Solving Gas Well Liquid Loading Problems

72092DAS.qxd

3/15/04

12:18 PM

Page 30

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

Solving Gas-Well Liquid-Loading Problems

Eventually, gas wells will cease producing as the reservoir pressure depletes. The usual presence of some liquids can reduce production even faster. This paper describes the problem of liquid accumulation in a gas well. Recognition of gas-well liquid-loading problems and solution methods are discussed.1 Introduction Gas wells producing dry gas have a low flowing bottomhole pressure (FBHP), especially for low-rate wells. When liquids are introduced, the FBHP increases. Liquids in the gas may be produced directly into the wellbore or condensed from vapor in the upper portion of the tubing. The total flowing-pressure drop can be expressed as the sum of the pressure drops from elevation (weight of the fluids), friction, and acceleration. For low-rate wells, the acceleration term is very small, and, with correctly sized tubing, the friction term is also small. The elevation, or gravity term, becomes larger when liquid loading occurs. Fig. 1 shows the approximate flow regimes as gas velocity decreases in a gas/liquid well. If the well is flowing as a mist of liquid in gas, then the well still may have a relatively low gravity-pressure drop. However, as the gas velocity begins to drop, the well flow can become slug and then bubble flow. In this case, a much larger fraction of the tubing volume is filled with liquid. As liquids accumulate, 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-loading problem will have been solved. Recognizing Liquid Loading Liquid loading is not always obvious. If a well is liquid loaded, it still may produce for a long time. If liquid loading is recognized and reduced, higher producing rates are achieved. Symptoms indicating liquid loading include the following. • Sharp drops in a decline curve (Fig. 2). • Onset of liquid slugs at the surface of well.

Copyright 2004 Society of Petroleum Engineers This is paper SPE 72092. Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

30

• Increasing difference between the tubing and casing flowing pressures (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 models to 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 droplets upward. Lower rates allow droplets to fall and accumulate. Coleman et al.3 later correlated to well data with lower surface flowing pressures than did Turner. Turner’s analysis gives the following for critical velocity: νgc=k

σ1/4(ρl−ρg)1/4 , ρg1/2

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, and a temperature of 120ºF, then νgc=C

(ρl−0.0031Ptf)1/4 , (0.0031Ptf)1/2

where C is 5.34 for water or 4.02 for condensate2 or 4.43 for water or 3.37 for condensate.3 The corresponding critical gas rate, Qgc, in MMscf/D is Qgc=

3.06PAνgc . (T+460)z

If any water is produced, conservatively use water properties to calculate critical velocity. Typically evaluated at the wellhead, the above equations are valid at any well depth if the in-situ pressure and temperature are known. The distance between the tubing end and the perforations should be minimized because casing flow is usually liquid loaded. Stability and Nodal Analysis. As liquids accumulate at lower gas rates, tubing performance can become unstable. Fig. 3 shows a tubing performance curve (TPC), or “J” curve, evaluated at the tubing bottom near perforations. This flowing pressure is needed for varying production rates at a constant gas/liquid ratio (GLR). It is plotted across a gas-deliverability curve, or inflow-performance curve. The flowing pressure is the sum of the tubing-pressure drop and the Ptf. The curve turns up (required pressure increases) at low rates because of liquid holdup in the tubing. At high rates, liquids

APRIL 2004

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

are carried with the gas, liquid holdup is low, and friction is more predominant. If the TPC and the reservoir inflow performance relationship (IPR) are plotted, their intersection predicts the flow rate. As shown in Fig. 3, two intersections can exist with only the higher-rate intersection being stable. Points A and B move from the lower intersection, and Points C and D move to the higher intersection. Operate to the right of the TPC minimum above critical rate, with tubing sized for low friction. The analysis method (Nodal analysis from Schlumberger) has many possibilities for gas-well analysis. The effects of flow-path area, surface pressure, future reservoir pressure, and others can be studied. Fig. 4 illustrates the effects of tubing diameter. In this case, D1 would be judged to be too large because the IPR intersection is to the left of the TPC minimum. Diameter D3 shows higher friction. Diameter D2 might be judged the best size for the current situation. Diameter D3 would continue to

provide flow without liquid loading to the lower rates, but D2 allows higher rates at the current intersection. Use critical velocity, Nodal analysis, and experience to predict liquid-loading trends. Analysis cautions include the following. • Verify calculated tubing-pressure drops with measurements before selecting a multiphase-flow correlation before broad use. • Annulus-flow calculations should be viewed with caution. • The prediction of the onset of sharp liquid loading at low rates varies tremendously with different flow correlations. • GLRs and IPR data often are unknown. Solutions Liquid loading may be present, but what solutions are best to alleviate the problem? No universal solutions exist. Sizing Production Strings to Eliminate Liquid Loading. A properly designed smaller tubing or velocity string can increase gas velocity to reduce liquid loading.4 The following factors should be evaluated before installing smaller-inside-diameter tubing. • Will the installation be a long-term solution compared with use of the existing tubing and other methods (e.g., plunger lift)?

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

APRIL 2004

(To Page 69)

72092DAS.qxd

3/15/04

12:13 PM

Page 69

Fig. 3—Intersection of TPC and IPR determine potential operating rates.

Distinguished Author Series (From Page 31)

• The tubing string should extend to near the perforations. Hanging tailpipe below high-set tubing5 to eliminate casing flow can be beneficial if needed. • If flow is above critical at the bottom of the tubing, it will be so for all of the tubing, which is a desired goal. • The decline curve, after a successful installation, should show a projection of higher future rates than before. Immediate rates may be misleading. Casing production with an occasional tubing-production period to lift liquids up a smaller string may be referred to as a “siphon string.”

Fig. 4—Sensitivity of tubing performance to diameter.

• 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 casing with the plunger at the bottom of the well. Next, the well opens and annulus gas expands to lift the plunger and liquid to the surface. Gas flows while the plunger remains at the surface. Liquids accumulate in the well as gas flow decreases. The valve closes and the plunger falls to the bumper spring. Repeating cycles may be adjusted continuously by use of a plunger-lift controller. The pressure that builds in the annulus during the shut-in portion of the cycle is the major source of energy to bring the plunger and liquid to surface along with some well inflow. Installations operate best with no packer in the well. Some

Compression. Compression is used to lower the tubing pressure and increase flowing gas velocity.6 Compression considerations include the following. • Will wellhead compression increase the rate economically and provide long-term effects? As Figs. 3 and 4 show, the gas-deliverability curve extends to a steep curve near the absolute open flow. Lowering the FBHP will result in little production increase. Avoid compression in this region. • Adding a larger or twin flowline may reduce the wellhead pressure considerably without compression. • Often compression is applied to a group of wells or an entire field. 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 operating a gas well with liquids. It uses a free-traveling plunger to assist the gas 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. The plunger and liquids are lifted by use of gas pressure built up in the tubing/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.

APRIL 2004

Fig. 5—Typical plunger-lift installation.

69

72092DAS.qxd

3/15/04

12:14 PM

Page 70

plunger wells operate with a packer, but greater well pressure and GLR 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 pressurebuildup effects. 2. The “slug-size” pressure should be less than 50% of the “net” pressure. The “slug-size” indication is the operating static casing pressure minus the tubing pressure, or Pcs−Pts. The “net pressure” is Pcs−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 chart for 21/2-in. tubing-plunger operation also is available.8 The “net operating 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 performance curve. Another study10 incorporates the use of a reservoir model 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) probably trend 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.

Fig. 6—Plunger-lift cycle.

70

Land the tubing, without a packer, such that some open perforations 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. A window of arrival would be (750 ± X) ft/min, where X is the incremental velocity of rise. Speed is plunger-travel length divided by travel 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 liquid in the tubing. When the BHP is sufficient to raise the plunger and liquid, the well is opened to begin the cycle. A more-productive cycle 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 the upstroke when the ball and cylinder are together, and components cycle to the bottom of the well when apart.11 Beam Pumping. Beam-pump systems are a common method of dewatering gas wells. These systems function when wells do not have enough pressure and GLR to allow use of other methods. Initial and operating costs can be high. Attention to problem areas can significantly reduce operating expense. Fig. 8 shows a downhole dynamometer pump card with the rod load and position plotted above the pump for one cycle with no gas interference. Gas in the pump may cause gas lock, which in turn can cause production to cease temporarily, as well as fluid pound and associated mechanical problems, which also reduce production. Gas separation is recommended, when possible, by setting the pump or a dip tube below the perforations. If the operator ensures that the pump is built and spaced correctly to obtain a high compression ratio (CR) on the downstroke, as shown in Fig. 9, then many problems can be solved with a simple pump in a gassy well. First, try to separate gas from the pump intake. Ranked guidelines include the following. • Use a dip tube below the pump intake to receive fluids below the perforations, but use a moderate length to avoid gas breakout. • Set the pump below the perforations. • Use “poor-boy” separators12,14 for low rates when the pump must be set above the perforations. This type of separator uses the principle of downward flow at a slower rate (approximately 0.5 ft/sec) than the bubbles rise. Higher production rates (approximately 150 to 200 B/D) can gas lock this type of separator. • If landed above the perforations, consider separators such as a packer separator, filter element, or vortex.

APRIL 2004

72092DAS.qxd

3/15/04

12:14 PM

Page 71

Fig. 8—Pump card with gas interference.

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

• Ensure a good CR13 on the pump downstroke and a high flow area through the valves (Fig. 9). A high CR will prevent gas lock. • Use specialty pumps. Some pump designs open the traveling valve (TV) mechanically. Others take the fluid load of the TV with a top sliding valve (SV). Other pumps1 use a top TV to hold the hydrostatic pressure in the tubing at the beginning of the downstroke. This method allows the bottom TV to open, allowing liquid and gas to enter the upper compression chamber. This upper compression chamber compresses on the upstroke to open the top TV and discharge into the tubing. These pumps are two-stage compression pumps. Other designs1 include a tapered-barrel pump and the “panacea pump” with an enlargement in the barrel; both designs ensure liquids enter the barrel on the downstroke to prevent gas lock. Consider a backpressure regulator1,13 on the tubing at the surface. Originally used to seat valves when wells flow at low rates, it seems to benefit gassy wells in general. Values of surface pressure might be 100 to 300 psi or more. Also consider matching the pump to the well using pump-off controllers or jack shafts (an additional set of sheaves between the motor and original motor sheave to slow the pump speed). The casing gas must be allowed to flow through a check valve to the flowline in all cases. Beam pumps will dewater gas wells but are subject to gas interference if not installed correctly. Maintenance, energy, and initial cost can be high, but they are reliable in general. Hydraulic Pumping. Hydraulically powered downhole pumps are powered by a stream of high-pressure water or oil (power fluid) supplied by a power-fluid pump at the surface. Hydraulic pumps are of two types.

APRIL 2004

• Piston pumps, which are similar to beam pumps. • Jet pumps that operate by power fluid passing through a venturi, exposing the formation to low pressure. The surface power-fluid pump usually is a piston-type or centrifugal high-pressure pump. A small-diameter jet pump, which fits inside 11/4-in. coiled tubing (CT)1, allows a power string and pump to be run inside 23/8- or 27/8-in. tubing and is a relatively new dewatering method. Liquid production comes up the tubing/CT annulus. The gas flows up the tubing/casing annulus. The pump can be reverse circulated up the CT for service in minutes. Jet pumping may require high power. Foaming. In gas-well applications, the liquid/gas/surfactant mixing occurs most commonly downhole. This method works best with water only, but condensates can be present. Some operators prefer that foams be tried first for liquid-loading problems because they are inexpensive. Foaming may not be the most economical solution if large quantities of expensive surfactants are needed. The foam produces a less-dense mixture by increasing the

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

71

72092DAS.qxd

3/15/04

12:15 PM

Page 72

surface area of the liquid with bubbles. The result is less gas/liquid slippage. The gas can more easily carry the foamed liquids to the surface. One test procedure to determine which surfactants work best in wellbore fluids is shown in Fig. 10. Well liquids are placed into a tube, and a specified amount of the foaming agent to be tested is added. A specified gas rate is injected at the bottom of the tube through a fritted disk, and liquid Fig. 10—Bureau of Mines setup for carryover into the testing foaming agents.15 beaker vs. time is measured. This test15,16 is simple, quick, and inexpensive. It allows evaluation of foaming agents before expensive field trials. Recent methods17 test for surface tension and lower effective liquid-phase density to calculate a lower required critical velocity as a method of predicting foam performance.

There are various methods of introducing surfactants into the well. The simplest method is to batch or continuously inject chemicals down the annulus of a well with no packer. Also, soap sticks can be dropped down the tubing, manually or with an automatic dispenser. 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 1 a /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 and controls 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. It has been used successfully in many applications. Gas Lift. Gas lift18 introduces additional gas into the tubing to lighten the flowing gradient and can increase the fluid velocity above critical. 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 gas lift 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 the tubing end or injected through only one valve or port if gas pressure is available to unload. A series of unloading valves can be used to help inject 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, comparing with other methods. Actually, plunger lift is an intermittent method of lift, sometimes augmented by gas injection down the casing. Intermittent gas lift for low-rate wells is used in wells with no plunger. “Stopcocking” is a method of opening and closing wells so that gas pressure in the shutin 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. There are several methods of injecting the water in a gas well.19 • Bypass seating nipple:20 Pressure from water pumped up through the tubing is allowed to bear on an injection zone below the sucker-rod pump (Fig. 11) through concentric vertical holes in the bypass seating nipple. Some systems mechanically apply pressure on the downstroke.1 • Electrical-submersible-pump (ESP) -driven injection system: Systems are available that allow an ESP to pump water below a packer. Other pumping methods could inject water as well. An injection test should be run on a suitable underlying injection zone before considering this method. Other Methods. Many other methods exist. A resistance cable to heat and prevent condensation was shown to approximately triple production.21 Various controllers exist to prevent annulus heading and to control casing-to-tubing flow for best production.22 Inserts at each joint to keep liquids dispersed have proved beneficial.23 Many other methods have been demonstrated over the years, although it is hoped that the major concepts have been identified here.

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

72

Summary • Recognize liquid loading from well symptoms, critical velocity, and/or Nodal analysis.

APRIL 2004

• Surfactants may be tried with little initial cost and can be laboratory tested. Evaluate economics of continued use. • Use of smaller-diameter tubing can be very effective for higher ranges of flow and can be a long-term solution. Smaller tubing may eventually have to be downsized to continue flow. However, small tubing (approximately 1-in. diameter or less) can be very difficult to unload. • Plunger lift may be preferred over smaller tubing for lower rates, because the plunger works well with existing larger tubing and may perform to depletion of the reservoir. The two-piece plunger shows advantages in some wells. • Use of compression to lower wellhead pressures helps almost any method of producing gas wells, but economics must be considered. • Jet hydraulic pumps are easy to install, produce high rates, and have low servicing costs. They do not achieve low producing BHPs, and initial cost is a consideration. High power requirements may be experienced. • For low-pressure wells, a beam pump may be the only possibility. High initial and energy costs may be encountered. Careful attention can reduce servicing costs. • Gas lift, by adding gas to the tubing to raise the velocity above critical, is viable if high-pressure gas is available. • Consider injecting water below a packer if an underlying injecJPT tion zone is present. Nomenclature A = cross-sectional area of flow, ft2 C = coefficient of reduced critical velocity, (ft/sec).(lbm/ft3)0.25

APRIL 2004

= coefficient of basic critical velocity, (ft/sec).(lbm/ft3)0.25/(dyne/cm)0.25 P = pressure, psia Pcf = casing pressure, flowing, psia Pcs = casing pressure, shut-in, psia Ptf = tubing pressure, flowing, psia Pts = tubing pressure, shut-in, psia Qgc = critical gas flow rate, MMscf/D T = temperature, ºF vgc = critical velocity of gas, ft/sec X = increment of velocity of rise, ft/min z = gas compressibility factor ρg = density of gas, lbm/ft3 ρl = density of liquid, lbm/ft3 σ = surface tension of liquid to gas, dynes/cm k

References 11. 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 of Liquids 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 and Installation,” 1st Annual Conference on Coiled-Tubing Operations and Slimhole Drilling Practices, Houston, 1–4 March 1993.

73

72092DAS.qxd

3/15/04

12:32 PM

Page 74

15. Campbell, J.A. and Bayes, K.: “Installation of 27/8-in. Coiled-Tubing Tailpipes in Live Gas Wells,” paper OTC 7324, 1993 Offshore Technology Conference, Houston, 3–6 May. 16. Thomas, F.A.: “Low Pressure Compressor Applications,” presentation at the 49th Annual Liberal Gas Compressor Inst., 4 April 2001. 17. Foss, D.L. and Gaul, R.B.: “Plunger Lift Performance Criteria with Operating 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 Lift Method of Oil Production,” “Part 2: Constructing Nomographs to Simplify Calculations,” “Part 3: How to Use Nomographs to Estimate Performance,” “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 Resources Technology (December 1999); Trans., ASME, Vol. 121, 234. 10. Wiggins, M. and Gasbarri, S.: “A Dynamic Plunger Lift Model for Gas Wells,” paper SPE 37422 presented at the 1997 SPE Production Operations Symposium, Oklahoma City, Oklahoma, 9–11 March. 11. Garg, D. et al.: “Two-Piece Plunger Test Results,” prepared for presentation at the 2004 Southwestern Petroleum Short Course, Lubbock, Texas, 19–21 April. 12. Clegg, J.D.: “Another Look at Gas Anchors,” presented at the 1989 Southwestern Petroleum Short Course, Lubbock, Texas, 19–29 April. 13. Parker, R.M.: “The Importance of Compression Ratio for Pumping Gassy Wells,” 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 Decentralized Continuous-Flow Gas Anchor,” 46th Annual Technical Meeting of the Petroleum Society of the CIM, Calgary, 1995. 15. Dunning, H.N. et al.: “Foaming Agents for Removal of Liquids from Gas Wells,” Bull. 06-59-1, American Gas Assn., New York City. 16. Libson, T.N., and Henry, J.R.: “Case Histories: Identification of and Remedial Action for Liquid Loading in Gas Wells, Intermediate Shelf Gas Play,” paper SPE 7467, JPT (April 1980) 685; Trans., AIME, 269.. 17. Campbell, S., Ramachandran, S. and Bartrip, K.: “Corrosion Inhibition/Foamer Combination Treatment to Enhance Gas Production,” paper SPE 67325, presented at the 2001 SPE Production and Operations Symposium, 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 Injection Using Beam-Lift Systems,” presented at the 1997 Southwestern Petroleum Short Course, Lubbock, Texas, 2–3 April. 20. Grubb, A.D. and Duvall, D.K.: “Disposal Tool Technology Extends Gas Well Life and Enhances Profits,” paper SPE 24796 presented at the 1992 SPE Annual Technical Conference and Exhibition, Washington, DC, 4–7 October. 21. Pigott, M.J. et al.: “Wellbore Heating to Prevent Liquid Loading,” paper SPE 77649 presented at the 2002 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September–2 October. 22. Elmer, W.G.: “Tubing Flowrate Controller: Maximize Gas Well Production From Start to Finish,” paper SPE 30680 presented at the 1995 SPE Annual Technical Conference and Exhibition, Dallas, 22–25 October. 23. Putra, S.A. and Christiansen, R.L.: “Design of Tubing Collar Inserts for Producing Gas Wells Below Their Critical Velocity,” paper SPE 71554 presented 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 Texas Tech U. Previously, he was the Team Leader of Production Optimization and Artificial Lift at Amoco EPTG. He received the 1996 SPE International Production Award. Lea also received the J.C. Schlonneger award from the Southwestern Petroleum Short Course for outstanding contributions to artificial lift. He has served on many SPE committees related to artificial lift. Henry V. Nickens is on the Well Performance Team at BP plc and works on production optimization and artificial-lift problems. Before joining Amoco in 1981, he was a nuclear engineer with Westinghouse Electric. With Amoco, he did research in drilling-fluid mechanics, well control, artificial lift, and production optimization. Nickens holds MS degrees in physics and mathematics and in nuclear engineering and holds a PhD degree in fluid mechanics.

74

APRIL 2004