Study of Gas Lift Methods

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STUDY OF GASLIFT METHODS


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TABLE OF CONTENTS

Chapter 2 Artificial Lift Selection.17

2.1. Introduction 17

2.2. Criteria conidered for electin! Artificial Lift

Techni"ue.1#

Chapter $ T%pe of Artificial Lift...2&

$.1'u(p T%pe2&

$.2)a *ethod.2&

$.1.1Bea( 'u(pin!+Suc,er -od 'u(p -od Lift/...2&

$.1.2'ro!rein! Ca0it% 'u(p 'C' 'u(p/2

$.1.$Suurface 3%draulic 'u(p27

$.1.&Electric Su(erile 'u(p ES'/..2#

$.2.1)a Lift.$4

Chapter & )a Lift *ethod................$1

&.1. 5efinition of )a Lift *ethod$1

&.2. 3itor% of )a Lift *ethod$1

&.$. 'rinciple..$2

&.&. )a Lift S%te(.$$

&. T%pe of )a Lift Intallation..$6

&.6. Operation$#

&.7. nloadin! e"uence&1&.#. )a Lift 8al0e and their *echani( .&$

&.9. T%pe of )a Lift 8al0e ..&7

&.9.1. 'reure 8al0e

&.9.2. Fluid:Operated 8al0e

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&.9.$. Co(ination 8al0e ...

&.14.Ad0anta!e &9

&.11. Li(itation 4

-eference.2

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LIST OF TABLES

Tale2.1 Suitale pri(e (o0er t%pe for different artificial lift techni"ue24

Tale 2.2 preent ran!e of operatin! para(eter for different artificial lift techni"ue2$

LIST OF FI)-ES

Fi!ure A Location *ap CB+OS:2 ;ith Area Brea,do;n12

Fi!ure B Onhore Su0ali Ter(inal1$

Fi!ure C 'lant 'roce Flo;:5ia!ra(.1&

Fi!ure 2.1.Suitale production rate for different artificial lift techni"ue.1#

Fi!ure 2.2. Ener!% efficiencie of different artificial lift techni"ue.21

Fi!ure $.$ Suc,er -od 'u(p2

Fi!ure $.&. 'ro!rein! Ca0it% 'u(p.....26

Fi!ure $. 3%draulic 'u(p.....2#

Fi!ure $.6 Electric Su(erile 'u(p.29

Fi!ure $.7 )a Lift S%te(...$4

Fi!ure &.# )a Lift ;ell confi!uration....$$

Fi!ure &.9 )a Lift S%te( che(atic for Onhore 'lant .$

Fi!ure &.14 T%pe of !a lift intallation$#

Fi!ure &.11 Continuou )a Lift.$9

Fi!ure &.12 Inter(ittent )a Lift..&4

Fi!ure &.1$ nloadin! e"uence.&2

Fi!ure &.1& Ele(ent of preure re!ulator and a !a lift 0al0e..&$

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C3A'TE- 2 A-TIFICIAL LIFT SELECTION

2.1. INT-O5CTION

The most important problem is how to select optimum artificial lift techniques taking into

consideration reservoir, well, environmental conditions. Also economic implications are

important (such as investment, work over costs).

The main objective is select an artificial lift method to increase the chances of maximiing profit

under safe operational conditions (for humans and for the environment).

The artificial lift techniques need also to be flexible enough to cope with the expected changes of

production conditions and reservoir performance. !ometimes more than one method is selected

to be used in a well or in a field at different phases of development.

The proper selection of artificial lift s"stem depends on several other disciplines such as drilling,

completion, reservoir management, production la"out, flow assurance and automation.

The selection should be strictl" technical and economical. The objective is to maximie the

expected profit through an intelligent management of operational and investment costs. A well

designed s"stem will balance costs, production and reliabilit" under the various ph"sical,

economical, safet", environmental, human and technical constraints.

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2.2. C-ITE-IA CONSI5E-E5 FO- SELECTIN) A-TIFICIAL LIFT TEC3NI


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1ormation volume factor& %atio of reservoir volume to surface volume determines how much

total fluid must be lifted to achieve the desired surface production rate.

%eservoir drive mechanism& 0epletion drive reservoirs& atestage production ma" require

pumping to produce low fluid volumes or injected water.

4ater drive reservoirs& 5igh water cuts ma" cause problems for lifting s"stems

6as cap drive reservoirs& #ncreasing gasliquid ratios ma" affect lift efficienc".

4ell depth& The well depth dictates how much surface energ" is needed to move fluids to

surface, and ma" place limits on sucker rods and other equipment.

8ompletion t"pe& 8ompletion and perforation skin factors affect inflow performance.

8asing and tubing sies& !malldiameter casing limits the production tubing sie and constrains

multiple options. !malldiameter tubing will limit production rates, but larger tubing ma" allow

excessive fluid fallback.

4ellbore deviation& 5ighl" deviated wells ma" limit applications of beam pumping or $8$

s"stems because of drag, compressive forces and potential for rod and tubing wear.

1low rates& 1low rates are governed b" wellhead pressures and backpressures in surface

production equipment (i.e., separators, chokes and flow lines).

1luid contaminants& $araffin or salt can increase the backpressure on a well.

$ower sources& The availabilit" of electricit" or natural gas governs the t"pe of artificial lift

selected. 0iesel, propane or other sources ma" also be considered.

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Tale 2.1 Suitale pri(e (o0er t%pe for different artificial lift techni"ue

9nerg" 9fficienc"& 9nerg" efficienc" also affects the selection of artificial lift. 1igure 2.2 depicts

a comparison of the energ" efficiencies of different artificial lift techniques.

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Fi!ure 2.& Ener!% efficiencie of different artificial lift techni"ue

1ield location& #n offshore fields, the availabilit" of platform space and placement of directional

wells are primar" considerations. #n onshore fields, such factors as noise limits, safet",

environmental, pollution concerns, surface access and well spacing must be considered.

ongrange recover" plans& 1ield conditions ma" change over time.

$ressure maintenance operations& 4ater or gas injection ma" change the artificial lift

requirements for a field.

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9nhanced oil recover" projects& 9:% processes ma" change fluid properties and require changes

in the artificial lift s"stem.

1ield automation& #f the surface control equipment will be electricall" powered, an electricall"

powered artificial lift s"stem should be considered.

Availabilit" of operating and service personnel and support services& !ome artificial lift s"stems

are relativel" lowmaintenance others require regular monitoring and adjustment. !ervicing

requirements (e.g., workover rig versus wire line unit) should be considered. 1amiliarit" of field

personnel with equipment should also be taken into account.

9conomic Anal"sis& After designing the appropriate candidates, a final realistic economic

anal"sis will indicate the ;best< choices. The economic anal"sis requires investment costs and

salvage values, operational costs, artificial lift s"stem horsepower consumption, production

forecast, estimate of failure rate for the expected operating conditions, estimated cost and

duration time of repairs.

The best possible artificial lift s"stem is selected after taking into account, the above mentioned

parameters. !election of poor technique could result with decrease in efficienc" and low

profitabilit". As a result, it will lead to high operating expenses. !everal techniques have been

developed for selection of optimum artificial lift techniques. 1or example, :$=! (optimal

pumping unit search) firstl" was introduced b" 7alentine et al. (3>??) for selection of optimum

artificial lift techniques. The advantage of such computer based programs like :$=! is that these

programs take into consideration technical and financial issues of each artificial lift technique.

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Tale 2.2 preent ran!e of operatin! para(eter for different artificial lift techni"ue.

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C3A'TE- $ T='ES OF A-TIFICIAL LIFT

T='ES OF A-TIFICIAL LIFT

Artificiallift methods fall into two groups, those that use pumps and those that use gas.

$.1. 'u(p T%pe

eam $umping / !ucker %od $umps (%od ift)

$rogressive 8avit" $umps

!ubsurface 5"draulic $umps

9lectric !ubmersible $umps$.2. )a *ethod

6as ift

9ach of these methods will be discussed below&

$.1.1. Bea( 'u(pin!+Suc,er -od 'u(p -od Lift/

This t"pe of artificial lift utilies a positive displacement pump that is inserted or set in the

tubing near the bottom of the well. The pump plunger is connected to surface b" a long rod

string, called sucker rods, and operated b"a beam unit at surface. 9ach upstroke of the beam unit

lifts the oil above the pump's plunger.

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Fi!ure $.$ Suc,er -od 'u(p

$.1.2. 'ro!rein! Ca0it% 'u(p 'C' 'u(p/

$rogressing 8avit" $umps ($8$) are also widel" applied in the oil industr". The $8$ consists of

a stator and a rotor. The rotor is rotated using either a top side motor or a bottom hole motor. The

rotation created sequential cavities and the produced fluids are pushed to surface. The $8$ is a

flexible s"stem with a wide range of applications in terms of rate (up to @,+++ bbl/d (>+ mB/d)

and -,+++ ft (3,?++ m)). The" offer outstanding resistance to abrasives and solids but the" are

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restricted to setting depths and temperatures. !ome components of the produced fluids

like aromaticscan also deteriorate the stator's elastomer.

Fi!ure $.&. 'ro!rein! Ca0it% 'u(p

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$.1.$. Suurface 3%draulic 'u(p

5"draulic ift !"stems consist of a surface power fluid s"stem, a prime mover surface pump,

and a downhole jet or reciprocating/piston pump. #n the operation of a h"draulic lift s"stem,

crude oil or water (power fluid) is taken from a storage tank and fed to the surface pump. The

power fluid, now under pressure built up b" the surface pump, is controlled b" valves at a control

station and distributed to one or more wellheads. The power fluid passes through the wellhead

valve and is directed to the downhole pump. #n a piston pump installation, power fluid actuates

the engine, which in turn drives the pump, and power fluid returns to the surface with the

produced oil, is separated, and is piped to the storage tank. A jet pump has no moving parts and

emplo"s the 7enturi principle to use fluid under pressure to bring oil to the surface.

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Fi!ure $. 3%draulic 'u(p

$.1.&. Electric Su(erile 'u(p ES'/

9lectric !ubmersible $umping (9!$) !"stems incorporate an electric motor and centrifugal

pump unit run on a production string and connected back to the surface control mechanism and

transformer via an electric power cable. The downhole components are suspended from the

production tubing above the wellsC perforations. #n most cases the motor is located on the bottom

of the work string. Above the motor is the seal section, the intake or gas separator, and the pump.

The power cable is banded to the tubing and plugs into the top of the motor. As the fluid comes

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into the well it must pass b" the motor and into the pump. This fluid flow past the motor aids in

the cooling of the motor. The fluid then enters the intake and is taken into the pump. 9ach stage

(impeller/diffuser combination) adds pressure or head to the fluid at a given rate. The fluid will

build up enough pressure as it reaches the top of the pump to lift it to the surface and into the

separator or flowline. 9lectric submersible pumps are normall" used in high volume (over 3,+++

$0) applications.

Fi!ure $.6 Electric Su(erile 'u(p

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$.2.1. )a Lift

#n a t"pical gas lift s"stem, compressed gas is injected through gas lift mandrels and valves into

the production string. The injected gas lowers the h"drostatic pressure in the production string to

reestablish the required pressure differential between the reservoir and wellbore, thus causing the

formation fluids to flow to the surface. 9ssentiall", the liquids are lightened b" the gas which

allows the reservoir pressure to force the fluids to surface. A source of gas, and compression

equipment is required for gas lift. $roper installation and compatibilit" of gas lift equipment,

both on the surface and in the wellbore, are essential to an" gas lift s"stem.

Fi!ure $.7 )a Lift S%te(

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C3A'TE- & )AS LIFT *ET3O5S

&.1.5efinition of )a Lift *ethod

A continuous lift gas lift installation is one where compressed high pressure gas is injected

continuousl" at the surface into the gas injection conduit and then continuousl" downhole into

the production fluid conduit.

&.2. 3itor% of )a Lift *ethod

6as lifting of water with a small amount of oil used in the =nited !tates as earl" as 3?*-.

8ompressed air is known to have been used earlier to lift water. #n fact, it has been reported that

compressed air was used to lift water from wells in 6erman" as earl" as the eighteenth centur".

These earl" s"stems operated in a ver" simple manner b" the introduction of air down the tubing

and up the casing. Aeration of the fluid in the casing tubing annulus decreased the weight of the

fluid column so that fluid would rise to the surface and flow out of the well. The process was

sometimes reversed b" injecting down the casing and producing through the tubing. Air lift

continued in use for lifting oil from wells b" man" operators, but it was not until the mid3>2+Cs

that gas for lifting fluid became more widel" available. 6as, being lighter than air, gave better

performance than air, lessened the haards created b" air when exposed to combustible materials

and decreased equipment deterioration caused b" oxidation. 0uring the 3>B+Cs, several t"pes of

gas lift valves became available to the oil producing industr" for gas lifting oil wells. 6as lift was

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soon accepted as a competitive method of production, especiall" when gas at adequate pressures

was available for lift purposes.

&.$. 'rinciple

6as lift technolog" increases oil production rate b" injection of compressed gas into the lower

section of tubing through the casingDtubing annulus and an orifice installed in the tubing string.

=pon entering the tubing, the compressed gas affects liquid flow in two wa"s&

(a) The energ" of expansion propels (pushes) the oil to the surface and

(b) The gas aerates the oil so that the effective densit" of the fluid is less and, thus, easier to get

to the surface.

There are four categories of wells in which a gas lift can be considered&

3. 5igh productivit" index ($#), high bottomhole pressure wells

2. 5igh $#, low bottomhole pressure wells

B. ow $#, high bottomhole pressure wells

*. ow $#, low bottomhole pressure wells

4ells having a $# of +.@+ or less are classified as low productivit" wells. 4ells having a $#

greater than +.@+ are classified as high productivit" wells. 5igh bottomhole pressures will

support a fluid column equal to +E of the well depth. ow bottomhole pressures will support a

fluid column less than *+E of the well depth.

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&.&. )a Lift S%te(

A complete gas lift s"stem consists of a gas compression station, a gas injection manifold with

injection chokes and time c"cle surface controllers, a tubing string with installations of unloading

valves and operating valve and a downhole chamber.

Fi!ure &.#depicts a configuration of a gaslifted well with installations of unloading valves and

operating valve on the tubing string.

Fi!ure &.#)a Lift ;ell confi!uration

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There are four principal advantages to be gained b" the use of multiple valves in a well&

3. 0eeper gas injection depths can be achieved b" using valves for wells with fixed surface

injection pressures.

2. 7ariation in the well's productivit" can be obtained b" selectivel" injecting gas valves set at

depths FFhigher'' or FFlower'' in the tubing string.

B. 6as volumes injected into the well can be FFmetered'' into the well b" the valves.

*. #ntermittent gas injection at progressivel" deeper set valves can be carried out to FFkick off'' a

well to either continuous or intermittent flow.

Fi!ure &.9illustrates schematic of a gas lift s"stem. 1or proper selection, installation, and

operations of gas lift s"stems, the operator must know the equipment and the fundamentals of

gas lift technolog". The basic equipment for gas lift technolog" includes the following&

a. Gain operating valves

b. 4ireline adaptations

c. 8heck valves

d. Gandrels

e. !urface control equipment

f. 8ompressors

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Fi!ure &.9 )a Lift S%te( che(atic for Onhore 'lant

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&. T%pe of )a Lift Intallation>

0ifferent t"pes of gas lift installations are used in the industr" depending on well conditions.

The" fall into four categories&

A. :pen installation,

. !emiclosed installation,

8. 8losed installation, and

0. 8hamber installation.

As shown in Fi!. &.14a/, no packer is set in open installations. This t"pe of installation is

suitable for continuous flow gas lift in wells with good fluid seal. Although this t"pe of

installation is simple, it exposes all gas lift valves beneath the point of gas injection to severe

fluid erosion due to the d"namic changing of liquid level in the annulus. :pen installation is not

recommended unless setting packer is not an option.

Fi!ure &.14/ demonstrates a semiclosed installation. #t is identical to the open installation

except that a packer is set between the tubing and casing. This t"pe of installation can be used for

both continuous and intermittentflow gas lift operations. #t avoids all the problems associated

with the open installations. 5owever, it still does not prevent flow of well fluids back to

formation during unloading processes, which is especiall" important for intermittent operating.

#llustrated in Fi!. &.14c/ is a closed installation where a standing valve is placed in the tubing

string or below the bottom gas lift valve. The standing valve effectivel" prevents the gas pressure

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from acting on the formation, which increases the dail" production rate from a well of the

intermittent t"pe.

8hamber installations are used for accumulating liquid volume at bottom hole of intermittent

flow gas lift wells. A chamber is an ideal installation for a low 5$ and high $# well. The

chambers can be configured in various wa"s including using two packers, insert chamber, and

reverse flow chamber.

A standard twopacker chamber is installed to ensure a large storage volume of liquids with a

minimum amount of backpressure on the formation so that the liquid production rate is not

hindered.

An insert chamber is normall" used in a long open hole or perforated interval where squeeing of

fluids back to formation b" gas pressure is a concern. #t takes the advantage of existing bottom

hole pressure. The disadvantage of the installation is that the chamber sie is limited b" casing

diameter.

A reverse flow chamber ensures venting of all formation gas into the tubing string to empt" the

chamber for liquid accumulation. 1or wells with high formation 6%, this option appears to be

an excellent choice.

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Fi!ure &.14 T%pe of !a lift intallation

&.6. Operation>

6as ift !"stems are broadl" of two t"pes& 8ontinuous and #ntermittent. A continuous gas lift

operation is a stead"state flow of the aerated fluid from the bottom (or near bottom) of the well

to the surface. #ntermittent gas lift operation is characteried b" a startandstop flow from the

bottom (or near bottom) of the well to the surface i.e. gas is injected in batches which follows a

timec"cle. This is unstead" state flow.

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Fi!ure &.11 Continuou )a Lift

#n continuous gas lift (shown in fi!ure &.11), a small volume of highpressure gas is introduced

into the tubing to aerate or lighten the fluid column. This allows the flowing bottomhole

pressure with the aid of the expanding injection gas to deliver liquid to the surface. To

accomplish this efficientl", it is desirable to design a s"stem that will permit injection through a

single valve at the greatest depth possible with the available injection pressure. 8ontinuous gas

lift method is used in wells with a high $# ( +.@stb/da"/psi) and a reasonabl" high reservoir

pressure relative to well depth.

#ntermittent gas lift method (shown in fi!ure &.12) is suitable to wells with (3) high $# and low

reservoir pressure or (2) low $# and low reservoir pressure. The time c"cle surface controller

regulates the startandstop injection of lift gas to the well. 5ere, initiall" the liquid slug that has

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accumulated. 4hen gas lift valve opens, highpressure injection gas enters the tubing and rapidl"

expands. This action forces the liquid slug (shaded in fi!ure &.12) from the tubing.

Fi!ure &.12 Inter(ittent )a Lift

The t"pe of gas lift operation used, continuous or intermittent, is also governed b" the volume of

fluids to be produced, the available lift gas as to both volume and pressure, and the well

reservoir's conditions such as the case when the high instantaneous 5$ drawdown encountered

with intermittent flow would cause excessive sand production, or coning, and/or gas into the

wellbore.

&.7. nloadin! e"uence>

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Fi!ure &.1$shows a well unloading process. =suall" all valves are open at the initial condition,

as depicted in Fi!. &.1$a, due to high tubing pressures. The fluid in tubing has a pressure

gradient 6s of static liquid column. 4hen the gas enters the first (top) valve as shown in Fi!.

&.1$, it creates a slug of liquidDgas mixture of less densit" in the tubing above the valve depth.

9xpansion of the slug pushes the liquid column above it to flow to the surface. #t can also cause

the liquid in the bottom hole to flow back to reservoir if no check valve is installed at the end of

the tubing string. 5owever, as the length of the light slug grows due to gas injection, the bottom

hole pressure will eventuall" decrease to below reservoir pressure, which causes inflow of

reservoir fluid.

4hen the tubing pressure at the depth of the first valve is low enough, the first valve should

begin to close and the gas should be forced to the second valve as shown in Fi!. &.1$c. 6as

injection to the second valve will gasif" the liquid in the tubing between the first and the second

valve. This will further reduce bottomhole pressure and cause more inflow. " the time the slug

reaches the depth of the first valve, the first valve should be closed, allowing more gas to be

injected to the second valve. The same process should occur until the gas enters the main valve

(Fi!. &.1$d). The main valve (sometimes called the master valve or operating valve) is usuall"

the lower most valve in the tubing string. #t is an orifice t"pe of valve that never closes. #n

continuous gas lift operations, once the well is full" unloaded and a stead"state flow is

established, the main valve is the onl" valve open and in operation (Fi!. .29e).

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Fi!ure &.1$ nloadin! e"uence

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&.#. )a Lift 8al0e and their *echani(

The heart of an" gas lift s"stem is the gas lift valve. 6as lift valves are basicall" downhole

pressure regulator. The functional elements of a pressure regulator and a gas lift valve are similar.

A spring (Fi!:&.1&A), as in the gas lift valve (Fi!:&.1B), forces the stem tip against the seat.

Fi!ure &.1& Ele(ent of preure re!ulator and a !a lift 0al0e

The diaphragm of the pressure regulator and the bellows of the gas lift valve provide an area of

influence for the upstream pressure greater than the port area. The force that results from this

combination of upstream pressure and diaphragm or bellows area acts in a direction to overcome

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the force of the spring. 4hen this force of pressure times area exceeds the force of the spring, the

stem tip moves awa" from the seat, opening the valve. oth the pressure regulator and the gas

lift valve illustrated are controlling the upstream pressure. The regulator upstream pressure is a

function of spring force and effective diaphragm or bellows area. $racticall" all gas lift valves

use the effect of pressure acting on the area of a valve element (bellows, stem tips, etc) to cause

the desired valve action. Hnowledge of pressure, force, and area is required to understand the

operation of most gas lift valves.

ecause the opening and closing characteristics of the various valves in our gas lift s"stem are so

important to their operation, we should understand how and when a valve will open, when it will

close, and what the difference in these two pressures, referred to as spread, reall" means.

4e would like to calculate the opening and closing pressures. To do this, we must write a force

balance equation for the valve.

Cloin! Force>

Gost gas lift valves have gas pressure ($b) trapped in the dome. This pressure acts on the area of

the bellows and create a force ( 1c ) that is applied to the stem. The stem tip is forced into contact

with the upper edge (seat) of the port. The stem tip and seat portion of the port are finel"

matched (often lapped) to form a seal. 4hen the dome pressure ($b) and bellows area (Ab) are

known, the force holding the stem tip against the seat is&

1c I $bJAb KKKKKKKKKK..KKKKKKKKKKKKKKKKKKKK..(@.3)

1c I 8losing 1orce.

$c I $ressure inside the dome space sealed b" the bellows and valve housing

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Ab I Area of the bellows.

Openin! Force>

A valve starts to open when the stem tip moves out of contact with the valve seat. This occurs

when the opening force is slightl" greater than the closing force, therefore, just before opening

(1oI1c). Two forces usuall" work together to overcome the closing force (1c). $ressure ($3)

applied through the side opening and pressure ($2) applied through the valve port are the

pressure sources to produce the two opening forces. 4hen the stem tip is seated on the port, $3

does not act on the entire bellows area (Ab). The area of stem tip (Ap) in contact with the seat

forms part of the bellows area (Ab). Ap is isolated from $3 b" the stem tip and seat. The area

acted on b" pressure ($3) is the bellows area minus the area of the stem tip isolated b" the seat

(Ab D Ap).

The opening force resulting from pressure $3 applied through the side opening is&

13I$3J(AbDAp) KKKKKKKKKKKKKKKKKKKKKKKKKKKKK.(@.2)

The area of the stem tip in contact with the seat (Ap) is acted upon b" pressure ($2) applied

through the port. The opening force contributed b" this combination is&

12 I $2JAp KKKKKKKKKKKKKKKKKKKKKKKKKK.......................(@.B)

The total opening force is the sum of these two forces&

1o I 13 L 12

:r

1oI $3J(Ab D Ap) L $2JAp KKKKKKKKKKKKKKKKKKKKKKKKK(@.*)

Must before the valve port opens, the opening force and the closing force are equal

1o I 1c

or

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$3J(Ab D Ap) L $2JAp I $bJAb KKKKKKKKKKKKKKKKKKKKKKK(@.@)

!olving for $3(injection pressure required to balance opening and closing forces prior to opening

an injection pressure operated valve under operative conditions)&

$3 I N$b D $2J(Ap/Ab)O / 3 D (Ap/Ab)KKKKKKKKKK...KKKK..KKKKK..(@.-)

:r

$3 I N$b D $2J%O / 3 D %KKKKKKKKKK...KKKK..KKKKK..........................(@.)

4here,

%I Ap/Ab I %atio of port area to bellows area.

$3 is the pressure in contact with the valve bellows.

$2 is the pressure in contact with the portion of the stem tip sealed b" the seat (port).

Ap is the area of the portion of the stem tip sealed b" the seat.

Ais the area of the bellows.

13 I :pening force resulting from $3 acting on the bellows area less than the port area

12 I :pening force resulting from $2 acting on the stem tip area in contact with the

!eat (port)

1o I Total opening force.

The pressure ($3) determined b" this equation is the balance pressure. Actuall" the valve stem tip

is still on seat and onl" slight leakage b" the stem tip and seat ma" be observed. An increase in

$3 or $2 will move the stem tip proportionall" further from the seat and allow more gas passage.

A decrease in $3 or $2 will load the stem tip harder against the seat and cause a tighter stem tip

to seal. This is the case as the valve closes.

The difference between the opening pressure and the closing pressure is the 0al0e pread.

!pread I opening pressure closing pressure

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4e see that for given bellows and tubing pressures we ma" reduce the spread b" reducing the

area of the port opening. The spread is particularl" important in intermittent gas lift installations,

because it controls the volume of gas used in each c"cle. As the pressure reduction, or spread,

required to close the operating valve increases, the amount of gas injected during the c"cle also

increases. A small port sie, though, increases horsepower requirements and, therefore, a balance

must be struck between gas conservation and horsepower requirements.

&.9. T%pe of )a Lift 8al0e

There are different t"pes of unloading valves, namel" casing pressureoperated valve (usuall"

called a pressure valve), throttling pressure valve (also called a proportional valve or continuous

flow valve), fluidoperated valve (also called a fluid valve), and combination valve (also called a

fluid openpressure closed valve). 0ifferent gas lift design methods have been developed and

used in the oil industr" for applications of these valves.

&.9.1. 'reure 8al0e

$ressure valves are further classified as unbalanced bellow valves, balanced pressure valves, and

pilot valves. Tubing pressure affects the opening action of the unbalanced valves, but it does not

affect the opening or closing of balanced valves. $ilot valves were developed for intermittent gas

lift with large ports.

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&.9.2. Fluid:Operated 8al0e

The basic elements of a fluidoperated valve are identical to those in a pressureoperated valve

except that tubing pressure now acts on the larger area of the bellows and casing pressure acts on

the area of the port. This configuration makes the valve mostl" sensitive to the tubing fluid

pressure.

&.9.$. Co(ination 8al0e

A combination valve consists of two portions. The upper portion is essentiall" the same as that

found in pressureoperated valves, and the lower portion is a fluid pilot, or a differential pressure

device incorporating a stem and a spring. 5oles in the pilot housing allow the casing pressure to

act on the area of the stem at the upper end. The spring acts to hold the stem in the upward

position. This is the open position for the pilot. The casing pressure acts to move the stem to the

closed position. The fluid pilot will onl" open when tubing pressure acting on the pilot area is

sufficient to overcome the casing pressure force and move the stem up to the open position. At

the instant of opening, the pilot opens completel", providing instantaneous operation for

intermittent lift.

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&.14. Ad0anta!e

Advantages&

8an produce high rates from high productivit" wells

1lexible, eas" to change rate

8an handle solids

9as" to obtain downhole pressures and gradients

ifting gass" wells is no problem

8rooked/deviated holes pose no problem

$ermits the concurrent use of wire line equipment, and such downhole equipment is easil"

and economicall" serviced.

The normal gaslift design leaves the tubing full" open. This permits the use of 5$ surve"s,

sand sounding and bailing, production logging, cutting, paraffin, etc.

A central gaslift s"stem can be easil" used to service man" wells or operate an entire field

which lowers total capital cost and permits easier well control and testing.

5as a low profile. The surface well equipment is the same as for flowing wells except for

injectiongas metering.

4ell subsurface equipment is relativel" inexpensive and their repair and maintenance

expenses normall" are low. Also, major well 4orkover occur infrequentl".

#nstallation of gas lift is compatible with subsurface safet" valves and other surface

equipment. The use of a surfacecontrolled subsurface safet" valve with a 3/*in. control line

allows eas" shut in of the well.

6as lift can still perform fairl" well even when onl" poor data are available when the design

is made. This is fortunate because the spacing design usuall" must be made before the well is

completed and tested.

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&.11. Li(itation

5igh initial investment

Availabilit" of lift gas

Pot feasible for marginal fields

6as h"drate problem

!afet" issues with high pressure gas

%elativel" high backpressure ma" seriousl" restrict production in continuous gas lift. This

problem becomes more significant with increasing depths and declining static 5$s.

!killed operators and good compressor mechanics are required for reliable operation.

8ompressor downtime should be minimal (Q BE).

0ifficult" when lifting low gravit" (less than 3@RA$#) crude because of greater friction, gas

fingering, and liquid fallback. Also, the cooling effect will compound an" paraffin problem.

6ood data are required to make a good design. #f not available, operations ma" have to

continue with an inefficient design that does not produce the well to capacit".

$otential gaslift operational problems that must be resolved include&

1reeing and h"drate problems in injection gas lines

8orrosive injection gas

!evere paraffin problems

1luctuating suction and discharge pressures

4ireline problems

:ther problems that must be resolved are&

8hanging well conditions

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9speciall" declines in ottom 5ole $ressure (5$) and productivit" index ($#)

0eep highvolume lift

7alve interference (multipointing)

Additionall", dual gas lift is difficult to operate and frequentl" results in poor lift efficienc".

9mulsions forming in the tubing, which ma" be accelerated when gas enters opposing the

tubing flow, also must be resolved.

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-EFE-ENCES

'aper in a ?ournal

ea, M. 1., S Pickens, 5. 7. (3>>>, Manuar" 3). !election of Artificial ift. !ociet" of

$etroleum 9ngineers. doi&3+.233?/@23@G!

Peel", ., 6ipson, 1., 8legg, M., 8apps, ., S 4ilson, $. (3>?3, Manuar" 3). !election of

Artificial ift Gethod. !ociet" of $etroleum 9ngineers. doi&3+.233?/3+BBG!

rown, H. 9. (3>?2, :ctober 3). :verview of Artificial ift !"stems. !ociet" of

$etroleum 9ngineers. doi&3+.233?/>>>$A

Alawati, G. (2+3*, :ctober -). 6asift Podal Anal"sis Godel 9conomical

:ptimiation Approach. !ociet" of $etroleum 9ngineers. doi&3+.233?/33B*@G!

-eferred Boo,

Takacs, 6.& ;Godern !ucker%od $umping< $enn4ell ooks. Tulsa, :klahoma, 3>>B.

6ault, %. 5.& ;0esigning a !ucker%od $umping !"stem for Gaximum 9fficienc"?, 2?*>+

rown, H 9& ;The Technolog" of Artificial ift Gethods?+

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npulihed -eport and 'h. 5. Thei

!chlumberger& ;6as ift 0esign and Technolog">>

9lshanali"ev& ;0evelopment of expert s"stem for artificial lift selection< G! Thesis,

Giddle 9ast technical universit", 2+3B

Takacs, 6.& ;$rogram :ptimies !ucker%od $umping Gode.< :il and 6as Mournal.

:ct. 3>>+, ?*>

*aterial fro( @e Site

!ucker %od $ump $roduction Technolog"& http&//aoghs.org/technolog"/allpumpedup

oilproductiontechnolog"/

http&//www.ulcon.com/page/files/A$resentationPotes.pdf

http&//web.mit.edu/2.>2/www/reports/suckerrodpump/suckerrodpump.html

http&//www.pfts"s.com/products.php

http&//vigiku.blogspot.in/2+32/3+/introductiontooilandgasproduction.html

Documents

Study of Gas Lift Methods