16 Oilfield Review

The Giant Karachaganak Field,Unlocking Its Potential

Steve ElliottH.H. HsuTerry O’HearnIan F. SylvesterRicardo VercesiKarachaganak Integrated OrganizationLondon, England, UK

For help in preparation of this article, thanks to TomOlsen, Dowell, Aberdeen, Scotland; Keith Rappold,Schlumberger Oilfield Services, Sugar Land, Texas, USA;and Daniel Ugwuzor, Schlumberger Oilfield Services,Luanda, Republic of Angola.StimCADE is a mark of Schlumberger.

Karachaganak, one of the world’s largest gas condensate reservoirs,

requires an innovative team approach to maximize field potential. Its

remoteness, complex carbonate structure and perplexing fluid behavior

present both obstacles and opportunities for production optimization.

The Karachaganak field of northernKazakhstan, under production for the last fif-teen years, imposes major challenges inreservoir characterization and productionoptimization on the international teamcharged with developing the giant conden-sate accumulation. The KarachaganakIntegrated Organization (KIO) DevelopmentTeam, comprising technical experts fromAgip, BG, Texaco and Lukoil, is responsiblefor devising a field production strategy thatwill make the most of the complex carbon-ate structure. Constructing structural andstratigraphic models and understanding thebehavior of the reservoir fluids are keys tothis problem. This article describes the infor-mation available to the team and discussesthe approaches being taken to maximizerecovery of Karachaganak reserves.

Land of the GiantsThe Karachaganak field lies on the northernmargin of the Pre-Caspian basin, the prede-cessor of the Caspian Sea, 150 km [93 miles]east of Uralsk, Kazakhstan (next page). Thesediments in the 500,000-km2 [193,000 sq-mile] basin are up to 22 km [14 miles] thick,with a salt layer dividing the volume intosubsalt and suprasalt sections.

Hydrocarbon exploration has been activein the suprasalt section of the Pre-Caspianbasin since the early 1900s: about 80 small,mainly oil fields were discovered, but arenow almost depleted. Subsalt explorationbegan only in the 1970s. Since then, discov-ery of the giant fields such as Karachaganak,Tengiz and Astrakhan has placed the Pre-Caspian among the richest oil and gas basinsin the world.

Autumn 1998 17

Quantifying reserves and optimizingrecovery from these fields require an overallunderstanding of the basin and its architec-ture. Drilling into the subsalt has beenconfined mainly to the margins of the basin,and in some parts there exist seismic sur-veys. These and a knowledge of the regionalgeology have helped to construct a vision ofthe basin that is guiding exploration andproduction efforts.

Field HistoryKarachaganak itself was discovered in 1979and began production in 1984 under theoperatorship of Karachaganakgazprom, asubsidiary of Russia’s GazProm. Kazakhgas,the Kazakhstan state gas company, took overoperatorship when Kazakhstan became asovereign state in 1992. Agip and British Gasformed a contractor group after beingawarded sole negotiating rights to the field in1992. Texaco and Lukoil joined this group inMarch 1995 and signed a ProductionSharing Agreement (PSA) with the Republicof Kazakhstan in November 1997. The PSAbecame effective in January 1998.

The field is located near the borderbetween Kazakhstan and Russia in a low-lying, almost flat area noted for its arablefarming but traditionally considered part ofthe steppes. The region is characterized byhot summers, cold winters and short springs

Caspian Sea

Car

bona

tepl

atfo

rmm

argin

Carbonate platform

To SamaraTo Orenburg

To Black Sea

Astrakhan

Basinmargin suture

Tengiz

Zhanazhol

UralskKarachaganak

VOLGA–U

RAL PROVINCE

CENTRAL DEPRESSION

0 250

0 400mileskm

■■Karachaganak field,now being developed by BG, Agip, Texacoand Lukoil. Currently,produced fluids arepiped 130 km for pro-cessing and distributionto Orenburg, Russia. In the future, separatedand stabilized oil will be sent, via a connector,to the Caspian PipelineConsortium pipeline.[Map adapted fromCook HE, Zhem-chuzinikov VG,Buvtyshkin VM, GolubLY, Gatovsky YA andZorin AY: “Devonian and Carboniferous Pas-sive-Margin CarbonatePlatforms of SouthernKazakhstan: Summaryof Depositional andStratigraphic Models toAssist in the Explorationand Production ofCoeval Giant CarbonatePlatform Oil and GasFields in the NorthCaspian Basin, WesternKazakhstan,” in Pangea:Global Environmentsand Resources, CanadianSociety of PetroleumGeologists, Memoir 17.Calgary, Alberta,Canada: CanadianSociety of PetroleumGeologists (1994):363–381.]

KazakhstanMoscow

IranBolshoi mountains

18 Oilfield Review

and autumns. The severe continental cli-mate, with wind blowing constantly, makesoperating conditions very difficult (above).From November to March, with tempera-tures regularly around –40°C [–40°F], theground is frozen and travel is hazardous.Crews have to fly to Uralsk using a charterairline. During the spring thaw and afteroccasional rain showers, the soil turns toheavy, sticky mud and roads are regularlywashed out, so roads in the field have to bebuilt up onto banks several meters high. Thesummer months, by contrast, are noted fortemperatures in excess of +40°C [140°F].

Currently, the operating team uses existingbuildings for both accommodation andoffices in the nearest support town, Aksai,over 30 km [19 miles] away. Plans are afootto develop a new camp site to provide mod-ern working and living facilities for a staff of200 expatriates and 600 local residents.

The 1979 discovery of the field resultedfrom drilling to confirm a structural highdetected during reinterpretation of 1970 to1971 vintage 2D seismic data. Extensiveappraisal drilling resulted in the identificationof the huge Permian-Carboniferous reef com-plex measuring 30 by 15 km [19 by 9 miles](next page). The crest of the structure is rec-ognized at 3500 meters subsea (mss), the gas-oil contact at 4950 mss and the oil-watercontact at 5150 mss. This provides a gas col-umn of over 1450 m [4757 ft] and an oil col-umn of 200 m [656 ft], with hydrocarbon inplace of 1.2 Tcm [42.4 Tcf] gas and 1 billiontonnes [0.1 billion tons] of liquids.

It is hardly surprising therefore thatKarachaganak is ranked as one of the largestgas condensate fields in the world and isexpected to produce far into the next cen-tury. The field consists of a carbonate massif,the structure and stratigraphy of which havebeen documented in several publications.1

The formations are heterogeneous, espe-cially the uppermost reservoir in the Permian.The average reservoir permeability is 2 mDwith 9% porosity, 40% net/gross ratio and awater saturation of only 10%. Initial reservoirpressure was 52,000 to 59,500 kPa [7547 to8630 psi] and the field temperature rangedfrom 70 to 95°C [158 to 203°F].

Hydrocarbon production began in October1984, initially from three wells penetratingthe Permian. An oil and gas separation plantwas installed to treat the oil and gas for trans-fer by pipeline to the Orenburg processingplant located 130 km [80 miles] north inRussia. In 1984 the pilot production planlimited production operations to partialseparation and dewpoint control with all sub-sequent stages of processing at Orenburg.The condensate delivered is approximately47 degrees API and contains a high mercap-tan content of 1700 ppm.2 Also, the gas isdifficult to handle as it is sour, averaging 3.5 to 5.0% hydrogen sulfide [H2S] and 5.5%carbon dioxide [CO2]. The hydrocarboncomposition varies with depth.3

The previous development plan, created byVNIIGaz, called for full voidage gas reinjec-tion to maintain the reservoir pressure abovethe dewpoint pressure. Since then, this dew-point restriction policy on production wellshas been maintained by the KazakhstanMinistry of Geology and Protection ofNatural Resources.

During the pilot production phase, produc-tion rose steadily as more wells were broughton-stream to reach a plateau rate of 155 Bcf/yrof gas and 100,000 B/D of liquid in 1990. Theplateau lasted for two years until a gradualdecline began in mid-1992. The field isexpected to produce 2.0 Mt of liquids in1998. There have been 252 vertical produc-tion wells drilled on the field, but the currentmaximum number of active wells on produc-tion is only 36. Because of technical difficul-

ties associated with drilling to depths of 6500m [21,330 ft], very few of these wells pene-trated as far as the Middle Devonian.However, hydrocarbons from the MiddleDevonian have flowed to surface on test, so itis an important appraisal target for the KIOReservoir Team.

The Development Plan Karachaganak has a large number of devel-opment options and challenges due to itsremoteness, size and fluid composition. Thedistance of the field from western markets isperhaps the greatest challenge for KIO. SinceKarachaganak is already partially developed,the development plan calls for the comple-tion, refurbishment and improvement of exist-ing facilities as well as the construction ofnew facilities. When completed, the field willbe equipped with wells, facilities and pro-cessing capabilities, which will increase pro-duction to maximum liquid and gas rates of13,000 tons/yr and 883 Bcf/yr by 2005 and2010, respectively.

While the previous development plan ofVNIIGas was based on full injection of gasafter the extraction of liquids, the currentdevelopment plan calls for injecting 10 Bcm/a353 Bcf/yr] of sour separator gas by the year2010, making the balance of the gas availablefor export. Injection will initially take place ina southeastern part of the Carboniferous reser-voir. Current development plans envision that40% of the total produced gas will be rein-jected over the 40-year term of the PSA.

The KIO Reservoir Team is working withNIPIMunaigas, a Kazakh technical institute,to develop a new technological scheme forthe development of the Karachaganak field.

1. Bagrintseva KI and Shershukov IV: “Models of the Distribution of Different Types of CarbonateReservoirs in Oil and Gas Fields of the Pre-CaspianDepression,” Abstracts, American Association ofPetroleum Geologists Annual Convention, vol. 6.Tulsa, Oklahoma, USA: AAPG (1997): A6.Bodden WR III, Sherman GX, Yugai TA, Savvin VA and Votsalevsky ES: “Karachaganak Field, PrecaspianBasin, Kazakhstan,” Abstracts, American Associationof Petroleum Geologists Annual Convention, vol. 6.Tulsa, Oklahoma, USA: AAPG (1997): A12.Grigor’yeva VA, Zul’pukarova NT, Ivanova MM andKolesnikov AF: “Geology of Karachaganak Field andTasks for Bringing it Onstream,” Petroleum Geology29, no. 1-2 (1995): 8–15.Kononov YS: “The Carbonate Massif of TheKarachaganak Field,” Petroleum Geology 23, no. 7-8 (1989): 287-291.

2. Mercaptans are pungent-smelling sulfur compoundsthat occur in natural gas and are sometimes used toadd odor to refined gas.

3. Perepelichenko VF, Shilin AV and Rovenskaya AS:“Gigantic Hydrocarbon Fields of Pre-Caspian Basin—Aspects of their Distribution, Features of Explorationand Development,” Abstracts, 58th Conference andTechnical Exhibition of the European Association ofGeoscientists & Engineers, Amsterdam, TheNetherlands, June 3-7, 1996, A042.

■■Karachaganak field operating conditions.A remote location and harsh conditions,including extreme variations in seasonalweather, make production operationsdifficult and challenging.

Autumn 1998 19

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C1t

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C - Carboniferous

D - Devonian

kg - Kungurian ar - Artinskian s - Sakmarian a - Asselian

s - Serpukhovian v - Visean t - Tourmaisian

fm - Famennian

■■Structural cross sections through the Karachaganak field showing the buildup associated with the Permo–Carboniferous reef complex.The flanks of the structure are overlain by salt so imaging them seismically is difficult. Consequently, the new 3D seismic acquisitionprogram being planned for 1999 may lead to a different interpretation of the flanks.

20 Oilfield Review

Optimizing Karachaganak OperationsThe team is actively evaluating suitablemethods for stimulating production fromKarachaganak and in 1997 collaboratedwith Schlumberger on a pilot stimulationprogram whose aim was to increase fieldproductivity from 50,000 to 70,000 B/D[7945 to 11,125 m3/d]. Initially, 10 wellswere chosen and a program consistingprimarily of matrix acidizing to reduce thehigh skin was carried out in the summer and fall of 1997.

The first part of the pilot stimulation pro-gram involved using coiled tubing to cleanout the wells and spot hydrochloric acid at alow rate (0.6 bbl/min) across the long payinterval. The matrix acid was then bull-headed into the formation at a rate of 5bbl/min, and the first wells saw a substantial400% increase in productivity index,although much of the surface productionincrease was tempered by current tubingrestrictions (above). This success was veryencouraging. However, the extremely largezones did cause a problem for conventionalbull-headed acid jobs. As soon as the acidopened up a section of the damaged zone,that zone absorbed all the remaining acid.Also, high-permeability streaks within thepay zone inhibited total interval stimulation;the acid flowed preferentially into certainzones and did not open the entire interval.

Next the team focused on diversion tech-niques to achieve more effective acidization.In many of the Karachaganak wells, the qual-ity of the cement bond behind the casing isunknown. Thus, diversion techniques wouldhave to take into account the possibility ofacid channeling behind the casing throughthe cement and not into the formation. The

aggressiveness of the diversion programwould then be a function of the connectivityof the reservoir. If the reservoir intervals areseparate, then each interval would need tobe stimulated individually to tap the oil.Ideally, the wells would be worked over andvertical conformance testing performed withpackers to determine vertical permeability.Such tests would help determine reservoirconnectivity. However, as workovers areexpensive, the stimulation program was per-formed through tubing.

The first trial step in the diversion programinvolved the use of self-diverting acid pumpedat a high rate—exceeding 30 bbl/min. This type of gelled acid etches wormholes intothe carbonate formation, but as the acid isspent, pH increases, causing the fluids tocrosslink and thicken. The acid’s viscosityincreases, thereby temporarily shutting off thewormhole and diverting the fresh acid toother damaged areas in the formation.

Finally, the diversion program evaluatedmechanical diverters, such as ball sealers orcoiled tubing injection with through-tubinginflatable packers. Alternatively, a fullworkover may be necessary to run straddlepackers or fullbore packers and bridge plugsto isolate zones.

The combination of mechanical and chem-ical diversion techniques has helped toimprove the production stimulation programand achieve the desired production targets.Simulations using StimCADE well stimula-tion software are now being run to match theresults of the damage removal from the pilotacidizing program with the modeled jobdesigns. Mechanical and particulate diver-sion techniques are also being modeled todetermine additional means of removing theskin from the wells.

Another option under consideration for thefuture is acid-etched fracturing. The acidfracs would bypass the deep-penetrating for-mation damage, which is difficult to removeby the radial flow of matrix acidizing. Acidfracs also allow stimulation of lower perme-ability intervals and can attain significantnegative skins to improve production. Thesejobs are not perfect, however, and withoutmechanical diversion, the fractures tend toinitiate in the high-permeability streaks,leading to suboptimal conformance.

Another potential problem is control offracture height and placement. In order toprevent gas cusping—analogous to waterconing—into the oil zone, the team willneed to ensure that the fractures do notextend beyond 200 m [656 ft]. In fact, it maybe technically less risky to drill horizontaldrainholes because the risk of gas cusping isreduced as gas is injected or liquid is pro-duced. Cusping may become an evengreater problem as gas is reinjected.

Similarly, modern horizontal well technol-ogy could be used to optimize productionfrom the 200-m thick Carboniferous oil rim.One approach would be to use existing verti-cal wells as starting points for horizontaldrainholes. For this purpose it is important toknow the condition of the wells, so anotherpart of the Karachaganak project involves astudy of the mechanical state of the wells.Initially, all well log data such as cement bondlogs are being analyzed for rock mechanicsinformation to characterize the rock proper-ties. Also, all datum depths are being verified,because it is crucial to know the precise spa-tial extent of one well if another horizontalwell is being drilled nearby.

Reservoir Characterization ChallengesPrevious 2D mapping and detailed litho-stratigraphic and chronostratigraphic studiesof the Karachaganak field by Agip and BritishGas geologists in 1992 produced a layer-cakemodel. This was done by correlating “poros-ity packets” interpreted from wireline logdata and using the original reservoir rock-type classification scheme based on five rocktypes. Since 1992, advances in sequencestratigraphy and 3D reservoir modeling tech-niques now enable a more realistic reservoirdescription incorporating all the availablecore, log, seismic and performance data.

Cores promise to reveal a great deal aboutreservoir quality and facies distribution.Much of the original sedimentary fabric isreported to have been preserved, despitelocally extensive dolomitization of thecarbonate reservoir. One of the keys to reser-voir model development will be locatingoriginal core from the field. At least 52 wells

Abs

olut

e pr

essu

re, k

Pa

0

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Post-acidproduction

IPR

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Oil rate, m3/d

History-Matched Delta Skins from Well 621 Total Skin Before = 75, Post-Acid Skin = 18

■■Increase in production after stimulation. Production rate before stimulation is plotted atthe intersection of the two pink curves. The rate after stimulation appears at the intersec-tion of the pink and purple curves.

Autumn 1998 21

were cored early in the life of the field and approximately 1800 to 2500 m [5900 to 8200 ft] of core were collected.Unfortunately, the cores were not continu-ous, and core recovery was not consistent.Additionally, through the years, the coreshave been divided and distributed to a num-ber of institutions in Russia and Kazakhstan.The KIO reservoir team plans to recover thecore to enable detailed interpretation ofwhole well cores. The team understands thatmuch work has been completed in the pastand plans to ensure that past studies areincorporated into the present work and thatlocal experts in Kazakh institutes are closelyinvolved in the field development.

The cores may also be useful for answeringan important question about the role playedby fractures and faulting in the production ofhydrocarbons from Karachaganak. In theexisting 2D seismic datasets, significantfaults have not been identified in thePermian-Carboniferous reservoir, yet theyare recognized in the Middle Devonian. Thereservoir team has not seen compelling argu-ments for fracture support in the past pro-duction history of the field and can accountfor existing production rates through matrixsupport from the low-permeability, 1650-m[5414-ft] thick reservoir. However, until thecores have been studied in detail, the team iskeeping an open mind on the issue. Localexperts have indicated the possibility of frac-tures in their interpretations of well logs, butthere are only limited borehole images avail-able that could cast some light on the issue.

Currently, the largest contribution to thegeological database for modeling the fieldcomes from electric logs taken in 173 wells.In only one well, K818, have both “western-style” and “Russian-style” logs been run.Even so, this single occurrence of dual log-ging has enabled an algorithm to be createdthat relates western rock property measure-ments to Russian log values and ratios (see “Comparing Schlumberger and RussianWell Logs,” page 22). Consequently, the large quantity of older Russian log data wasusable in producing rock property distribu-tions and the present reservoir model forKarachaganak. In the well deepening thatwill occur with further development of thefield, there will be a number of opportunitiesto run new sets of both Russian and western-style logs including borehole imaging tools.

Construction of a detailed digital 3D reser-voir and visualization model will thereforeconsist of a number of stages:• Collection, repatriation, description and

interpretation of the cores

• Development of modern genetic sedimen-tary units within a sequence stratigraphicapproach

• Integration of petrophysical, geologicaland seismic data

• Creation of a 3D stochastic geologicalmodel (above)

• Upscaling for reservoir simulation anddevelopment planning.

4950 GOC

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■■Examples of two vertical cross sections through the Karachaganak field showing thedistribution of porosity according to a multilayered model. Note the heterogeneous natureof the units.

22 Oilfield Review

In order to make independent estimates of

reserves, and to determine or predict how the

Karachaganak reservoir might perform, Russian

and Schlumberger logs were run in the same well,

K818 (right). This operation allowed Russian logs

to be calibrated against Schlumberger logs, which

are in turn calibrated against known standards for

rock and fluid properties.

In general, there is good agreement between

the Russian and Schlumberger log curves. The

exception is the neutron curve: in most intervals,

the Russian logs read 2 to 5 porosity units higher

than the Schlumberger curve, reflecting the algo-

rithm used to convert Russian curve counts to

porosity. Hole conditions are reported to be good,

as revealed by an excellent caliper response.

Effective porosity curves from the neutron/sonic

crossplots are presented in the far right-hand

track. Despite the different ways in which Russian

and western experts interpret the meaning of effec-

tive porosity, neutron/sonic crossplot porosities

compare much more closely than do the raw neu-

tron curves.1 Porosities from the Russian logs were

then calibrated, using an algorithm developed

from K818 relationships, against western logs.

As a result of this comparative study, and other

‘back-to-back’ well log evaluations,2 considerable

confidence was gained in the Russian logs and

logging contractors, to the extent that calibrated

Russian logs from the remaining 170 wells in

Karachaganak could be used to obtain valuable

reservoir parameters for mapping, modeling and

reserve estimation. In addition, these results

showed that a substantial new log acquisition pro-

gram was not required, and that operational cost-

savings could be made by using local contractors.

Comparing Schlumberger and Russian Well Logs

GRAPI–Schlumberger0 200

LLDohm-m–Schlumberger

Depth,

m

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DTMµs/m

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DTMµs/m–Russian300 100

NPHLLS–Schlumberger0.4 –0.1

NPHLLS–Russian0.4 –0.1

PHIESchlumberger0.4 –0.1

PHIERussian0.4 –0.1

GKRussian0 10

■■Russian and Schlumberger log responses for Karachaganak Well K818. Schlumberger curves and headersare in blue; Russian curves and headers in red. Reading from left to right, the curves are as follows. Track 1: gamma ray. Track 2: laterolog resistivity (LL) and deep laterolog resistivity (LLD). Track 3: sonic logs.Track 4: neutron porosity (limestone matrix). Track 5: neutron/sonic crossplot porosity.

1. Moss B and Stocks A: "Log Interpretation Methods in theFormer Soviet Union," in Harrison R (ed): Russian-StyleFormation Evaluation: London, England: LondonPetrophysical Society (1995): 175–182.

2. Kennedy M: "A Direct Comparison of Western and RussianPorosity Logs," in Harrison R (ed): Russian-StyleFormation Evaluation: London, England: LondonPetrophysical Society (1995): 187–191.

Autumn 1998 23

The Fluid ModelThe Karachaganak field is considered tohave a range of fluids and fluid behavior thatis uniquely complex, so a thorough under-standing of these properties is essential tomodeling the behavior of the field and plan-ning its development in the future.4

The reservoir hosts a gas condensate fluidsystem grading from “rich” at the structuraltop of the reservoir to “extremely rich” and“black oil” at the bottom. The initial pressureand temperature of the system place it in thecategory of “retrograde gas condensate”behavior: when production causes the pres-sure to drop below the saturation pressure—acondition called the dewpoint—condensateliquid will condense from the gas phase. Theproperties of such a fluid, especially its mobil-ity, and the effects on well productivity duringproduction below the dewpoint, are underdebate within the technical community. Thiswill be discussed in more detail in the nextsection (see “Production Below theDewpoint,” page 24).

The ratio of gas to liquid varies with depththroughout the reservoir. At the top of thePermian, for example, the gas/liquid ratio(GLR) is about 2000 scm/scm, at the gas-oilcontact (GOC) it is 800 scm/scm and at thebase of the oil leg in the Carboniferous theratio has dropped to 200 scm/scm. There is acontinuous and steady compositional grada-tion between these points, as can be seen inthe decreasing GLR (above right), thedecreasing API of the product liquids (right)and by the variation in dew- and bubblepointwith depth (below right). In fact, there is nodistinct boundary between the gas conden-sate and oil legs of Karachaganak, and at thegas-oil contact zone the reservoir fluid isclose to the critical point. This means that thegas and oil have very similar compositionsand there are no sudden changes in fluidproperties as gas condensate becomes oil. Infact, the formation pressure would have todrop by 20% for a heterogeneous fluid sys-tem to appear.

A large amount of data on reservoir andsurface liquids was available from earlierSoviet sources, which allowed Agip and BGto develop a robust fluid model for the reser-voir. Field data available to the companiesincluded: historical produced gas/liquidratios; drillstem test (DST) data for explo-ration and production wells plus associatedlaboratory studies; and well test data on pro-duction wells. Karachaganakgazprom gener-ated these data and the Agip-BG group wasable, in addition, to conduct several “western

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■■Variation of gas/liquid ratio with depth. Practically speaking, the boundary betweenthe oil and gas condensate zones is a continuum and is marked as a transition zone.

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■■A steady variation in dewpoint and bubblepoint with depth. At the boundarybetween the gas and oil legs, the reservoir pressure is close to the critical point,resulting in a very smooth transition between fluid compositions of the different legs.

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■■Variation of API with depth. API decreases gradually from 48° in the gas condensateleg to 26° at the base of the oil column, but there is no obvious boundary between thetwo layers, reflecting a continuum as the gas/liquid ratio varies with depth.

4. Wheaton R: ”Characterisation and DevelopmentPlanning for a Giant Gas Condensate Field,” pre-sented at the Optimisation of Gas Condensate FieldsConference, Aberdeen, Scotland, June 26–27, 1997.

24 Oilfield Review

standard” DSTs and pressure-volume-tem-perature (PVT) experiments at the Agip andBG laboratories.

Integrating the field-observed GLR variationwith depth and the experimental PVT resultsallowed development of the equation of state(EOS) for the fluid model. GLR changes withdepth were considered to be “primary” datasources, while the laboratory-derived reser-voir fluid data such as saturation pressures,liquid drop-out and compositions were con-sidered to be a “secondary” data source sincethey depend on the accuracy of recombina-tion of surface fluids.

However, there are a number of difficultiesin measuring GLRs for a gas condensate-volatile oil system when the reservoir exhibitsa high degree of heterogeneity. In these cir-cumstances, pressures around the wellboremay drop below the saturation pressure whenthe well is flowed and therefore change theGLRs. This sensitivity to changes in tubing-head pressure and thus to flow rate producesGLRs that can be substantially above orbelow the “true” initial GLR. This is particu-larly true in the Permian because of the lim-ited drainage volumes and connectivitybetween wells. Inaccuracies in GLRs can alsoresult from practical difficulties such as poortemperature control or exceeding the capac-ity of the separator. However, the effects ofthese potential problems were all carefullyconsidered and accounted for when analyz-ing the available GLR data.

The GLR data were used in conjunctionwith the PVT experimental data to develop a12-component EOS fluid model thatmatched saturation pressures, liquid drop-out and surface densities at all depths fromwhich samples were collected. To increaseconfidence in the compositional trends withdepth, the validity of the fluid model waschecked in a series of field tests in 1996. Inall cases the fluid property model was deter-mined to be reliable.

Production Below the DewpointWhen a retrograde condensate fluid isproduced below the dewpoint, a liquid-condensate phase forms. It was commonlybelieved that allowing reservoir pressure tofall below the dewpoint could significantlylimit reservoir performance and ultimaterecoveries of liquids and gas. However, thereare now strong technical arguments and fieldanalogies that can support a productionstrategy which yields efficient recoveries atpressures below the dewpoint. The low inter-facial tension and the offsetting effects ofhigh flowing velocities near the wellboreand improving fluid properties at lower pres-sures may negate the reduction of effectivegas permeability.

Historically, the industry has employedpressure maintenance techniques—cyclingproduced gas through the reservoir—tomaintain reservoir pressure above the dew-point. This was due to mobility concerns andother factors such as the lack of a gas market.A review of literature shows that as early as1947 Standing et al presented a differentview of the need to maintain pressure abovethe dewpoint.5 They stated, “The recovery ofthe heavier components from a gas cap orretrograde pool is shown to be the greatestwhen the sand is cycled with a dry gas at alow pressure. This conclusion is in directopposition to the belief that the most effi-cient production program is pressure mainte-nance and cycling at or near the dewpoint.”

Weinaug and Cordell reported on revapor-ization studies in 1948.6 They stated, “A studyof the behavior of retrograde condensationfrom gas mixtures was made in the presenceand absence of sand in order to determine ifthe condensed liquid would revaporize in thepresence of sand. The data obtained for thissystem also show that equilibrium is main-tained at all times during the pressuredecline. These results indicate that revapor-ization is aided rather than prevented by thefact that the condensate wets the sand.”

In 1967 Havlena et al reported on theirstudy of cycling at declining pressures in theWindfall field.7 They addressed the issue ofrevaporization and concluded, “Cyclingcondensate reservoirs under conditions ofdeclining pressure rather than constant pres-sure is advantageous both from a recoveryand an economic standpoint. By operating atdeclining pressure, the wet gas displacedfrom the swept areas is recovered concur-rently with wet gas recovered by expansionfrom the unswept portions of the reservoir.Any liquid condensed in the swept areas isrevaporized by dry injection gas and recov-ered as an enriched gas.”

In 1983 Aziz gave a critique of gas cyclingand in his discussion of factors affectingrecovery efficiency he noted, “It is veryimportant to closely define reservoir hetero-geneity in order to predict the performanceby cycling a gas-condensate reservoir.”8

This applies especially to numerical mod-eling. Aziz discussed revaporization of con-densate and reminded the reader of thework of Standing et al. He stated, “A popu-lar concept prevailing until the sixties wasthat any liquid condensed in the reservoir bypressure reduction would be lost forever.Standing et al had presented an oppositeconcept in 1946. However, the possibility ofrevaporization of condensate with dry gasinjection was ignored as a viable process.

The increasing price of gas forced opera-tors to make a thorough study of the cyclingprocess. As a result of these findings and theincreased price of gas, the previous cycle ofgas production, condensate stripping, gasreinjection with makeup gas followed byblowdown and gas sales only has beenmodified. Net present worth of a gas-condensate reservoir can now be maximizedby an optimal amount of gas and condensatesales right from the start.” Essentially, Azizemphasized the economic aspects of gas-condensate reservoir operations.

These quotations by leading reservoir engi-neers show that production below the dew-point with gas injection does not cause thelarge-scale loss of condensate that was pre-viously anticipated. The volume of gasinjected will depend upon an optimizationof technical and economic conditions rele-vant for that field.

The development strategy for Karachaganakis designed to efficiently recover hydrocar-bons from each distinct producing horizonusing state-of-the-art technologies such as 3Dreservoir characterization and horizontaldrilling. The dewpoint is only an issue in theCarboniferous, where gas reinjection isplanned. Heterogeneities in the Permian willnot support reinjection, while the volatile oil rim will be developed using horizontalwells. Staged reinjection is planned in theCarboniferous with extensive monitoring todetect mobility losses should they occur. Thistargeted development plan—along with tech-nical arguments, field analogies and contin-ual laboratory testing—will guide thereservoir development.

To investigate the phenomena of conden-sation and condensate mobility below thedewpoint, BG Technology performed severalexperiments at their London ResearchStation in England. Soon after, BGTechnology relocated in 1994 to the pur-pose-built Gas Research and TechnologyCentre in Loughborough, England. BGTechnology completed additional experi-ments to measure the interfacial tension (IFT)of the condensate at pressures below thedewpoint and measured the relative perme-ability of gas and condensate at various pres-sures below the dewpoint.

An important benefit for the Karachaganakdevelopment is that the fluid is near-criticalin the lower section of the gas leg. The fluidEOS model predicted low IFT in the near-critical fluid, which increases the pseudo-pressure, offsetting a reduction in relativepermeability caused by liquid drop-out. TheEOS model prediction of low IFT was con-firmed by BG Technology’s laser IFT rig thatmeasured IFT values at reservoir conditionsas low as 0.08m N/m at more than 6900 kPa

Autumn 1998 25

[1000 psi] below dewpoint pressure. Thisresult indicated that condensate thatdropped out of the gas phase would still bemobile within the given pressure range.

Further laboratory experiments carried outunder reservoir conditions involved deposit-ing condensate onto core samples by reduc-ing pressure below the dewpoint. Flowingequilibrium gas through the core and mea-suring gas and liquid flow rates demon-strated that liquid mobility continued wellbelow the dewpoint with residual conden-sate saturation still at only 5% at 6900 kPabelow the dewpoint. Agip also conductedgas injection experiments on the oil leg todetermine the alteration of the bubblepointas lean gas is injected.

Based on the results of the experimentalprogram, Agip and BG proposed a fieldexperimental program to evaluate the labo-ratory phenomena under field conditions. InAugust 1995 Agip and BG signed a protocolwith the Republic of Kazakhstan Ministry ofOil and Gas and Ministry of Geology andProtection of Natural Resources to allow sixwells to be produced below the dewpoint toa pressure of 410 bar to test the laboratoryresults. These wells have been on productionsince, and no reduction in condensate/gasratio (CGR) has been observed. It has beenagreed with the Kazakh technical governingbodies that condensate mobility in the pro-ducing wells of the field trial is not adverselyaffected for drawdowns consistent with thepressure drops applied during the laboratoryexperimental program.

The KIO reservoir team has receivedapproval to add more wells to the dewpointtrial well stock during 1998 to drawdown thewells even further below the dewpoint toobserve the effect on the CGR. To assist inthe field experiment program, equipmentthat will allow continuous monitoring of theCGR ratio will be applied to the dewpointwell stock.

Additional plans call for conducting furtherreservoir-condition laboratory measurementsof IFT and gas-condensate relative permeabil-ities to support the field experiment program.

3D Seismic Survey To further understand the reservoir andpetroleum system, the team is planning toconduct a large 3D seismic survey over thefield in 1999. This survey will cover approx-imately 800 km2 [308 sq miles], and willhave three primary objectives. The first is toimage the detailed internal structure and het-erogeneities within the Permian andCarboniferous reservoirs to resolve theeffects of faulting and fracturing. The secondis to delineate the flanks of the KarachaganakPermian and Carboniferous reservoirs, whichare overlain by thick salt. The third objectiveis to image deep Devonian strata to 7000 m[23,000 ft] to appraise its exploration andproduction potential.

Planning, designing and executing the sur-vey will be particularly challenging in viewof the multiple, and to a certain extent con-flicting, objectives of the survey, the size ofthe study and the environment of the region.9

To assist in the 3D interpretation, the team isinvestigating the placement of geophonessuspended down wells during the 3D acqui-sition. The 3D survey will require carefulplanning in order to obtain balanced resultsand optimize the trade-offs between cost and benefits.

Although imaging the Devonian may bethe most difficult of the objectives, it isnevertheless vital for the team to obtainsome information on the potential of thisunit. The Production Sharing Agreementbetween the KIO and the Government ofKazakhstan was signed in November 1997;the team has only five years from that date tosubmit a development plan for theDevonian. The appraisal program willinclude workovers, DSTs and new wellsdrilled into the Devonian.

Looking AheadKarachaganak is a giant field with largecommercial (gas marketing) and technicalchallenges caused by reservoir heterogeneityand the complex fluid system (left).Describing, monitoring and predicting reser-voir performance will require the use ofleading-edge technologies to optimizerecovery from the field. The reservoir andoperations teams of KIO will be closelywatching the development of technologiesand working with technology solutionproviders such as Schlumberger to addressthese challenges:• planning and completing a large 3D

seismic survey with both exploration andproduction objectives

• characterizing heterogeneity of the reser-voir: can the heterogeneity be predicted?

• understanding the role of fractures andfaults in field performance

• predicting the performance of the oil leg• evaluating the potential of horizontal wells• resolving the dewpoint issue: how far

below the dewpoint can the field be pro-duced? What is the best timing and quan-tity of gas reinjection?

The teamwork approach and application of appropriate technology promise to go along way toward answering these questions,thus unlocking the full potential ofKarachaganak. —LS

5. Standing MB, Lindblad EN and Parsons RL:“Calculated Recoveries by Cycling from a RetrogradeReservoir of Variable Permeability,” Transactions.AIME 174 (1948): 165-190.

6. Weinaug CF and Cordell JC: “Revaporization ofButane and Pentane from Sand,” Transactions, AIME179 (1949): 303-312.

7. Havlena ZG, Griffith J D, Pot R and Kiel OG:“Condensate Recovery by Cycling at DecliningPressures,” paper SPE 1962, presented at the 42ndSPE Annual Fall Meeting, Houston, Texas, USA,October 1-4, 1967.

8. Aziz RM: “A 1982 Critique on Gas Cycling Operationson Gas-Condensate Reservoirs,” paper SPE 11477,presented at the SPE Middle East Oil TechnicalConference, Manama, Bahrain, March 14-17, 1983.

9. For more on survey design: Ashton CP, Bacon B, Mann A, Moldoveanu N,Deplante C, Ireson D, Sinclair T and Redekop G: “3DSeismic Survey Design,” Oilfield Review 6, no. 2 (April 1994): 19–32.Multi-objective surveys:Boardman M and Walker R: “The Road to High-Den-sity Seismic,” Oilfield Review 7, no. 3 (Autumn 1995):52-60.Subsalt surveys:Farmer P, Miller D, Pieprzak A, Rutledge J and WoodsR: “Exploring the Subsalt,” Oilfield Review 8, no.1(Spring 1996): 50–64.

■■Gas production and marketing challenges.A complex carbonate reservoir and compli-cated fluid behavior present obstacles andopportunities for Karachaganak operationsthat are addressed through an innovativeteam approach.