principles of gas lift

7/31/2019 Principles of Gas Lift

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CHAPTER 7

PRINCIPLES OF GAS LIFT

When the natural reservoir energy is insufficient to lift oil

from the bottom hole up to the surface, one or more ofthe artificial lift methods of oil production will beapplied.

One of the most popular artificial lift methods is the gaslift method.

The process can be described as follows. The gas isinjected into the annular space to displace the liquid,which reaches the tubing shoe, and moves up through

the tubing, thus aerating the column of liquid.


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Fig. 7-1 Gas Lift Performance

(a) Single string, (b) Dual string, (c) Stepped two-string


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The gas bubbles rise through the tubing and entrain the

liquid. Since the density of a gas-oil mixture is lower

than the hydrostatic pressure of the gas-oil column islower and the back pressure on the formation

decreases.

Therefore, the difference between the formation pressure

and the bottom-hole flowing pressure causes oil to flow

from the pay zone bed into the well.


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The used gas in the process of gas-lift may be:

(a) natural gas,

(b) air, or

(c) a an air-gas mixture.

When the air is used, the process is called air-liftand similarly, when air-gas mixture is used,the process is called air-gas lift.


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The gas lift installationconsists of two strings oftubing, one inside theother.

The gas is injected throughthe annular space betweenthe two strings while thegas-liquid mixture rises up

the inner tubing.

The new level of the gas-liquid mixture in theannulus is called thedynamic level (Hdyn).Therefore the pressure atthe bottom hole will be as

follow: gHP dynb ** =

Gas-In

Oil

Mixture-Out

ho

Hdyn

Dual-Tubing


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The distance between the wellhead and the

dynamic level is:

Where

H is the well depth.

)/( gpHHHh bdyno ==


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Features of Gas Lift

The basic advantages of gas lift production are as follows;(1) equipment is simple in design, has no sliding subsurface parts

and is thus free from fast-wearing mechanisms;

(2) the surface equipment accounts for the larger stock offacilities and thus is readily accessible for service and repair;

(3) the flow rate is easy to control and can be raised to a high of1800 to 1900 tons per day regardless of the well depth and tubing

diameter;

(4) many types of oil well can be produced, such as sandy,drowned, crooked, directionally drilled, and small-diameter;

(5) high temperature and gas evolving from the beds do not affectthe well performance, rather the gas facilitates the flow of fluidto the surface;

(6) well survey is simple.


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PRINCIPLES OF GAS LIFT- Drawbacks

the main drawbacks of this artificial lift system are as

follows:

(1) a low efficiency of both the gas lift and the entirecompressor-well system (gas lift efficiency does not

often exceed 5 % at low dynamic levels);

(2) large consumption of pipes, particularly in water-and sand-producing wells;

(3) high initial costs of construction of gas-lift

compressor stations, distribution booths, and anextended network of pipelines;


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Calculation of Gas Lift InstallationsThe calculation of a gas lift system reduces to the

determination of the diameter and length of the gas lift

itself, bottom and the wellhead.

For this, the following initial data on each well must be

available-1. reservoir pressure and formation depth

2. casing string diameter;

3. fluid density;4. gas factor and gas solubility;

5. the pressure of the gas distribution system.


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Calculation of Gas Lift Installations

In practice, gas lift wells can be flown so as to givethe highest possible output (uncontrollable, orunlimited withdrawal) or a limited(controllable) output for geologic and technicalreasons.

Two methods are available including:1. Unlimited fluid withdrawal

2. Limited fluid withdrawal


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Unlimited fluid withdrawal

Since a maximum rate of production corresponds to aminimum bottom-hole pressure, the tubing should berun in somewhat short of the upper perforationinterval.

If run in below this interval, the working agent injectedinto the annulus impedes the inflow of fluid into thewell:

L=H - (20 to 30)

where

L is the tubing setting depth (height, or depth of lift), m

His the total well depth, m.


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Neglecting the pressure exerted by the gascolumn and the pressure loss due to the

dynamic friction of gas on the walls of the gas

string, the bottom-hole pressure Pb can be setequal to approximately the tubing bottom

pressure:

Pb = P1


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The maximum diameter of flow tubing can be estimated in

conformity with the well production rate using Table 7-1.

A minimum diameter of tubing depends on the diameter of theproduction casing (final casing string).

Table 7-1 Production rate based upon selected tubing diameterDnom, mm Din, mm Q, ton/day

48

60

73

89

114

40.3

50.3

59 to 62

76

100.3

20 50

50 70

70 250

250 350

above 350


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The pressure p1 at the flow string shoe is given by

P1 = Pa0.4 Mpa

where

Pw is the working pressure in the discharge line ofcompressors, MPa;

the pressure loss in the gas line from compressor to

wellhead = 0.4 Mpa.

The gas pressure loss due to friction and the head of gas

column in the gas string may be neglected.


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The specific gas injection rate Ri-max with consideration ofthe volume of gas flowing together with oil the well can

be expressed as:

Ri-max = Rmax Go

Go is the gas factor, m3 per day.

Knowing Ri-max,

The daily gas injection rate

Vi = Qmax

* Ri-max

( ) )/(88.3

2121

5.0

2

maxPPLogPPd

LR i

=


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Limited fluid withdrawal

In this case, the oil and gas production rates and also thebottom-hole pressure corresponding to these rates areknown.

In the conditions of a maximum flow rate the specificenergy (gas flow rate) the pressure differential per unit

length of lift is

(dh/L) = 0.5

where there is an optimal flow rate, the relative maximumproduction rate will be at (dh/L) = 0.6.


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Limited fluid withdrawal

Hence, the length of lift can be calculated proceeding fromthe conditions

at Qmax

at Qop

Assuming that P2 is less than P1 the following conditioncan be written as follows:

L = 2h = 2 ho = 2[H Pb/(g)]

Knowing L, the pressure at the bottom of the well can bedetermined.

5.0/)( 21 = gLPP

6.0/)( 21 = gLPP


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Complications of Gas Lift Well

Operation

Factors affecting the normal operation of gas lift wells are

the following:

(a) formation of sand bridges on the bottom or air blocks

in the flow string;

(b) deposition of salts on the bottom or in the flow siring;

(c) accumulation of water in the bottom and formation

of stable viator-oil emulsions.


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Complications of Gas Lift Well

Operation

Recommended Treatments:

1. The measures has to be taken to prevent and

eliminate the deposition of sand

2. Remove severe salt deposition, the string is

withdrawn and milled at machine shops.

3. Control paraffin/asphaltene deposition by suitable

means


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Treatment of Gas Slippage Problem to

Increase Efficiency Well surveys show that the efficiencies of

compressor gas lift are low as follows:compressor gas lift 0.10 to 0.14

straight gas lift 0.30 to 0.32

Intra-well gas lift 0.32 to 0.35

A low gas lift efficiency results from a large lossof head due to gas slippage in the flow strings.


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Increase EfficiencyOne way of combating the problem is to perform the

following operations to disperse gas in flow strings.

1. Dissolve the gaseous phase in the liquid. A subsequentdecrease in the tubing pressure liberates gas in the

form of tiny bubbles.2. Introduce a liquefied gas into the flow string, which is

given off as tiny bubbles with a decrease in tubingpressure. This method has successfully passed trialsconducted in field conditions on a number of wells.Investigations are currently under way for developinga special gas lift cycle of increased efficiency.


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Increase Efficiency

3. Pump surfactants down the flow tubing, which

accelerate gas evolution and prevent bubblecoalescence and enlargement.

4. Inject high-molecular compounds which reduce the

floating5. Disperse the gaseous phase by various means when

introducing it into the flow string: pass the gaseousphase through a system of fine orifices, increase

turbulent surges in a hydraulic disperser, subject gas tothe action of electric, magnetic, and ultrasonic fields,etc.


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Determination of Optimum Gas-Liquid

Ratio (GLR)

It is so important to determine the optimum gas-liquid

ratio (GRL) because this value of GLR is the base for

the determination the mount of gas required to be

injected into the reservoir.

The following solved example can be used to follow up the

procedure for this purpose


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Ratio (GLR)Example: Given the following data:

- producing depth of the pay zone 5000 to 5040 ft- well is completed with with 2 7/8-in tubing at depth

5000 ft

- PI is 0.50 bbl/d/psi and the GRL is 300 cuftbbl

- Te well THP is 100 psi and Ps (BHP)is 1350 psi

(a) What will be the well flow rate against THP = 100 psiif Ps = 1300 psi and Ps 1300 psi?

(b) Does an artificial lift method is required for this wellor not?

(c) Determine the optimum GRL?


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Ratio (GLR)

Solution

1.1. Assume different flow rate as 50, 100, 200, 400, and

600 b/d and get equivalent depth to THP = 100 psi2. Add 5000 ft to the depth equivalent to THP to get

equivalent depth to Pwf. Then get Pwf from suitable

Gilbert charts, as shown below.


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THP = 100 psi and GLR = 0.3 mcf/bbl


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The above figure shows that the well can flow at 150 bbl/day at Ps =1400 psi but this well will die before reservoir pressure Ps = 1300 psi

( at approximately Ps = 1350 psi).

For each flow rate at tubing size = 2 7/8 ID = 2 873 inch select the LOWEST


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For each flow rate at tubing size = 2 7/8-ID = 2.873 inch select the LOWEST

CURVE of GRL to get the opt. GRL for each q as shown below.

Then get the equivalent depth to THP = 100 psi and add 5000 ft to get

equivalent depth of Pwf. Then get Pwf at optimum GRL.

Optimum GRL at Tubing size = 2.873-in and THP = 100 psi


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Then at selected Q for example Q = 475bbl/d, optimum

GLR can be obtained and then required volume of gasto be injected can also be calculated as follows:

Total volume of gas = Q * Optimum GLR

= 475 (bbl/d) x 2900 cuft/bbl (from figabove) scf

Daily gas volume supplied by formation = 475 x 300 scf

Injected gas required daily = Q x (Opt. GLR current

GLR)

= 475 (2900 - 300 ) = 475 x

2600 scf

= 1.235 x 10 ^ (6) scf

principles of gas lift

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