40 Journal of Canadian Petroleum Technology

Introduction

The presence of a liquid phase during gas production has longbeen recognized as detrimental to well flow. In gas condensatereservoirs, as the gas in the reservoir travels towards the wellbore,it encounters decreasing pressures and as a result, a liquid hydro-carbon phase (condensate) is formed below the dew pointpressure(1). Furthermore, as the gas travels to the surface, the pres-sure and temperature decreases causing more liquid to drop out ofthe gas phase.

As long as the gas flow rate is sufficiently high to maintainannular mist flow, these liquids are lifted out of the well.However, when the tubing velocity becomes too small to maintainsteady flow conditions, liquid accumulation in the well becomes aproblem. The problem can be attributed to a low gas productionrate due to low bottom hole pressure in a mature reservoir and/orlow gas relative permeability for given conditions(1). The flowregime in the wellbore switches from annular mist flow to churn-ing or slug flow and the liquid lifting capacity of the gas decreases

dramatically. The flow rate for this switch is called the criticalflow rate(2, 3).

Below the critical flow rate, liquids tend to migrate down thetubing and start to collect at the bottom. For a while, the well willbe able to unload small slugs on its own. The well will eventuallystop flowing continuously and the fluid is produced in smallheads with spikes of gas. If no remedial measures are taken, theproblem will worsen as the liquids continue to accumulate in thetubing and the production rate continually decreases(4, 5). Finally,at a certain fluid level, the liquid accumulation can load up andkill the well due to the backpressure exerted on the formationand the reduced gas relative permeability in the vicinity of theperforations(1, 6).

Various technologies are available to deal with liquid loadingin gas wells(7). They include sucker rod pump, additional com-pression, plunger lift, siphon string, gas lift, intermittent produc-tion, and velocity strings. Correct selection of the artificial liftmethod is important to the long-term profitability of a given well.A poor choice can reduce production and increase operating costs.For low rate gas reservoirs, the capital investment and operatingcost associated with the solution must be minimal. For instance,sucker rod pumps are too costly to install in these reservoirsunless they are very shallow.

Intermittent Well ProductionOne of the lowest cost solutions is to sustain the natural flow of

the well by alternate flow and shut-in periods. This can be donemanually or can be automated by installing a controller and inter-mitter at the well head. No downhole modifications are needed.The well is shut in for specific periods of time so that enoughenergy can be built up to lift the liquids out of the wellbore.Accumulated gas in the casing tubing annulus essentially blowsthe liquid to the surface. However, intermittent well production isonly a temporary solution as there are several problems that causethe daily production time, hence the gas rate, to graduallydecrease.

The condensate is lifted from the well in the form of a slug.Among other factors, the size and length of the tubing also influ-ences the slug recovery efficiency. As the slug moves towards thesurface, the tubing walls exert a certain amount of friction. Thiscreates drag on the outer perimeter of the slug while the centralcore moves with a higher velocity. At the same time, the gasunderneath attempts to break through. In addition, each producedslug wets the tubing walls as it is being produced. This wettingfilm, together with the portion of the slug that is bypassed due tothe friction, cause what is known as fallback.

Production Optimization of Liquid LoadingGas Condensate Wells: A Case Study

G. COS,KUNER, T. STROCEN (BOGDAN)Husky Oil Operations Limited

AbstractLiquid production can be a serious problem in gas condensate

wells nearing the end of their production life. As the pressure inthe drainage area is depleted, the gas velocity in the productiontubing falls below the critical rate resulting in inadequate energyto lift all the condensate out of the wellbore. The condensatemigrates down the tubing and collects at the bottom of the com-pletion increasing the bottom hole flowing pressure and, inmany cases, killing the well. A similar liquid loading problemcan be also encountered in low productivity gas condensatewells.

This paper investigates the behaviour of gas condensate wellsin a deep basin fractured sandstone reservoir in Alberta.Regardless of the initial well productivity, sooner or later,declining reservoir pressures and/or poor productivity causewells to liquid load. The first and the cheapest solution is to pro-duce these wells intermittently. Although such wells continue toflow, the liquid fallback still tends to increase the average flow-ing bottom hole pressure, thus reducing the production rate. Thepaper discusses the process of selecting the best candidatesamong such wells for the next level of intervention, which is theinstallation of plunger lift systems. As a result, 19 wells wereequipped with plunger lifts and a significant production increasehas been observed. The project has been a technical and eco-nomic success so far and is now being extended to the rest of thefield.

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November 2003, Volume 42, No. 11 41

The severity of the fallback is a function of the slug velocity,which in turn, is a function of the pressure difference between thebottom hole and the wellhead. Depending on this pressure differ-ence, the lifting efficiency can range from 60% to as low as 30%.A lack of efficiency also creates an unnecessarily heavy flowinggradient in the tubing causing higher flowing bottom hole pres-sures and reduced drawdown. The reduced drawdown results inless inflow from the formation.

In an intermittent producing well, there is a minimum liquidcolumn height (submergence) necessary for a beginning slug toachieve an acceptable recovery at the surface. The portion of theslug lost as fallback increases with depth, thus, the deeper thewell, the higher the submergence necessary for acceptable recov-ery. Intermittent well production cannot be used once the bottomhole pressure decreases below that necessary to support therequired liquid column height.

The inflow from the formation is reduced due to the backpres-sure exerted by an increasing hydrostatic column. The highercolumns require longer build-up times. The gas inflow is higher atthe beginning of the cycle, therefore, there is a distinct advantageto working with smaller liquid slugs. Consequently, increasing the

cycle frequency may result in some additional production for aperiod of time.

Production With Plunger LiftThis method is an artificial lift technique that uses a free piston

or plunger to lift the fluids to the surface using the reservoir ener-gy stored in the gas. Installation of a plunger eliminates or drasti-cally reduces all of the problems associated with intermittent wellproduction by acting as a mechanical interface between the lift gasand the condensate(4, 5, 8-10). The efficiency of the lift now increas-es dramatically to almost 100%.

The results are the reduced flowing gradients in the tubing andlower flowing bottom hole pressures leading to higher gas produc-tion rates. It can be expected that a gas well will re-establish anormal decline as shown in Figure 1 if loading can be prevented.However, it has also been observed in many instances that the rateof decline changes after a plunger installation, thereby extendingthe life of the well significantly and adding reserves(11). Finally,reduced need for submergence allows for deeper and lower pres-sure wells to be lifted as shown in Figure 2. The plunger also hasthe secondary benefit of preventing the build-up of paraffindeposits in the tubing.

In general, plunger lifts are used in high gas liquid ratio wells,therefore, they are ideally suited to gas condensate reservoirs. Anadvantage over other lift methods is the relatively small initialcost and low operating costs. A typical plunger lift installationconsists of a stop and spring set at the bottom of the tubing string,and a lubricator and a catcher on the surface acting as a shockabsorber at the upper end of the plunger travel (Figure 3). Thesystem is completed with the addition of a controller and a motorvalve with the ability to open and close the flow line.

Operation of the system is initiated by closing the flow line andallowing the formation gas to accumulate in the casing annulusthrough natural separation. The annulus acts primarily as a reser-voir for storage of this gas. After pressure builds up in the casingto a certain value, the flow line is opened. The transfer of gasfrom the casing to the tubing, in addition to the flow of gas fromthe formation, creates a high instantaneous velocity that causes a

FIGURE 1: Typical gas well production decline curve(5).

FIGURE 2: Required submergence in a low pressure intermittentgas well(5). FIGURE 3: Conventional plunger lift installation(8).

42 Journal of Canadian Petroleum Technology

pressure drop across the plunger and the liquid. The plunger thenmoves upwards, pushing all of the liquids in the tubing before it.

Upon the arrival of the plunger at the surface, the tubing stringis completely free of liquids. At this point, the formation encoun-ters the least resistance to flow. Depending on the productivity ofthe well, high flow rates can be maintained for some incrementaltime by leaving the flow line open. This period is called the after-flow. The well is shut in when loading is evidenced again, allow-ing the plunger to fall and the cycle is repeated.

Ansell Gas Condensate FieldAnsell gas condensate field is located 15 km southwest of

Edson in the deep gas basin of Western Alberta. The CretaceousCardium formation that makes up the gas pool is comprised oftexturally mature, fine to coarse grained sandstone. The Cardiumwithin the Ansell area has a gross average isopach value between10 m and 35 m and consists of widespread stacked shallow marineand shoreline cycles deposited on trends which project to thenorthwest/southeast. The shallow marine and shoreline deposits ofthe Cardium were subsequently buried and deeper marine shalesacted as a hydrocarbon source. The average reservoir depth is2,300 m and log porosities of 9 12% are common.Permeabilities of less than 0.1 mD are generally encountered withan average matrix permeability in the order of 0.01 mD 0.1 mD.

Subsequent Laramide compression tectonics have resulted inareas of thrust faulting in the Cardium at Ansell. Thrust faultingproduces fracture networks within the Cardium which serve toincrease permeability near the overthrust section. Although target-ing areas of potential faulting, and thus fracturing, is advanta-geous to the Cardium Sandstone play at Ansell and other adjacentareas, it is not mandatory for success. Having a thrust fault nearbydoes increase the potential that the drilled well will be successfuleconomically. However, there are also successful wells in non-faulted Cardium settings.

The average reservoir pressure is 21 MPa and the temperatureis 82 C. The reservoir has a gas condensate fluid which yields170 m3/E6m3 (30 bbl/mmscf) of free liquids at the well head, andfurther processing yields another 280 m3/E6m3 (50 bbl/mmscf) ofliquids for a total liquid content of 450 m3/E6m3 (80 bbl/mmscf).The initial reservoir pressure is very close to the dew pointpressure.

Identification of Plunger LiftCandidate Wells

The first step in identifying plunger lift candidates is to inspectthe difference between the tubing head pressure and the casinghead pressure. Wells with large differential pressure between thecasing and tubing, which indicates liquid loading, are consideredprime candidates for plunger lift installations.

The second step is to estimate the potential flow rate increasewith the plunger lift. Naturally, wells with the largest impact aregiven priority for plunger lift installation. The estimation of awells performance with the plunger lift requires at least twoimportant pieces of information. These are the current reservoirpressure and the producing liquid-to-gas ratio for the well underconsideration.

The current reservoir pressure is obtained using the gas materi-al balance equation. The material balance requires the originalreservoir pressure and the original gas in place (OGIP). These val-ues are then plotted on a graph of P/Z vs. cumulative gasproduced. The original reservoir pressure is usually constantthroughout the area. The OGIP, or the reserves available to thewell within its drainage area, is determined by analyzing the gasrate vs. time and extrapolating the decline curve to the economiclimit. Once the original reservoir pressure and OGIP are known,the current reservoir pressure is determined from the material bal-ance equation using the cumulative gas produced to date.

The liquid-to-gas ratios are determined using currentproduction data. Since the liquid is not removed from a well on aconsistent basis, it is important to have a few months of liquid-to-gas ratios so that a reliable estimate can be made. The informationfor this paper was obtained from a database with daily productiondata. The current gas production rate was determined using a 14-day average.

Having obtained the above data, it is possible to calculate theinflow performance of the well and overlay the tubing perfor-mance curve on it. The operating points before and after theplunger lift installation yield the expected gas flow rate increaseupon the plunger lift installation. A comparison of the predictedvs. actual increase in gas flow rates is shown in Figure 4 for thewells where a plunger lift was installed in 2001 and 2002. A per-fect match would have been the 45-degree line shown on this plotand the dashed lines indicate a variation of 10% from it. It canbe concluded that the increase in rate can be estimated using theabove technique with reasonable confidence for the majority ofthe wells. Therefore, wells can be prioritized for plunger installa-tion using the aforementioned technique. That is, wells with, high-est incremental gas rate are given priority.

Well PerformancesWhen the wells are put on production, the initial drawdown

causes liquids to drop out in the reservoir and the gas relative per-meability decreases rapidly, resulting in steep productiondeclines(1,12). After a certain period of time (three to 12 months), asemi steady state is reached and the rate of production decline isreduced. The decline rates and time to reach semi steady stateflow is controlled by the permeability of the drainage area as wellas the amount of the drawdown applied at the well.

A typical well is shown in Figure 5 where the initial rapiddecline occurs over the first nine months of production. This

0

20

40

60

80

100

0 20 40 60 80 100

Observed Rate Increase, %

Pre

dic

ted R

ate

Incr

ease

, %

FIGURE 4: Incremental gas rate prediction.

Plunger Lift Installed

100

1,000

10,000

0 10 20 30 40 50 60Months

Gas Rate (m

cf/cd)

FIGURE 5: Well 1 production decline.

November 2003, Volume 42, No. 11 43

period is followed by relatively mild decline when the semi steadystate is reached. An intermitter was installed at 23 months as flowrates declined to the point where liquids were not being lifted effi-ciently. The intermitter worked well for another year. However,when pressures declined further so that the liquid submergencecould not be handled by the gas production, then the rate of pro-duction decline increased significantly. Longer and longer build-up times were needed to lift the liquid column.

The higher production declines started at 35 months in this welland continued until a plunger lift was installed at 47 months.Initial variation in the gas flow rate reflects the efforts to optimizethe plunger operation while a new semi steady state was beingestablished. Based on the 11 months of production after theplunger lift was installed, a clear production decline trend has notbeen established yet. A conservative estimate would be a declinesimilar to the decline established during the initial semi steadystate flow between the months nine to 34, which is shown on thisplot.

The reserves associated with this well can be calculated basedon the exponential production decline before and after the installa-tion of the plunger lift. This is shown in Figure 6. The well wouldhave produced 23.4 E6m3 (0.827 bcf) of gas without the plungerlift. The installation of the plunger lift increased the reserves by50% to 35.0 E6m3 (1.237 bcf).

Another example of the well behaviour in the Ansell field isshown in Figures 7 and 8. In this case, an intermitter was installedat 19 months and the plunger lift was installed at 29 months.Based on the performance of the well for 21 months after the

plunger lift installation, the reserves increased by 197% to 21.8E6m3 (0.772 bcf). Note that the decline assumed by the well afterthe plunger lift installation was significantly less than that estab-lished during the initial semi steady state that lasted betweenmonths four to 18 for this particular well.

It should be noted that, although most of the wells follow asimilar trend to the two discussed above, there were some excep-tions. In some wells, the increased rate of production decline priorto the plunger lift installation was not very prominent. In otherwells, the semi steady state was attained very quickly and therewas only one long production decline period prior to the accelerat-ed decline that happens due to liquid loading.

ResultsPlunger lifts were installed in one well in 1997, two wells in

1999, two wells in 2000, and fourteen wells in 2001. There werethree additional wells in 2002, but their performance history withthe plunger lift has been brief and, hence, are not included in theperformance analysis here. Reserves additions attributed to theplunger lift for the pre-2001 wells are shown in Table 1, and foryear-2001 wells in Table 2.

Incremental reserves are 231.4 E6m3 (8.171 bcf) for the wellsshown in Table 1 and 176.4 E6m3 (6.229 bcf) for the wells shownin Table 2. If one includes the associated liquids with these incre-mental reserves, then the cost of adding reserves were 0.126 $/m3oil equivalent (0.02 $/boe) and 0.315 $/m3 oil equivalent (0.05$/boe) for the wells shown in Tables 1 and 2, respectively. Thewells paid out the investment in plunger lifts in two to fourmonths. Therefore, the project is considered to be a technical andeconomic success. Currently, Husky Oil Operations Limited havean active work plan to extend the plunger lifts installations to therest of the field where it is warranted.

Plunger Lift Installed

10

100

1,000

0 10 20 30 40 50 60Months

Gas

Rate (m

cf/cd)

FIGURE 7: Well 2 production decline.

Plunger Lift Installed

0

50100150

200250300350

400450500

0 100000 200000 300000 400000 500000 600000 700000 800000 900000

Cumulative Gas Produced (mcf)

Gas

Rate (m

cf/cd)

FIGURE 8: Well 2 cumulative gas production.

Plunger Lift Installed

0

200

400

600

800

1,000

1,200

0 200000 400000 600000 800000 1000000 1200000 1400000Cumulative Gas Produced (mcf)

Gas

Rate (m

cf/cd)

FIGURE 6: Well 1 cumulative gas production.

TABLE 1: Plunger lift installations before 2001.

Reserves Reserves Incremental Incremental(bcf) (bcf) Reserves Reserves

Well Prior P/L Post P/L (bcf) (%)

2 0.262 0.772 0.509 194.1%3 0.363 0.573 0.210 57.8%4 1.904 7.760 5.857 307.6%5 0.809 0.475 -0.334 -41.2%6 0.271 2.710 2.439 899.8%

Total 3.609 12.290 8.171 306.0%

TABLE 2: Plunger lift installations during 2001.

Reserves Reserves Incremental Incremental(bcf) (bcf) Reserves Reserves

Well Prior P/L Post P/L (bcf) (%)

1 0.827 1.237 0.410 49.6%7 4.003 5.310 1.307 32.6%8 1.920 2.696 0.776 40.4%9 0.915 1.502 0.586 64.1%10 0.736 2.115 1.379 187.5%11 0.223 0.299 0.076 34.1%12 0.378 0.396 0.018 04.7%13 1.202 1.879 0.677 56.3%14 0.596 0.703 0.107 18.0%15 0.991 1.150 0.159 16.0%16 0.503 0.968 0.466 92.6%17 0.790 0.823 0.033 04.2%18 1.071 1.177 0.107 10.0%19 0.736 0.864 0.128 17.3%

Total 14.890 21.118 6.229 44.8%

44 Journal of Canadian Petroleum Technology

Summary and ConclusionsRegardless of initial well productivity, wells in the Ansell gas

condensate field eventually liquid load due to declining reservoirpressure and/or low gas permeability. The problem can be tem-porarily remedied by producing the wells intermittently. However,intermitting is inefficient and cannot be used once the bottomholepressure decreases below that necessary to support the requiredliquid column height. Installation of a plunger lift eliminates theliquid fallback problem associated with intermittent well produc-tion. Consequently, the production can be restored with declinerates equal to or below previous levels.

The application of the plunger lift technology in Ansell resultedin total incremental gas reserves of 14.400 bcf. These reserveswere added at an average cost of 0.03 $/boe. The initial project isconsidered to be a technical and economic success and is nowbeing extended to the rest of the field.

Conversion Factor1 m3 = 35.31 ft3

REFERENCES1. COS,KUNER, G., Performance Prediction in Gas Condensate

Reservoirs; Distinguished Author Series, Journal of CanadianPetroleum Technology, Vol. 38, No. 8, pp. 32-36, August 1999.

2. TURNER, R.G., HUBBARD, M.G., and DUKLER, A.E., Analysisand Prediction of Minimum Flow Rate for the Continuous Removalof Liquids From Gas Wells; Journal of Petroleum Technology, pp.1475-1482, November 1969.

3. COLEMAN, S.B., CLAY, H.B., MCCURDY, D.G., and NORRIS,H.L., A New Look at Predicting Gas Well Load Up; Journal ofPetroleum Technology, pp. 329-333, March 1991.

4. BEAUREGARD, E. and FERGUSON, P.L., Introduction to PlungerLift: Applications, Advantages, and Limitations; presented at theSouthwestern Petroleum Short Course, Department of PetroleumEngineering, Texas Tech. University, Lubbock, TX, April 23 24,1981.

5. FERGUSON, P.L. and BEUREGARD, E., Will Plunger Lift Workin My Well?; presented at the Southwestern Petroleum ShortCourse, Department of Petroleum Engineering, Texas Tech.University, Lubbock, TX, April 27 28, 1983.

6. YAMAMOTO, H. and CHRISTIANSEN, R.L., Enhancing LiquidLift From Low Pressure Gas Reservoirs; paper SPE 55625, present-ed at the SPE Rocky Mountain Regional Meeting, Gillette, WY, May15 18, 1999.

7. CLEGG, J.D., BUCARAM, S.M., and HEIN, N.W.,Recommendations and Comparisons for Selecting Artificial LiftMethods; Journal of Petroleum Technology, pp. 1128-1131, pp.1163-1167, December 1993.

8. WIGGINS, M.L., NGUYEN, S.H., and GASBARRI, S., OptimizingPlunger Lift Operations in Oil and Gas Wells; paper SPE 52119,presented at the SPE Mid-Continent Operations Symposium,Oklahoma City, OK, March 28 31, 1999.

9. AVERY, D.J and EVANS, R.D., Design Optimization of PlungerLift Systems; paper SPE 17585, presented at the SPE InternationalMeeting on Petroleum Engineering, Tianjin, China, November 1 4,1988.

10. NEVES, T.R. and BRIMHALL, R.M., Elimination of LiquidLoading in Low Productivity Gas Wells; paper SPE 18833, present-ed at the SPE Production Operations Symposium, Oklahoma City,OK, March 13 14, 1989.

11. FERGUSON, P.L. and BEAUREGARD, E., Extending EconomicLimits and Reducing Lifting Costs: Plungers Prove to be Long-TermSolutions; presented at the Southwestern Petroleum Short Course,Department of Petroleum Engineering, Texas Tech. University,Lubbock, TX, April 20 21, 1988.

12. COS,KUNER, G., Microvisual Study of Multiphase Gas CondensateFlow in Porous Media; Transport in Porous Media, Vol. 28, pp. 1-18, 1997.

ProvenanceOriginal Petroleum Society manuscript,Production Optimization of Liquid Loading Gas CondensateWells: A Case Study (2002-107) first presented at the CanadianInternational Petroleum Conference (the 53rd Annual TechnicalMeeting of the Petroleum Society) June 11-13, 2002, in Calgary,Alberta. Abstract submitted for review December 17, 2001; edito-rial comments sent to the author(s) June 24, 2003; revised manu-script received July 25, 2003; paper approved for pre-pressSeptember 25, 2003, final approval November 6, 2003.

Authors Biographies

Gkhan Cos,kuner is an engineeringspecialist with Husky Oil OperationsLimited. He is involved in projects rangingfrom gas storage to offshore fielddelineation and development. Prior tojoining Husky Oil, he worked for Agip as areservoir engineering advisor; ScientificSoftware Intercomp as a senior consultingassociate; and, at Imperial Oil, ShellCanada, and the Petroleum RecoveryInstitute in various research capacities. He

holds a B.Sc. degree from the Middle East Technical University,Turkey, and M.Sc. and Ph.D. degrees from the University ofAlberta, Canada, all in petroleum engineering.

Taryn Strocen (Bogdan) is anExploitation Engineer at Husky Energy inCalgary, Alberta. She graduated with aBachelor of Science degree in mechanicalengineering from the University ofSaskatchewan in 2001. Taryn is also amember of APEGGA.