10-2 bbl/ft. This means that for the same

starting slug length of 300 ft, the cycle volume for the tubing string is 1.16 bbl, and for the chamber

(tubing plus annulus) is 11 bbl.

CHAMBER LIFT contd..

contd.. CHAMBER LIFT contd..
contd..

Since the accumulation time for this 300 ft of liquid is identical in both cases, the cycle Gas injection below the liquid slug and into the tubing occurs only after all the liquid has left

volume – and consequently the daily liquid production rate of the well – can be increased drastically if a the casing-tubing annulus. Note that the point of gas injection is at the perforated nipple and not at the

chamber installation is used. operating GLV.

The operation of the intermittent cycle in a chamber installation of the two-packer type is APPLICATIONS of Chamber Lift

illustrated in Fig. After the previous liquid slug has been lifted and the operating valve has closed, fluid Due to its advantageous features, chamber lift is recommended for gas lifting wells with very

inflow to the well starts with the opening of the standing valve. low formation pressures near their abandonment. It can be used in the latest stages of a well’s or a field’s

Well fluids simultaneously rise in the casing-tubing annulus as well as in the tubing because of productive life and is usually the last kind of gas lifting before the well is finally abandoned.

the perforated nipple situated close to the bottom packer. Additionally, chamber lift is ideally suited to produce deep, high productivity wells with low formation

The bleed valve continuously vents formation gas into the tubing so that the chamber fills up pressures.

fully with liquid. The low pressure gas is allowed to escape through the bleed port into the tubing. The common types of chamber lift installations are: Two-Packer Chambers & Insert Chambers.

Otherwise, this gas will be compressed in the upper portion of the chamber, restricting liquid entry. The selection of the type of chamber lift installation is governed by many factors such as well completion

At this moment, gas injection at the surface occurs, forcing the operating chamber GLV to type, casing size &condition, production rate, etc.

open and to inject gas to the top of the chamber. The resultant extra pressure closes the bleed valve, and Two – Packer Chambers are more expensive and are justified if the well’s production rate is

the liquid in the casing-tubing annulus is gradually U-tubed into the tubing string and to the surface. sufficient to cover the additional costs. They are recommended when the dynamic liquid level is above the

top perforations. All the equipments ( operating & bleed valves, standing valve) can be of wireline –

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APPLICATIONS of Chamber Lift contd..

contd..
ADVANTAGES of Chamber Lift contd..
contd..

Insert Chambers are required for open hole completions and cases when the dynamic liquid
Liquid fall back is considerably reduced when compared to conventional installation because
level is below the top of the perforations. The recommended choice for shallow, low capacity well is the
gas injection takes place only after all of the accumulated liquid is U-tubed to the tubing and the liquid slug
installation with a hookwall packer as shown in the Fig. The bottom of the tubing takes the shape of a
is in full motion. Gas breakthrough is thus greatly reduced, leading to a higher liquid recovery than that
chamber. A dip tube, with a diameter smaller than that of the tubing, is hung against the inside of the
available with other installation types.
tubing with the help of a hanging nipple.
Since the point of gas injection in an Insert Chamber installation is at the bottom of the dip-
In deeper wells with more production potential, the use of a more expensive bypass packer
tube, lift gas can be injected near the total depth in wells with a long perforated interval.
can be justified, and the installation given in Fig 2 is recommended. Here the tubing is used as the dip tube.
The injection gas requirement will be less for a chamber installation due to greater liquid

recovery per cycle.

ADVANTAGES of Chamber Lift

Chamber Lift installation offer many advantages over conventional intermittent gas lift
LIMITATIONS of Chamber Lift
installations.
The basic limitations of chamber lift are the same as those for intermittent lift in
Chamber lift produces the lowest possible FBHP for gas lifting and can thus markedly increase
general, such as limited production rate, etc. Additional disadvantages are as follows:
the production rate of most intermittent wells.
In wells with high sand production, wireline operations and pulling of the chamber may be
Wells with low formation pressures can be produced until ultimate depletion.
difficult.

PLUNGER LIFT PLUNGER LIFT contd..

contd..

During the lifting of the liquid slug in intermittent gas lift, injection gas breakthrough occurs Plunger Lift proper

at the bottom of the slug resulting in liquid fall back. Liquid fallback is a natural phenomenon caused by the

great difference in density between the liquid and gas phases making the gas bubble below the liquid slug

penetrate the liquid.

In deeper wells, it can so happen that fallback consumes the total starting slug length and no

liquid is produced at the wellhead. Due to the great amount of fallback, no liquid is obtained at the surface.

In such cases, the use of plunger might be the only way to economically produce the well.

Liquid fallback can be reduced or eliminated by inserting a free piston called plunger between

the gas and the liquid slugs, thereby improving the efficiency of intermittent lift.

It is primarily used to remove water and condensate from gas wells. It is especially applicable

in well with fairly low PI (less than 0.5 bbl/day/psi) and high formation GORs.

If paraffin or other solids deposit in the tubing, the continuous cleaning action of the plunger

provides for the trouble-free operation.

In some wells there is sufficient formation gas to permit plunger lift to operate

unassisted, but in others injection have to be intermittently injected into the casing.

PLUNGER LIFT contd..

contd.. PLUNGER LIFT contd..
contd..

Fig shows the Plunger-Assisted Intermittent Gas Lift Installation. Lift gas is injected into the casing-tubing annulus through a surface intermitter or choke or

The tubing is usually run close to the perforation depth because of low formation pressure of through a choke & regulator. On top of the master valve, a special lubricator should be installed, to fulfill

the wells and to maximize production. To ensure the free travel of the plunger, the tubing string should be the following functions: The high kinetic energy of the plunger arriving at the wellhead is absorbed by a

free of bends, tight spots etc. strong bumper spring connected to a strike plate in the lubricator; For periodical inspection, plungers are

The standing valve should be run near the tubing bottom to prevent well fluids from being removed from the well but have to be first catch in the lubricator by a catcher mechanism that allows the

forced by high-pressure injection gas back into the formation. plunger to enter the lubricator but prevents it from falling back into the well. A actuator rod is installed

A strong spring set in the tubing string close to & above the standing valve absorbs the kinetic inside the bumper spring in the lubricator, to open the plunger’s bypass valve on arrival.

energy of the plunger falling at high speed at the bottom. The bumper spring can be separately set on a Plunger Assisted Intermittent Lift Cycle

tubing stop or seating nipple; or an integral bumper spring-standing valve unit can be used. Like the conventional intermittent lift cycle, this cycle can also be divided into three peiods.

The Plunger is the heart of the installation. It should tolerate the high shock loads on arrival Accumulation Period starts when the standing valve opens and liquid inflow into the tubing begins/

at the bottom and surface bumper springs, should be resistant to wear & tear, should provide for the commences. The plunger with its open bypass valve falls to the bottom bumper spring with impact closing

maximum of liquid recovery, etc. Solid plungers are solid steel cylinders with smooth or grooved surfaces. A the bypass valve.

bypass plunger contains a valve that, if opens, allows the flow of fluids through the plunger body. The Slug Lifting Period starts with the opening of the operating GLV when lift gas injected below the plunger

bypass valve is opened by an actuating rod situated in the lubricator and is closed on hitting the striker resting on the bottom bumper spring with a closed bypass valve displaces the liquid slug along with the

plate as it arrives to the bottom bumper spring. plunger to the surface. During the slug’s upward travel, gas breakthrough and liquid fallback are almost

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PLUNGER LIFT contd..

contd..

completely eliminated by the action of a properly selected plunger. This period can further be divided into

three phases:

1. The slug acceleration phase lasts only for a few seconds because the slug very rapidly reaches its

maximum velocity.

2. The next phase lasts until the top of the slug reaches the wellhead and is characterized by a constant

but small deceleration of the slug. The drop in slug velocity is caused by the interaction of the

continuous decrease of gas pressure below the plunger and the largely constant fluid load.

3. After the liquid enters the wellhead, slug velocity starts to increase rapidly due to the decrease of

fluid head on the plunger.

14