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Copyright 2001, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the SPE Asia Pacific Oil and Gas Conference andExhibition held in Jakarta, Indonesia, 1719 April 2001.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented at

SPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractExploitation of ultra-thin oil columns under gas cap and

water support is challenging since both gas and water coningcan seriously curtail oil recovery. Horizontal wells haveshown to alleviate some of this problem as they allow for lessdrawdown and hence reduce coning for better recoveryefficiency. Although the industry has shown horizontaldrilling cost continues to be lowered, economics is still a

major issue in exploiting ultra-thin oil bands using horizontalcompletion.

This paper presents a case study showing lessons learnedfrom managing reservoirs with ultra-thin oil bands with lessthan 20 ft and sandwiched between gas cap and bottom/edgeaquifer. Actual data from a field characterized by stackedpays of fluvial and deltaic channel sands in the MahakamDelta complex are demonstrated. Subject to long-termproduction, the originally thick oil columns in these reservoirshave now become thinner, yet carry significant reserves to beprudently further developed. Issues involved in reservoirmanagement such as well surveillance, well planning andprognosis, operating while drilling and producing, and long-

term development plans are discussed. Reservoir modeling isshown to be the guide not only for well planning but also forwell operations as it is used to select well type and completionstrategy, optimize well production and prepare for continuousannual operating plan.

The vast well performance database provided from thepaper shows horizontal drilling continues to be the mainvehicle to develop these ultra-thin oil bands. Care howeverneeds to be taken to scrutinize the economics inherent in

selecting this type of completion, as other alternative methods

also deserve to be considered.

IntroductionMature oil reservoirs with gas-cap and water support havebecome the prime targets for horizontal drilling by many

operators in the last fifteen years. Operating in EasKalimantan, Unocal Indonesia Co. (UIC) has extensively usedhorizontal applications in developing their mature fields bycompleting more than 100 wells since 1996. Althoughhorizontal wells have proven their performance to developthin oil bands by providing better oil recovery efficiency, theremaining, ultra-thin oil pays (e.g. less than 20 ft) in thesereservoirs that need to be further developed, pose higher riskwith horizontal drilling. As expected, recovery naturallybecomes less with thinner oil columns, horizontal drillingbecomes more costly as it requires more accurate geologicainterpretation and sophisticated equipment that would havenegative effect on the project NPV's. To alleviate risk and

improve economics, feasible options to be considered are (i)short- to medium-radius horizontal completion for singlezones, or (ii) conventional completion penetrating severastacked pays.

The paper presents a case study to demonstrate lessonslearned from exploiting ultra-thin oil bands under 20 ft in theAttaka field and its plan to continue developing theseremaining oil columns using horizontal technology. The papefirst describes the Attaka field and discusses its recenthorizontal drilling program and results based on performancedata from 13 horizontal wells drilled in various ultra-thinsands. Reservoir management issues involved in drilling andoperating these wells are briefly reviewed. To support futureplan of development, a reservoir model based on field data isused as a basis to examine various completion strategiesEffects of reservoir and well conditions on recovery are notedfrom results of many sensitivity runs that examine variationsin well length, well placement standoff to fluid contactstubing size, initial rate, and effect of gas lift. Reserves andeconomic evaluations (NPV) are then used as guidelines forthe future development plan of the remaining ultra-thin oicolumns in the field.

SPE 68675

Reservoir Management for Ultra-Thin Oil Columns Under Gas-Cap and Water Support:Attaka Field ExamplesD.T. Vo, Renas S. Witjaksana, Sukerim Waryan, Agung Dharmawan, Iwan Harmawan, Unocal Indonesia Company, andMasato Okuno, Inpex

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2 D.T. VO, RENAS S. WITJAKSANA, SUKERIM WARYAN, AGUNG DHARMAWAN, IWAN HARMAWAN, AND MASATO OKUNO SPE 68675

Attaka field and its recent horizontal drilling programAs one of the major oil fields in the region, the Attaka fieldcomprises massive stacked channel sandstones deposited inthe ancient Mahakam Delta of the Kutei Basin, a known majorpetroleum province. The field is located about 25 kilometersnortheast of the Mahakam Delta, offshore East Kalimantan

(Fig. 1). The area closure of the field structure covers nearly8000 acres (Fig. 2) with traps identified by a large roll-overanticline in combination with stratigraphic and fault features1.Spread over several thousand feet vertical, hydrocarbons arefound in multi-layered sandstones deposited in deltaic toshallow marine environments during the Middle to LateMiocene ages (Fig. 3). UIC drilled and tested the discoverywell Attaka #1A in 1970 at 11,330 Bopd. The first productionstarted in 1972 at approximately 22,000 Bopd from ten wells.Oil production peaked at 120,000 Bopd in 1977 from 50 wells,gradually declined and currently production is maintained atabout 25,000 Bopd by continuous infill drilling/redrilling andworkovers (Fig. 4). Cumulative production as of October 2000is 597.1 MMBo of oil and 1.29 Tcf of gas.

The horizontal drilling in the field began in 1996 withprimary targets of thin oil columns in the Shallow, MainDeltaic and Low Deltaic sands. These wells are designed todrain by-passed or isolated oil pockets of prolific quality withhigh permeability and porosity and under large gas cap andwater leg. With thickness varying between 10 to 40 ft, thebenefits of using horizontal wells in these sands are (i) toreduce coning, (ii) drain larger areas, (iii) and impose lessdrawdown to alleviate potential sand problems, particularlyfor the Shallow sequence.

Performance lookback2 on data from the Attaka horizontalwells clearly show they provide larger drainage areas andvolumes compared to that associated with contemporary

conventional wells targeting the same pay zones. Results2

obtained from 24 Attaka wells show an average well of near900-ft long recovers 670 MBo (28% recovery) by draining a66-acre area of 25-ft oil column. Overall, with an averagedevelopment cost at 1.7 $/bbl, the horizontal drilling programin the field is successful as it relies on an integrated teamapproach that plans and implements wells with the followingreservoir management practices2: optimizing recovery and revenue by planning wells using

reservoir modeling reducing risk by continuous reservoir surveillance to

assess current fluid contacts due to dynamic fluidmovement from production by using formation testing

and saturation logging tools, recent well data, andreservoir models, etc. reconciling surveillance data with geological model by

continuing calibration of reservoir models after new wells using simple plans for drilling and operating wells such as

selection of landing point with minimum standoff belowGOC, plan for TD point, implementing a simple wellcourse by connecting landing and TD points, andoperating under GOR control, etc.

Although successful as shown by the overall lowdevelopment cost, detailed examination of results fordevelopment of oil columns under 20 ft shows an average near900-ft well would recover about 380 MBo (27%) fromdraining a 54-acre area. These results are captured in Fig.5where related actual well parameters are correlated against log

normal distribution. With a development cost at 3.1 $/bbl, theexploitation of oil columns under 20 ft clearly presents achallenge and an important issue for the continuing futuredevelopment of the remaining thinner oil columns in the fieldas they carry significant reserves. To further improvedevelopment cost by reducing risk and improving economicsoptions currently under consideration are to selectivelyimplement short- to medium-radius horizontal completions forsingle zones, in combination with conventional completionsfor multi-zone stacked pays. In the following, the focus othe discussion is on the feasibility of short to medium-radiushorizontal wells for future development plan.

Reservoir modeling for planning completion strategy

Oil and gas recovery from an ultra-thin oil column under gascap and water support strongly depends on the oil columnthickness, formation permeability, gas-cap size, aquiferstrength, reservoir geometry, bed-dip magnitude, and oiviscosity2-4. Use of reservoir modeling to select a completionstrategy (well placement, length, distance to fluid contactsrate) and predict performance is essential. A sensitivityanalysis to investigate the effect of well placement on oirecovery in an ultra-thin oil column (under 20 ft) with gas-capand bottom-water support was performed. Using a reservoirmodel (Fig. 6) representing the field data (Appendix A)effects of completion placement in the oil column, well lengthtubing size, use of gas lift and rate control on oil recovery are

examined. The model includes a 45-acre drainage area of 20-foil column thickness at the well or near 18-ft average oicolumn over the area. In the following, results of more than180 sensitivity runs are summarized and discussed. Forsimplicity, results presented are based on average responsescondensed from many runs to represent a "likely" caseassociated with a particular scenario of well conditions.Effect of well placement in oil column. In general, results inFig. 7 show that placing the well towards the middle of the oilband tends to give better recovery as early gas cap production(completion close to GOC) or water production (completionclose to OWC) can be delayed. Consistent with resultspresented in Refs. 2-4 wherein the oil column is thicker (30-40

ft), results in Fig. 7 suggest the free gas volume in this case islarge enough (m=1 Bcf/MMBo) to require a minimum wellplacement standoff against the gas cap for improving oirecovery. In practice, the GOC can be determined withcertainty while approaching the sand, but the OWC is howevernot always known with certainty unless a pilot hole or recentlogs from nearby wells are available. In this case, it is prudentto determine a minimal standoff for the landing point belowthe GOC (determined while approaching) and select the TD acertain standoff distance above the OWC (estimated ahead of

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RESERVOIR MANAGEMENT FOR ULTRA-THIN OIL COLUMNS UNDER GAS-CAP ANDSPE 68675 WATER SUPPORT: ATTAKA FIELD EXAMPLES 3

time by surveys or reservoir models) and plan for the well pathaccordingly.Effect of well length. Results in Fig. 7 also suggest thatoptimal lateral length for an oil column under 20 ft to drain a50-acre area requires about 600-ft lateral. In practice, althoughthe longer the well the better it performs, an excessively long

well may pose higher geological and drilling risk as it maycross unexpected faults, stratigraphy or encounter potentialmechanical problem with running long screens. It is alsonoticed that with high permeability and strong gas cap andwater support, pressure drop in the reservoir and along thewell is relatively small, a significant long well may notcontribute a lot more than it should. In addition, since mostpressure drop occurs at the heel of the well, it is prudent toavoid undulated well path as any "low" points along the wellcourse may induce hydraulic flow stagnancy.Effect of tubing size and gas lift. Results in Fig. 8 show thesmaller tubing gives better recovery due to better liftingefficiency especially when water production becomesdominant. This observation is consistent with whether gas lift

was used or not. On average, results show incrementalrecovery of 3% for each tubing downsizing without using gaslift. The recovery difference becomes smaller (about 1% foreach incremental tubing downsizing) when gas lift is used.Effect of initial rate. Although all cases show high rates(>1000 bopd) can be delivered at the beginning including thesmaller tubing size cases, the key issue encountered withproducing thin oil band is that early high offtake rate tends tocone gas earlier that could finally hurt recovery. It is prudentto operate wells with some GOR control measure especially atthe beginning; for example, by less than 3 times the solutionGOR as recommended by Ref. 2. Fig. 9, showing oil recoverydecline with high GOR as observed from all simulation runs

and actual performance data, reconfirms this practice. Inaddition, results from all cases show although initialproduction (IP) is high, average annual rate for the first year ofproduction from ultra-thin oil column is typically lower thanthe early IP's. This further suggests the benefit of earlycontrol of excessive gas production to improve long-termrecovery. Fig. 10 presents average annual rate and recoveryover the life of a 600-ft well for various tubing sizes. Resultsshow the effect of large tubing size has a small impact onaccelerating production since wells with smaller tubing willcatch up production within two years of production. Inaddition, ultimate recovery for wells with smaller tubing sizestends to be higher after year four as its lifting effect is more

efficient after water production becomes significant at the end.For all cases considered, average production life is about 4years for 2-3/8" tubing, 3.5 years for 2-7/8" tubing and 3 yearsfor 3-1/2" tubing.Economic implication. Results in Figs. 11-12 show thesmaller tubings of 2-3/8" and 2-7/8'' generally give betterrecovery and NPV (@12%) than that of the 3-1/2'' tubing casein most horizontal laterals considered, using short- to medium-radius completion. The key assumption used in the economicevaluation shown in Fig. 12 is that the drilling and completion

cost for short- to medium-radius wells is expected to be lowerthan that of the conventional horizontal drilling (Appendix B)Fig. 12 also compares the data against the average NPV value(single solid point) obtained from the lookback on the 13existing horizontal wells for oil columns less than 20 ft thawere drilled by conventional horizontal technique and

completed with 3-1/2'' tubing. Besides improving recovery andreducing drilling cost, the competitive economic figure forshort- to medium-radius completion for thinner oil bands inpart lies in the cost saving of using smaller 2-3/8" or 2-7/8'tubings.Effect of oil column thickness on recovery and economics

It is expected that when oil column thickness gets too thin, iwould be difficult to continue applying horizontal drilling forsingle zone in principle, concerning data control and cosefficiency as recovery can be low. Fig. 13 compares oirecovery for oil columns under 15 ft against that of thickercolumns obtained from simulation results. Economiccomparison in NPV's for three base cases is also presented(details shown in Appendix B). Relevant to stacked-pay

reservoir setting in Attaka, multi-zone completion byconventional well is selectively considered as it deems moreappropriate when oil column thickness becomes very thin (e.gless than 10 ft or so) as results of Fig. 13 suggest.

Plan for future development of ultra-thin oil columnsResults from the lookback of existing horizontal wellstargeting ultra-thin oil columns under 20 ft using conventionaldrilling suggest development cost could be further improvedAdditional simulation results demonstrate that it is feasible toimprove recovery and economics for ultra-thin oil columnsunder 20-ft using cost-effective short- to medium-radiusdrilling while maintaining recovery efficiency. In particular

built on operating experiences of many horizontal wellsdrilled, future plan for developing these types of thin oil bandswould selectively consider drilling short- to medium-radiuswells with the principal guidelines as follows: use reservoir model and surveillance for well planning depending on the situation encountered, first plan wells

for around 600 ft, then modify to accommodate reservoirmechanical and cost conditions

depending on the gas-cap size, typically place wells inthe top half of the oil column with a sufficient standofbelow the GOC for the landing point

plan for simple well course by simply connecting thelanding point to TD and avoiding undulated well path

complete wells open-hole with screens consider using smaller tubing sizes (2-3/8'' or 2-7/8'') use artificial lift (e.g. gas lift) for improving recovery take advantage of batch drilling for cost savingWhen oil columns encountered are less than 10 ft or so, othercompletion options may be considered for cost effectivenessfor examples, multi-zone stack-pay with conventional wells oreven a possibility of short to medium-radius multi-laterals.

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ConclusionsThe objective of the paper is to offer ways to cost-effectivedevelop ultra-thin oil columns under influence of gas cap andwater production. Based on analysis of performance data from13 existing wells in ultra-thin oil bands, reservoir modelingresults, and operating experience, the study has examined

options to further optimize development of the remainingultra-thin oil columns in the Attaka field by considering short-to medium-radius completion for cost and recovery efficiency.In summary, the paper has captured the followings: It is possible to improve cost and maintain recovery

efficiency by planning wells around 600 ft for oil columnunder 20 ft and drainage area around 50 acres.

The use of small tubing and gas lift is essential toimproving recovery efficiency and economics.

Practical considerations during pre-well plan, whiledrilling and post-well operations are provided based onthe drilling and operating experience of many horizontalwells completed in the field and the area.

AcknowledgementsWe would like to thank Unocal Indonesia Company and Inpexfor their support and permission to present this study. Specialthanks are due to Jerry Bowen of UIC drilling department forproviding well parameters and costs used in the economicevaluation for short- to medium-radius drilling & completion.Fruitful discussion with Mark Boehm, lead geologist of theUIC Attaka team, on the idea of planning short- to medium-radius wells is acknowledged.

References1. Zagalai, B.M., Houtzager, J.F., Mahadi, S., Partono, Y.,

and Goodwin, B.: "Reservoir Simulation Facilitates

Synergism in Management of the Attaka Field," SPE22352, presented at SPE International Meeting onPetroleum Engineering, Beijing, China (March 1992).

2. Vo, D.T., Sukerim, Dharmawan, A., Susilo, R.,Wicaksana, R.: "Lookback on Performance of 50Horizontal Wells Targeting Thin Oil Columns,Mahakam Delta, East Kalimantan," SPE 64385presented at the SPE Asia-Pacific Conference andExhibition, Brisbane, Australia, Oct.16-18, 2000.

3. Vo, D.T., Sukerim, Widjaja, D.R., Partono, Y.J., andClark, R.T.: "Development of Thin Oil Columns UnderWater Drive: Serang Field Examples," SPE54312presented at the SPE Asia-Pacific Oil &Gas Conference

& Exhibition, Jakarta, Indonesia, April 20-22, 1999.4. Vo, D.T., Sukerim, Ivanowicz, M., Syahrani, Bouclin,D., Clark, R., Stites, J. and Partono, Y.: "ReservoirModeling Assists Operations to Optimize FieldDevelopment: Serang Field, East Kalimantan,"SPE59441 presented at the SPE Asia-Pacific Conferenceon Integrated Modelling for Asset Management,Yokohama, Japan, April 25-26, 2000.

Appendix AData used in the simple model for completion strategy:Model area = 51 acres (= 1600 x 1400 ft2); Dip Angle=3o

GOC @ 4340 ft and OWC @ 4360 ft ssOil column of 20 ft underlain gas cap and overlain water legEffective oil covered area = 45 acres

Average oil column thickness over the area = 17.7 ftOil column thickness at and around well = 20 ftOriginal fluid in place:OOIP = 1.16 MMSTBO; OGIP = 1.71 Bcf(including free gas = 1.18 Bcf; m = 1 Bcf/MMBo )Initial pressure = 1750 psi @ 4345 ft; Temperature = 170o FOil gravity = 40 oAPI; Gas gravity = 0.65Oil FVF = 1.28 rb/stb; Solution GOR = 460 scf/stb;Oil viscosity = 0.46 cpResidual oil saturation = 0.3; Porosity = 0.3Connate water saturation = 0.2; Critical gas saturation = 0.05Sensitivity analysisStandoff completion from GOC: from 2.5 - 17.5-ft from GOCInitial oil rate: 1000, 2000, and 3000 STB/D

Horizontal length from 200 to 1000Tubing size: from 2-3/8 to 3-1/2Gas lift application @ 500 Mscf/dayPartial depletion effect: initial pressure varying from 1750 psito 1275 psi

Appendix B1. Economic evaluation presented in Fig. 12Base case for short- to medium-radius drilling & completion:Well length = 600 ft; Well depth = 6000 ft MD; 3-1/2 tubingDrilling and completion cost = 650 K$Variation:10K$ for each incremental 100 ft lateral

2$/ft for each incremental tubing down/up sizingCapital cost = 28% of total cost; Fixed annual operating costs2. Economic evaluation for the average case from 13 existingwells (conventional horizontal drilling):Average length = 900 ft; Average recovery by well 380 MBoAverage cost = 1.19 M$; Capital cost = 28% of total cost;Fixed annual operating costsAll wells were completed with 3-1/2'' tubing and most weregas lifted. All evaluations are based on Indonesia's EasKalimantan PSC terms3. Data used in Fig. 13Model area = 51 acres; Dip angle = 3o

Effective oil covered area = 45 acres

Variation:OOIP = 812, 1160 and 1600 MBoOil column thickness = 15, 20 and 30 ftEffective ave. oil column thickness = 12.4, 17.7 and 24.4 ftFor the NPV(@12%) calculations: drilling and completioncost is fixed at 650K$ for the three cases presented

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Table 1. Summary of Attaka ultra-thin (< 20 ft) horizontal well performance analysis results

ATTAKAFIELD

Reserve

Well Start Sand Sequence Status Todate Current Ultimate Ultimate Area H L I.P.

(MBO) (%) (MBO) (%) (Acres) (ft) (ft) (BOPD)

A-6RD3ST1HZ Jun-98 55-5/ 4 L-Deltaics Active 124 11 261 23 39 22 700 326

A-5RD2ST3HZ Jun-98 51-1/ 4 L-Deltaics Active 243 21 330 29 45 16 700 285B-7RDHZ Aug-98 44-5B/ 4 U-Deltaic Active 467 23 541 26 73 20 920 2182

D-19HZ Apr-99 44-5A / 4 U-Deltaic Active 323 19 450 27 67 15 850 575

L-21HZ Feb-97 44-1 / 4 U-Deltaic Active 479 24 570 29 55 20 800 1299

F-5RD3HZ Jan-98 43-5B/4 U-Deltaic Active 218 21 250 25 52 21 750 949

FS-7RD2ST2HZ Apr-98 43-5B/ 3 U-Deltaic Active 118 21 131 24 19 20 600 980

B-14RDHZ Jul-98 42-0AB/ 4 U-Deltaic Active 679 43 690 44 70 11 1300 1809

L-29HZ Oct-97 42-0A / 4 U-Deltaic SI 215 20 215 20 28 20 500 659

E-16HZ Feb-97 37-4B / 4 Shallow SI 316 19 316 19 92 20 1160 3158

UA-8HZ Dec-98 40-0 / 4 Shallow Active 479 27 649 36 63 15 900 2070

E-14HZ Jan-97 36-5 / 4 Shallow SI 120 14 120 14 39 20 1140 1725

UA-4HZ Dec-98 32-7A / 4 Shallow Active 457 28 470 29 55 20 1000 1674

326 22 384 27 54 18 871 1361Average horizontal well

TerminalTerminal

Fertilizer PlantLNG Plant

TerminalTerminal

KALIMANTAKALIMANTA

MALAYSIMALAYSI

BRUNEBRUNE

Balikpapan

Refinery

Attaka

Mahakam River

Figure 1. Attaka Field Location, Offshore East Kalimantan, Indonesia

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Figure 2. Attaka Structure Map View

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Figure 3. Stratigraphic column in Attaka field

Figure 4. Contribution of horizontal wells to the total Attaka oil production

Attaka Field: Impact of Horizontal Wells on Oil Production

0

10,000

20,000

30,000

40,000

50,000

60,000

BOPD

Workover Wells

Horizontal Wells

Conventional W ells

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P1 P10 P50 P90 P99

73 145 335 775 1536

Swanson's Mean 410 Psm = 62.11 %

Statistical M ean 415 P23 = 207

Arithm etic Average 384 P77 = 543

Attaka Ultra-thin H-well Oil Recovery Distribution

0.1

2

0.2

0.5

1

5

10

20

30

40

50

60

70

80

90

95

98

99

99.5

99.8

99.9

10 100 1000 10000

Oil recovery by well, MBo

Percentequaltoorlessthan...

P1 P10 P50 P90 P99

16 27 50 93 154


Statistical Mean 56 P23 = 35

Arithmetic Average 54 P77 = 71

Attaka Ultra-Thin H-Well Drainage Area

Distribution

0.1

2

0.2

0.5

1

5

10

20

30

40

50

60

70

80

90

95

98

99

99.5

99.8

99.9

10 100 1000

Drainage area by well, acres


P1 P10 P50 P90 P99

403 561 842 1263 1759


Statistical M ean 885 P23 = 666

Arithm etic Average 871 P77 = 1064

Attaka Ultra-Thin H-Well Length Distribution

0.1

2

0.2

0.5

1

5

10

20

30

40

50

60

70

80

90

95

98

99

99.5

99.8

99.9

100 1000 10000

Well length, ft


Figure 5. Ultra-Thin (< 20ft) Attaka Horizontal Well Performance Against Log Normal Distribution

P1 P10 P50 P90 P99

12 17 26 39 55


Statistical Mean 27 P23 = 20

Arithmetic Average 27 P77 = 33

Attaka Ultra-Thin H-Well Oil Recovery Distribution

0.1

2

0.2

0.51

5

10

20

30

40

50

60

70

80

90

95

98

99

99.5

99.8

99.9

1 10 100

Oil Recovery by Well. %


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Figure 6. Reservoir model useful for planning completion strategy in thin oil columns

Oil band

Gas cap

Water leg

H-well

Figure 7. Effect of completion placement standoff to GOC and well length

on oil recovery of a 20-ft oil column

0

5

10

15

20

25

30

0 200 400 600 800 1000 1200

Well Length, ft

OilRecovery,%

2.5' from GOC

7.5' from GOC

12.5' from GOC

17.5' from GOC

Vertical

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Figure 9. Effect of rate control for improved recovery by avoiding early gas cap production

Figure 8. Effect of tubing size and well length on oil recovery of a 20-ft oil column

(average for all cases of well placement standoff against GOC)

0

5

10

15

20

25

30

0 200 400 600 800 1000 1200

Well Length, ft

OilRecovery,%

2 3/8 tubing

2 7/8 tubing

3 1/2 tubing

Vertical

0

100

200

300

400

500

600

0 1000 2000 3000 4000 5000

Cum. GOR, scf/stb

Cum.oil,MB

Sensitivity Simulation Data Ac tual Data from 13 Wells

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Figure 10. Effect of tubing size and well length on well performance for a 20-ft oil column

(L=600 ft completed in the top half, near middle of oil band; Tubing = 2-7/8 with gas lift)

Figure 11. Effect of tubing size and well length on oil recovery for a 20-ft oil column

0

100

200

300

400

0 200 400 600 800 1000 1200

Well Length, ft

Oilrecovery,MB

Tub.2-3/8 Tub.2-7/8 Tub.3-1/2

0

100

200

300

400

500

0 1 2 3 4 5

Year

AnnualOilRate,Bopd

0

50

100

150

200

250

300

Cum.Oil,MBo

Tub.2-3/8 Tub.2-7/8 Tub.3-1/2

Tub.2-3/8 Tub.2-7/8 Tub.3-1/2

Rate

Cum. oil

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Figure 12. Effect of tubing size and well length on NPV (@12%) for ultra-thin oil column

(under 20-ft) using short- to medium-radius horizontal completion

Figure 13. Effect of oil column thickness on recovery factor and NPV(@12%)

0

0.1

0.2

0.3

0.4

0 200 400 600 800 1000 1200

Well Length, ft

NPV(@12%),MM$

Tub.2-3/8 Tub.2-7/8 Tub.3-1/2 Ave. NPV from existing wells

0

10

20

30

40

0 200 400 600 800 1000 1200 1400

Well Length, ft

RF,

0

0.2

0.4

0.6

0.8

NPV(@12%),MM$

RF (15-ft col.) RF (20-ft col.) RF (30-ft col.)NPV 15-ft col. NPV 20-ft col. NPV 30-ft col.

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