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Journal of Natural Gas Science and Engineering 14 (2013) 66e76

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Journal of Natural Gas Science and Engineering

journal homepage: www.elsevier .com/locate/ jngse

Well productivity in an Iranian gas-condensate reservoir: A case study

R. Mokhtari, F. Varzandeh, M.R. Rahimpour*

Department of Chemical Engineering, School of Chemical and Petroleum Engineering, Shiraz University, Shiraz 71346-1719, Iran

a r t i c l e i n f o

Article history:Received 14 April 2013Accepted 7 May 2013Available online

Keywords:Well productivityGas condensate reservoirCondensate blockageReservoir simulation

* Corresponding author. Tel.: þ98 711 2303071; faxE-mail address: rahimpor@shirazu.ac.ir (M.R. Rahi

1875-5100/$ e see front matter � 2013 Elsevier B.V.http://dx.doi.org/10.1016/j.jngse.2013.05.006

a b s t r a c t

This work is another step forward in our understanding of the dynamics of condensate buildup aroundwellbores in gas condensate fields. For this purpose one of the unique and huge Iranian gas condensatereservoirs is selected. The effects of condensate bank on the gas and condensate productivity and also thereservoir performance have been investigated throughout a simulation study. The productivity of thewells in the moderately rich gas condensate reservoir was observed to have initial rapid decrease andthen reach a relatively constant value and after that a second decrease as the reservoir was depleted.Compositional simulation clarified the reasons for this uncommon productivity change. During earlyproduction, a ring of condensate rapidly formed around wellbore when the near-wellbore pressuredecreased below the dew point pressure of the reservoir fluid. Moreover, relative permeability effectscaused the saturation of condensate in this region to be considerably higher than the maximumcondensate predicted by the PVT laboratory work. Gas productivity also decreased as the effectivepermeability to gas was severely reduced due to this high condensate saturation in the ring. Aftercondensate formation throughout the reservoir due to pressure reduction below dew point, the gasflowing into the ring became leaner causing the condensate saturation in the ring to decrease. Thisincreased the effective permeability of the gas. On the other hand, the reservoir pressure drop leads toless productivity which caused the gas productivity to reach a constant value. Changes in gas andcondensate compositions in the reservoir also impacted gas productivity. As the result of this study itcould be mentioned that the gas production rate may stabilize, decrease or possibly increase, after theperiod of initial decline. This is controlled primarily by the condensate saturation near the wellborewhich would decrease in the near wellbore region because of the leaner gas entering this region and alsopartial vaporization. In addition to the gas production rate, the composition change should also beconsidered in the sale contracts.

� 2013 Elsevier B.V. All rights reserved.

1. Introduction

Liquid formation in gas-condensate reservoirs occurs when thebottom-hole flow pressure decreases below the dew point of thereservoir gas (Kniazeff and Nvaille, 1965). This leads to creation ofthree regions with different liquid saturations and as a result, acomposite reservoir (Hashemi et al., 2006). In the first region that isfarthest from the wellbore, the reservoir fluid is located in the gasphase and the only liquid phase in this part of reservoir is connatewater. In the second section which is located closer to the wellborein comparison with the first region, the reservoir fluid is still gasphase; however its hydrocarbon liquid saturation is greater thanconnatewater saturation. Themain characteristic of this area is thathydrocarbon liquids drop out saturation is less than the critical

: þ98 711 6473180.mpour).

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value, and as a result, they do not flow in the reservoir. In theseconditions, the gas flow is lowered due to high saturation of notflowing condensates. In other words, the condensate is initiallyimmobile in the reservoir due to the impact of the capillary forcebefore critical saturation (Muskat, 1949). Needless to mention thatthe total liquid saturation of this region is the summation ofconnate water and condensate saturations.

In the third region which is located closer to the wellbore incomparison with the other two regions, the hydrocarbon liquidssaturation is greater than the critical saturation and both gas andliquid phases are mobile. The increase in condensate saturation asthe wet phase and its movement with gas phase cause the relativepermeability of the gas phase to decrease (Kniazeff and Nvaille,1965). The excess liquid in the reservoir near the wellbore, leadsto closing of the pore throats (Barnum et al., 1995) and also trappingof the gas phase with condensate which result in a decrease in gasproduction and productivity index in longer periods of time(Afidick et al., 1994; Barnum et al., 1995; Favang andWhitson,1995;

Fig. 1. Marun field location.

Table 2Local grid refinement.

Parameter Value

I-coordinate 6J-coordinate 6Minimum K-coordinate 1Maximum K-coordinate 10Number of radial divisions 10Number of angular segments 1Number of vertical divisions 30

R. Mokhtari et al. / Journal of Natural Gas Science and Engineering 14 (2013) 66e76 67

Fussell, 1973). Apart from these three regions, there is another areaadjacent to the wellbore, where hydrocarbon liquid saturation isless than the third region due to the effect of capillary number andcomingled effect. The existence of this area is proven throughseveral experimental studies on core samples at low surface ten-sion and high flow rates (Henderson et al., 1996; Ali et al., 1997).

Pressure reduction below dew point pressure due to productionfrom rich gas-condensate reservoirs results in hydrocarbon liquidsretrograde condensation in the reservoir which leads to formationof a zone of increased condensate saturation around the wellborethat is called “condensate bank” or “condensate ring” (Shandryginand Rudenko, 2005; Calisgan et al., 2006).

Most gas condensate wells experience rapid production declineas a result of condensate banking when the bottom-hole pressurefalls below the dew point. Several authors have studied the physicalaspects such as well productivity related to retrograde condensa-tion in near-wellbore zones (Fussell, 1973; Clark, 1985; Hinchmanand Barree, 1985; McCain and Alexander, 1992; Barnum et al.,1995; Boom et al., 1995; Favang and Whitson, 1995; Novosad,1996; Ahmed et al., 1998). Well productivity in gas-condensatereservoirs often decreases significantly since this near wellborecondensate drop out blocks gas inflow to some extent, leads to

Table 1Reservoir parameters.

Parameter Value

Number of grids in X direction 11Number of grids in Y direction 11Number of grids in Z direction 10Dimensions (ft) X 980Dimensions (ft) Y 980Dimensions (ft) Z 405Porosity (%) 5.9Net to gross (NTG) (%) 36Permeability (md) 0.32Reservoir reference depth (ft) 16,026Reservoir reference pressure (psi) 12,750Depth of gasewater contact (ft) 18,629Reservoir temperature (�F) 285Water formation volume factor (Bw) at

reference pressure (rb/stb)1.0525

Rock compressibility (1/psi) 3.447E-7

reduced gas relative permeability and thus to low recovery prob-lems. Radial compositional simulation models were often used toinvestigate the problem of reduction in productivity (Fussell, 1973;Clark, 1985; Hinchman and Barree, 1985; McCain and Alexander,1992; Novosad, 1996). These models clearly showed that therapid well productivity decline was due to liquid drop out aroundthe wellbore when pressure drops below the dew point.

Barnum et al. (1995) have noticed that the recovery factor of gascondensate wells is only affected by condensate blocking if thewell’s kh is less than 1000 md-ft. This implies that the effect ofcondensate blocking is more obvious in low permeability reservoirsas this is the casewe have studied in this paper. Thewell’s kh for thereservoir of interest in this study is 1269 md-ft. Although thereservoir pressure is high, the pressure drop due to low perme-ability of the reservoir is rapid specially near wellbore andcondensate blockage is considered as the significant problem.

Since optimum production from gas condensate reservoirsneeds precise analysis, schematization and well management andin addition by regarding that gas contracts are at the beginning lifeof the reservoir and for a long time, therefore, the prediction of theproductivity index is so important and needs comprehensiveknowledge of the reservoir behaviors, throughout a simulationstudy, this paper investigates the effects of condensate bank on thegas and condensate productivity and totally the reservoirperformance.

2. Simulation model

Marun field, discovered in 1963, is one of the largest oil and gasfields in Iran, and is located near the city of Ahwaz. The meandistance of this field to the city of Ahwaz is about 60 km. This field islocated between two huge oil fields of Ahwaz and Aghajari, whereAhwaz field is in the southwest and the Aghajari field is located inthe northwest respect to the Marun field. It is a NorthwesteSoutheast plunging anticline. Marun field is consisting of threedistinct reservoirs. Asmari and Bangestan are oil reservoirs andKhami is a gas condensate reservoir. In the recent decades, Asmari

Table 3Composition at reference depth.

Component mole %

N2 0.0010CO2 0.0272C1 0.7231C2 0.0615C3 0.0333iC4 0.0094nC4 0.0200iC5 0.0093nC5 0.0084C6 0.0137C7þ 0.0520

C14þ 0.0295

C25þ 0.0116

Table 4Some fluid characteristics.

Parameter Value

Dew point pressure (psi) 7588Reservoir temperature (�F) 285Maximum condensate saturation from CVD test (%) 20.86

Table 5Separators conditions.

Stage Separator temperature (�C) Separator pressure (psia)

1st separator 80 8002nd separator 60 14.7

R. Mokhtari et al. / Journal of Natural Gas Science and Engineering 14 (2013) 66e7668

and Bangestan oil reservoirs were two major sources of oil pro-duction in Iran. Fig. 1 indicates the location of this field.

Khami reservoir in Marun field is a carbonated gas-condensatereservoir with an initial pressure of 12,750 psia and temperatureof 285 �F at a depth of 16,026 feet below sea level. Marun subsur-face anticline on the Khami horizon has almost 60 km long and5.3 km wide. The reservoir consists of Darian (limestone), Gadvan(shale-marl) and Fahlian (limestone) formations. Several wells inthe reservoir have been completed and most of them had noparticular production problems. There is only one well with a sig-nificant permanent wellhead flowing pressure drop since 2006(Mirzaei Payaman and Zarei Foroush, 2012).

2.1. Reservoir parameters

Table 1 indicates the characteristics of the reservoir used for thisstudy. Khami is a unique lowpermeable, deep and high pressure gascondensate reservoir. To enhance the grid definition near the well,especially for the gas condensate reservoir simulation studies and toallow accurate modeling of near wellbore gas/condensate behavior,radial local grid refinement is used. Table 2 shows the local grid

Fig. 2. Oil/water relative

refinement parameters. The production well is located in the (6, 6)grid block and is completed in the all blocks in the z direction.

2.2. Fluid PVT properties

In any comprehensive gas condensate reservoir simulationstudy, the first and the key step, which is necessary to be done isTuning an EOS to predict the PVT properties based on the labora-tory tests. The accuracy and reliability of gas condensate simulationstudies are dramatically sensitive to the accuracy of EOS which isused. For tuning a suitable EOS for this reservoir a commercial PVTsoftwarewas used, and 3-parameter Peng Robison equation of statewas chosen.

After lots of efforts including: splitting the C7þ in to C7

þ, C14þ and

C25þ , and selecting proper regression parameters, a good match forthe mentioned EOS and viscosity equation was obtained. PVT lab-oratory sample data including constant composition expansion(CCE), constant volume depletion (CVD) and separator flash testswere used in the tuning of the EOS. The initial components andtheir composition at reference depth are shown in Table 3. Table 4illustrates the specific characterization of the reservoir fluid.

The common separator conditions used in the field aredemonstrated in Table 5. Generally two separator stages are used todecrease the reservoir fluid pressure and temperature.

2.3. Reservoir rock properties

The two-phase oil/water at Sg ¼ 0 and gas/liquid relativepermeability and capillary pressure curves used for the simulationstudy are shown in Figs. 2e4. These curves are generated from theSCAL analysis on the reservoir core samples. Compositional simu-lator interpolates the gas relative permeability curves between abase and a miscible fluid relative permeability curve to account forthe relative permeability dependency on velocity and IFT. The baserelative permeability curve is the measured curve at the lowestpossible velocity level and the highest realistic IFT value(Jamiolahmady et al., 2003). The miscible or straight-line relativepermeability is calculated and accounts for inertial effects. The

permeability curve.

Fig. 3. Gas/oil relative permeability curve.

R. Mokhtari et al. / Journal of Natural Gas Science and Engineering 14 (2013) 66e76 69

interpolation is weighted by capillary number dependent functionsaccording to correlations developed by Henderson et al. (1996).

2.4. History matching

History matching is often an iterative process, inwhich steps arerepeated several times with variations in reservoir characteristics.History matching was performed in an attempt to explain the un-common behavior of the well and reservoir. History matching was

Fig. 4. Gas/liquid capilla

conducted over 3 years (2006e2009) of production data. Themodel was constrained by gas rate while reservoir properties werechanged to match average reservoir pressure and condensate pro-duction rate. Fig. 5 shows the match between actual and simulatedgas production rate and Fig. 6 illustrates the history match ofcondensate production rate. Fig. 7 also indicates a good matchbetween simulated and actual reservoir pressure. Permeability,porosity, and permeability distribution of themodel were altered toachieve this match.

ry pressure curve.

Fig. 5. History match of gas production rate.

R. Mokhtari et al. / Journal of Natural Gas Science and Engineering 14 (2013) 66e7670

3. Results

After the successful history matching, several reasons for theuncommon behavior (reduction in gas production then reaching aconstant value, and again repeating this pattern and finally a bitincrease in gas rate) of this reservoir became apparent. The gasproduction rate pattern and produced CGR versus time are show inFig. 8 and Fig. 9 respectively. All results are discussed in threedifferent distances from the wellbore (cell 1 is 25 ft, cell 5 is 221 ftand cell 10 is 466 ft away from the wellbore) in order to have acomparison between reservoir behavior at different locations.

Fig. 6. History match of cond

The initial well productivity declined when the near wellboreflowing pressure decreased below the dew point pressure. This wasdue to the increase in condensate saturation around the wellbore.Fig.10 shows condensate saturation versus time in three grid blocksrepresenting near wellbore, middle of the reservoir, and far end ofthe reservoir.

The condensate saturation near the wellbore increased toalmost 65 percent when the pressure dropped below dew pointpressure. This increase is considerably above the maximumcondensate saturation predicted by the constant volume depletionexperiment (CVD). This high condensate saturation is determined

ensate production rate.

Fig. 7. History match of reservoir pressure.

R. Mokhtari et al. / Journal of Natural Gas Science and Engineering 14 (2013) 66e76 71

by the relative permeability curve (the condensate saturation has tobe high enough to ensure that the correct amount of condensatepasses to the wellbore).

After pressure throughout the reservoir drops below dew pointpressure, significant condensate saturation builds up in the reser-voir. As a result, the gas arrives to the wellbore is leaner and dropsless condensate around the wellbore. The decline in near-wellbore(cell 1) condensate saturation in the period of 10,000e12,000 days,which is seen in Fig. 10, is because of the partial vaporization of thecondensate in the lean gas. It is confirmed from Fig. 13 which showsthe reduction in the surface tension in this time period. This

Fig. 8. Gas prod

reduction in condensate saturation allows partial recovery of gasproduction in a constant rate.

3.1. Relative permeability effects

The relative permeability to both condensate and gas is deter-mined from condensate and gas saturations. Fig. 11 shows therelative permeability of the condensate in three different distancesfrom the wellbore. The figure shows that the relative permeabilityto condensate in cell 1 and cell 5 increases as condensate saturationincreases and decreases as condensate saturation decreases.

uction rate.

Fig. 9. Condensate/Vgas ratio.

R. Mokhtari et al. / Journal of Natural Gas Science and Engineering 14 (2013) 66e7672

Condensate relative permeability continuously declines as theincoming gas becomes leaner in the cell 10. The figure also showsthat the condensate far in the reservoir (cell 10) does not movesince its saturation does not become high enough to build anyrelative permeability.

Fig. 12 shows the relative permeability to gas in cells 1, 5 and 10.After the initial drop when pressure goes below dew point pres-sure, the relative permeability to gas increases with time. This in-crease in gas permeability is due to decrease in condensatesaturation shown in Fig. 10.

Fig. 10. Condensate saturation in three

3.2. Compositional changes

The simulation results show that the compositions of bothcondensate and gas in the reservoir change as reservoir pressuredecreases. The compositional changes around the wellbore aremore dramatic than in the reservoir. This is shown by surfacetension plot (Fig. 13). The surface tension reflects the closeness ofthe compositions of the condensate and the gas. Around thewellbore (cell 1) higher surface tension reflects considerable dif-ference between condensate and gas compositions. Whereas in

different distances from wellbore.

Fig. 11. Condensate relative permeability in three different distances from wellbore.

R. Mokhtari et al. / Journal of Natural Gas Science and Engineering 14 (2013) 66e76 73

the reservoir (cells 5 and 10), the surface tension is much lowerthan near the wellbore. Increase in surface tension shows that theflowing gas to the near wellbore region becomes leaner during theproduction time.

The compositional changes affect the viscosities of both thecondensate and the gas. Fig. 14 and Fig. 15 show the viscosity of thecondensate and the gas respectively (calculated from their com-positions). Increase in condensate viscosity and decrease in gasviscosity result in increased gas mobility.

Fig. 12. Gas relative permeability in thre

3.3. Condensate ring development

Fig. 16 illustrates the buildup of condensate around the wellboreand shows the way the condensate saturation profiles change withtime. Initially the condensate saturation builds to nearly 65 percentnear the wellbore when the pressure near the wellbore dropsbelow the dew point pressure of the gas. This maximum conden-sate saturation is considerably higher than predicted in the staticlaboratory PVT work. This condensate saturation decreases to zero

e different distances from wellbore.

Fig. 13. Reservoir fluid surface tension in three different distances from wellbore.

R. Mokhtari et al. / Journal of Natural Gas Science and Engineering 14 (2013) 66e7674

a short distance away from the wellbore and is zero throughoutmost of the reservoir (where pressures are above dew point pres-sure). The diameter of the ring grows with time but as long as mostof the reservoir has pressures above dew point the maximumconcentration of condensate near the wellbore remains near 65percent. After thirty years of production the condensate ring hasexpanded to about 1000 feet into the reservoir (Fig. 16).

Between the thirtieth and fortieth years of production thepressure throughout the reservoir drops below dew point pressure.Condensate saturation builds in the reservoir and would finally

Fig. 14. Condensate viscosity in three

reach to the level predicted by the laboratory PVT results; leanergas approaches near wellbore, and the near wellbore condensatesaturation decreases (from 64 percent for ten years to 57 percentfor sixty years).

After that the pressure in all reservoir parts drops below thedew point, the condensate saturation throughout the reservoirincreases as pressure decreases according to the PVT results and thecondensate saturation near the wellbore decreases. This, of course,results in an increase in gas saturation near the wellbore whichincreases the gas productivity.

different distances from wellbore.

Fig. 15. Gas viscosity in three different distances from wellbore.

R. Mokhtari et al. / Journal of Natural Gas Science and Engineering 14 (2013) 66e76 75

3.4. Discussion

Production plateau in this field were rather unusual. The gasproduction rate initially declined rapidly then stabilized, after thatagain the gas production rate declined and then stabilized, andfinally increased a bit. The time at which the gas production ratesstabilized coincided with the start of the decline in condensateyield (approximately 10,000e12,000 and 17,000e22,000 days inFigs. 8 and 9). Thus, the gas productivities appeared to be related tothe dew point pressure of the reservoir gas.

Compositional simulation showed that the fairly severe gasproductivity decline early in the life of the reservoir was caused by

Fig. 16. Condensate s

the buildup of a ring of condensate near the wellbore when thepressure near the wellbore dropped below dew point pressure.Note the subtle decline in yield in the production data (Figs. 8 and9) during this period as the diameter of ring increases. Thecondensate saturation in this ring of condensate had to build to alevel high enough to allow the condensate lost from the gasentering the ring to pass into the wellbore.

In this reservoir, the condensate saturation near the wellborebuilt to about 65 percent which with an irreducible water satura-tion of 16 percent reduced the relative permeability of the gas toless than 0.15. When the pressure in the bulk of the reservoir fellbelow the dew point, condensate dropped throughout the

aturation profile.

R. Mokhtari et al. / Journal of Natural Gas Science and Engineering 14 (2013) 66e7676

reservoir. The saturation of this condensate did not increase to ahigh enough value for the condensate to flow, however the gasflowing to the wellbore was leaner and thus had less condensate todrop in the ring. This allowed the condensate saturation in the ringto decline to about 57 percent. Although this change does notappear to be dramatic, it did result in a gas saturation of 27 percentwhich increased the relative permeability of gas to about 0.22,more than 1.5 times of the value when the ring first formed (0.14).This, of course, resulted in the increase in gas productivity.

Other changes in the gas after reservoir pressure declines belowdew point pressure also aid in the improvement of gas productivity.These changes are not as significant as the improvement in relativepermeability to gas. However, the leaner gas has a measurablylower viscosity which improves productivity. Furthermore, theproduction of leaner gas reduces both the hydrostatic and frictioncomponents of the pressure drop through the tubulars. This effectalso tends toward productivity improvement.

4. Conclusions

1) Production rate of gas condensate wells in low permeabilityreservoirs declines because of liquid drop out around thewellbore, once the near wellbore pressure drops below the dewpoint pressure.

2) Condensate builds up in the reservoir as the reservoir pressuredrops below the dewpoint pressure. As a result, the gasmovingto the wellbore becomes leaner.

3) Condensate saturation would decrease in the near wellboreregion because of the leaner gas entering this region and alsopartial vaporization.

4) The gas production rate may stabilize, decrease or possiblyincrease, after the period of initial decline. This is controlledprimarily by the condensate saturation near the wellbore.

5) Both the liquid and gas around the wellbore change incomposition. The liquid could become heavier or lighterdepending on the reservoir behavior and the gas could becomeleaner or richer as well.

6) Viscosity of the liquid and gas also had not a uniform trendespecially in different parts of the reservoir and they couldbecome higher or lower.

7) Using one of the well productivity index improvementmethods such as gas recycling is recommended, but acomprehensive study about the performance of any of thesemethods is needed.

8) In addition to the gas production rate, the composition changealso should be considered in the sale contracts.

Acknowledgment

The technical support from National Iranian South Oil Company(NISOC) is greatly acknowledged.

Nomenclature

Bw Water formation volume factorC CelsiusCCE Constant composition expansionCGR Condensate gas ratiocp CentipoiseCVD Constant volume depletionEOS Equation of stateF Fahrenheitft Footh Height

IFT Interfacial tensionk Permeabilitykm KilometerKrg Gas relative permeabilityKro Oil relative permeabilityKrw Water relative permeabilitymd MillidarcyMSCF Million standard cubic feetMSCFD Million standard cubic feet per dayNTG Net to grosspsia Absolute pound per square inchPVT Pressureevolumeetemperaturerb Reservoir barrelSg Gas saturationSCAL Special core analysisstb Stock tank barrelSTBD Stock tank barrel per day

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