_____________________________________________________________________________

* Institute of Technology Bandung

** PetroChina International Bermuda, Ltd

*** LAPI ITB

IPA15-E-094

PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION

Thirty-Ninth Annual Convention & Exhibition, May 2015

LABORATORY TEST OF CHEMICAL SELECTION FOR ENHANCED OIL RECOVERY IN

FRACTURED CARBONATE RESERVOIRS,

CASE STUDY: KAIS FORMATION ON WAKAMUK FIELD

Jackson Andreas Theo Pola*

Leksono Mucharam*

Hari K. Oetomo**

Budi Susanto**

Wisnu Nugroho***

ABSTRACT

About half of the world oil reserves are located in

carbonate reservoirs (Roehl and Choquette, 1985),

where 65% of the total carbonate reservoirs are oil

wet and 12% intermediate wet (Chillingar and Yen,

1985). Oil recovery in oil wet or mixed wet carbonate

reservoirs can be increased by dissolving surfactant

to injected water to change the rock wettability from

oil wet to more water wet.

The Wakamuk Field operated by PetroChina

International (Bermuda) Ltd. and PT. Pertamina EP

in Papua, produces from main reservoir of Miocene

Kais Limestone. First production commenced on

August, 2004 and the peak field production of 1456

BOPD occurred in August, 2010. It was found that is

a complex reservoir system and until 2014

cumulative oil production was 2.07 MMBO, less

than 9% of OOIP. This performance is indicative of

presence of secondary porosity, other than matrix

porosity which is of low average porosity 13% and

permeability less than 7 mD.

Implementing chemical EOR in this case is the best

way to increase oil production. However, the

selected chemical must be able to lower the

interfacial tension (IFT), reduce oil viscosity, and

alter the wettability; thus a special chemical

treatment named SeMAR has been proposed.

Numerous laboratory tests such as phase behavior

test, core compatibility test, mixture viscosity,

contact angle measurement, IFT, imbibitions test and

core flooding were conducted on Wakamuk field

samples.

Based on the spontaneous imbibitions results for

Wakamuk field core, formulation of SeMAR with

compositional S12A gave oil recovery 43.94% at

1wt% concentration and maximum percentage of oil

recovery 87.3 % at 3 wt% concentration respectively.

In addition, the results for first scenario of core

flooding test gave oil recovery 60.32% at 1 wt%

concentration S12A and the second scenario gave

96.78% of oil recovery at concentration 3 wt%

respectively. The soaking time of chemicals has a

significant effect on the recovery and higher

chemical concentrations affect larger areas for

wettability and therefore, higher oil recovery.

The chemical that gives best overall results from

laboratory tests study will also be a consideration for

Huff and Puff injections trial (pilot project) for

increasing oil recovery from Wakamuk Field.

Keywords:Wakamuk Field, chemical treatment,

natural fractured, carbonates.

INTRODUCTION

Wakamuk Field background

Wakamuk Field is an oilfield in the area of Salawati

Basin (Papua) discovered in May 2004 which is

located on Walio Block between the oil fields of

Walio to northwest, Sele to the north-northeast and

South Walio A-1X oil discovery well to the south,

with objective Miocene Kais Limestone (Figure 1).

During DST, initial reservoir temperature was 160o F

with reservoir pressure at 946 psi. Bubble point

pressure is assumed at 20 bar (290 psi) and water

salinity measured 9425 ppm. The oil gravity

measured at 37o API with oil viscosity 3.1 cP. First

production commenced in August, 2004 peaking at

1456 BOPD in August, 2010 with water cut around

25% from 16 active wells of total 18 wells in

Wakamuk Field. The reservoir cores appear to be

ACKNOWLEDGEMENT

The authors wish to express their appreciation to

PetroChina International Bermuda, Ltd,

SKKMIGAS, DITJEN MIGAS, and the Government

of Indonesia for allowing the publication of this

paper. Special thanks to Hari K. Oetomo as General

Manager and Budi Susanto as Production

Engineering Manager of PetroChina International

Bermuda, Ltd for their support and special

appreciation to Ir. Leksono Mucharam, M.Sc, Ph.D.,

for his guidance, and patience during this research.

REFERENCES

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Recovery from Fractured Carbonates by Surfactant-

Aided Gravity Drainage: Laboratory Experiments

and Mechanistic Simulations, SPE 99773,

Proceedings of Symposium on Improved Oil

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Austad, T., Milter, J. (1997): Spontaneous Imbibition

of Water into Low Permeable Chalk at Different

Wettabilities Using Surfactants. SPE 37236,

International Symposium on Oilfield Chemistry,

Houston.

Chilingar, G.V., Yen, T.F, (1983): Some notes on

wettability and relative permeabilities of carbonate

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Fractured Carbonates, SPE 110204, proceedings of

Annual Technical Conference and Exhibition, 11–

14. Anaheim.

Healy, R.N., Reed, R.L. (1973): Physicochemical

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SPE-AIME 48th Annual Meeting, Las Vegas.

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Stegemeier, G.L. (1984): Cosurfactant-enhanced

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(2004): Physicochemical interactions during

surfactant flooding of fractured carbonate reservoirs.

SPE J. 9 (4), 411–418.

Standnes, D.C., Nogaret, L.A.D., Chen, H.L.,

Austad, T. (2002): An evaluation of spontaneous

imbibition of water into oil-wetcarbonate reservoir

cores using a nonionic and a cationic surfactant.

Energy Fuels 16, 1557–1564.

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laboratory evaluation of the wettability of fifty oil-

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The Effect of Temperature and Potential

Determining Ions Present in Seawater on Oil

Recovery From Fractured Carbonates, SPE 99438,

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Roehl, P.O. and Choquette, P.W. (1985): Carbonate

Petroleum Reservoirs, Springer-Verlag, New York

Zhou, X., Morrow, N. R. and Ma, S., (1996) :

“Interrelationship of wettability, initial water

saturation, Aging time and oil recovery by

spontaneous imbibition and waterflooding” Paper

SPE 62507, Revised from SPE 35436, SPE/DOE

Symposium on improved oil recovery, Tulsa.

TABLE 1

LIST OF CHEMICALS

NO Chemicals Surfactant type Active

Content

1 S10 Non-ionic Surfactant 100%

2 S12A Non-ionic Surfactant 100%

3 S13A star Cationic Surfactant 100%

4 S13B Non-ionic Surfactant 100%

5 S14A Non-ionic Surfactant 100%

6 S14A star Non-ionic Surfactant 100%

7 S14B Non-ionic Surfactant 100%

8 S15A Non-ionic Surfactant 100%

9 S15A star Non-ionic Surfactant 100%

10 S15B Non-ionic Surfactant 100%

11 S16A Non-ionic Surfactant 100%

12 S17A Anionic Surfactant 100%

13 S17B Anionic Surfactant 100%

14 S18A Non-ionic Surfactant 100%

TABLE 2

THE RESULTS OF THE IMBIBITION TEST FOR WAKAMUK FIELD

No SeMAR

Formula Core Code

Porosity

(%)

Soaking

Time

(Day)

% Oil

Recovery

Well WAKAMUK #10

1 Brine WK#10-2 26.3578 15 12.77

2 S12A 1% WK#10-14 26.7889 15 43.94

3 S12A 3% WK#10-5 20.958 15 87.54

4 S13A* 1% WK#10-9 33.5475 15 18.38

5 S16A 1% WK#10-17 28.1235 15 21.31

6 S18A 1% WK#10-13 26.3068 15 18.17

7 S14A 1% WK#10-8 25.1418 15 25.41

8 S14A* 1% WK#10-10 25.1457 15 29.64

9 S15A 1% WK#10-16 24.5568 15 19.67

10 S15A* 1% WK#10-12 26.6763 15 38.59

Well WAKAMUK #5

1 Brine WK#10-2 26.3578 15 24.68

2 S12A 1% WK#10-14 26.7889 15 56.32

3 S13A* 1% WK#10-9 33.5475 15 35.29

4 S14A* 1% WK#10-10 25.1457 15 50.58

5 S15A* 1% WK#10-12 26.6763 15 32.07

TABLE 3

THE RESULTS OF THE CORE FLOODING

Scenario Concentration Injection

Rate Soaking Time RF Max

Scenario #1 1 wt%

surfactant 0.2 cc/min

Water flooding

60.32% Direct Injection

1 hour

24 Hours

Scenario #2 3 wt%

surfactant 0.2 cc/min

Water flooding

96.78% Direct Injection

1 hour

24 Hours

Figure 1 - Wakamuk Field Location Map

Figure 2 - Wkm#10 Field Core after drilled

Figure 3 - Wkm#5 Field Core after drilled

Figure 4 - Contact Angle Measurement: A) Wakamuk─10-7A with Formation water; B) Wakamuk─10-7

with Crude oil

Figure 5 - Phase behavior

Figure 6 - Spontaneous Imbibition Test Results using Field Core of Wakamuk #10

Figure 7 - Spontaneous Imbibition Test Results using Field Core of Wakamuk #5

0

10

20

30

40

50

0 3 6 9 12 15

% O

il R

eco

very

Soaking Time (Days)

Spontaneous Imbibition Test for Wakamuk#10(Depth. 2288-2291 ft)

S12A 1% (WK#10-14)

S15A* 1% (WK#10-12)

S14A* 1% (WK#10-10)

S14A 1% (WK#10-8)

S16A 1%(WK#10-17)

S15A 1% (WK#10-16)

S13A* 1% (WK#10-9)

S18A 1% (WK#10-13)

Formation Water (WK#10-2)

0

10

20

30

40

50

60

0 3 6 9 12 15

% O

il R

eco

very

Soaking Time (Days)

Spontaneous Imbibition Test for Wakamuk#05(Depth. 2253-2256 ft)

S12A 1% (WK#5-7)

S14A* 1% (WK#5-8)

S13A* 1% (WK#5-2)

S15A* 1% (WK#5-9)

Formation Water (WK#5-3)

Figure 8 - IFT values with varying SeMAR S12A concentration

Figure 9 -Graph of Mixture Viscosity of Wakamuk crude oil

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

0 10 20 30 40 50 60 70 80 90 100

Vis

cosi

ty (

cP)

% Oil

Mixing Viscosity Measurement Wakamuk Crude oilS15A* 1%

S12A 3%

S15A 1%

S12A 1%

S14A* 1%

S14A 1%

S18A 1%

S13A* 1%

S16A 1%

Figure 10 - Core flooding Scenario #1

Figure 11 - Core flooding Scenario #2

0

20

40

60

80

100

0 2 4 6 8 10 12 14 16 18 20 22 24

RF

& W

C (

%)

PV

Pore Volume (PV) vs Water Cut (WC) & Recovery Factor (RF) CURVEKais Formation, Wakamuk #10 -18 SEMAR S12A 1wt% (Scenario #1)

Start Injection S12Awith Soaking 2 hours

Start Direct Injection S12AStart Water

Flooding

Stop Water Flooding

Start Injection S12Awith Soaking 1 day

Stop DirectInjection S12A

Stop Injection S12Awith Soaking 2 hours

Stop Injection S12Awith Soaking 1 day

RF max: 60,32%

0

20

40

60

80

100

0 2 4 6 8 10 12 14 16 18 20 22 24

RF

& W

C (

%)

PV

Pore Volume (PV) vs Water Cut (WC) & Recovery Factor (RF) CURVEKais Formation, Wakamuk #10-18, SEMAR S12A 3wt% (Scenario #2)

Start Injection S12Awith Soaking 2 hours

Start Direct Injection S12A

Start Water Flooding

Stop Water Flooding

Start Injection S12Awith Soaking 1 day

Stop Direct Injection S12A

Stop Injection S12Awith Soaking 2 hours

Stop Injection S12Awith Soaking 1 day

RF max: 96,78%

Figure 2 - Wettability Alteration on spontaneous imbibition test

Figure 3 - Fractured Carbonate core from Kais formation; A). Well cleaned core; B). Core after saturated by

oil; C). Photographs of core Wkm#10