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Copyright 2005, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Improved Oil Recovery Conference in Asia Pacific held in Kuala Lumpur, Malaysia, 5–6 December 2005. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position 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 of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment 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. Abstract Most of oil fields managed by PT PERTAMINA (PERSERO) are considered as brownfields and the oil produced only from primary recovery stage. To get better recovery of oil in those brown fields, it is necessary to have a long term project such as Enhanced Oil Recovery (EOR). Some screening criteria had been completed to select appropriate method which could be applied in certain field. In this study, we present gas injection program in West Java to obtain better recovery of the mature field/brownfield. The gas injection program include natural gas such as ethane, propane and CO2 flooding. The viability relates mainly to the availability of CO2, the structure complexity, and finally the achievement of the Minimum Miscible Pressure (MMP). In the Jatibarang Field, it is not an issue of gas and CO2 availability since gas and CO2 sources are available in the field itself, and near by fields.

The Jatibarang Field primary recovery is only 16.2%, and the current reservoir pressure is as low as 500 psia. The reservoir performance shows the driving mechanism in this zone is very weak water influx. Therefore a Waterflood and/or EOR Program need to be evaluated to increase oil recovery. Based on the screening criteria for oil fields in West Java, there are several possible CO2 flood candidates, one of which is the Jatibarang Field. A fluid compatibility test was conducted using Jatibarang Field fluids, from current to initial conditions. The fluid properties of current and initial conditions were compared and analyzed using numerical simulation. Then an appropriate fluid model was selected to represent the reservoir conditions. Regression and fine-tuning of the equation of state resulted in the fluid characterization

for this study. Tuning of the EOS should give a fluid model that closely matches the lab test results. Reservoir pressure is very important when it comes to designing gas and CO2 floods, as it is usually far below the MMP, as was the case in the Jatibarang Field. Based on the fine tuned fluid model, several gas and CO2 processes (immiscible and miscible flooding) were evaluated for the Jatibarang Field. These also included evaluation of different compositions of the natural gas and CO2 gas.

The best tuning of EOS will give the fluid model that closely matches the lab test results. and then the fluid is applied to the compositional reservoir simulation. More than 25 alternatives of gas injection is studied using the compositional simulation. The best recovery is combination of water injection, CO2, ethane and propane flooding (% incremental oil recovery). Introduction Gas and CO2 injection an reservoir oil has been widely used for the purpose of increasing oil recovery. Gas injection are used because of gas considered as non reactive gas, no needs special handling when the gas is produced with oil. Gas and CO2 flooding acts as an effective EOR method by reducing the remaining oil in the reservoir through several mechanisms (swelling, viscosity reduction, crude vaporization and miscible displacement). Most of the cases EOR is implemented after the primary recovery stage when the inner energy of the reservoir is not sufficient to produce the oil. The Jatibarang Field lies in the northwest Java Basin. It is located northwest of the city of Cirebon, West Java (Figure 1). Block III/Zone F of the Jatibarang Field has 31 wells. Currently, 12 wells are producing and 19 wells are inactive. The average reservoir depth is about 1140 m SS (3740’ SS). The field is considered as mature field and production only from primary recovery.

Most field applications and pilot tests of CO2 injection are for miscible floods. However, in the case where miscibility is not achievable, CO2 also dissolves in oil, swells the oil, reduces viscosity, and reduces interfacial tension. Khatib et al 1 described in their work involving field cases evaluating immiscible CO2 flooding, the use of CO2 is especially attractive in heavy oil, but may also be applicable in a number of light oil reservoirs at shallow depths, where pressure

SPE 97507

Gas Injection Programs in PERTAMINA West Java To Obtain Better Recovery: Field Screening, Laboratory and A Simulation Study B. Gunadi; PT PERTAMINA (PERSERO), IP. Suarsana; PT PERTAMINA (PERSERO), and T. Marhaendrajana; Institute Technology Bandung

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required for miscibility cannot be reached. Records of successful immiscible CO2 floods for increasing oil recovery in field and laboratory applications were published by Kantar et al.2, Spivak and Chima 3,4, Attanuci et al.5, Mangalsingh6, and Singh et al.7. In addition to providing energy to the reservoir CO2 flooding provides four mechanisms, which contribute to increased oil recovery. These are i) viscosity reduction, ii) oil swelling or expansion, iii) interfacial tension reduction, and iv) blow down recovery. The first three factors influence the improvement of the oil’s mobility and as a result increase the recovery 8. The blow down is associated with the residual CO2 within the reservoir that is liberated when the pressure is reduced below the saturation pressure. CO2 forms chemical bonds with some of the light end components of the heavy oil producing compounds of lower viscosity.

Results of these previously mentioned works were reviewed to evaluate the CO2 flooding potential of the Jatibarang Field, particularly Block III/Zone F. The goal of this study was to evaluate the reservoir aspect feasibility of CO2 flooding in a full-scale reservoir using numerical reservoir simulation. Field Screening Taber et al.9 summarize oil and reservoir characteristic for successful EOR methods. Based on those screening criteria, engineer team summarized the PERTAMINA mature fields located in west Java. There are several possible CO2 flood candidates, one of which is the Jatibarang Field. The screening criteria based on oil properties, reservoir characteristic, source of CO2 and remaining recoverable reserve. The summary table of Pertamina West Java field candidates can be seen in Table 1. Laboratory Work There are 2 field candidates being selected to have laboratory analysis of CO2 injection process. But in the lab analysis, it is only Jatibarang F3 oil can get the MMP. The MMP is 2575 psig. We decided to do further investigation of CO2 flooding in Jatibarang field. First fluid samples taken from Wells JTB-57 and JTB-140 in 1983, the fluid samples (liquid and gas) was analyzed for black oil PVT (differential liberation, separator test). The fluid composition from recombination of gas and liquid reservoir Jatibarang F3 can be seen in Figure 2. The swelling profile, saturation pressure and CO2 solubility of Jatibarang oil are presented in is presented in Table 2. The lab result from JTB-140 was the only used to characterize of the reservoir fluid for initial model fluid in the compositional simulation. The calculation of original oil in place of Jatibarang field based on the properties of this PVT. To support the evaluation of CO2 flooding, the next fluid sample was taken in 2003 at Well JTB-137. This fluid represent as a current fluid condition. Extensive laboratory

works were conducted include: gas and liquid recombination, pressure volume relationship, differential Vaporation, fluid viscosity measurement, swelling test, slime tube experiment to determine minimum miscibility pressure (MMP). PVT Modeling Before the compositional simulation model was constructed, PVT data, which was obtained from lab, were validated using equation of state phase property from commercial PVT simulation package. The validation include: selection of equation of state, characterization of C7+, fine tuning between the lab experiment data and PVT model, comparing the MMP, and swelling process. The Peng Robinson Equation of State (PR- EOS) was selected to model the phase behavior of our reservoir oil and fine-tuned using samples from JTB-140 and JTB-137. This process was performed to obtain a valid model that works and is consistent with the compositional changes. The example results of fine tuning process are presented in Figure 3-6 respectively. Geologic and Reservoir Description Jatibarang F3 reservoir is shelf carbonate platform reefal complex, and the trap is structural and stratigraphic. The field trends north south. The lithology is associated classic and carbonate framework. The original oil water contact is 1174 meters, and gas oil contact is 1100 meters. The average thickness of the reservoir is 4.3 meters. The horizon top and bottom structures are presented in Figure 7. The scarcity of core data from this zone is overcome by performing an integrated analysis of core, log, well test and production. This analysis provides meaningful reservoir description and characterization. The permeability and porosity transform is depicted in Figure 8. The average value for porosity, permeability and water saturation is 16%, 65 md, and 40% respectively. Maps of porosity, permeability, water saturation and ternary diagram are shown in Figure 9 to 14. Reservoir Model Validation The reservoir model is validated by history matching production and reservoir pressure. The results are summarized in Figures 15 to 18. Oil production starts declining in the middle of 1982, due to a lack of reservoir energy as indicated by declining reservoir pressure. The production becomes relatively steady after 1990, and the reservoir pressure maintains at about 500 psia due to weak support from a limited aquifer.

The results from the simulation model fit well with the oil/water production data, and the reservoir pressure data. The simulation model predicts fairly well the gas production from Block III/Zone F before 1992, but it underestimates the gas production afterward. The probable reason is the difficulties in allocating gas production from wells that are producing from commingled zones.

3 SPE 97505

Production Performance of Gas & CO2 Flooding Prediction of the continued existing production mechanism yields an oil recovery factor of 20.7%. From several scenarios of water flooding the maximum oil recovery factor achieved for this reservoir is 36.2% (a 15.5% incremental recovery).

Continuous flooding with pure CO2, field source CO2, and a mixture of CO2/Propane yield oil recovery of 25.1%, 26.3% and 37% respectively. The performance of continuous flooding of CO2 and field source CO2 is almost the same, only slightly better than current natural depletion. This indicates the concentration of CO2 does not provide any effect on the production performance. This may be caused by the high MMP, which cannot be achieved during injection. The mixture of CO2/Propane yields results little better than waterflooding. Results for various scheme of continuous CO2 flooding are plotted in Figure 20.

Simulation of WAG and slug injection scenarios yield a maximum oil recovery of 41%. The application of slug injection in the field may be easier than WAG injection. A slug size of 25% pore volume is considered optimum as it was observed from this study that increasing the slug size does not improved oil recovery for this reservoir. Results of various schemes of CO2 WAG flooding are plotted in Figure 19.

Combining CO2 injection at the top of the reservoir and water injection at the bottom improved oil recovery significantly especially for the CO2/C2/C3 mixture. The maximum oil recovery achieved 58.57% for the composition of 40%CO2 and 60% propane. If the gas injection is C2 and C3 and CO2 and combine with water injection, the recovery factor almost 64%. Production performances of these scenarios are plotted in Figure 21 to 22. Summary results of various optimum injection scenarios are presented in Table 3. CONCLUSIONS

1. CO2 flooding may yield a significantly incremental oil recovery. For Block III/Zone F Jatibarang Field, the preferred CO2 flooding mechanism appears to be a combination of water injection and continuous CO2/propane mixture injection; which results in oil recovery of 63.94% (43.28% incremental to existing ultimate primary recovery or 27.79% incremental to waterflood). However, if for economical reason propane is not viable as an injection fluid, slug injection of field source CO2 source is a potential candidate. This injection scheme yields 45.82% oil recovery (24.62% incremental to existing ultimate primary recovery, or 9.13% incremental to waterflood). But should be measured against waterflooding on an economical basis.

2. Implementation of the results from this study requires

evaluation of surface facilities and economics, as well as a more detail investigation on the injection pattern.

REFERENCES 1. Khatib, A.K., Earlougher, R.C. and Kantar, K.: “CO2 Injection

As An Immiscible Application For Enhanced Recovery in Heavy Oil Reservoir”, Paper SPE 9928, presented at The 1981 California Regional Meeting, Bakersfield, California, March 1981.

2. Kantar, K., Karaoguz, D., Issever, K. and Varana, L.: ”Design Concepts of Heavy-Oil Recovery Process by an Immiscible CO2 Application”, JPT (1985), 275-283.

3. Spivak, A. and Chima, C.M.: ”Mechanisms of Immiscible CO2 Injection in Heavy Oil Reservoirs, Wilmington Field, CA. Paper SPE 12667, presented at The 1984 California Regional Meeting, Long Beach, CA, April 1984.

4. Spivak, A., Garrison, W.H. and Nguyen, J.P.: ”Review of an Immiscible CO2 Project, Tar Zone , Fault Block V, Wilmington Field, California”, SPERE (1990), 155-162.

5. Attanucci, V., Aslesen, K.S. and Wright, C.A.: “WAG Process Optimization in the Rangely CO2 Miscible Flood”, Paper SPE 26622, presented at The 68th Annual Technical Conference and Exhibition of The Society of Petroleum Engineers, Houston, TX, October 1993.

6. Mangalsingh, D.: ”A Laboratory Investigation of The Carbon

Dioxide Immiscible Process,” Paper SPE 36134, presented at The 4th Latin American and Caribbean Petroleum Engineering Conference, Port of Spain, Trinidad and Tobago, April 1996.

7. Singh, L., Lorna, J. and Singhal, A.K.: ”Lessons From

Trinidad’s CO2 Immiscible Pilot Projects 1973-2003”, Paper SPE 89364: Presented at The 2004 SPE/DOE Fourteenth Symposium in Improved Oil Recovery, Tulsa, OK, April 2004.

8. Klins, M.A.: ”Carbon Dioxide Flooding Basic Mechanisms and Project Design,” International Human Resources Development Corporation, Boston, USA, 1984.

9. Taber, J.J., Martin, F.D., and Seright, R.S.: “EOR Screening

Criteria Revised-Part 1:Introduction to Screening Criteria and Enhanced Recovery Fields Projects”, SPERE, August 1997.

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Figure 1. PERTAMINA Jatibarang (West Java – Indonesia) Field Location

Jatibarang

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Figure 2. Gas Composition of Jatibarang Field

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Table 1. Field Candidate for CO2 Flooding - PERTAMINA West Java Fields

F/Block III

JTRB F/3

PENGADEN BRF

PENGADEN Z16

TUNGGUL MAUNG PARIGI TGB-A

GRAVITY ºAPI 38 48 29.51 26 40

VISCOSITY ( cp ) 0.0195 0.17 0.1751

19.43 122F 2.76

COMPOSITION 88.94 3 3 ???? 55

OIL SATURATION 44 65 64 65 50

FORMATION TYPE LST

EQ.BRF LST LST LST

PARIGI LST

NET THICKNESS

( Ft ) 19.26 16.05 32.81 13.124 29.529

AVERAGE PERMEABILITY

(md) 22 3.6 40 ?? 2500

DEPTH ( Ft ) 3723.935 5955.015 6562 7119.77 2821.66

TEMPRATURE ( ºF ) 204 235 276 255 203

OOIP MMSTB 58.7 0.718 0.302 2.428 38

Cum. Production

MMSTB 9.4 0.0003 0.0067 0 8.85

Remaining reserve 49.3 0.7177 0.2953 2.428 29.15

Reservoir Pressure

(Current) Psia 603 2100 3077 3500 1000

CO2 From OWN FIELD IMPORT (15KM) IMPORT (15KM) OWN FIELD OWN FIELD

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Table 2. Laboratory Results of CO2 Swelling Using Sample from JTB-137 (Current Fluid)

Fluid Systems

Saturation Press. Psia

Solubility of Injected CO2 SCF/bbl-Resv*

Swelling factor Bbl/bbl**

Original Reservoir Oil 454 - 1.00

CO2/Oil System I 1162 371.51 1.11

CO2/Oil System II 1850 958.49 1.31

CO2/Oil System III 2490 2071.15 1.72

* Volume of CO2 per barrel of original reservoir oil ** Ratio of volume at saturation pressure (Vsat/Vinitial sat)

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Dif. Lib. Calc. JTB#137

0

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140

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Dif. Lib. Calc. JTB#140Regression Summary

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Figure 3. PVT Modeling result of JTB#137 (Current Fluid) Figure 4. PVT Modeling result of JTB#140 (Initial Fluid)

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Figure 5. Effect of % Make Up Gas to Multi Contact Miscible Figure 6. Comparison of Swelling Model and Lab Result JTB#137 Oil

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Figure 7. Structure and Horizon of Jatibarang F3

Top Structure Structure

Bottom Structure BBotomBottomBott

om

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Figure 8- Permeability-Porosity Transform of Jatibarang F3

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Figure 9. Porosity Distribution of Jatibarang F3

MODELING AND INTEGRATION

Iso-Porosity Mapping and Gridding

Mapping Result Gridding Result

Effective Porosity

3D projection

HIGH AREA

LOW AREA

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Figure 10. Permeability Distribution of Jatibarang F3

MODELING AND INTEGRATION

Iso-Permeability Mapping and Gridding

Mapping Result Gridding Result

Effective Permeability

3D projection

HIGH AREA

LOW AREA

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Figure 11. 3D Water Saturation at Initial Condition Figure 12. 2D Water Saturation at Water Injection Started

Figure 13. 2D Ternary Diagram at Gas Injection Started Figure 14. 2D Ternary Diagram at End Project (CO2/C3 Case)

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Figure 15. History Matching of Oil Rate and Cumulative Production Figure.16 History Matching of Water Rate

Figure 17. History Matching of Gas Rate Figure 18 History Matching of Reservoir Pressure

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Figure 19 Production Profile of Various WAG CO2 injection Figure 20 Production Profile of Various Continuous CO2 injection

Figure 21. Production Profile of Various CO2 Inj. & Water Flooding Figure 22. Production Profile of Various Continuous CO2/Gas Injection

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Table 3. Summary Results of Oil Recovery from Optimum Injection Scenarios

No Injection Scenario Np RF Rec Res Add RF(MM Bbl) (%) (MM Bbl) (%)

1 Inj CO2 Propane (CO2=30%, C2toC3=70%)+ Waterflood 34.7 63.94 26.11 48.112 Inj CO2 (40%)Propane(60%) + Water Flood 31.22 58.57 22.63 37.923 Water Flood +Inj CO2 (40%)Propane(60%)+Water Flood 22.34 41.91 13.75 21.264 Slug CO2 Propane (CO2=10%, C2toC3=90%) 24.87 45.82 16.28 29.995 Slug CO2 Source 25%PV 22.28 41.8 13.69 21.146 Slug CO2 Pure 40%PV 22.25 41.74 13.66 21.097 Slug CO2 Source 40%PV 22.15 41.56 13.56 20.98 WAG CO2 Source 22.05 41.37 13.46 20.719 Slug CO2 Pure 25%PV 22.04 41.35 13.45 20.6910 WAG CO2 Pure 21.86 41.01 13.27 20.3611 Slug CO2 Propane 40%PV 21.47 40.28 12.88 19.6212 Inj CO2 Source + water flood 21.45 40.24 12.86 19.59