14 Oilfield Review

Understanding Gas-Condensate Reservoirs

Li FanCollege Station, Texas, USA

Billy W. HarrisWagner & Brown, Ltd.Midland, Texas

A. (Jamal) JamaluddinRosharon, Texas

Jairam KamathChevron Energy Technology CompanySan Ramon, California, USA

Robert MottIndependent Consultant Dorchester, UK

Gary A. PopeUniversity of TexasAustin, Texas

Alexander ShandryginMoscow, Russia

Curtis Hays WhitsonNorwegian University of Science andTechnology and PERA, A/STrondheim, Norway

For help in preparation of this article, thanks to Syed Ali,Chevron, Houston; and Jerome Maniere, Moscow.ECLIPSE 300, LFA (Live Fluid Analyzer for MDT tool), MDT(Modular Formation Dynamics Tester) and PVT Express aremarks of Schlumberger. CHEARS is a mark of Chevron.Teflon is a mark of E.I. du Pont de Nemours and Company.

How does a company optimize development of a gas-condensate field, when

depletion leaves valuable condensate fluids in a reservoir and condensate blockage

can cause a loss of well productivity? Gas-condensate fields present this puzzle.

The first step must be to understand the fluids and how they flow in the reservoir.

A gas-condensate reservoir can choke on itsmost valuable components. Condensate liquidsaturation can build up near a well because ofdrawdown below the dewpoint pressure,ultimately restricting the flow of gas. The near-well choking can reduce the productivity of awell by a factor of two or more.

This phenomenon, called condensateblockage or condensate banking, results from acombination of factors, including fluid phaseproperties, formation flow characteristics andpressures in the formation and in the wellbore.If these factors are not understood at thebeginning of field development, sooner or laterproduction performance can suffer.

For example, well productivity in the Arunfield, in North Sumatra, Indonesia, declinedsignificantly about 10 years after productionbegan. This was a serious problem, since welldeliverability was critical to meet contractualobligations for gas delivery. Well studies,including pressure transient testing, indicatedthe loss was caused by accumulation ofcondensate near the wellbore.1

Arun is one of several huge gas-condensatereservoirs that together contain a significantglobal resource. Other large gas-condensateresources include Shtokmanovskoye field in theRussian Barents Sea, Karachaganak field inKazakhstan, the North field in Qatar thatbecomes the South Pars field in Iran, and theCupiagua field in Colombia.2

This article reviews the combination of fluidthermodynamics and rock physics that results incondensate dropout and condensate blockage.We examine implications for production andmethods for managing the effects of condensatedropout, including reservoir modeling to predictfield performance. Case studies from Russia, theUSA and the North Sea describe field practicesand results.

Forming DewdropsA gas condensate is a single-phase fluid atoriginal reservoir conditions. It consistspredominantly of methane [C1] and other short-chain hydrocarbons, but it also contains long-chain hydrocarbons, termed heavy ends. Under

1. Afidick D, Kaczorowski NJ and Bette S: “ProductionPerformance of a Retrograde Gas Reservoir: A CaseStudy of the Arun Field,” paper SPE 28749, presented atthe SPE Asia Pacific Oil & Gas Conference, Melbourne,Australia, November 7–10, 1984.

2. For a case study of the Karachaganak field: Elliott S,Hsu HH, O’Hearn T, Sylvester IF and Vercesi R: “TheGiant Karachaganak Field, Unlocking Its Potential,”Oilfield Review 10, no. 3 (Autumn 1998): 16–25.

3. Gas-condensate fluids are termed retrograde becausetheir behavior can be the reverse of fluids comprisingpure components. As reservoir pressure declines andpasses through the dewpoint, liquid forms and theamount of the liquid phase increases with pressuredrop. The system reaches a point in a retrogradecondensate where, as pressure continues to decline,the liquid revaporizes.

4. Injection of cold or hot fluids can change reservoirtemperature, but this rarely occurs near productionwells. The dominant factor for fluid behavior in thereservoir is the pressure change. As will be discussedlater, this is no longer the case once the fluid is producedinto the wellbore.

Winter 2005/2006 15

certain conditions of temperature and pressure,this fluid will separate into two phases, a gas anda liquid that is called a retrograde condensate.3

As a reservoir produces, formation temper-ature usually doesn’t change, but pressuredecreases.4 The largest pressure drops occurnear producing wells. When the pressure in agas-condensate reservoir decreases to a certainpoint, called the saturation pressure ordewpoint, a liquid phase rich in heavy endsdrops out of solution; the gas phase is slightlydepleted of heavy ends (right). A continueddecrease in pressure increases the volume of theliquid phase up to a maximum amount; liquidvolume then decreases. This behavior can bedisplayed in a pressure-volume-temperature(PVT) diagram.

The amount of liquid phase present dependsnot only on the pressure and temperature, butalso on the composition of the fluid. A dry gas, bydefinition, has insufficient heavy components togenerate liquids in the reservoir, even with near-well drawdown. A lean gas condensate generates

> Phase diagram of a gas-condensate system. This pressure-volume-ttemperature (PVT) plot indicates single-phase behavior outside the two-phase region, which is bounded by bubblepoint and dewpoint lines. Linesof constant phase saturation (dashed) all meet at the critical point. Thenumbers indicate the vapor phase saturation. In a gas-condensatereservoir, the initial reservoir condition is in the single-phase area to theright of the critical point. As reservoir pressure declines, the fluid passestthrough the dewpoint and a liquid phase drops out of the gas. Thepercentage of vapor decreases, but can increase again with continuedpressure decline. The cricondentherm is the highest temperature at whichttwo phases can coexist. Surface separators typically operate atconditions of low pressure and low temperature.

Temperature

Pres

sure

Initial reservoirInitial reservoirconditionconditionCritical pointCritical point

SeparatorSeparatorconditioncondition

C i d thCricondentherm

Two phase regionTwo-phase region

60%60%

70%70%

80%

90%

100% vapor00% apo

BBBuu

bbbblleepp

ooinntt liinneeDDewwppooiinntt liinnee

a small volume of the liquid phase, less than100 bbl per million ft3 [561 m3 per million m3],and a rich gas condensate generates a largervolume of liquid, generally more than 150 bblper million ft3 [842 m3 per million m3] (above).5

There are no established boundaries in thedefinitions of lean and rich, and furtherdescriptors—such as very lean—are alsoapplied, so these figures should be taken merelyas indicators of a range.

Determining the fluid properties can beimportant in any reservoir, but it plays aparticularly vital role in gas-condensatereservoirs. For example, condensate/gas ratioplays a major role in estimates for the salespotential of both gas and liquid, which areneeded to size surface processing facilities. Theamount of liquid that may be stranded in a fieldis also an essential economic consideration.These considerations and others, such as theneed for artificial lift and stimulationtechnologies, rely on accurate fluid sampling.Small errors in capturing samples, such as anincorrect amount of captured liquid, can havesignificant errors in measured behavior, so greatcare must be taken in the sampling process (see“Sampling for Fluid Properties,” next page).

Once reservoir fluids enter a wellbore, bothtemperature and pressure conditions maychange. Condensate liquid can be produced intothe wellbore, but liquid also can drop out withinthe wellbore because of changes in conditions. Ifthe gas does not have sufficient energy to carrythe liquid to surface, liquid loading or fallback inthe wellbore occurs because the liquid is denserthan the gas phase traveling along with it. If theliquid falls back down the wellbore, the liquidpercentage will increase and may eventuallyrestrict production. Gas lift and pumpingtechnologies that are used to counter thisbehavior will not be discussed in this article.6

16 Oilfield Review

> Examples of rich and lean gas-condensate behavior. When pressure decreases at reservoir temperature, a rich gas (top left) forms a higherttpercentage of liquid than a lean gas (top right). The rich gas drops out more condensate than the lean gas (tt bottom left). The liquid dropout curvettassumes the two phases remain in contact with one another. However, in a reservoir, the mobile gas phase is produced; the liquid saturation in thenear-well region builds until it is also mobile. As a result, eventually condensate blockage can affect formations with both lean and rich gases, andtthe normalized well productivity index (J/J J0) of both can be severely impacted (0 bottom right).tt

Liqu

id d

ropo

ut, %

Pressure, psi

0 2,000 3,000 4,000 5,000 6,0001,0000

5

10

15

20

25

Lean gas condensateLean gas condensateLean gas condensate

Rich gas condensateRich gas condensateRich gas condensate

0

0.2

0.4

0.6

0.8

1.0

0 0.2 0.4 0.6 0.8 1.0

Lean gas condensateL dLean gas condensateg

Rich gas condensateRich gas condensateRich gas condensate

Paverage/Pdewpoint

Prod

uctiv

ity ra

tio, J

/Jo

CriticalCriticalpointpoint

0

1,000

2,000

3,000

4,000

5,000

6,000

150 200 250 300 350 400 450 500 550 600

Temperature, K

Reservoir temperatureReservoir temperature

98 5%98.5%99%99%

99.5%

Pres

sure

, psi

Lean GasCondensate

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

0 200 300 400 500 600 700 800 900100

Temperature, K

Pres

sure

, psi

CriticalCriticalpointpoint

Reservoir temperatureReservoir temperature

75%75%80%0

85%85%590%90%

95%95%

Rich GasCondensate

5. Gas volumes in this article are given at the conditions thatare considered standard at the measurement location,which is not the same around the world. Conversionsbetween metric and oilfield units are volumetric.

6. For more on artificial lift: Fleshman R, Harryson andLekic O: “Artificial Lift for High-Volume Production,”Oilfield Review 11, no. 1 (Spring 1999): 48–63.

Winter 2005/2006 17

Fluid composition is determined by capturinga representative sample of reservoir fluid.Surface samples can be obtained relativelyeasily by collecting liquid and gas samplesfrom test or production separators. Thesamples are then recombined in a laboratory.However, the result can be unrepresentativeof reservoir conditions, particularly whensampling from a gas-condensate reservoir. Afew examples of potential problems includerecombining the gas and liquid samples atan incorrect ratio, changing productionconditions prior to or during sampling andcommingling zones with different properties.If the liquid content is low when capturingsurface samples, a small loss of the liquid inproduction tubulars or separators couldrender the condensate sample unrepresen-tative of the formation fluid.

Samples can also be collected downholefrom wellbore fluids in gas-condensatereservoirs. This is practical and desirable ifthe wellbore flowing pressure is above thedewpoint pressure, but it is generally notrecommended if the pressure anywhere in thetubing is lower than the dewpoint pressure. Inthat condition, there is two-phase flow in thewellbore. Any liquid forming in the tubingduring or prior to the sampling may segregateto the bottom of the tubing string—where abottomhole sampler collects fluids—potentiallyresulting in an unrepresentative sample withtoo much of the heavier components.

Formation testers have improved signifi-cantly over the past decade. The MDT ModularFormation Dynamics Tester collects fluids bypressing a probe against an uncased boreholewall and withdrawing fluids from a formation.1

The LFA Live Fluid Analyzer module on thetool measures the cleanup of contaminationfrom oil-base drilling or completion fluids,minimizing the wait time and assuring qualitysamples.2 The LFA detector also provides anindication of the amount of methane, otherlight components and liquids. From thesedata, the ratio of methane to liquid providesa measure of the condensate/gas ratio, animportant consideration for early economicevaluation of a prospect. The analysis canalso show zones with different compositionsor compositional gradients.

Measured data from the MDT tool are trans-mitted to surface immediately, so samplingdecisions can be made based on knowledgeof approximate composition and reservoirpressure, another measured parameter. Ifdesired, fluid samples can be collected beforemoving to another downhole location.

For gas condensates that are at pressuresabove the dewpoint in the reservoir, it isimportant to capture and maintain single-phase fluid. If the fluid pressure drops belowdewpoint, it may take a long time torecombine the sample. Even worse, somechanges that occur in a sample on its trip tosurface may be irreversible. By providing

evidence when a fluid goes through itsdewpoint, the LFA measurement can indicatewhen the pressure drawdown is too large andshould be decreased before sampling to keeppressure above the dewpoint.

A sample that is single-phase when collectedshould be kept in a single phase when broughtto surface. Special MDT sample bottles areavailable for this purpose. A single-phasebottle uses a nitrogen cushion to increase thepressure in the sampled fluid.3 The samplecools as it is brought to surface, but thenitrogen cushion on the sample keeps itspressure above the dewpoint.

In most cases, the PVT Express onsite wellfluid analysis service can provide fluidproperty measurements at the wellsite inabout 24 hours, saving the weeks or monthsthat may be needed to get results from alaboratory.4 The PVT Express systems canmeasure gas/liquid ratio, saturationpressure—bubblepoint or dewpoint—composition to C30+, reservoir fluid density,viscosity and oil-base mud contamination.5

These measurements are critical because anoperating company can use them immediatelyto make a decision to complete or to test awell. Rapid turnaround may be crucial whendrilling exploration or development wells froman expensive offshore rig. More completeanalyses can be obtained later from samplessent to a laboratory.

With the basic understanding of whereand how condensate drops out of the gasphase, engineers can devise ways to optimizeproduction of gas and condensate.

Sampling for Fluid Properties

1. Andrews RJ, Beck G, Castelijns K, Chen A, Cribbs ME,Fadnes FH, Irvine-Fortescue J, Williams S, Hashem M,Jamaluddin A, Kurkjian A, Sass B, Mullins OC,Rylander E and Van Dusen A: “QuantifyingContamination Using Color of Crude and Condensate,”Oilfield Review 13, no. 3 (Autumn 2001): 24–43.

2. Betancourt S, Fujisawa G, Mullins OC, Carnegie A,Dong C, Kurkjian A, Eriksen KO, Haggag M, JaramilloAR and Terabayashi H: “Analyzing Hydrocarbons in theBorehole,” Oilfield Review 15, no. 3 (Autumn 2003):54–61.

3. Jamaluddin AKM, Ross B, Calder D, Brown J andHashem M: “Single-Phase Bottomhole SamplingTechnology,” Journal of Canadian PetroleumTechnology 41, no. 7 (July 2002): 25–30.

4. Jamaluddin AKM, Dong C, Hermans P, Khan IA,Carnegie A, Mullins OC, Kurkjian A, Fujisawa G,Nighswander J and Babajan S: “Real-Time and On-Site Reservoir Fluid Characterisation Using SpectralAnalysis and PVT Express,” Australian PetroleumProduction & Exploration Association Journal (2004):605–616.

5. The nomenclature “composition to C30+” indicatescompounds up to 29 carbon atoms are separatelydiscriminated, with the remainder combined into afraction indicated as C30+.

Dewdrops in a ReservoirWhen condensate liquid first forms in a gasreservoir, it is immobile because of capillaryforces acting on the fluids. That is, a microscopicliquid droplet, once formed, will tend to betrapped in small pores or pore throats. Even for rich gas condensates with substantial liquid dropout, condensate mobility, which is theratio of relative permeability to viscosity,remains insignificant away from wellbores. As aconsequence, the condensate that forms in mostof the reservoir is lost to production unlessthe depletion plan includes gas cycling. Theeffect of this dropout on gas mobility is typically negligible.

Near a producing well, the situation isdifferent. Once bottomhole pressure dropsbelow the dewpoint, a near-well pressure sinkforms around the well. As gas is drawn into thepressure sink, liquid drops out. After a brieftransient period, enough liquid accumulatesthat its mobility becomes significant. The gasand liquid compete for flow paths, as describedby the formation’s relative-permeabilityrelationship. Condensate blockage is a result ofthe decreased gas mobility around a producingwell below the dewpoint (right).

Reservoir pressure dropping below thedewpoint has two main results, both negative:gas and condensate production decreasebecause of near-well blockage, and the producedgas contains fewer valuable heavy ends becauseof dropout throughout the reservoir, where thecondensate has insufficient mobility to flowtoward the well.

Large productivity losses have been reportedfor wells in gas-condensate fields. In the Arunfield, which was operated by Mobil, nowExxonMobil, the loss in some wells was greaterthan 50%.7 In another case, Exxon, nowExxonMobil, reported two wells that died due tocondensate blockage.8 Shell and PetroleumDevelopment Oman reported a 67% productivityloss for wells in two fields.9

In another field, the initial productivitydecline has reportedly reversed. The productivityof wells in the moderately rich gas-condensatereservoir declined rapidly when bottomholepressures dropped below dewpoint. This declinecontinued until pressure throughout thereservoir dropped below dewpoint, then gasproductivity began to increase. Compositionalmodeling showed that condensate saturationincreased near the wells to approximately 68%,decreasing gas permeability and therefore gasproductivity. However, when pressure throughoutthe reservoir dropped below dewpoint, some

liquid dropped out everywhere. The gas movingtoward the wellbore was leaner and had lesscondensate to drop out in the near-well region,resulting in decreased condensate saturation toabout 55% and increased gas productivity.10 Thecondensate blockage decreased as the near-wellgas mobility increased.

Condensate BlockageNot all gas-condensate reservoirs are pressure-limited because of near-well condensateblockage, even though all of these fields willexperience condensate blockage. The degree towhich condensate dropout is a productionproblem depends on the ratio of the pressuredrop that is experienced within the reservoir tothe total pressure drop from distant areas of thereservoir to a control point at surface.

If reservoir pressure drop is significant, thenadditional pressure drop due to condensateblockage can be very important for welldeliverability. This condition typically applies ina formation with a low kh, the product ofpermeability and net formation thickness.Conversely, if little of the total pressure dropoccurs in the reservoir, typical of high kh

formations, then adding more pressure drop inthe reservoir due to condensate blockage willprobably have little impact on well deliverability.As a general guideline, condensate blockage canbe assumed to double the pressure drop in thereservoir for the same flow rate.

Conceptually, flow in gas-condensate fieldscan be divided into three reservoir regions,although in some situations not all three arepresent (next page).11 The two regions closest toa well can exist when bottomhole pressure isbelow the dewpoint of the fluid. The third region,away from producing wells, exists only when thereservoir pressure is above the dewpoint.

This third region includes most of thereservoir away from producing wells. Since it isabove the dewpoint pressure, there is only onehydrocarbon phase, gas, present and flowing.The interior boundary of this region occurswhere the pressure equals the dewpointpressure of the original reservoir gas. Thisboundary is not stationary, but moves outward ashydrocarbons are produced from the well andthe formation pressure drops, eventuallydisappearing as the outer-boundary pressuredrops below the dewpoint.

18 Oilfield Review

> Condensate blockage. Once bottomhole pressure in a well fallsbelow the dewpoint, condensate will drop out from the gas phase.Capillary forces favor having condensate in contact with the grains(inset, right). After a brief transient period, the region achieves attsteady-state flow condition with both gas and condensate flowing(inset, top). The condensate saturation, So, is highest near theowellbore because the pressure is lower, which means more liquiddropout. The oil relative permeability, kro, increases with saturation.oThe decrease in gas relative permeability, krg, near the wellboreillustrates the blockage effect. The vertical axis, represented by awellbore, is schematic only.

Distance from borehole

kro

So

ativ

e pe

rmea

bilit

yRe

l

0

0.5

1.0

0 0.5 1.0Condensate saturation

kkkkkrororokkkkkrgrgrgg

krg

Condensateflow channel

Sand grain

Gas flowchannel

Winter 2005/2006 19

In the second region, the condensate-buildupregion, liquid drops out of the gas phase, but itssaturation remains low enough that it isimmobile; there is still single-phase gas flow.The amount of liquid that drops out isdetermined by the fluid’s phase characteristics,as indicated by its PVT diagram. The liquidsaturation increases and the gas phase becomesleaner as gas flows toward the wellbore. Thisregion’s inner-boundary saturation usually isnear the critical liquid saturation for flow, whichis the residual oil saturation.

In the first region, closest to a producingwell, both gas and condensate phases flow. Thecondensate saturation here is greater than thecritical condensate saturation. This regionranges in size from tens of feet for leancondensates to hundreds of feet for rich

condensates. Its size is proportional to thevolume of gas drained and the percentage ofliquid dropout. It extends farther from the wellfor layers with higher permeability than averagesince a larger volume of gas has flowed throughthese layers. Even in a reservoir containing leangas with low liquid dropout, condensateblockage can be significant, because capillaryforces can retain a condensate that builds to ahigh saturation over time.

This near-well condensate blockage regioncontrols well deliverability. The flowingcondensate/gas ratio is essentially constant andthe PVT condition is considered a constant-composition expansion region.12 This conditionsimplifies the relationship between gas and oilrelative permeabilities, making the ratiobetween the two a function of PVT properties.

However, additional relative-permeabilityeffects occur in the near-well region because thegas velocity, and therefore the viscous force, isextreme. The ratio of viscous to capillary forcesis called the capillary number.13 Conditions ofpressure gradient caused by high velocity or lowinterfacial tension have high capillary numbers,indicating that viscous forces dominate, and therelative permeability to gas is higher than thevalue at lower flow rates.

At even higher flow velocities nearer thewellbore, the inertial or Forchheimer effectdecreases the gas relative permeabilitysomewhat.14 The basis of this effect is theinertial drag as fluid speeds up to go throughpore throats and slows down after entering apore body.15 The result is a lower apparentpermeability than would be expected fromDarcy’s law. The effect is usually referred to asnon-Darcy flow.

The overall impact of the two high-velocityeffects is usually positive, reducing the impact ofcondensate blockage. Laboratory corefloodexperiments are needed to measure the inertial and capillary number effects onrelative permeability.

Although the first indication of condensateblockage is typically a productivity decline, itspresence is often determined by pressuretransient testing. A pressure-buildup test can beinterpreted to show the distribution of liquidbefore the well is shut in. The short-timebehavior in the transient test reflects near-wellconditions. Condensate blockage is indicated bya steeper pressure gradient near the wellbore.With longer test times, the gas permeability farfrom the wellbore dominates the response;permeability can be determined from thederivative curve on a log-log plot of pseudo-pressure and shut-in time. If the test continueslong enough—and that shut-in test timedepends on the formation permeability—flowproperties far from the well will be evident.

Gas-Condensate Reservoir ManagementHistorically, condensate liquids have beensignificantly more valuable than the gas, andthis is still true in a few places far from a gasmarket or transport system. The pricedifferential made gas cycling a commonpractice. Injecting dry gas into a formation tokeep reservoir pressure above the dewpointslowly displaces valuable heavy ends that arestill in solution in the reservoir gas. Eventually,the reservoir is blown down; that is, the dry orlean gas is produced at a low bottomhole pressure.

7. Afidick et al, reference 1.8. Barnum RS, Brinkman FP, Richardson TW and

Spillette AG: “Gas Condensate Reservoir Behaviour:Productivity and Recovery Reduction Due toCondensation,” paper SPE 30767, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,October 22–25, 1995.

9. Smits RMM, van der Post N and al Shaidi SM: “AccuratePrediction of Well Requirements in Gas CondensateFields,” paper SPE 68173, presented at the SPE MiddleEast Oil Show, Bahrain, March 17–20, 2001.

10. El-Banbi AH, McCain WD Jr and Semmelbeck ME:“Investigation of Well Productivity in Gas-CondensateReservoirs,” paper SPE 59773, presented at the SPE/CERIGas Technology Symposium, Calgary, April 3–5, 2000.

11. Fevang Ø and Whitson CH: “Modeling Gas-CondensateWell Deliverability,” SPE Reservoir Engineering 11, no. 4(November 1996): 221–230.

12. In a constant-composition expansion condition, the fluidexpands with pressure decline and two phases may form,but no components are removed. This contrasts with thesecond region, which is considered a constant-volumedepletion region, because the liquid phase that formsdrops out from the gas phase and becomes trapped.

13. Henderson GD, Danesh A, Tehrani DH and Al-Kharusi B:“The Relative Significance of Positive Coupling andInertial Effects on Gas Condensate RelativePermeabilities at High Velocity,” paper SPE 62933,presented at the SPE Annual Technical Conference andExhibition, Dallas, October 1–4, 2000.Whitson CH, Fevang Ø and Sævareid A: “GasCondensate Relative Permeability for Well Calculations,”paper SPE 56476, presented at the SPE Annual TechnicalConference and Exhibition, Houston, October 3–6, 1999.

14. Forchheimer PH: “Wasserbewegung durch Boden,”Zeitschrift ver Deutsch Ingenieur 45 (1901): 1782–1788.

15. Barree RD and Conway MW: “Beyond Beta Factors: AComplete Model for Darcy, Forchheimer, and Trans-Forchheimer Flow in Porous Media,” paper SPE 89325,presented at the SPE Annual Technical Conference andExhibition, Houston, September 26–29, 2004.

> Three reservoir regions. Gas-condensate field behavior can be dividedinto three regions once bottomhole pressure, PBH, drops below theHdewpoint pressure, PD. Far from a producing well (3), where the reservoirpressure is greater than PD, there is only one hydrocarbon phase present,Dgas. Closer to the well (2), there is a region between the dewpoint pressureand the point, r1, at which the condensate reaches the critical saturationfor flow. In this condensate-buildup region, both phases are present, butonly gas flows. Once condensate saturation exceeds the critical saturation,both phases flow toward the well (1).

Pres

sure

PD

PBH

r1

Dewpoint pressureDewpoint pressure

Reservoir pressureReservoir pressure

Distance

2 32 32 3reorbo

ell

We

W1

The price of gas has risen to a value thatmakes reinjection a less attractive strategy,unless the fluid is very rich in heavy ends. Gasinjection is now more commonly used as atemporary activity, until a pipeline or othertransport facility is built, or as a seasonalactivity during periods of low gas demand.

Operators also work to overcome condensateblockage. Some techniques are the same in agas-condensate field as they are in a dry-gasfield. Hydraulic fracturing is the most commonmitigating technology in siliciclastic reservoirs,and acidizing is used in carbonate reservoirs.Both techniques increase the effective contactarea with a formation. Production can beimproved with less drawdown in the formation.For some gas-condensate fields, a lowerdrawdown means single-phase production abovethe dewpoint pressure can be extended for alonger time.

However, hydraulic fracturing does notgenerate a conduit past a condensate saturationbuildup area, at least not for long. Once thepressure at the sandface drops below thedewpoint, saturation will increase around thefracture, just as it did around the wellbore.

Horizontal or inclined wells are also beingused to increase contact area within formations.The condensate still builds up around theselonger wells, but it takes a longer time. Theproductivity of the wells remains high longer,but the benefit must be weighed against theincreased well cost.

Some operators have tried shutting in wellsto allow time for the gas and condensate torecombine, but fluid phase behavior generallydoes not favor this approach. Separation of afluid into a gas and liquid phase in the two-phase region of the phase diagram happens

quickly, and after this the phases tend tosegregate, either within a pore or on a largerscale. This phase separation dramatically slowsthe reverse process of recombining gas andliquid. This reversal requires immediate contactbetween the gas and liquid phases.

Another method, cyclic injection andproduction from one well, sometimes called huffand puff injection, uses dry gas to vaporizecondensate around a well and then produce it.This can have short-term benefit for increasedproductivity, but the blockage returns whenproduction begins again and the formation dropsbelow the dewpoint pressure of the currentgas mixture.

In a field test, methanol solvent was injectedinto Hatter’s Pond field, Alabama, USA. In thisfield, production of a gas condensate comesmainly from the lower Norphlet sandstone, butthe field also produces from the Smackoverdolomite. Wells in Hatter’s Pond field are about18,000 ft [5,490 m] deep with 200 to 300 ft [60 to90 m] of net pay. Gas productivity had declinedby a factor of three to five because of condensateand water blockage. The operator, Texaco (nowChevron), pumped 1,000 bbl [160 m3] ofmethanol down tubing at a rate of 5 to 8 bbl/min[0.8 to 1.3 m3/min] into low-permeabilityformations.16 The methanol treatment removesboth oil and water through a multiple-contactmiscible displacement.17 As a result of thetreatment, gas production increased by a factorof three initially, then stabilized at 500,000 ft3/d3

[14,160 m3/d], a factor of two over thepretreatment rate. Condensate productiondoubled to 157 bbl/d [25 m3/d]. Both gas andcondensate rates persisted for more than10 months after treatment.18

Treatment methods have been suggested forremoving condensate blockage through injectionof surfactants mixed with solvents to alterwetting preference in the reservoir. This topicwill be discussed later in this article.

Remobilizing Stranded CondensateThe Vuktyl gas-condensate field in the KomiRepublic, Russia, has been in production since1968. Although productivity was not severelyimpacted by condensate blockage in the field, asignificant amount of condensate dropped out inthe carbonate reservoir. Several condensaterecovery pilots were run in this field.

The field is a long anticline with productionfrom the Middle Carboniferous Moscow andBashkir sequences (above left). The 1,440 m[4,724 ft] thick structure comprises alternating

20 Oilfield Review

> Vuktyl field, Russia. The Vuktyl field in the Komi Republic in western Russia (top) is an anticline,80 km [50 mi] long and up to 6 km [3.7 mi] wide (bottom). The Roman numerals denote gas-processingfacility collection areas. The fluid is predominantly methane [C1], but with a significant amount ofintermediate hydrocarbon components and nitrogen (table, right). The field has three lithotypestt(table, left).tt

0 mi 4

Komi

RRRRRR U S S II I I S S S S S S S S S U U U U U

AAAAAA

ComponentComposition,

% by molevolume

C2

C1

C3

C4

C5+

N2

74.68.93.81.86.44.5

Porosity, %Permeability, mDTypeFine porosity, microvugs, microfracturedPorous, microvugs, microfracturedFractured, microvugs, porous 0.1 to 4513

0.01 to 0.1<0.1 0.1 to 3

3 to 6>6

Winter 2005/2006 21

limestone and dolomite layers, with an averageinterbed thickness of 1.5 m [5 ft]. The reservoirproperties vary widely throughout the field, butthe field has been divided into seven paysequences of three basic types. All three typeshave microfractures and microvugular porosity.Fine pores, low permeability and low porositydistinguish the first type. The third type hasfractures large enough to contribute topermeability. The other type is intermediate.

At discovery, reservoir conditions were36 MPa [5,200 psi] and 61°C [142°F], with 77.5%initial gas saturation. There is a small rimcontaining light oil. Initial gas in place wasabout 430 x 109 m3 [15 x 1012 ft3] and initialcondensate was about 142 million metric tons[1,214 million bbl].19 The initial, stable,producing condensate/gas ratio was 360 g/m3

[87.1 bbl per million ft3].20 The field has anunderlying aquifer, but the water drive wasinsignificant and laterally uneven.

The complex geology of the field, includinghigh-permeability zones that could have acted asthief zones, led the operator, Gazprom, to developthe field with no gas cycling, using depletion gasdrive as the primary production mechanism.

Approximately 170 vertical wells at a typicalspacing of 1,000 to 1,500 m [3,280 to 4,920 ft]were placed in an irregular triangular grid. Mostof the production wells had 10-in. intermediatecasing and 65⁄5

8⁄⁄ -in. production casing. Severalprolific wells had larger, 7 ⁄5⁄⁄ -in. production casing,

allowing 4 ⁄5⁄⁄ -in. tubing. Typical completions in the500- to 800-m [1,640- to 2,625-ft] producing zonewere perforated casing, but some wells usedscreen or openhole completions. The deepestproducers were drilled about 100 to 150 m [328to 492 ft] above the gas/water contact. Atwo-stage hydrochloric acid treatment was themain method of well stimulation.

After nine years, the production plateau was19 x 109 m3/yr [671 x 109 ft3/yr]. A peak stablecondensate production of 4.2 million tons/yr [36 million bbl/yr] occurred during thesixth year of development.

Currently, the Vuktyl field is in its finaldevelopment phase. Reservoir pressure is 3.5 to5 MPa [508 to 725 psi]. Approximate fieldrecoveries are 83% of the gas and 32% of thecondensate, so about 100 million tons[855 million bbl] of condensate remain inthe field.

Experts from Severgazprom, a part of theGazprom Russian Joint Stock Company, and theVNIIGAZ and SeverNIPIgaz institutes conducteda variety of pilot projects in Vuktyl field torecover additional condensate. In 1988, thecompany began the first pilot experiment, usinga solvent to recover stranded condensate.21 Thepilot included six producers, one injection welland three monitor wells (above). The solvent,25,800 tons [293,000 bbl at formation

conditions] of a mixture of propane [C3] andbutane [C4], was injected into the formationfollowed by 35 million m3 [1.24 x 109 ft3] ofseparator gas.22 The intent was to recovercondensate through miscible displacement ofthe solvent bank.

Geophysical observations conducted duringthe experiment indicated that solvent andinjected gas entered the producing intervals ofthe injection well unevenly. Component analysesof samples from the production and monitorwells indicated solvent and injected gas brokethrough only in the two closest monitor wellsand in none of the production wells. Two eventswere seen in these two monitor wells, a changein condensate/gas ratio from 43 to 65 g/m3 [10.4to 15.7 bbl per million ft3] with a decline to theinitial ratio, followed by a second increase from43 to 54 g/m3 [to 13 bbl per million ft3].

Production logging in the monitor wellsrevealed two-phase flow—gas and solvent—onlyin the bottom part of the productive section.Overall, 95% of the solvent was produced from thetwo monitor wells, but condensate recovery wasonly about 0.4%. The pilot study concluded thatthe propane and butane solvent bank was notsufficiently effective in recovering condensate.

A different recovery method, injecting drygas, began in the Vuktyl field in 1993. The gas,from a trunk pipeline that originated in theTyumen district, is injected under pipelinepressure at 5.4 to 7.4 MPa [780 to 1,070 psi]

16. Al-Anazi HA, Walker JG, Pope GA, Sharma MM andHackney DF: “A Successful Methanol Treatment in aGas-Condensate Reservoir: Field Application,” paper SPE 80901, presented at the SPE Production andOperations Symposium, Oklahoma City, Oklahoma, USA,March 22–25, 2003.

17. In a miscible displacement, a solvent allows fluids to mixfreely in a homogeneous mixture. Multiple-contactmiscibility requires sufficient mass transfer between thesolvent and hydrocarbons to achieve miscibility.

18. Al-Anazi et al, reference 16.19. Zhabrev IP (ed): Gas and Gas-Condensate Fields—

Reference Book. Moscow: Nedra, 1983 (in Russian).kTer-Sarkisov RM: The Development of Natural Gas Fields.Moscow: Nedra, 1999 (in Russian).Conversion from mass to volume is based on condensatedensity of 8.55 bbl/ton.

20. Vyakhirev RI, Gritsenko AI and Ter-Sarkisov RM: TheDevelopment and Operation of Gas Fields. Moscow:sNedra, 2002 (in Russian).

21. Ter-Sarkisov RM, Gritsenko AI and Shandrygin AN:Development of Gas Condensate Fields UsingStimulation of Formation. Moscow: Nedra, 1996(in Russian).Vyakhirev et al, reference 20.

22. For more on the role of propane in lowering the dewpointof a gas-condensate field: Jamaluddin AKM, Ye S,Thomas J, D’Cruz D and Nighswander J: “Experimentaland Theoretical Assessment of Using Propane toRemediate Liquid Buildup in Condensate Reservoirs,”paper SPE 71526, presented at the SPE Annual TechnicalConference and Exhibition, New Orleans, September 30–October 3, 2001.

> Plan view with depth to the formation top at a solvent-injection pilotproject near gas-processing facility number 1 (GPF-1). Propane and butanewere injected into Well 103, followed by separator gas. Six productionwells—designated 91, 92, 93, 104, 105 and 106—and three monitor wells—designated 38, 256 and 257—made up the pilot study area. Solvent wasobserved and produced only from the two closest monitor wells: Wells 38and 256.

2 32,30000

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2 9002,9003 000 m3,000 m

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Pilot areaProduction well

Injector wellMonitor well

without local compression.23 Formation gas,which is in equilibrium with the retrogradecondensate, is replaced by injected dry gas. Thelight C2 to C4 components and intermediate C5+

fractions evaporate into the dry gas.24 Thus,recovery is improved both by producing moreformation gas, which still contains componentsother than methane, and by vaporizing strandedliquids and producing them along with theinjected gas. In addition, the injected gas causesno problems for the production facilities when itbreaks through. However, a significant volume ofdry gas has to be injected to produce tangibleamounts of condensate.

Engineers monitored the process in bothinjection and production wells using gas-liquidand gas-adsorption chromatography (below).25

Since the injection gas did not contain nitrogen,the nitrogen content was used as the indicatorof formation gas.26

The 1993 pilot test program was expanded toadditional pilot locations in 1997, 2003 and 2004.By the middle of 2005, the operator had injected10 x 109 m3 [354 x 109 ft3] of dry gas into thepilot wells, and recovered a significant amountof liquid. Comparing the recovery with estimatesof production through depletion alone showedthat the pilot area produced an additional

785 thousand tons [9.45 million bbl] of C2 to C4

and 138 thousand tons [1.22 million bbl] of C5+.27

The operators also ran single-well pilotprojects in Vuktyl field. Although blockage wasnot severe enough to cause a dramatic drop inproductivity in this field, the operator soughtways to counteract the increased saturation thathad formed around wells. The treatmentincluded injecting solvent—a mix of ethane andpropane—into a well, followed by dry gas. Aftera sufficient volume of injection, the well wasreturned to production.

When the solvent contacts the trappedcondensate, the solvent, formation gas andcondensate mix freely into a single phase. Thedry gas that follows is able to mix freely with thesolvent mixture. Thus, when the well producesagain, the injected gas, solvent and condensateare produced as a single fluid. As a result,the condensate saturation is at or near zero inthe treated zone. As formation gas follows themixture back through the treated zone, a zone ofincreased condensate saturation will reform,but well productivity can be improved byperiodic treatments.

Treatment volumes ranged from 900 to2,900 tons [10,240 to 33,000 bbl] of solvent and1.2 to 4.2 million m3 [42 to 148 million ft3] of drygas.28 Although the effectiveness varied from wellto well, the treatments generally had goodresults. The productivity of four of the wellsincreased by 20% to 40% over a period rangingfrom 6 months to 1.5 years, followed by a declineto the original production levels (next page).

Modeling Condensate BlockageReservoir-simulation models are commonly usedto predict the performance of gas-condensatefields. The models incorporate rock and fluidproperties to predict the dynamic influence ofcondensate blockage on gas and condensateproduction. However, a typical gridblock of afull-field model (FFM) can be much larger thanthe blockage zone, so a coarse grid model maysignificantly overestimate well deliverability.

The most accurate way to determine near-well behavior of a gas-condensate field is byusing a simulator with a fine grid. There are twoways to do this: use a FFM with local gridrefinement (LGR), or use a single-well modelwith a fine grid near the well.

Modern simulators, such as the ECLIPSE 300reservoir simulation software, include capabilityfor LGR. Small gridblocks can be used nearwellbores or other features—such as faults—that can significantly impact local flow. Farther

22 Oilfield Review

> Dry-gas injection pilot. Separator gas injected into three wells— designated 269, 270 and 273—vaporized stranded condensate for production from surrounding wells (top). Dry gas (blue) broketthrough a few months after the pilot began (middle). Nitrogen in the produced gas (green) graduallydecreased, indicating that less formation gas was being produced. The liquid C5+ fraction (red)indicates a slow decline after gas breakthrough. The results show significant production of formationgas, light (C2 to C4) and intermediate components (C5+) from both produced formation gas andremobilized stranded condensate (table, bottom).

Oct93

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pone

nt c

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1

2

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30

20

10

0

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ion,

%

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Component from:

Formation gas,million m3

Formation gas,thousand tons

Strandedcondensate,

thousand tonsDry gas,

million m3

5,9731,996

380238208

Produced gasInjected gas

Produced C2 to C4Produced C5+

10,0357,366

130

270129

2697

195

158

273

133

254151

128

127

100

2,700 m2,700 m2 6002,6002,5002,5002,4002,4002 3002,300

2,2002,2002,1002,100

2,1002,1002,2002,2002,3002 300

131/150132

Injector wellProduction wellPilot area

Winter 2005/2006 23

away from such features, the gridblocks grow toa size typical of a FFM. The cost of using LGRmay be a significant increase in computationtime in some cases.

Another way to examine gas-condensateblockage effects is by using a single-well model.In many cases, radial symmetry allows a well tobe treated in a two-dimensional model, using thedimensions of height and radial distance. Thegridblocks nearest the well are small, nominallyhalf a foot [about 15 cm] in the radial direction.The radial dimension increases with eachgridblock away from the wellbore, until itreaches a maximum size used for the rest of themodel. The fine grid provides good resolutionwhere the flow is highest and the formationsaturation behavior is at its most complex.Capillary, viscous and inertial forces can beappropriately modeled. Far from the wellbore,conditions of pressure and flow can be takenfrom a FFM and applied as boundary conditions.

Sometimes, gas-condensate reservoirsimulations can be performed using a black-oilmodel. This type of model assumes that thereare only two hydrocarbon components in thefluid, oil and gas, and it allows for somepressure-dependent mixing of gas in oil. Thismodel is inappropriate when the compositionschange significantly with time, such as throughgas injection, or when there is a significantcompositional gradient. In those cases, acompositional model with many hydrocarboncomponents is necessary. In addition, some

black-oil models do not include capillarynumber effects, which are important fordetermining well deliverability.

Another way to account for condensateblockage in a full-field model is through the useof pseudopressures. The equation for flow of gasfrom a reservoir to a wellbore can be expressedin terms of a pseudopressure, which is anintegral over pressure. By separately treatingthe three regions described before—two-phaseflow near the well, gas flow with condensatebuildup next, and single-phase gas flow far fromthe well—it is possible to calculate thepseudopressure from the producing gas/oil ratio,PVT properties of the fluid, and gas and oilrelative permeabilities.29 As discussed previously,the constant-composition expansion condition inthe first region simplifies the relative-permeability ratios. This pseudopressuremethod adds little time to running a FFM.

Pseudopressure methods have also beenimplemented in spreadsheet format.30 Thesespreadsheets assume a homogeneous reservoirand a simple black-oil model. They provide fastpredictions that can be used when manysensitivity runs are necessary. A similarsemianalytical method was combined with theeffects of non-Darcy flow and permeabilitylayering. Comparisons using a compositionalsimulator with a fine grid showed that the semianalytical method captured all thenear-well effects accurately and was easy toembed in a FFM at essentially no increase incomputational time.31

Modeling Behavior Around a FractureReservoir simulation modeling was used todetermine the effectiveness of fracturing in theSW Rugeley field in south Texas, USA. Thisfield produces gas condensate from low-permeability—about 1-mD—Frio sand. A well inthis field, which was drilled and completed byWagner & Brown, was hydraulically fracturedinitially, but a rapid decline in productivity ledthe company to refracture the formation aboutthree months later, in June 2002. Productivityimproved, but then continued to decline overthe next few months. The drawdown in thevicinity of the well was below the dewpointpressure, so the company investigated the accumulation of condensate saturationaround a fracture.

Engineers at Schlumberger developed ahomogeneous, radially symmetric, single-wellmodel. This simple model demonstrated thatcondensate blockage could result in a rapidfalloff in productivity. It also provided a meansto quickly check the impact of permeabilityreduction due to compaction caused by pressure decline.

23. Ter-Sarkisov RM, Zakharov FF, Gurlenov YM, Levitskii KOand Shirokov AN: Monitoring the Development of Gas-Condensate Fields Subjected to Dry Gas Injection.Geophysical and Flow-Test Methods. Moscow: Nedra,s2001 (in Russian).Dolgushin NV (ed): Scientific Problems and Prospects ofthe Petroleum Industry in Northwest Russia, Part 2: TheDevelopment and Operation of Fields, ComprehensiveFormation and Well Tests and Logs, A Scientific andTechnical Collection. Ukhta: SeverNIPIgaz, 2005 (in Russian).Vyakhirev et al, reference 20.Ter-Sarkisov et al, reference 21.Ter-Sarkisov, reference 19.

24. For a laboratory study of methane injection into coreswith condensate saturation: Al-Anazi HA, Sharma MMand Pope G: “Revaporization of Condensate withMethane Flood,” paper SPE 90860, presented at theSPE International Petroleum Conference, Puebla,Mexico, November 8–9, 2004.

25. Dolgushin, reference 23.26. Vyakhirev et al, reference 20.27. Dolgushin, reference 23.28. Gritsenko AI, Ter-Sarkisov RM, Shandrygin AN and

Poduyk VG: Methods of Increase of Gas CondensateWell Productivity. Moscow: Nedra, 1997 (in Russian).yVyakhirev et al, reference 20.The density of the solvent mixture is 553 kg/m3.

29. Fevang and Whitson, reference 11.30. Mott R: “Engineering Calculations of Gas-Condensate-

Well Productivity,” SPE Reservoir Evaluation &Engineering 6, no. 5 (October 2003): 298–306.

31. Chowdhury N, Sharma R, Pope GA and Sepehrnoori K:“A Semi-Analytical Method to Predict Well Deliverabilityin Gas-Condensate Reservoirs,” paper SPE 90320,presented at the SPE Annual Technical Conference andExhibition, Houston, September 26–29, 2004.

> Changes in well productivity as a result of injection of ethane andpropane followed by dry gas. The difference of the squares of the reservoirpressure, PR, and the bottomhole pressure,R PBH, as the flow rate increasesHprovides a measure of productivity. Before treatment (blue), the wellrequired a larger pressure difference to produce than it needed afterttreatment (red). Four months after treatment, productivity had degradedslightly (green), but it was still significantly better than productivity beforetthe treatment.

P2 Rese

rvoi

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ttom

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, MPa

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0 50 100 150 200 250

Gas-condensate mixture production, thousand m3/d

With these results in hand, Wagner & Brownhad Schlumberger develop a more detailedreservoir model, using ECLIPSE 300 reservoirsimulation software (above). The model wasrefined by history-matching to the gasproduction rate, which also provided a goodcorrelation to the condensate production.Drawdown in the fracture induced the buildupof condensate saturation along the fracture(next page). The average reservoir pressuredropped below the 6,269-psi [43.22-MPa]dewpoint pressure during the modeled period.

With a good history-match, Wagner & Browncould determine whether the fracture providedsignificant gains in productivity. The model wasrerun without the fracture, which resulted in aproduction curve that continued the previousdecline rate (left). The difference between thenonfractured case and the measured productionindicates the success of the fracture job. Over aseven-month period, the cumulative productionattributed to the fracture job was 256 million ft3

[7.25 million m3] of gas and 15,300 bbl [2,430 m3]of condensate. This modeling study verified thesuccess of a field application.

24 Oilfield Review

> History-match of model of SW Rugeley field with a hydraulic fracture. The ECLIPSE 300 model of one well in the Frio sand has small grids around thewell and along the fracture (top left). Smaller grids were also placed at the fracture tips. The field gas-rate history was matched by the simulation (tt topright), yielding good results for condensate rate (tt bottom right). The changes in production after the fracture job were due to fracture cleanup andttchanges in pressure in flowlines. The model indicated the average reservoir pressure dropped below the 6,269-psi dewpoint pressure during thisproduction period (bottom left).tt

Fracture Well

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> The hydraulic fracture effect. Rerunning the Frio well model with no fracture generated a simpledecline curve indicating a significant productivity increase could be attributed to an induced fracture.

Mar2002

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Production historyModel with no fracture

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Winter 2005/2006 25

2,500

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< C d bl k dCondensate blockage around afracture, Frio model. For each timestep, model results indicatepressure decline (top), condensatesaturation (middle) and gas relativepermeability (bottom). The first twottime steps in July 2002 (left) focustton the immediate vicinity of thefracture and the later three timesteps (below) show a wider viewwof the whole model area. Pressuredeclines rapidly along the fracture(left, top). The approximate dewpointpprofile (oval curves) expands outwardfrom the fracture. The low gaspermeability around the fracture at later time steps indicates thecondensate blockage.

Application of Best PracticesChevron recently completed a study of five gas-condensate reservoirs that are at differentstages of development. The objective was totransfer best practices among variousdevelopment teams.

One of the fields in the study, a North Seareservoir, is a marine turbidite with gross-payinterval of more than 120-m [400-ft] thickness.The average reservoir permeability is 10 to15 mD, with average porosity of 15%. Theoriginal reservoir pressure of 6,000 psi[41.4 MPa] is a few hundred psi [a few Mpa]above the dewpoint pressure, although thedewpoint varies from east to west.32

The bottomhole pressure was below thedewpoint from first production. Thecondensate/gas ratio ranged from 70 bbl permillion ft3 [393 m3 per million m3] in the east to110 bbl per million ft3 [618 m3 per million m3] inthe west. Some wells experienced a productivityreduction of about 80%, most of which occurredin early production.

Chevron followed a step-by-step procedure tounderstand and history-match the field’s gas-condensate behavior. The operator selected coresamples that spanned the range of permeabilityand porosity of the field and fluids that mimicreservoir-fluid behavior—liquid dropout as afunction of pressure, viscosity and interfacialtension—at lower temperature. The companymeasured relative permeability over a rangeof flow conditions and fitted those datato several relative-permeability models for usein simulators.

A spreadsheet using an analyticalpseudopressure method was used to calculatedeliverability. The calculation showed thatproductivity index (PI) decreased from about 80 to about 15 thousand ft3/d/psi [33 to 6 thousand m3/d/kPa], with little differencebased on bottomhole pressure until late in fieldlife (above).

A detailed single-well, compositional flowsimulation using the Chevron CHEARS reservoirsimulator was performed with realistic geology.Far-field boundary conditions came from a full-field model. The simulation honored wellproduction practices and differential depletionin the field. The predictions provided a goodmatch to results from three vertical wells andone inclined well (next page).

This study led to several initiatives in thefield. Hydraulic fracturing to improveproductivity is an active effort in this field, sothese models are being used to betterunderstand fracture effectiveness. In addition,lessons learned from this field regarding theimpact of condensate blocking have been usedextensively in planning for wells in new projectsin other gas-condensate fields.

A Fundamental AlterationThe high price of natural gas on world marketsin recent years has stimulated interest indeveloping gas reservoirs. Companies seek newways to optimize their gas-condensate resources.

Hydraulic fracturing can mitigate the effectof condensate blockage, but it does noteliminate the accumulation of condensate in

26 Oilfield Review

> Spreadsheet model results for a North Sea well. A homogeneous single-well model in a spreadsheetprovided a way to quickly examine different effects. For example, the bottomhole pressure had littleeffect on gas productivity index, PI.

0

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32. Ayyalasomayajula P, Silpngarmlers N and Kamath J:“Well Deliverability Predictions for a Low PermeabilityGas Condensate Reservoir,” paper SPE 95529, presentedat the SPE Annual Technical Conference and Exhibition,Dallas, October 9–12, 2005.

33. Fahes M and Firoozabadi A: “Wettability Alteration toIntermediate Gas-Wetting in Gas/Condensate Reservoirsat High Temperatures,” paper SPE 96184, presented atthe SPE Annual Technical Conference and Exhibition,Dallas, October 9–12, 2005.

34. Kumar V, Pope G and Sharma M: “Improving Gas andCondensate Relative Permeability Using ChemicalTreatments,” paper SPE 100529, to be presented at the SPE Gas Technology Symposium, Calgary, May 15–18, 2006.

Winter 2005/2006 27

areas where the pressure in the formation isbelow dewpoint. Dry gas and solvent injectionsare able to mobilize some condensate, but theliquid saturation profile near a producing wellreforms and the blockage effect returns.

New alternatives are being examined inlaboratories. For example, some studies havefocused on ways to prevent fluid buildup byaltering reservoir-rock wettability.

Although mineral surfaces such as quartz,calcite and dolomite prefer to be wetted byliquids rather than gas, there are solids thathave a gas-wetting preference. In particular,fluorinated compounds such as Teflon surfacesare gas-wetting. So, fluorinated solvents havebeen used to alter the wettability of cores.Recently reported results at high temperature—140°C [284°F]—typical of gas-condensatereservoirs showed a strong reversal of wetting ina gas-water-reservoir rock system, but was lesssuccessful in a gas-oil-reservoir rock system.33

Researchers at the University of Texas atAustin conducted laboratory tests using 3Mfluorocarbon surfactants.34 The results onreservoir core samples blocked by condensateindicate about a doubling of the gas andcondensate relative-permeability values aftertreatment. Based upon these promisinglaboratory data, Chevron may test this treatmentin a blocked gas-condensate well sometime in2006. Treatments such as these must be fieldtested under a variety of conditions to fullydevelop and prove the technology. If thetechnique is ultimately successful, then the costof the surfactants used in the treatment will bevery small compared to the benefits of increasedgas and condensate production rates.

The alteration these solvents make in therock addresses a fundamental cause ofcondensate blockage: capillary accumulation ofliquid because of the wetting preference of therock. Avoiding liquid buildup alleviates theproblem of choking production, so that a highproduction rate can be achieved. —MAA

> Single-well simulation results. The simulator gave a good match to bothgas PI (top) and bottomhole pressure (middle) for behavior in a North Seawell. Different layer properties resulted in different extents of condensatesaturation buildup (bottom).

Gas

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3.5 4.0 4.5 5.0 5.5

3.5 4.0 4.5 5.0 5.5