7/30/2019 00054280

1/15

Copyright 1999, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 1999 SPE Asia Pacific Oil andGas Conference and Exhibition held in Jakarta, Indonesia, 2022 April 1999.

This paper was selected for presentation by an SPE Program Committeefollowing review of information contained in an abstract submitted by the author(s).Contents of the paper, as presented, have not been reviewed by the Society ofPetroleum Engineers and are subject to correction by the author(s). The material,as presented, does not necessarily reflect any position of the Society of PetroleumEngineers, its officers, or members. Papers presented at SPE meetings aresubject to publication review by Editorial Committees of the Society of Petroleum

Engineers. Electronic reproduction, distribution, or storage of any part of thispaper for commercial purposes without the written consent of the Society ofPetroleum Engineers is prohibited. Permission to reproduce in print is restricted toan abstract of not more than 300 words; illustrations may not be copied. Theabstract must contain conspicuous acknowledgment of where and by whom thepaper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX75083-3836, U.S.A., fax 01-972-952-9435.

AbstractKartini field was discovered in 1977 and was

followed by the drilling of three delineation wells. Thereservoirs are fluvial sandstones of the Gita member, TalangAkar Formation that contain gas, oil and water. Kartini-1 and-2 tested at 4,485 BOPD and 2,944 BOPD, respectively.Trapping is created by combination structure and stratigraphic

pinch out along the channel edges. In 1992 the initial planswere to develop the field by installing a 9-slot platform anddrilling 8 development wells. The well locations were basedon 2-D seismic and un-migrated 3-D seismic data. The firsttwo wells were drilled in the field and resulted inuncommercial wells. Maxus ascertained that the developmentrisk was high and put the field's development on hold.

Subsequently the seismic data was migrated whichallowed Maxus to utilize the seismic attributes in conjunctionwith a new geological interpretation to remap the mainproductive reservoirs.

During this hiatus period, Maxus's experience withcaissons progressed from a simple design with a maximum

three wells without workover capability to the currenttechnology allowing up to eight wells with workovercapability. This improved technology results in significant costsavings and allowed the Kartini field to be developedeconomically. In addition to the deviated wellbores, threehorizontal wells will be drilled and are designed to drainreserves from thin oil-bearing sandstones that would beuneconomic otherwise.

Based on new seismic and geological interpretationsinstallation of a low cost Guardian structure, and utilization ofhorizontal wells, Kartini field was developed as an economicfield with production beginning in October 1998.

IntroductionKartini field is located in the northeastern flank of the

Sunda Basin along the boundary of the Southeast Sumatra and

Northwest Java Production Sharing Contract areasapproximately 80 mile north of Jakarta ( Fig.1). The field wasdiscovered in October 1977 when Kartini-1 was drilled to atotal depth of 12,000 ft and penetrated 61 feet of net oil pay inmultiple sandstones of the Gita Member of Talang AkarFormation. The oil has a high pour point ( 90o F) and relativelyhigh viscosity ( 6.4 cp at reservoir condition ) with a gravity o22 degree API. Average porosity and permeability of thereservoirs are high, averaging 30 percent and 700 - 4000 mdrespectively. The field was initially planned to be developed in1992, and because the first two development wells wereuncommercial, the development of the field was postponed forfurther geological and geophysical study.

In 1998 the Kartini field was re-evaluated by aCentral Business Unit multidisciplinary team in order to putthe field on production. Based on new seismic and geologicalinterpretations, cost reductions in facilities and increased inrecovery of reserves by utilization of horizontal wells, Kartinifield has been brought on stream and the first productioncommenced in October 1998 with the initial production rateof 4,000 BOPD.

The primary aim of this paper is to show how theteam effort in integrating 3-D seismic and geologic modelsutilization of new technology with a low cost structure andoptimum reserves recovery using the horizontal drilling waseffective in commercializing a 20-year old undeveloped

discovery.

Geology OverviewThe Kartini field is a three-way-dip faulted closure

with a small four-way-dip closure in the middle of the field, tothe east bounded by a north-northeast-south trending normafault, down to the west (Fig. 2 ). The Kartini structure wasformed in late Miocene.

SPE 54280

Marginal Field Development strategy, Kartini Field, Offshore Southeast SumatraBudiyento Thomas, Miguel M Galuccio, Wira Dharma, Sudharmono Mitrodihardjo, Jonny Pasaribu, YPF - Maxus Southeast Sumatra

http://contents.pdf/

7/30/2019 00054280

2/15

SPE 54280 [Marginal Field Development Strategy, Kartini Field, Offshore Southeast Sumatra] 2

The regional stratigraphy of Sunda Basin issummarized in Fig. 3. The sedimentary sequences ranges inage from Eocene to Holocene. The oldest deposit is theEocene to early Oligocene Banuwati Formation whichunconformably overlies the Cretaceous basement. Theoverlying Zelda Member of the Talang Akar Formation ispredominantly fluvial, although lacustrine shale are

encountered in the lower Zelda in parts of the basin. Thismember is capped by Gita Member of the top Talang Akar, atransgressive fluvial-deltaic sequences of interbededsandtones, shales and coals. The overlying Batu RajaCarbonate/shale member reflects the onset of marineconditions across the entire basin. The regional seals of theSunda Basin are claystones of overlying the Gumai Formation.The remainder of the succession consists of Miocene, shallow-marine shale, limestones, which are overlain by predominantlyalluvial sediments and volcanics of the Plio-Pleistocene.

Figure 4 is the type log of the Kartini field andillustrates the various productive Gita sandstone reservoirs.The oil and gas were trapped in six different sandstones, from

base to top, the C, B-3, B-2, A-3, A-2, and A-1 over a verticalinterval of approximately 400 ft. These reservoirs have thedifferent oil-water and gas-oil contacts with a maximum oilcolumn approximately 60 ft.

Reservoir Distribution MappingC Sandstone

The C sandstone reservoir is the main target thatcontains the largest volume of reserves within the Kartini fielddevelopment. Kartini-1 well penetrated 34 feet of net oil payfull to base of C sand and tested 1,212 BOPD with no water.The oil/water contact was encountered in this sand at -5830feetin Kartini -3 but the gas/oil contact has not seen yet in the

field. Based upon logs facies analysis of C interval in Kartini-1indicate that it consists of a coarsening upward delta frontsandstone overlain by fining upward distributary channelsandstone succession, and it is interpreted to be deposited asfluvio-deltaic depositional environment. In the initial Plan OfDevelopment ( P.O.D.), Kartini A-8 located 1500 feet north ofKartini-1 and Kartini A-8 S/T located 300 feet. west ofKartini-1 attempted to develop the C sandstone reserves butfailed to encounter the reservoir and caused the Kartini fielddevelopment to be delayed.

Subsequently, the 3-D seismic data over Kartini areawas reprocessed and the analysis of seismic amplitudes showsthe presence of a strong seismic anomaly at the C sand

interval slightly below the coal-3 marker. The strongamplitude anomaly correlates to the presence of the sandstonewithin the C sand interval (Fig. 5) Additionally, the isochronof the C sand interval was mapped and it corresponds to theamplitude anomaly map, showing a thick over the sandstoneanomaly (Fig. 6). Another attribute, the instantaneous phasealso supports the presence of an anomaly related to the C sand

distribution. This new seismic interpretation combined with arevised geologic model, has allowed to improve mapping ofthe C sand distribution ( Fig. 7). The C sandstone consists oftwo channels which trend north-south and just north of Kartini-1, they converge to the east. The width of the channel rangesfrom 1,000 to 2,000 feet and the thickness ranges 6 - 37ft (Fig8). Average porosity and DST permeability for the C

sandstone are 24% and 700 md, respectively.Since approval of the 1998 POD, three wells have

been drilled and two encountered commercial pay withthickness ranging from 14 to 34 feet. The wells werecompleted and were put on production at the initial productionrate of 4,000 BOPD.

B - Sandstone

The second set of reservoirs are the B-3 and B-2sandstone reservoirs. These sandstones are separated from theC sand by the regional coal marker -3. The sandstones havebeen mapped using well data and a fluvial channel geologicmodel and they have a north-south trend with width

approximately 5000 ft and maximum thickness about 60 fee(Fig. 9). The oil/water contact was encountered in the B-3 sandat - 5566 ft and gas/oil contact was encountered in the B-2sand at -5549 ft. The average porosity and DST permeabilityof these reservoir are 29% and 4900 md, respectively.

A - Sandstone

The uppermost reservoirs in the Kartini field are theA-1. A-2, and A-3 sandstone reservoirs. These reservoirs arerelatively thin with thickness ranging from 5 to 24 feet. Anaverage porosity and DST permeability are 32 percent and3,750 md, respectively. Because of its thickness and lateraextent, the A-2 sandstone is the main drilling target for A

series sandstone reservoirs. The A-2 interval was cored in theA-4, but there was not reservoir facies in this core. Thesandstone consists of mostly very fine grained, well sorted, andhas horizontal and vertical burrows with tube up to 3 cm.interbedded with siltstone. Electro facies analysis ovesandstones interval indicate that A-2 sand tend to have adecreasing-gamma-shaling upward signature which suggests amouth bar origin with a tidal influenced . The isopach map ofthe A-2 sandstone ( Fig. 10 ) and geological cross section (Fig11 ) indicate a mouth bar complex prograding from south tonorth

Implication of Low Cost Facilities

Reducing the capital cost of facilities is a key factorthat allows economic development of marginal fields. Aninnovative low cost structure has been designed andconstructed by the Maxus engineering team. In 1997 Maxusinstalled 4 Monopods to develop four marginal fields withreserves ranging from 1 to 1.2 MMBO in water depth ofapproximately 70 feet. Maxus' experience with Monopod has

7/30/2019 00054280

3/15

SPE 54280 [Marginal Field Development Strategy, Kartini Field, Offshore Southeast Sumatra] 3

progressed from a simple design with a maximum of threewells without workover capability to the current technologyallowing up to eight wells with workover barge capability (Fig.12). This enhanced design accommodate eight developmentwells from one braced caisson structure rather than requiring alarge, expensive, 4-pile platform. Kartini field utilized the 7-well braced caisson structure with a deck to accommodate

workover barge and the cost saving in facilities is substantial,approximately $ 3.4 MM.

Horizontal DrillingThe objective of a horizontal well is to drain

hydrocarbons from a reservoir in more cost-efficient mannerthan a conventional vertical or deviated well ( Ranney, 1939 inD.C Carter). The most practical application of horizontaldrilling is to place a well below a gas or above water zone inorder to avoid gas and water coning, and to optimize theproduction rate and reserves recovery. In Kartini field, thin oilreservoirs such as B-2 and A-2 reservoirs are good candidatesfor horizontal well drilling . With a relatively high water-oilmobility ratio, a vertical well could not effectively drainreserves from thin oil reservoirs.Gas is present within the A-2 sandstone in the structurally higharea. A gas/oil contact in Kartini-5, oil in the A-8 S/T andKartini-1, and the highest known water Kartini-4 indicate amaximum oil column of approximately 60 feet covering a verylarge area with potential thicker pay/ sweet spot at Kartini -1and AV-2 in Northwest Java PSC and just North of Kartini-5.Two horizontal wells are designed to drain A-2 reserves in thesweet spot. The A-2 sand was tested in Kartini at a rate of3,200 BOPD, 200 GOR with no water. A simulation studyindicates that a 500 to 600 ft horizontal length will optimizethe net cash flow ( Fig. 13)

The third horizontal well is designed to drain B-2 oilreserves that were discovered by Kartini-2 delineation well.The well encountered 30 ft net oil pay underlying 28 feet netgas pay, and tested 2,944 BOPD with no water at the oil payinterval. Based on the new structure and net sand maps, themaximum oil column is approximately 34 feet covering anarea of 150 acres ( Fig. 9B)

Reserves and EconomicBased on the new geophysical and geological

interpretation, and horizontal drilling technology for thereservoirs that contain thin oil columns, a total recoverable

reserves for Kartini field is 4 MMBO.The C sandstone is the primary reservoir target andexpected to have a partial water drive. A 30 % recovery factoris expected from this reservoir. The A-1 and A-2 sandstonereservoirs are thinner than the C sand and both have gas/oilcontacts and oil/water contacts. These reservoirs will recover20% of OOIP. The oil pay in B series sandstone reservoirs are

an oil leg between water and gas column, and recovery of only15% of OOIP is expected.

Kartini field is classified by Pertamina as a new fieldtherefore this project entitles for the new field incentives of 60months DMO holiday and 17% investment credit. Total cost ofKartini field development is estimated to be $ 17 MM whichincludes facilities and wells cost. A team effort to increase

reserves and reduce costs has successfully developed amarginal field in period of low oil price.

Conclusions1. Integrated 3-D seismic attributes and geologic models are

powerful tools to aid mapping the distribution of areservoir.

2. An innovative braced caisson structure has a significantlyreduced costs and has allowed the development of theKartini field.

3. Horizontal drilling is expected to optimize production rateand increase reserves recovery in the thin oil columnreservoirs, and will enhance the rate of return on the

project.4. The aggressive of Multidisciplinary Central Business Uni

is the key factor for successfully Kartini fielddevelopment.

AcknowledgmentsThe authors would like to thank Pertamina-BPPKA

YPF-MAXUS SES Indonesia and all partners for permissionto publish this paper. The manuscript has benefited fromcritical reviews by Chris Oglesby, Jorge Burgos and MarkSchneider.

References1. Carter D.C. et al.: An Integrated Approach to HorizontaWell Design and Planning in Widuri field, OffshoreSoutheast Sumatra, Indonesia," IPA , May 1998.

2. Girgis, John et al. : Multi-disciplinary Teams -What is the"right" structure ? Based on Ten Years of MDTs inIndonesia, IPA, October 1995.

3. Maxus S.E.S June 1988 : Kartini Field DevelopmenProposal" unpublished.

4. Prayitno, Wicaksono et al. : The Implication Of BasinModeling for Exploration - Sunda Basin Case StudyOffshore Southeast Sumatra, " IPA October 1992

5. Wight A, et al. : Stratigraphic response to structura

evolution in a tensional Back-arc setting and itsExploratory significance Sunda Basin, West Java SeaIPA, October 1986

7/30/2019 00054280

4/15

7/30/2019 00054280

5/15

7/30/2019 00054280

6/15

7/30/2019 00054280

7/15

7/30/2019 00054280

8/15

Fig. !5 : Anwl i tude map a& J%E? C Sand intxxwzil.

7/30/2019 00054280

9/15

7/30/2019 00054280

10/15

KARllNE! A+$T K#rm AC-4

,-2

,-3

I q ,,, . .

Figure - $a: Seismic line through IGrtixriA- 8&T,l & AC!- 4.

KarthlAC41q

M,,

/-//

kk.------Karl i nlC44

d

t?ok%?....

---5MD

I?igure- 8b : Ckdogic cross section showing C Sand geometry.

7/30/2019 00054280

11/15

7/30/2019 00054280

12/15

7/30/2019 00054280

13/15

7/30/2019 00054280

14/15

M O N O P O D

F i g . 1 2 : L o w c o s t C a i s s o n s t r u c t u r e

K A R T I N I - B R A C E D C A I S S

7/30/2019 00054280

15/15