principles of gas lift
TRANSCRIPT
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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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PRINCIPLES OF GAS LIFT
Fig. 7-1 Gas Lift Performance
(a) Single string, (b) Dual string, (c) Stepped two-string
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PRINCIPLES OF GAS LIFT
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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PRINCIPLES OF GAS LIFT
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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PRINCIPLES OF GAS LIFT
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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PRINCIPLES OF GAS LIFT
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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Unlimited fluid withdrawal
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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Unlimited fluid withdrawal
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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Unlimited fluid withdrawal
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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Treatment of Gas Slippage Problem to
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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Treatment of Gas Slippage Problem to
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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Determination of Optimum Gas-Liquid
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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Determination of Optimum Gas-Liquid
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