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Eventually, gas wells will cease producing as the reservoir pressuredepletes. The usual presence of some liquids can reduce productioneven faster. This paper describes the problem of liquid accumulationin a gas well. Recognition of gas-well liquid-loading problems andsolution methods are discussed.1

IntroductionGas wells producing dry gas have a low flowing bottomhole pres-sure (FBHP), especially for low-rate wells. When liquids are intro-duced, the FBHP increases. Liquids in the gas may be produceddirectly into the wellbore or condensed from vapor in the upperportion of the tubing.

The total flowing-pressure drop can be expressed as the sum ofthe pressure drops from elevation (weight of the fluids), friction,and acceleration. For low-rate wells, the acceleration term is verysmall, and, with correctly sized tubing, the friction term is alsosmall. The elevation, or gravity term, becomes larger when liquidloading occurs.

Fig. 1 shows the approximate flow regimes as gas velocitydecreases in a gas/liquid well. If the well is flowing as a mist of liq-uid in gas, then the well still may have a relatively low gravity-pres-sure drop. However, as the gas velocity begins to drop, the well flowcan become slug and then bubble flow. In this case, a much largerfraction of the tubing volume is filled with liquid. As liquids accu-mulate, the increased FBHP will reduce or prevent production.

Several actions can be taken to reduce liquid loading. • Flow the well at a high velocity to stay in mist flow by use of

smaller tubing or by creating a lower wellhead pressure.• Pump or gas lift the liquids out of the well (many variations).• Foam the liquids, enabling the gas to lift liquids from the well.• Inject water into an underlying disposal zone.• Prevent liquid formation or production into the well (e.g., seal

off a water zone or use insulation or heat to prevent condensation).If liquid accumulations in the flow path can be reduced, then the

FBHP will be reduced and production increased. The liquid-loadingproblem will have been solved.

Recognizing Liquid LoadingLiquid loading is not always obvious. If a well is liquid loaded, it stillmay produce for a long time. If liquid loading is recognized andreduced, higher producing rates are achieved. Symptoms indicatingliquid loading include the following.

• Sharp drops in a decline curve (Fig. 2).• Onset of liquid slugs at the surface of well.

• Increasing difference between the tubing and casing flowing pres-sures (i.e., Pcf −Ptf) with time, measurable without packers present.

• Sharp changes in gradient on a flowing-pressure survey.

Critical Velocity. Turner et al.2 developed two mechanistic modelsto estimate critical velocity.

• A film of liquid on the wall of the tubing.• A droplet suspended in the flowing gas. The model that best fit their well data was the droplet model. Gas

rates exceeding critical velocity are predicted to lift the dropletsupward. Lower rates allow droplets to fall and accumulate. Colemanet al.3 later correlated to well data with lower surface flowing pres-sures than did Turner. Turner’s analysis gives the following for criti-cal velocity:

σ1/4(ρl−ρg)1/4

νgc=k ,ρg

1/2

where k=1.92 (Turner et al.2) or 1.59 (Coleman et al.3).Assuming2 σ=20 and 60 dynes/cm and ρl=45 and 67 lbm/ft3 for

condensate and water, respectively, a gas gravity of 0.6, z=0.9, anda temperature of 120ºF, then

(ρl−0.0031Ptf)1/4

νgc=C ,(0.0031Ptf)1/2

where C is 5.34 for water or 4.02 for condensate2 or 4.43 for wateror 3.37 for condensate.3

The corresponding critical gas rate, Qgc, in MMscf/D is

3.06PAνgcQgc= .

(T+460)z

If any water is produced, conservatively use water properties to cal-culate critical velocity. Typically evaluated at the wellhead, the aboveequations are valid at any well depth if the in-situ pressure and tem-perature are known. The distance between the tubing end and theperforations should be minimized because casing flow is usually liq-uid loaded.

Stability and Nodal Analysis. As liquids accumulate at lower gasrates, tubing performance can become unstable. Fig. 3 shows a tub-ing performance curve (TPC), or “J” curve, evaluated at the tubingbottom near perforations. This flowing pressure is needed for vary-ing production rates at a constant gas/liquid ratio (GLR). It is plot-ted across a gas-deliverability curve, or inflow-performance curve.

The flowing pressure is the sum of the tubing-pressure drop andthe Ptf. The curve turns up (required pressure increases) at lowrates because of liquid holdup in the tubing. At high rates, liquids

Solving Gas-Well Liquid-Loading Problems

Distinguished Author SeriesJames F. Lea, Texas Tech U., and Henry V. Nickens, BP plc

Copyright 2004 Society of Petroleum Engineers

This is paper SPE 72092. Distinguished Author Series articles are general, descriptive rep-resentations that summarize the state of the art in an area of technology by describing recentdevelopments for readers who are not specialists in the topics discussed. Written by individualsrecognized as experts in the area, these articles provide key references to more definitive workand present specific details only to illustrate the technology. Purpose: to inform the generalreadership of recent advances in various areas of petroleum engineering.

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are carried with the gas, liquid holdup islow, and friction is more predominant.

If the TPC and the reservoir inflow per-formance relationship (IPR) are plotted,their intersection predicts the flow rate. Asshown in Fig. 3, two intersections can existwith only the higher-rate intersection beingstable. Points A and B move from the lowerintersection, and Points C and D move tothe higher intersection. Operate to the rightof the TPC minimum above critical rate,with tubing sized for low friction.

The analysis method (Nodal analysis fromSchlumberger) has many possibilities forgas-well analysis. The effects of flow-patharea, surface pressure, future reservoir pres-sure, and others can be studied.

Fig. 4 illustrates the effects of tubingdiameter. In this case, D1 would be judgedto be too large because the IPR intersectionis to the left of the TPC minimum. DiameterD3 shows higher friction. Diameter D2might be judged the best size for the currentsituation. Diameter D3 would continue to

provide flow without liquid loading to thelower rates, but D2 allows higher rates at thecurrent intersection.

Use critical velocity, Nodal analysis, andexperience to predict liquid-loading trends.Analysis cautions include the following.

• Verify calculated tubing-pressure dropswith measurements before selecting a multi-phase-flow correlation before broad use.

• Annulus-flow calculations should beviewed with caution.

• The prediction of the onset of sharp liq-uid loading at low rates varies tremendous-ly with different flow correlations.

• GLRs and IPR data often are unknown.

SolutionsLiquid loading may be present, but whatsolutions are best to alleviate the problem?No universal solutions exist.

Sizing Production Strings to EliminateLiquid Loading. A properly designedsmaller tubing or velocity string can

increase gas velocityto reduce liquidloading.4 The fol-lowing factorsshould be evaluatedbefore installingsmaller-inside-diam-eter tubing.

• Will the installa-tion be a long-termsolution comparedwith use of the ex-isting tubing andother methods (e.g.,plunger lift)?

Fig. 2—Decline curve showing onset of liquid loading.

Fig. 1—Flow regimes in gas wells producing liquid.1

(To Page 69)

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• The tubing string should extend to near the perforations.Hanging tailpipe below high-set tubing5 to eliminate casing flowcan be beneficial if needed.

• If flow is above critical at the bottom of the tubing, it will be sofor all of the tubing, which is a desired goal.

• The decline curve, after a successful installation, should show aprojection of higher future rates than before. Immediate rates maybe misleading.

Casing production with an occasional tubing-production peri-od to lift liquids up a smaller string may be referred to as a“siphon string.”

Compression. Compression is used to lower the tubing pressureand increase flowing gas velocity.6 Compression considerationsinclude the following.

• Will wellhead compression increase the rate economically andprovide long-term effects?

As Figs. 3 and 4 show, the gas-deliverability curve extends toa steep curve near the absolute open flow. Lowering the FBHP willresult in little production increase. Avoid compression inthis region.

• Adding a larger or twin flowline may reduce the wellhead pres-sure considerably without compression.

• Often compression is applied to a group of wells or an entirefield. Model the field to determine fieldwide response.

• Select the type of compressor for throughput, intake pressure,liquid tolerance, durability, and best economics.6

Plunger Lift. Plunger lift7 (Fig. 5) is a premier method of operatinga gas well with liquids. It uses a free-traveling plunger to assist thegas in carrying liquid upward without excessive liquid fallback.Periods of flow and no-flow for pressure buildup are required.Plunger lift can operate with no external power to the well. Theplunger and liquids are lifted by use of gas pressure built up in thetubing/casing annulus while the production valve is closed.

Components include the following. • A wireline-installed downhole bumper spring to catch the

falling plunger. • A surface lubricator designed to catch the plunger and allow

flow to continue with the plunger at the surface.

• A motorized valve at surface to open and close the well. • A sensor at surface to monitor plunger arrival.• An electronic controller with logic to set cycles of production

and shut-in time for best operation.Fig. 6 illustrates a plunger-lift cycle. Pressure builds in the cas-

ing with the plunger at the bottom of the well. Next, the wellopens and annulus gas expands to lift the plunger and liquid tothe surface. Gas flows while the plunger remains at the surface.Liquids accumulate in the well as gas flow decreases. The valvecloses and the plunger falls to the bumper spring. Repeating cyclesmay be adjusted continuously by use of a plunger-lift controller.

The pressure that builds in the annulus during the shut-inportion of the cycle is the major source of energy to bring theplunger and liquid to surface along with some well inflow.Installations operate best with no packer in the well. Some

Fig. 5—Typical plunger-lift installation.

Fig. 3—Intersection of TPC and IPR determine potentialoperating rates. Fig. 4—Sensitivity of tubing performance to diameter.

Distinguished Author Series(From Page 31)

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plunger wells operate with a packer, but greater well pressure andGLR are needed.

Plunger feasibility is evaluated as follows. • Check industry guidelines to see if the well is a plunger candidate.1. The GLR should be approximately 400 scf/bbl per 1,000 ft

of depth.Example.Given: GLR=800 scf/bbl and depth=5,000 ft.400 scf/bbl×5,000/1,000=2,000 scf/bbl required. This well is

not a candidate by this rule, which does not consider pressure-buildup effects.

2. The “slug-size” pressure should be less than 50% of the “net”pressure. The “slug-size” indication is the operating static casingpressure minus the tubing pressure, or Pcs−Pts. The “net pressure” isPcs−Ptf, where Ptf is the starting flowing-tubing pressure. If Pcs=600,Pts=500, and Ptf =100 psi, then:

(600−500)/(600−100)=20%, which is less than 50%; therefore,the well is ready to open.

3. See Fig. 7 for a 2-in. tubing-plunger feasibility chart.8 A chartfor 21/2-in. tubing-plunger operation also is available.8 The “netoperating pressure” is Pcs−Ptf when the well is opened initially.

Example.Given: depth=8,000 ft, 23/8-in. tubing, Pcs=250 psi, and Ptf = 50

psi.Then, the net operating pressure is 250−50=200 psi. Fig. 7

shows that the required GLR for plunger lift is 10,000 scf/bbl.With larger 27/8-in. tubing, less GLR is needed. Other methods9 include calculation of the average FBHP during a

plunger cycle, which shows results as a nodal plunger/tubing perfor-mance curve. Another study10 incorporates the use of a reservoirmodel and a tubing-flow model.

• Evaluate other methods of dewatering vs. plunger lift.Plunger lift works better with larger tubing size. A velocity string

requires smaller tubing. Lower rates (only a few Mscf/D) probablytrend toward plunger-lift use and not small tubing.

• Evaluate the well configuration.First run a gauge and scraper if needed. Use wireline to run a

mockup or plunger to check downhole clearances.

Land the tubing, without a packer, such that some open perfora-tions are below the tubing end.

The wellhead should be the same diameter as the tubing.• Select and install necessary plunger controls and equipment.Controllers vary with function and the degree of sophistication. A

typically accepted speed of arrival is approximately 750 ft/min. Awindow of arrival would be (750 ± X) ft/min, where X is the incre-mental velocity of rise. Speed is plunger-travel length divided bytravel time.

One example logic is as follows.If the plunger speed is greater than (750+X) ft/min, reduce the

casing-pressure buildup time and/or lengthen the flow time.If the plunger speed is (750 ± X) ft/min, make no adjustments.If the plunger speed is less than (750−X) ft/min, lengthen the

buildup time and/or reduce the flow time.After the flow period, the plunger should fall through some liq-

uid in the tubing. When the BHP is sufficient to raise the plungerand liquid, the well is opened to begin the cycle. A more-productivecycle involves lifting a small slug of liquid on each cycle.

A new two-piece plunger, consisting of a ball and cylinder,demonstrates increased production in some cases. It seals on theupstroke when the ball and cylinder are together, and componentscycle to the bottom of the well when apart.11

Beam Pumping. Beam-pump systems are a common method ofdewatering gas wells. These systems function when wells do nothave enough pressure and GLR to allow use of other methods.Initial and operating costs can be high. Attention to problem areascan significantly reduce operating expense.

Fig. 8 shows a downhole dynamometer pump card with the rodload and position plotted above the pump for one cycle with no gasinterference. Gas in the pump may cause gas lock, which in turn cancause production to cease temporarily, as well as fluid pound andassociated mechanical problems, which also reduce production. Gasseparation is recommended, when possible, by setting the pump ora dip tube below the perforations.

If the operator ensures that the pump is built and spaced correct-ly to obtain a high compression ratio (CR) on the downstroke, as

shown in Fig. 9, then many problemscan be solved with a simple pump in agassy well.

First, try to separate gas from thepump intake. Ranked guidelinesinclude the following.

• Use a dip tube below the pumpintake to receive fluids below the perfo-rations, but use a moderate length toavoid gas breakout.

• Set the pump below the perfora-tions.

• Use “poor-boy” separators12,14 forlow rates when the pump must be setabove the perforations.

This type of separator uses the prin-ciple of downward flow at a slower rate(approximately 0.5 ft/sec) than thebubbles rise. Higher production rates(approximately 150 to 200 B/D) cangas lock this type of separator.

• If landed above the perforations,consider separators such as a packerseparator, filter element, or vortex.

Fig. 6—Plunger-lift cycle.

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• Ensure a good CR13 on the pump downstroke and a high flowarea through the valves (Fig. 9). A high CR will prevent gas lock.

• Use specialty pumps. Some pump designs open the travelingvalve (TV) mechanically. Others take the fluid load of the TV witha top sliding valve (SV).

Other pumps1 use a top TV to hold the hydrostatic pressure inthe tubing at the beginning of the downstroke. This method allowsthe bottom TV to open, allowing liquid and gas to enter the uppercompression chamber. This upper compression chamber compress-es on the upstroke to open the top TV and discharge into the tub-ing. These pumps are two-stage compression pumps.

Other designs1 include a tapered-barrel pump and the “panaceapump” with an enlargement in the barrel; both designs ensure liq-uids enter the barrel on the downstroke to prevent gas lock.

Consider a backpressure regulator1,13 on the tubing at the sur-face. Originally used to seat valves when wells flow at low rates, itseems to benefit gassy wells in general. Values of surface pressuremight be 100 to 300 psi or more.

Also consider matching the pump to the well using pump-offcontrollers or jack shafts (an additional set of sheaves between themotor and original motor sheave to slow the pump speed). The cas-ing gas must be allowed to flow through a check valve to the flow-line in all cases.

Beam pumps will dewater gas wells but are subject to gas inter-ference if not installed correctly. Maintenance, energy, and initialcost can be high, but they are reliable in general.

Hydraulic Pumping. Hydraulically powered downhole pumps arepowered by a stream of high-pressure water or oil (power fluid) sup-plied by a power-fluid pump at the surface. Hydraulic pumps are oftwo types.

• Piston pumps, which are similar to beam pumps.• Jet pumps that operate by power fluid passing through a ven-

turi, exposing the formation to low pressure. The surface power-fluid pump usually is a piston-type or cen-

trifugal high-pressure pump. A small-diameter jet pump, which fitsinside 11/4-in. coiled tubing (CT)1, allows a power string and pumpto be run inside 23/8- or 27/8-in. tubing and is a relatively new dewa-tering method. Liquid production comes up the tubing/CT annulus.The gas flows up the tubing/casing annulus. The pump can bereverse circulated up the CT for service in minutes. Jet pumpingmay require high power.

Foaming. In gas-well applications, the liquid/gas/surfactant mix-ing occurs most commonly downhole. This method worksbest with water only, but condensates can be present. Some opera-tors prefer that foams be tried first for liquid-loading problemsbecause they are inexpensive. Foaming may not be the most eco-nomical solution if large quantities of expensive surfactants areneeded. The foam produces a less-dense mixture by increasing the

Fig. 9—Compression in beam pump with gassy flow.13

Fig. 7—Plunger-lift feasibility for 23/8-in. tubing.8

Fig. 8—Pump card with gas interference.

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surface area of theliquid with bub-bles. The result isless gas/liquid slip-page. The gas canmore easily carrythe foamed liquidsto the surface.

One test proce-dure to determinewhich surfactantswork best in well-bore fluids isshown in Fig. 10.Well liquids areplaced into a tube,and a specifiedamount of thefoaming agent tobe tested is added.A specified gas rateis injected at thebottom of the tubethrough a fritteddisk, and liquidcarryover into thebeaker vs. time is

measured. This test15,16 is simple, quick, and inexpensive. It allowsevaluation of foaming agents before expensive field trials. Recentmethods17 test for surface tension and lower effective liquid-phasedensity to calculate a lower required critical velocity as a method ofpredicting foam performance.

There are various methods of introducing surfactants into thewell. The simplest method is to batch or continuously inject chem-icals down the annulus of a well with no packer. Also, soap stickscan be dropped down the tubing, manually or with an automaticdispenser. Guidelines include the following.

• Screen foaming agents with lab tests.• Water is easiest to foam. Condensates are more difficult and

require more-expensive chemicals. Water loading is most common.• If a packer is present, systems1 exist that allow the lubrication of

a 1/4-in. capillary tube down the tubing to inject chemicals at depth. • With no packer, agents can be introduced down the annulus,

either batched or injected. Consider automated measurements andcontrols to schedule treatments.

Foaming is a cheap-initial-cost solution for gas-well dewatering,but can be expensive if large volumes of surfactants are required. Ithas been used successfully in many applications.

Gas Lift. Gas lift18 introduces additional gas into the tubing to light-en the flowing gradient and can increase the fluid velocity above crit-ical. A compressor or a high-pressure gas well must supply the lift gas.The usual process is to inject gas down the casing and through a gaslift valve into the tubing. The gas in the tubing lightens the gradient,and the well produces at a higher rate. Gas can be injected below thetubing end or injected through only one valve or port if gas pressureis available to unload. A series of unloading valves can be used to helpinject near the bottom of the well with limited gas pressure.

Gas lift guidelines are as follows.• Compare costs with other methods.18

• Be sure that compressors and additional gas are available. • Model the wells, and possibly the entire field, with gas lift, com-

paring with other methods. Actually, plunger lift is an intermittent method of lift, sometimes

augmented by gas injection down the casing. Intermittent gas lift forlow-rate wells is used in wells with no plunger. “Stopcocking” is amethod of opening and closing wells so that gas pressure in the shut-in period can expand and intermittently gas lift liquids from the well.

Injection Systems. Instead of producing the water from a gas well,it may be possible to inject it into a zone below the gas zone. Thereare several methods of injecting the water in a gas well.19

• Bypass seating nipple:20 Pressure from water pumped upthrough the tubing is allowed to bear on an injection zone below thesucker-rod pump (Fig. 11) through concentric vertical holes in thebypass seating nipple. Some systems mechanically apply pressureon the downstroke.1

• Electrical-submersible-pump (ESP) -driven injection system:Systems are available that allow an ESP to pump water below apacker. Other pumping methods could inject water as well.

An injection test should be run on a suitable underlying injectionzone before considering this method.

Other Methods. Many other methods exist. A resistance cable toheat and prevent condensation was shown to approximately tripleproduction.21 Various controllers exist to prevent annulus headingand to control casing-to-tubing flow for best production.22 Inserts ateach joint to keep liquids dispersed have proved beneficial.23 Manyother methods have been demonstrated over the years, although itis hoped that the major concepts have been identified here.

Summary• Recognize liquid loading from well symptoms, critical velocity,

and/or Nodal analysis.

Fig. 11—Bypass seating nipple for water injection in agas well using a beam-pump system.19,20

Fig. 10—Bureau of Mines setup fortesting foaming agents.15

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• Surfactants may be tried with little initial cost and can be labo-ratory tested. Evaluate economics of continued use.

• Use of smaller-diameter tubing can be very effective for higherranges of flow and can be a long-term solution. Smaller tubing mayeventually have to be downsized to continue flow. However, smalltubing (approximately 1-in. diameter or less) can be very difficult tounload.

• Plunger lift may be preferred over smaller tubing for lowerrates, because the plunger works well with existing larger tubingand may perform to depletion of the reservoir. The two-pieceplunger shows advantages in some wells.

• Use of compression to lower wellhead pressures helps almost anymethod of producing gas wells, but economics must be considered.

• Jet hydraulic pumps are easy to install, produce high rates, andhave low servicing costs. They do not achieve low producing BHPs,and initial cost is a consideration. High power requirements maybe experienced.

• For low-pressure wells, a beam pump may be the only possibil-ity. High initial and energy costs may be encountered. Careful atten-tion can reduce servicing costs.

• Gas lift, by adding gas to the tubing to raise the velocity abovecritical, is viable if high-pressure gas is available.

• Consider injecting water below a packer if an underlying injec-tion zone is present.

NomenclatureA = cross-sectional area of flow, ft2

C = coefficient of reduced critical velocity, (ft/sec).(lbm/ft3)0.25

k = coefficient of basic critical velocity,(ft/sec).(lbm/ft3)0.25/(dyne/cm)0.25

P = pressure, psiaPcf = casing pressure, flowing, psiaPcs = casing pressure, shut-in, psiaPtf = tubing pressure, flowing, psiaPts = tubing pressure, shut-in, psiaQgc = critical gas flow rate, MMscf/DT = temperature, ºF

vgc = critical velocity of gas, ft/secX = increment of velocity of rise, ft/minz = gas compressibility factor

ρg = density of gas, lbm/ft3

ρl = density of liquid, lbm/ft3

σ = surface tension of liquid to gas, dynes/cm

References11. Lea, J.F., Nickens, H.V., and Wells, M.: Gas Well Deliquification, Elsevier

Press, first edition (2003). 12. Turner, R.G., Hubbard, M.G., and Dukler, A.E.: “Analysis and

Prediction of Minimum Flow Rate for the Continuous Removal ofLiquids From Gas Wells,” paper SPE 2198, JPT (November 1969) 1475;Trans., AIME, 246.

13. Coleman, S.B et al.: “A New Look at Predicting Gas-Well Load Up,”paper SPE 20280, JPT (March 1991) 329; Trans., AIME, 291.

14. Wesson, H.R.: “Coiled-Tubing Velocity/Siphon String Design andInstallation,” 1st Annual Conference on Coiled-Tubing Operations andSlimhole Drilling Practices, Houston, 1–4 March 1993.

JPT

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15. Campbell, J.A. and Bayes, K.: “Installation of 27/8-in. Coiled-TubingTailpipes in Live Gas Wells,” paper OTC 7324, 1993 OffshoreTechnology Conference, Houston, 3–6 May.

16. Thomas, F.A.: “Low Pressure Compressor Applications,” presentation atthe 49th Annual Liberal Gas Compressor Inst., 4 April 2001.

17. Foss, D.L. and Gaul, R.B.: “Plunger Lift Performance Criteria withOperating Experience—Ventura Field,” Drilling and Production Practice,API (1965) 124–140.

18. Beeson, C.M., Knox, D.G., and Stoddard, J.H.: “Part 1: The Plunger LiftMethod of Oil Production,” “Part 2: Constructing Nomographs toSimplify Calculations,” “Part 3: How to Use Nomographs to EstimatePerformance,” “Part 4: Examples Demonstrate Use of Nomographs,” and“Part 5: Well Selection and Applications,” Petroleum Engineer Intl., 1956.

19. Lea, J.F.: “Plunger Lift vs. Velocity Strings,” J. of Energy ResourcesTechnology (December 1999); Trans., ASME, Vol. 121, 234.

10. Wiggins, M. and Gasbarri, S.: “A Dynamic Plunger Lift Model for GasWells,” paper SPE 37422 presented at the 1997 SPE ProductionOperations Symposium, Oklahoma City, Oklahoma, 9–11 March.

11. Garg, D. et al.: “Two-Piece Plunger Test Results,” prepared for presentation atthe 2004 Southwestern Petroleum Short Course, Lubbock, Texas, 19–21 April.

12. Clegg, J.D.: “Another Look at Gas Anchors,” presented at the 1989Southwestern Petroleum Short Course, Lubbock, Texas, 19–29 April.

13. Parker, R.M.: “The Importance of Compression Ratio for Pumping GassyWells,” presented at the 1993 Southwestern Petroleum Short Course,Lubbock, Texas, 21–22 April.

14. McCoy, J.N. et al.: “Field and Laboratory Testing of a DecentralizedContinuous-Flow Gas Anchor,” 46th Annual Technical Meeting of thePetroleum Society of the CIM, Calgary, 1995.

15. Dunning, H.N. et al.: “Foaming Agents for Removal of Liquids from GasWells,” Bull. 06-59-1, American Gas Assn., New York City.

16. Libson, T.N., and Henry, J.R.: “Case Histories: Identification of andRemedial Action for Liquid Loading in Gas Wells, Intermediate Shelf GasPlay,” paper SPE 7467, JPT (April 1980) 685; Trans., AIME, 269..

17. Campbell, S., Ramachandran, S. and Bartrip, K.: “CorrosionInhibition/Foamer Combination Treatment to Enhance Gas Production,”paper SPE 67325, presented at the 2001 SPE Production and OperationsSymposium, Oklahoma City, Oklahoma, 24-27 March.

18. Stephenson, G.B., Rouen, B., and Rosenzweig, M.H.: “Gas-Well Dewatering:A Coordinated Approach,” paper SPE 58984 presented at the 2000 SPE Intl.Petroleum Conference, Villahermosa, Mexico, 1–3 February.

19. Williams, R., Vahedian, S., and Lea, J.F.: “Gas Well Liquids InjectionUsing Beam-Lift Systems,” presented at the 1997 SouthwesternPetroleum Short Course, Lubbock, Texas, 2–3 April.

20. Grubb, A.D. and Duvall, D.K.: “Disposal Tool Technology Extends Gas WellLife and Enhances Profits,” paper SPE 24796 presented at the 1992 SPEAnnual Technical Conference and Exhibition, Washington, DC, 4–7 October.

21. Pigott, M.J. et al.: “Wellbore Heating to Prevent Liquid Loading,” paperSPE 77649 presented at the 2002 SPE Annual Technical Conference andExhibition, San Antonio, Texas, 29 September–2 October.

22. Elmer, W.G.: “Tubing Flowrate Controller: Maximize Gas WellProduction From Start to Finish,” paper SPE 30680 presented at the 1995SPE Annual Technical Conference and Exhibition, Dallas, 22–25 October.

23. Putra, S.A. and Christiansen, R.L.: “Design of Tubing Collar Inserts forProducing Gas Wells Below Their Critical Velocity,” paper SPE 71554presented at the 2001 SPE Annual Technical Conference and Exhibition,New Orleans, 30 September–3 October.

James F. Lea, SPE, is Chairperson of the Petroleum Engineering Dept. of TexasTech U. Previously, he was the Team Leader of Production Optimization andArtificial Lift at Amoco EPTG. He received the 1996 SPE InternationalProduction Award. Lea also received the J.C. Schlonneger award from theSouthwestern Petroleum Short Course for outstanding contributions to artifi-cial lift. He has served on many SPE committees related to artificial lift. HenryV. Nickens is on the Well Performance Team at BP plc and works on produc-tion optimization and artificial-lift problems. Before joining Amoco in 1981, hewas a nuclear engineer with Westinghouse Electric. With Amoco, he didresearch in drilling-fluid mechanics, well control, artificial lift, and productionoptimization. Nickens holds MS degrees in physics and mathematics and innuclear engineering and holds a PhD degree in fluid mechanics.

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