SPE SPE 9981 Society of Petroleum Engineer'S

Gas Lift Design and Performance

by Robert Wayne Pittman, * Texaco, Inc.

*Member SPE-AIME

Copyright 1982, Society of Petroleum Engineers This paper was presented at the International Petroleum Exhibition and Technical Symposium of the Society of Petroleum Engineers held in Bejing, China, 18-26 March, 1982_ The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write SPE, 6200 North Central Expressway, Dallas, Texas, 75206 USA. Telex 730989

ABSTRACT

The optimum design of a continuous flow gas lift installation is dependent upon the critical combina-tion of a number of pertinent variables, including well performance index, gas in solution. static res-ervoir pressure, tubing size and injection gas pres-sure. The economic performance of the optimum design is dependent upon maintaining a minimum injection gas to produced liquid ratio that relates to minimum adi-abatic power associated with recycle gas compression. Examples illustrate this to be accomplished by de-signing for and maintaining injection gas pressures such that a maximum injection valve depth for the design production rate can be utilized.

INTRODUCTION

Flowing oil wells have enough potential energy in the reservoir to push the liquids through the res-ervoir into the wel1bore, up the tubing and through the surface equipment to the tank battery. As the ~e11 is produced, the potential energy is converted to kinetic energy associated with the fluid movement. This dissipates the potential energy of the reser-~oir, thereby causing the flow rate to decrease and the flow to eventually cease. It may be economical ~t any point in the life of a well to maintain or even increase the production rate by the use of gas lift to offset the dissipation of reservoir energy.

Gas lift was practiced in the United States for oil production over 100 years ago. The system used a valve design was patented and given the name of "oil ejector" Although this original valve design was elaborate, the main feature in continuous flow gas lift is merely to lighten the gradient in the liquid column so that the reservoir pressure avail-able will be adequate to cause flow to occur or to increase.

Alternatively, the other type of gas lift may be used when reservoirs will not produce in a continuous flow manner. This method is called intermittent gas lift because a column or "slug" of liquid is allowed

References and illustrations at end of of paper.

to accumulate in the bottom of the well and then a large volume of gas is quickly injected below this slug to lift it to the surface. This cycle is re-peated at an experimentally-determined optimum combi-nation of fill-up time, slug lifting time and gas injection volume per slug. As a reservoir is deplet-ed, it may become necessary to consider this type of gas lift to maintain economic primary oil recovery.

The advantages of the gas lift method of arti-ficial lift are:

1. Operating depths in excess of those attain-able with rod pumps.

2. High fluid production rates. 3. Not affected by solids in produced fluids. 4. No heavy or unusual accessory equipment at

the wellhead. 5. Not mechanically affected by the inclination

of the wellbore.

The main concern in gas lift design is the speci-fication, spacing and pressure setting of the un-loading and operating valves in order to initiate and maintain oil production with economic gas injection rate. After design installation, a primary concern in the daily operation of gas lift is the cost of the gas compression facilities. This can be uneconomic if excessive gas volumes are circulated due to shallow injection depth or if excessive volumes are circulated with diminishing returns. The first of these is due to faulty design. The latter is due to improper operation of even a correctly designed system.

Other work has addressed these concerns. Redden et a12 discussed the benefit of optimizing gas lift systems where gas was being injected back into the reservoir for pressure maintenance in Venezuela. Blann et al 3 reported the benefit of redesigning gas lift installations such that a 46 percent increase in oil production was obtained with only 2 percent addi-tional gas injection in a large North African field.

This paper discusses the initial work by Texaco to improve gas lift operations by applying basic prin-ciples for improved performance through a computer

2 GAS LIFT DESIGN AND PERFORMANCE SPE 9981

design program. The examples given are pertinent to continuous flow gas lift in the Texas Gulf Coast region.

CONTINUOUS FLOW DESIGN

There are at least sixteen important variables that affect the design and operation of a gas lift well. These are:

*Perforation depth Bottom-Hole Pressure

*Wellhead Flowing Pressure *Gas Line Pressure Available Injection Gas Rate Available Bottom-Hole Temperature

*Tubing Diameter *Casing Diameter

Ambient Temperature

'/'cProduction Rate Well Productivity

Index Water Cut Percent Oil Gravity Water Gravity Injection Gas Gravity Formation Gas/Oil

Ratio

Those variables noted by the asterisk are often the only ones readily available. In fact, gas lift designs are sometimes based on this limited informa-tion alone. Inefficient or totally non-operable installations can result when this is practiced, since other not so readily-known but very critical variables are involved.

Basic Theory A typical continuous flow gas lift well schematic is shown in Figure 1. In this figure, a drawdown (DD)has been indicated by a bottom-hole pressure under flowing conditions (BHPF). This BHPF will give the desired production rate, since it is determined from the productivity index (PI) relation-ship. Since PI is known from earlier tests, drawdown (BHPS-BHPF) is calculated from:

DD "" BLPD/PI. (1)

With the bottom-hole pressure at static condi-tions (BHPS) also determined from earlier tests, the bottom-hole pressure for flOWing conditions (BHPF) is

BHPF = BHPS-DD. (2)

This assumes, however, that gas is injected some-where in the liquid column to lighten it and make it possible for the BHPF to exist as indicated. To accomplish this, a short column of liquid may be lightened by injecting a large quantity of gas high in the well or a smaller quantity of gas at a deeper location. If the longer column of fluid is lightened, it takes less gas volume, but it requires a high pressure to inject it at the greater depth. It is evident that the latter alternative allows a low gas-liquid ratio (GLR) , as seen in Figure 1, but is governed by gas pressure (PC) available at the well-head. Since there must be an adequate margin of differential pressure to flow the required gas volume, gas lift valve mechanics are also involved and influence the final operating value of the gas pres-sure required at the wellhead.

If gas compression facilities are pressure lim-ited, gas lift must operate at higher GLR and shal-lower depths, resulting in an increased volume of gas circulation. This practice will specify a greater number of compressor installations for the production of an entire field. This can amount to a significant

increase in capital investment over that required for adequately pressurized facilities.

The deeper injection of gas requires higher pres-sure and lower IGLR, and is consistent with a minimum adiabatic power 4 as shown in Figure 2. This curve is prescribed by the equation:

AP = 4.02 X 10- 6 (l/K-l) (BLPD) (IGLR)

(T) [(P!PWU) (K-l)!K - lJ' (3)

where: BLPD Volume of liquid flowing daily IGLR Injection gas/liquid ratio T Temperature at injection P Pressure at injection K Ratio of specific heats

P~~ Pressure at wellhead.

The IGLR is inversely dependent on the injection pres-sure available. The lower IGLR requires' lower power, since IGLR has a 1:1 effect on AP, as can be seen from equation (3). Although the corresponding injection pressure P must be increased to achieve a lower IGLR, this increase in the equation is less than 1:1 due to the fractional exponent on P/PWH. The minimum as indicated in Figure 2 need only be approached, not exactly attained, for efficient operation.

One of the problems in calculating appropriate gas lift designs is the modeling of the pressure loss in the tubular or annular conduit. Espanol et al 5 suggest that three of the best relationships for cor-relating flow rate and pressure loss are the Hagedorn and Brown6 , Duns and Ros 7 , and Orkiszewski8 methods.

The single phase fluid flow pressure drop, or head loss in equivalent head of fluid flowing, can be calculated from the equation:

lIh f(L/d)(v)2 , 2g (4)

where the friction factor f is a function of Reynolds Number. However, in two-phase flow it is necessary to select a pressure drop correlation that fits the range of gas-liquid ratios expected for the average opera-tion. The work by Espanol found the Hagedorn and Brown correlation to be the most accurate for gas-liquid ratios greater than 180 m3 /m3 and the Orkis-zewski correlation to be more accurate for GLR less than 180:1. However, the original work by Poettmann and Carpenter 9 is still a base line for comparison of later-developed correlations dealing with multiphase vertical flow. 10

Many others, as already mentioned, have offered additional correlations although there is only one "gradient equation". This is because each investi-gator has emphasized different variables. All of these correlations are based on the total preSsure drop in a vertical conduit being made up of energy loss by friction, the change in elevation (potential energy change) and the change in kinetic energy.

The gradient can be expressed as

dp/dh == static gradient + friction gradient + acceleration gradient. (5)

The Poettmann and Carpenter work yields

P [1 + dp/dh = 102

f w2

]

7.46496 x 109 gp 2d 5

(6)

The development of their energy loss factor correlation came by measuring dp/dh and solving the above equation for the energy loss factor:

f :: (7)

The Poettmann and Carpenter work is based on the overall average response of 49 flowing and gas lift wells, therefore, their correlation factor has lumped into it many factors that can cause anomalous behavior were it used out of the range of flows, tubing size and gas-oil ratios for which it is determined.

The conditions for which it is valid are 60 rom and 73 rom tubing; medium flow rates; medium gas-oil and gas-oil-water ratios and low to medium pressures. Since this range of conditions is not too far out of line with a good many gas lift installations the Poettmann and Carpenter correlation can give appro-priate answers in many instances.

Hagedorn and Brown developed a correlation in similar manners to Poettmann and Carpenter, except a 490 m experimental well was used to obtain the corre-lation data and liquid hold up and acceleration effects not present in Poettmann and Carpenter theory were introduced. The Hagedorn and Brown work yields a gradient equation using a form of friction factor, (f) 4 Fannin (f).

- f, _____ - __ + C:;;m)2/ 2g1, (8) dp dh 102e + 29.85984 X 109g(Pm)2d 5 dh J where the average mixture density is expressed as:

Pm p~H ~ + Pg (l - H~) (9)

and: P~ liquid density H~ liquid holdup

~g gas density average velocity of mixture v

m

Duns and Ros defined the static pressure gradi-ent as a function of a weighted density and developed correlations for wall friction from extensive labora-tory data for each flow region. This work was per-formed in the laboratory and modified with actual field data. The correlations are in terms of a dimen-sionless gas velocity number, diameter number, liquid viscosity number and a dimensionless mathematical ex-pression. These dimensionless groups are the same as developed in the work of Hagedorn and Brown. The Duns and Ros work yields a gradient equation in dimensionless form. Since the next discussion will concern the evaluation of this work and that by Grif-fith and Wallis ll , producing a more useful correla-tion, further detail at this point is omitted.

The Orkiszewski work is a combination of several published methods. After extensive comparison of all

available methods, the Duns and Ros and the Griffith and Wallis methods were used to form the base of this correlation. Since the Griffith and Wallis correla-tion was more accurate for the high viscosity range oils at low flow rates, it was chosen as a foundation on which to proceed.

The Orkiszewski work yields a gradient equation: dp

P + L (10) dh 102 - w q /(7.46496 x 10 12 (A )2 t g P where: p average density

L f friction gradient w

t mass flow rate

qg gas volumetric flow rate A flow area of tubing p p average pressure of flowing mixture.

The Texaco computer program uses the Orkiszewski correlation. It also has the capability of utilizing the Poettmann and Carpenter correlation if desired. The difference in final ga~ lift des~gn is not radi-cally affected for tubular conduit and high water cut production for depths under 1500 meters.

The downhole gas a number of

small-ported valves used to inject pressurized gas into the fluid column to reduce its density suffi-ciently so that flow can occur with the available drawdown of the ~eservoir pressure.

The principle of operation of these valves is relatively simple. They are pressure regulators employing a spring and/or nitrogen gas charge over a bellows area that opposes either the lift gas or the flowing fluid pressure for control. In operation, as a shut-in well is being started up, all valves are initially open and the high pressure gas maintained to supply the energy for the lift enters an upper valve at such depth that the fluid column above that valve can be forced by the pressure differential into the usually-pressurized gas-liquid separator at the sur-face. As this first increment of fluid is unloaded, the next lower valve will admit gas to an extent such that the resulting drop in operating gas pressure will allow the upper valve to close. This procedure is continued with each formerly open valve closing off until the final operating valve in the string is reached. Ideally, this operating valve then passes gas continuously into the flowing column of fluid, thereby producing a reduced density liquid that will continue to flow at a rate proportional to the draw-down of the reservoir pressure at the well perfora-tions. The upper unloading valves must then be closed, or excessive gas is used and erratic per-formance results.

A deficiency sometimes arises due to the diffi-culty of systematically locating the operating valve at the efficient injection point. This can be over-come by spacing the unloading valves with respect to this valve, rather than allowing the unloading valve spacing to dictate the operating valve location.

4 GAS LIFT DESIGN AND PERFORMANCE SPE 9981

The type of valve used in the procedure just described is often referred to as a gas pressure operated valve. As previously stated, the gas pres-sure must be decreased for these valves to close sequentially and allow the well to come to full design production rate from the operating valve.

The other basic type valve is often referred to as a fluid pressure operated valve. This valve does not require a decrease in gas pressure for it to close, but instead depends upon a decreasing pressure drop in the flowing fluid as the density is decreased, so that the resulting fluid pressure reduces and al-lows the valves to close sequentially. The difficul-ty in using this type valve is due to the problem of predicting flowing pressure drop accurately and the inability to effect changes by surface controls.

EXAMPLE INSTALLATIONS

Within the past decade, fuel costs for gas com-pression increased almost four-fold and there was less gas available for gas lift in the Texas Gulf Coast Region. This economic challenge was answered by an increased awareness and implementation of effi-cient gas lift design that permitted operations to continue without major revisions.

Table 1 illustrates the effect of the changes by the data shown for several closely-monitored contin-uous flow gas lift wells in Texaco's Texas Gulf Coast Region. The "before" and "after" statistics indicate a fluid production increase of two-fold with a Sig-nificant gas circulation reduction. In terms of in-creased lift efficiency in liquid volume per circu-lated gas volume, a potential improvement factor of 2.3 was demonstrated.

In the following discussion of computer-gener-ated design performance, the IGLR are quite low, con-trasting with the fact that for many years, while gas was plentiful, it was expedient to design with high gas-liquid ratios. This resulted in so called "mini-mum designs which were considered a reli-able way to achieve maximum drawdown of the reser-voir, instead of designing for the most efficient injection depth and gas-liquid ratio. While this probably evolved due to traditionally low pressure gas lines, it influenced design even in areas where higher pressure operations were possible.

Table 2 illustrates the design scenario for four wells, three of which contribute to the statistics of Table 1. The scenario is presented in terms of total liquid rate and IGLR for design gas pressure, average injection depth and total gas rate. These wells were restricted to a design gas pressure of 4137 kPa. Al-though the improvement that could have resulted from a higher gas pressure (Design 2) and (Design 3) was evi-dent, the changeover to higher injection pressures could not be made quickly. Therefore, with increased attention to designing with minimum IGLR, the improve-ment as indicated by Design 1 over that for the usual previous practice was sought. The actual production of these four wells was increased to 782 m3/d or 68% of the 1153 m3/d sought. Well C increased production rate from 109 m3/d to 131 m3/d but was less spectacu-lar than wells A and B, which will be discussed in more detail. Well D became plugged with sand shortly after start up and did not make a sustained contribu-tion toward fulfilling the design scenario. The final

IGLR for wells A, B, and C was 23 m3/m3 and was within the design scenario of 26 m3/m3.

Table 3 illustrates individual well design cri-teria with before and after rework comparisons for two of the wells of Table 2. Well A was redesigned to increase production from 115 m3/d to 318 m3/d. The computer design recommended an injection gas to liquid ratio (IGLR) of 14 m3/m3. The usual gas lift vendor design recommended planning for an IGLR of 36 m3/m3 . After installation by the computer design, the well performed at an IGLR of 18 m3/m3, or approximately half the gas volume that would have been planned for by the vendor's recommended design, even though the apparent well PI was found to be lower than that used to calculate the design. This lower PI required the use of an IGLR of 18 m3/m3 instead of 14 m3/m3

Another example illustrating improved design is seen for well B. Here the design production increase from 137 m3/d to 238 m3/d was possible with an IGLR of 33 m3/m3 according to the computer design, while the standard vendor design practice specified 43 m3/m3 IGLR and would only predict a maximum of 175 m3/d pro-duction rate with the existing well tubing and flow line sizes. After reworking the well, by computer design, it produced 215 m3/d and required an IGLR of only 15 m3/m 3. Since the final test on this well showed it to have an apparent PI of 0.15 m3/kPa.d, it should have produced in excess of 238 m3/d had the full design drawdown been achieved. This was pre-vented, however, by insufficient valve staging of only 69 kPa and a higher-than-designed surface gas pressure required to stroke the operating valve to sufficient opening to pass the required gas volume rate through the small valve port used. This resulted in opening up three of the four valves installed instead of one, thus causing multipoint injection of gas.

The next two examples contributing to the im-provements shown in Table 1 are from another field area where the injection gas pressure was of a magni-tude approaching that shown for Design 3 of Table 2. The first of these, shown in Table 4, is an example of obvious excessive gas injection before the well was reworked, since the computer design indicated that nearly twice the production rate could be lifted with about one-fourth the gas injection. Upon pulling the tubing to rework the well, a hole was found in the tubing. It was surprising to find that the gas lift vendor contacted recommended a design IGLR of 117 m3/m3 to obtain a desired production of 127 m3/d. Again, the computer design specified a much lower IGLR of 26 m3/m3 to achieve the production rate. After reworking the well with the injection depth specified by computer design, it is seen that the production rate is nearly attained with only a slightly higher IGLR than ideal. Had the apparent PI of the well truly been 0.115 m3/kPa.d as had been used for the design input, rather than 0.09 m3/kPa.d finally measured from final test, the design production rate and IGLR would have been more nearly achieved. This example illustrates that some designs wasteful of injection gas can call for an IGLR as high as that produced by a hole in the tubing. It also illustrates how critical it is to have an accurate PIon which to perform a gas lift design.

The final example shown in Table 5 illustrates the limiting effect of tubing size and gas pressure on production rate. The existing design had been

SPE 9981 R. W. PITTMAN 5

installed with the prospect of attaining 95 m3/d, using a high IGLR. Before rework, only 59 m3/d were being produced with a high IGLR of 152 m3/m3 in an attempt to obtain the maximum production. The com----puter design indicated that to produce this quantity of production through the small tubing would require maximum efficiency. This would require a minimum IGLR of 72 m3 /m3 injected at a higher pressure than avail-able in the field. The final solution was to install larger tubing which would theoretically give 127 m3 /d for the same IGLR. After rework, the well performed at 86% of its ideal design production rate with bet-ter-than-expected IGLR. This well design illustrated the difficulty of obtaining sufficient gas passage through valves with small bellows area without run-ning higher than design settings on gas pressure at the surface. The larger tubing required the use of 25 mm valves rather than the 38 mm valves that had been used with the 60 mm tubing due to 140 mm casing size. The stiffer bellows in the 25 mm valve re-quired more than design gas pressure to hold the valve open sufficiently to pass enough gas for the well to work down to the operating valve. This il-lustrates graphically the effect of valve mechanics on overall performance, and points out the short-comings of the standard design gas lift valve.

CONCLUSIONS

1.

2.

3.

Optimum design of continuous flow gas lift sys-tems is best achieved by careful consideration of all well' variables in a systematic computer program.

Reductions in gas compression costs associated with recycle gas compression can be as high as 50% if maximum injection depth and pressure are designed for and maintained.

The physical restrictions placed on the design of the standard gas lift valve render some inef-ficiency in its performance, especially in the smaller diameter sizes.

NOMENCLATURE

A Flow area of conduit m2 AP Adiabatic power kw BHPF Bottom-hole pressure flowing kPa BRPS Bottom-hole pressure static kPa BLPD Volume rate of liquid flowing m3 /d DD Drawdown pressure kPa d Diameter of conduit m dp/dh;;: Pressure gradient kPa/m f Friction factor GLR Total gas to liquid

ratio standard, m3/m3 g Acceleration due to gravity 9.8 H Liquid holdup factor Clh Pressure drop in terms of

liquid head m IGLR Inj ec t ion gas to liquid

ratio standard, m3 /m 3 K Ratio of specific heats L Length of conduit m P Absolute pressure kPa p Average pressure of flowing mixture kPa PC Gas pressure at surface kPa PI Productivity index m3 /kPa.d PS Separator pressure kPa PWH Absolute wellhead pressure kPa

q Gas volumetric flow rate m3/d kg/m 3 kg/m3 K kg/m3 m/sec kg/d

e. Density p Average density T Absolute temperature T Friction gradient v Velocity of fluid flow rate w Weight rate of fluid flow

Subscripts: f friction

gas liquid mixture

g I m

P t

pipe or tubing total

ACKNOWLEDGEMENT

The Author appreciates the historic opportunity to make available the Texaco work reported in this paper.

The Author wishes to acknowledge Hr. Noell C. Kerr, retired, Texaco Producing Department, for his assistance in field liaison and data retrieval, Mr. R. L. Simmons for his assistance in initial computer programming, and many others in Texaco for their assistance and consultation.

REFERENCES

1. Brown, K. E.: Gas Lift Theory and Practice, Prentice-Hall, 'Inc~nglewood-cIiffs, New Jersey (1967) 181-198.

2.

3.

4.

5.

6.

7.

8.

Redden, J. D., Sherman, T. A. G., and Blann, J. R.: 1I0pt imizing Gas-Lift Systems," paper SPE 5150 Proc. SPE 49th Annual Fall Meeting, Houston, Oct. 6-9, 1974.

Blann, J. R., Brown, J. S., and DuFresne, L. P.: "Improving Gas-Lift Performance in a Large North African Oil Field,!! J. Pet. Tech. (September, 1980) 1486-1492.

Craft, B. C., Holden, W. R., and Graves, E. D., Jr.: Well tice-Hall , (1962) 368-452.

Espanol, J. H., Holmes, C. S. and Brown, K. E.: IIA Comparison of Existing Multiphase Flow Methods for the Calculation of Pressure Drop in Vertical Wells," SPE Reprint Series, No. 12 (1975) 65-72.

Hagedorn, A. R. and Brown, K. E.: IIExperimental Study of Pressure Gradients Occurred During Con-tinuous Two-Phase Flow in Small Diameter Vertical Conduits," paper SPE 940 presented at SPE 39th Annual Meeting, Houston, October 11-14, 1964.

Ros, N. C. J. and Duns, H. J.: ItVertical Flow of Gas and Liquid Mixtures in Wells," Paper 22-PDG, Proc. 6th World Pet. Congress, Section II, Frankfort, June 19-26, 1963.

Orkiszewski, J.: "Predicting Two-Phase Pressure Drops in Vertical Pipe,1t Paper SPE 1546, Proc. 41st Annual Fall Meeting, Dallas, October 2-5, 1966.

6 GAS LIFT DESIGN AND PERFORMANCE

9. Poettmann, F. H. and Carpenter, P. G.: liThe Multiphase Flow of Gas, Oil, and Water Through Vertical Flow Strings with Applications to the

Design of Gas-Lift Ins tallations, II Drilling and Production Practice, API (1952) 257-317.

10. Lawson, J. D., and Brill, J. P.: "A Statistical Evaluation of Methods Used to Predict Pressure Losses for Multiphase Flow in Vertical Oilwell Tubing, SPE Reprint Series, No. 12 (1975) 84-95.

11. Griffith, P. and Wallis, G. B.: IITwo-Phase Slug Flow ll , ASME J Heat Transfer (August, 1961) 307-320.

TABLE I

RESULTS OF COMPUTER DESIGN PROGRAM APPLICATION

EXAMPLE WELLS TEXAS GULF COAST REGION

VARIABLE BEFORE AFTER

FLUID PRODUCTION, m3/d 591 1214

GAS CIRCULATEO*, m3/d 40921 36740

LIFT EFFICIENCY, m3/m 3 0.014 0.033

*STANOARD

TABLE 2

GAS LIFT DESIGN SCENARIO BY COMPUTER TEXAS GULF COAST REGION

WELLS A, B. C, 0

PREVIOUS PRACTICE DESIGN DESIGN 2

LIQUID IGLR PRESS. LIQUID IGLR PRESS. LIQUID IGLR PRESS. RATE m3/m3 k Po RATE m3/m3 k Po RATE m3/m3 k Po m31 d m3/d m3/d 475 35 4137 1153 26 4137 1153 19 4826

AVG. I NJ. DEPTH, m AVG. INJ. DE PTH, m AVG. INJ. DEPTH, m 557 699 794

GAS RATE, m3/d GAS RATE, m3/d GAS RATE, m3 /d 16625 29978 21907

SPE 9981

DESIGN 3

LIQUID IGLR PRESS. RATE m3/m3 k Po m3/ d

1153 15 5860

AVG. INJ. DEPTH, m 911

GAS RATE, m3/d 17295

WELL

A

8

WELL

E

TABLE :3

INCREASED PRODUCTION WITH DECREASE IN INJECTION GAS/LIQUID RATIO

COMPUTER GAS LIFT DESIGN

LIQUID RATE IGLR PI GAS INJECTED

STATUS m3/d m3/m3 m3/kPo'd m3/d

BEFORE REWORK 1\5 30 0.4 9540 (FOR 318

COMPUTER DESIGN 318 14 0.4 4452

GLV. MFGR. DESIGN 318 36 0.4 11448

AFTER REWORK COMPUTER DESIGN 334 18 0.38 6012

BEFORE REWORK 137 35 0.1 8330 (FOR 238

COMPUTER DESIGN 238 33 0.1 7854

GLV. MFGR. DESIGN 175 43 0.1 7525

AFTER REWORK COMPUTER DE SIGN 215 15 0.15 3225

TABLE 4

REESTABLISH ECONOMIC PRODUCTION WITH DECREASE IN INJECTION GAS/LIQUID RATIO

COMPUTER GAS II FT DESI GN

LIQUID

m 3/d)

m3/d)

RATE IGLR PI GAS INJECTED STATUS m3/d m3/m3 m 3/ k Po' d m3/d

BEFORE REWORK 71 97 12319 (FOR 127

COMPUTER DESIGN 127 26 0.115

GLV. MFGR. DESIGN 127 117 0.115

AFTER REWORK COMPUTER DESIGN 119 32 0.09

TABLE 5

INCREASED PRODUCTION WITH DECREASE IN INJECTION GAS/LIQUID RATIO

COMPUTER GAS LIFT DESIGN

LIQUID

3302

14859

3808

RATE IGLR GAS INJECTED

BFPD)

WELL STATUS m3/d m3/m3 m3/d BEFORE REWORK

59 152 8968 (60mm TUBING) COMPUTER DESIGN 95 72 N/A WITH EXISTING (60mm TUBING) FIELD GAS PRESSURE

F COMPUTER DESIGN

( 7:3mm TUBING) 127 72 9144

AFTER REWORK 110 69 7590

PC "'

o

PS

...... GAS ...... OIL

WATER PC P

,~~--+-- HIGH GLR

~-+-LOW GLR VALVES

BHPS

FLOWING LIQUID GRADIENT

D

FIGURE

CONTINUOUS FLOW GAS LI FT

INJECTION

'----STATIC LIQUID , GRADIENT ,

BHPF '. BHPS ' .... 00 +I

POWER

/",ADIABATIC POWER

..................

IGLR

o~-----+-----------------------. P

.....------ OPTIMUM INJECTION

--O~------------------------------~P

FIGURE 2

CONTINUOUS FLOW GAS LIFT OPTIMUM INJECTION POINT THEORY