Techno-Economic Solution For Extending Ccus Application In Natural Gas Fields: A Case Study Of B Gas Field In Indonesia

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Techno-Economic Solution for Extending CCUS Application in Natural Gas Fields: a Case Study of B Gas Field in Indonesia

Prasandi Abdul Aziz¹, Mohammad Rachmat¹, Steven Chandra¹, Wijoyo Niti Daton¹ and Brian Tony²

1Dapartment of Petroleum Engineering, Faculty of Mining and Petroleum Engineering Institut Teknologi Bandung Jl. Ganesha 10 Street, Lb. Siliwangi, Kecamatan Coblong, Bandung, Jawa Barat 40132, Indonesia

2Dapartment of Petroleum Engineering, Faculty of Technology Mineral Universitas Pembangunan Nasional

“Veteran” Yogyakarta

Padjajaran Street, Sleman, Yogyakarta 55283, Indonesia Corresponding author: [email protected]

Manuscript received: February 21^th, 2023; Revised: March 31^th,2023 Approved: May 09^th,2023; Available online: May 17^th,2023

How to cite this article:

Prasandi Abdul Aziz, Mohammad Rachmat, Steven Chandra, Wijoyo Niti Daton and Brian Tony, 2023, Techno-Economic Solution for Extending CCUS Application in Natural Gas Fields: a Case Study of B Gas Field in Indonesia, Scientific Contributions Oil and Gas, v46 (1) pp., 19-28 DOI.

org/10.29017/SCOG.46.1.1321.

SCIENTIFIC CONTRIBUTIONS OIL AND GAS

Testing Center for Oil and Gas LEMIGAS

Journal Homepage:http://www.journal.lemigas.esdm.go.id ISSN: 2089-3361, e-ISSN: 2541-0520

ABSTRACT - The application of carbon trading has been applied since 2005 in Northern America, has been adapted in Indonesia with pilot scale implementation namely as Carbon Capture and Storage. One of the biggest issue is the lack of financial incentive in conducting the CCS. Therefore, Carbon Capture, Utilization and Storage (CCUS) serves as an alternative to increase the economic value of the injected CO2. This study presents a new approach of CCUS studied in B Field in Indonesia, a natural gas producer with high CO2 and H2S content. By injecting CO2 as a mean of pressure maintenance, 5.8% of incremental gas production is achieved whilst being able to sequester 2.7 million tonnes of CO2 for 10 years operation. This study should become a pioneer in continuing researches related to enhanced CCS methods by increasing the value of CO2 as well as reducing dependency in expensive chemical EOR injection in the future.

Keywords: Carbon Capture and Storage (CCS), Carbon Capture, Utilization and Storage (CCUS), CO2, EOR

INTRODUCTION Background

The concept of Carbon Capture and Storage has been an endless talk since its inception in 2005 (IPCC, 2005). It has been projected that CCS will become one of the most effective solution in reducing the externalities generated from carbon dioxide pol- lution namely in large scale industries such as power plant, factories, and oil & gas industry. CCS has been successfully performed in several countries such as France, United States, Norway, and Canada (Global

CCS Institute, 2017). Yet the problem arises when this policy cannot be wholly implemented in grow- ing countries, such as Indonesia. One of the biggest obstacles that has to be faced is the lack of financial incentive in performing CCS, which is sometimes viewed as a non-rewarding work. Therefore, it is im- perative to present an innovation in order to increase the economic attractiveness of CCS.

Indonesia, as one of the emerging economics in the world, is highly reliant on fossil fuel to power its economics. One of the most reliant sectors is oil and gas exploitation where approximately 47

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this sector alone. The concern arises as Indonesia’s economic growth goes bigger every year, its dependency on fossil fuel would render higher emission and reducing quality of life. However, without any incentive from the government to utilize CCS, major oil and gas companies does not have any intention in performing it without any certainties of both financial and legal underlying laws. In order to adapt the concept of CCS, it is then modified into Carbon Capture, Storage, and Utilization (CCUS) where the injected CO₂ does not only trapped but also provide some economic value, mostly to oil and gas busi- ness as an extension to Enhanced Oil Recovery, a method to produce oil from reservoir that previously cannot be produced under conventional method or waterflood (Green & Willhite, 1998). However, CO₂- EOR cannot be implemented in a shorter timeframe as it requires lengthy study, around 7-10 years and Indonesia’s reservoir condition does not support field-wide, full scale EOR (Muslim, 2013; Chandra

on how to mitigate CO₂ production by reinjection to aquifer of gas reservoir, a concept which has not been previously applied due to the difficulty in finding the perfect sink. This study utilizes data from B Field in Indonesia, a highly productive natural gas field with excessive CO₂ production, intended to prove the concept of Enhanced Gas Recovery (EGR) potential.

Amijaya (2009), Usman (2021) and Bachu (2015) highlighted that exceptional CO₂ trapping mechanism would be performed on solubility and mineral trapping. It is most often that stratigraphic trapping would only be consistent for tens of years before CO₂ plume starts leaking, therefore the relatively massive aquifer present in B field would be an ideal solution for long term CO₂ sequestration, and also the presence of natural gas would be an added incentive for injecting CO₂ as a measure of pressure maintenance.

Historical study in the nearby Gundih area has also proven that CCUS study can be performed without additional uncertainties (Asikin, 2015 & Tsuji, 2014).

Figure 1 B Field location

Gundih Area Depth Structure Map

1:500000

0 500 1000 1500 2000 2500m

548800 548000 547200

546400 549600 550400 551200 552000 552800 553600 554400 555200 556000

0

9200000920100092020009203000920400092060009205000 556000 555200 554400 552800 553600 552000

551200 550400 549600 548800 548000 546400 547200 0

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(Prasandi Abdul Aziz, et al.)

Field Characterization

B Field is a part of East Java Basin, seen on Figure 1, comprising of several major fields such as Bukit Tua, Banyu Urip, and Sukowati Oil and Gas Fields with estimated reserves of 15 billion barrels of oil and 19 trillion cubic feet of natural gas located in the Oligo-Miocene reef based basin system (Satyana, 2002). Even though oil and gas has been actively explored since the times of Dutch East In- dies, economically developing massive gas reserves in East Java Basin has been a challenge due to its nature, namely high presence of CO₂ and occasional presence of H₂S. These issues require technological advancements not only in gas separation issues, but

also mitigation of CO₂ and H₂S waste. B Field has been operated since 2011, operated by Pertamina EP Asset-4. There are currently 5 active producing wells in the development area, shown below, bordering another prominent Randublatung Field. Based on geological characterization, B Field produces from carbonate reservoir with the main productive zone of Kujung Formation (Affandi et al, 2011). Produced reservoir fluid can be classified as retrograde condensate with high CO₂ (> 22%) and H₂S content (> 4000 ppm). Despite its challenge, the reservoir has been produced for almost 10 years, extracting around 79 BSCF of gas and 600 MSTB of oil.

Figure 2

Location of The injected well

B Producer Wells Last Q8 : 44 MMSCFD

CCS Injec�on Well (INJ-2, INJ-3, INJ-4) Using KTB-02 wellpad Surface Coordinate:

X: 554412.83 m Y: 9203232.44 m

Notes:

Porosity map overlays with Top Kujung Depth Structure

1:500000

500 1000 1500 2000 2000m

546400 547200 548000 548800 549600 550400 551200 552000 552800 553600 554400 555200 555600 556400 557200 558000

0

920000092010009202000 920300092040009205000

920500009204000092030000920200009201000092000000

546400 547200 548000 548800 549600 550400 551200 552000 552800 553600 554400 555200 555600 556400 557200 558000

D2400 D2200 D2000 D1800 D1600 D1400 D1200 D1000 D0800 D0600 D0400 D0200

B Producer Wells Last Q8 : 44 MMSCFD

CCS Injec�on Well (INJ-2, INJ-3, INJ-4) Using KTB-02 wellpad Surface Coordinate:

X: 554412.83 m Y: 9203232.44 m

Notes:

Porosity map overlays with Top Kujung Depth Structure

1:500000

500 1000 1500 2000 2000m

546400 547200 548000 548800 549600 550400 551200 552000 552800 553600 554400 555200 555600 556400 557200 558000

0

920000092010009202000 920300092040009205000

920500009204000092030000920200009201000092000000

546400 547200 548000 548800 549600 550400 551200 552000 552800 553600 554400 555200 555600 556400 557200 558000

D2400 D2200 D2000 D1800 D1600 D1400 D1200 D1000 D0800 D0600 D0400 D0200

In order to extend the lifetime of the reservoir, an idea is presented to inject CO₂ into the aquifer as a method of pressure maintenance to the gas reservoir above. It is a general practice that exploitation of gas reservoir hinges only on natural pressure difference between gas reservoir and the wellhead pressure, therefore maintaining high pressure is crucial in order to extend the life of gas reservoir. 2 wells are proposed to be an injection point of produced CO₂, seen below. It is also important to note that the ef- fectivity of CCUS in maintaining gas reservoir pressure is reliant on CO₂ sequestration capacity of the

aforementioned reservoir. Therefore, a correlation proposed by Goodman et al (2011) is proposed as a method to estimate the amount of CO₂ stored with three confidence levels shown below.

Table 1

Estimation of CO2 storability in B field Pore Volume

(m³)

࣋_ࢉ࢕૛

(kg/m³)

GCO2

Low (Mt)

GCO2

Best (Mt)

GCO2

High (Mt)

671 x 10⁶ 435 1.17 4.38 11.97

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In order to build a comprehensive case study that acknowledges uncertainties in CCUS for gas reservoir, several scenarios of injected CO₂ are then presented as shown on the list below.

• History Matching: 2014-2018

• Injection Start-up: Jan-2019

• Prediction until 2119 (100 years after injection)

• Case-1 (28 ton CO₂ / day)

CO₂ injection rate: 0.57 MMSCFD Injection Duration: 2 years

• Case-2 (143 ton CO₂ /day) Pilot Project CO2 injection rate: 2.85 MMSCFD Injection Duration: 2 years

• Case-3 (750 ton CO₂ / day) Full Capacity of Gundih CPP

CO₂ injection rate: 15 MMSCFD Injection Duration: 10 years

The following figures show reservoir fluid phase diagram, shown on Figure 3, concludes that the reservoir is a retrograde condensate reservoir, with Initial Gas In Place (IGIP) of 297 BSCF and Initial Condensate in Place (ICIP) of 4.6 MMSTB.

Figure 3

Reservoir fluid characterization for B field

model is first subjected into history matching, an ef- fort to calibrate the reservoir model against test data from actively producing wells. There are several op- tions to history match a natural gas reservoir, namely against gas rate, condensate rate, and/or bottom hole pressure. However, due to timing constraint of the study, only gas rate is matched, shown below, since the research emphasizes on the ability of injected CO₂ to maintain reservoir pressure and prolongs constant gas production rate (“plateau time”).

Several assumptions are made in order to en- hance the viability of the model, namely:

• k_v/k_h : 0.5 (RCAL data in water / targeted zone is required to reduce uncertainty)

• No hysteresis effect: no residual CO₂ trapping (SCAL data is required)

• Maximum Injection Pressure equals to Fracture Pressure, i.e. 8,000 psi (± 551 bar)

• The B field still producing (using last historical gas rate, i.e. q_g = ± 44 MMSCFD) until the end of field life

• Fluid Injection Composition: 100% CO₂ (in actual condition, H₂S can also be injected into reservoir but requires further study on well integrity)

Retrograde / Condensate Gas

Temperature, [degC]

-60 -40 -20 0 20 40 60 80 100 120 140 160 180 200 220 240

HYDROCARBON ANALYSIS OF SEPARATOR PRODUCTS AND CALCULATED WELL STREAM

Component ^SeparatorLiquid Mol%

Separator Gas Well Stream Mol % ^{Weight %} GPM

MOL % Hydrogen Sulphide

Carbon Dioxide Nitrogen Methane Ethane Propane i-Butane n-Butane i-Pentane n-Pentane Hexanes Heptanes Octanes Nonanes Decanes Undecanes Dodecanes plus Total

0.069 0.951 0.165 1.102 0.309 0.400 0.195 0.414 0.405 0.490 1.938 7.692 14.435 15.646 10.419 7.065 38.305 100.000

0.468 22.869 0.353 71.444 2.706 1.001 0.195 0.267 0.107 0.090 0.110 0.228 0.122 0.027 0.009 0.004 0.000 100.000

0.467 22.811 0.353 71.256 2.700 0.999 0.195 0.267 0.108 0.091 0.115 0.248 0.160 0.069 0.036 0.023 0.102 100.000

0.656 41.412 0.407 47.157 3.349 1.818 0.468 0.641 0.321 0.271 0.398 0.869 0.646 0.315 0.196 0.138 0.938 100.000 0.724

0.276 0.064 0.084 0.039 0.033 0.045 0.080 0.049 0.013 0.005 0.002 0.000 1.414

0 4080120160200240280320360400

240 220 200 180 160 140 120 100 80 60 40 20 0 -20 -40 -60 -80

400

-80 80120160 200240280320360400

Temperature, [degC]

-60 -40 -20 0 20 40 60 80 100 120 140 160 180 200 220 240

Component ^Separator^Liquid Mol%

Separator Gas Well Stream

Mol % ^{Weight %} GPM

0.069 0.951 0.165 1.102 0.309 0.400 0.195 0.414 0.405 0.490 1.938 7.692 14.435 15.646 10.419 7.065 38.305 100.000

0.468 22.869 0.353 71.444 2.706 1.001 0.195 0.267 0.107 0.090 0.110 0.228 0.122 0.027 0.009 0.004 0.000 100.000

0.467 22.811 0.353 71.256 2.700 0.999 0.195 0.267 0.108 0.091 0.115 0.248 0.160 0.069 0.036 0.023 0.102 100.000

0.656 41.412 0.407 47.157 3.349 1.818 0.468 0.641 0.321 0.271 0.398 0.869 0.646 0.315 0.196 0.138 0.938 100.000 0.724

0.276 0.064 0.084 0.039 0.033 0.045 0.080 0.049 0.013 0.005 0.002 0.000 1.414

0 4080120160200240280320360400

240 220 200 160 180 140 100 120 80 40 60 0 20 -20 -40 -60 -80

400

-80 80120160 200240280320360400

Temperature, [degC]

-60 -40 -20 0 20 40 60 80 100 120 140 160 180 200 220 240

Component ^SeparatorLiquid Mol%

Separator Gas Well Stream

Mol % Weight % GPM

0.069 0.951 0.165 1.102 0.309 0.400 0.195 0.414 0.405 0.490 1.938 7.692 14.435 15.646 10.419 7.065 38.305 100.000

0.468 22.869 0.353 71.444 2.706 1.001 0.195 0.267 0.107 0.090 0.110 0.228 0.122 0.027 0.009 0.004 0.000 100.000

0.467 22.811 0.353 71.256 2.700 0.999 0.195 0.267 0.108 0.091 0.115 0.248 0.160 0.069 0.036 0.023 0.102 100.000

0.656 41.412 0.407 47.157 3.349 1.818 0.468 0.641 0.321 0.271 0.398 0.869 0.646 0.315 0.196 0.138 0.938 100.000 0.724

0.276 0.064 0.084 0.039 0.033 0.045 0.080 0.049 0.013 0.005 0.002 0.000 1.414

0 4080120160200240280320360400

220 240 200 180 160 140 120 100 80 60 40 20 0 -20 -40 -60 -80

400

-80 80120160 200240280320360400

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Figure 4

Results of gas rate history matching

Symbol Legend

1-SEP-2014 1-JAN-2015 1-MAY-2015 1-SEP-2015 1-JAN-2016 1-MAY-2016 1-SEP-2016 1-JAN-2017 1-MAY-2017 1-SEP-2017 1-JAN-2018 1-MAY-2018 1-SEP-2018 1-JAN-2019

Field Gas Produc�on Rate

1-SEP-2014 1-JAN-2015 1-MAY-2015 1-SEP-2015 1-JAN-2016 1-MAY-2016 1-SEP-2016 1-JAN-2017 1-MAY-2017 1-SEP-2017 1-JAN-2018 1-MAY-2018 1-SEP-2018 1-JAN-2019

Gas produc�on cumula�ve CASE 1

Gas produc�on cumula�ve Observed Gas produc�on cumula�ve Observed Gas produc�on cumula�ve CASE 1

Gas Produc�on Volume, [sm3] 02E+8 4E+8 6E+8 8E+8 1E+9 1.2E+9 Gas Flowrate, [sm3/d] 1200000160000020000008000004000000

1.4E+9

The injection wells are located in the existing wellpad B-2, shown below, utilizing deviated well and perforated for 20 ft from 3896-3916 m MD. It is also important to note that the injection process is

Figure 5 Injection well placement

performed below the gas-water contact therefore reducing the possibility of CO₂ leakage into the surface and limiting its role as pressure maintenance only.

Using existing wellpad (KTB-02)

Well head:

Target

Permeability [mD]

544000 544800 545600 546400 547200 548000 548800 549600 550400 551200 552000 552800

00 553600

00 554400

0 555200

0 556000

0

920000092010009202000920300092040009205000

544000 544800 545600 546400 547200 548000 548800 549600 550400 551200 552000 552800 553600 554400 555200 556000

1:500000

0 500 1000 1500 2000 2500m

55412.83 9203232.44 26.20

X: Y: Z:

AZIM:

DeltaMD:

DLS:

DeltaMD:

TVD:

555338.42 DeltaMD:

INCL:

9204835.60 -3582.48 X: Y: Z:

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The following three cases are simulated for 100 years continuous CO₂ injection in order to monitor CO₂ plume growth as a function of time, as well as its effect on the overall performance to maintain ad- equate aquifer support for enhanced gas production.

• Case 1 (CO₂ Injection Rate 28 tonnes/day) The following figure 6 shows CO2 plume

Figure 6

Cross section view of plume growth in case 1

growth of only 0.2 km in circumference is encountered during the 100 year injection.

As it is evident on the attached figures, mini- mum displacement is encountered on the first case.

However small it is, this injection sequence is highly important to be conducted prior to larger field scale injection process in order to assess reservoir storability and any potential of leakage.

Figure 7

Lateral view of plume growth for case 1

(a)Initial (b)2 years after injection (c)100 years after injection

Total mole fraction (Component(CO2) ZMF)

FRACTION Total mole fraction (Component(CO2) ZMF)

FRACTION

Total mole fraction (Component(CO2) ZMF) FRACTION

0.7000 0.6000 0.5000 0.4000 0.3000 0.2000 0.1000 0.0000

INJ-2 INJ-2

INJ-2

• Case 2 (Injection Case of 140 tonnes CO₂ per day)

The second case, injection of 140 tonnes of CO₂ per day shown in figure 7, performs better com-

pared to the first case in terms of plume growth, analogous to better pressure support. It is worth noting that controlled injection is important in terms of maintaining plume growth stability.

9207200

(a)Ini�al (b)15 years a�er injec�on (c)100 years a�er injec�on

548800 549600 550400 551200 552000 552800 553600 554400 555200 556000 556800 548800 549600 550400 551200 552000 552800 553600 554400 555200 556000 556800 548800 549600 550400 551200 552000 552800 553600 554400 555200 556000 556800

91992009200000920080092016009202400920320092040009204800920560092064009207200

548800 549600 550400 551200 552000 552800 552800 554400 555200 556000 556800 548800 549600 550400 551200 552000 552800 553600 554400 555200 556000 556800 548800 549600 550400 551200 552000 552800 553600 554400 555200 556000 556800

91992009200000920080092016009202400920320092040009204800920560092064009207200 92072009206400920560092048009204000920320091992009200000920080092016009202400

9206400920560092048009204000920320092024009201600919920092000009200800 9206400920560092048009204000920320092024009201600920080092000009199200 91992009200000920080092016009207200920640092056009204800920400092032009202400

1:47728 2500m 2000 1500 1000 500 0

1:47728 2500m 2000 1500 1000 500

0 0

1:47728

500 1000 1500 2000 2500m

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• Case 3 (Injection Case of 700 tonnes CO₂ per day)

The third case, shown figure 10, is the best in terms of CO₂ plume growth and areal extent of the injected CO₂. From lateral view, it can be seen that injected CO₂ has an ability to extend aquifer support into two existing wellpads therefore increasing CCUS efficiency. Even though the result is promising, more study should be performed in order to ensure excessive breakthrough does not occur to gas bearing zones.

Figure 8

Figure 9

The injection study is then extended into full reservoir simulation study to observe the effect of injected CO₂ into reservoir performance. The selected case, case 3, is run and significant improvement in gas and condensate recovery, 36 BSCF and 382.7 MSTB, shown below, is observed whilst managing to sequestrate 2.7 Million tonnes of CO₂ in only 10 years of injection sequence. Approximate economic analysis is also calculated to measure the impact of the particular CCUS method, rendering 127 million USD assuming CO₂ tax of 3$/ ton CO₂.

(a)Initial (b)2 years after injection (c)100 years after injection

Total mole fraction (Component(CO2) ZMF) FRACTION

0.7000 0.6000 0.5000 0.4000 0.3000 0.2000 0.1000 0.0000

Total mole fraction (Component(CO2) ZMF)

FRACTION Total mole fraction (Component(CO2) ZMF)

FRACTION 0.7000 0.6000 0.5000 0.4000 0.3000 0.2000 0.1000 0.0000

INJ-2 INJ-2

INJ-2

9207200

(a)Ini�al (b)15 years a�er injec�on (c)100 years a�er injec�on

548800 549600 550400 551200 552000 552800 553600 554400 555200 556000 556800 548800 549600 550400 551200 552000 552800 553600 554400 555200 556000 556800 548800 549600 550400 551200 552000 552800 553600 554400 555200 556000 556800

91992009200000920080092016009202400920320092040009204800920560092064009207200

548800 549600 550400 551200 552000 552800 552800 554400 555200 556000 556800 548800 549600 550400 551200 552000 552800 553600 554400 555200 556000 556800 548800 549600 550400 551200 552000 552800 553600 554400 555200 556000 556800

91992009200000920080092016009202400920320092040009204800920560092064009207200 92072009206400920560092048009204000920320091992009200000920080092016009202400

9206400920560092048009204000920320092024009201600919920092000009200800 9206400920560092048009204000920320092024009201600920080092000009199200 91992009200000920080092016009207200920640092056009204800920400092032009202400

1:47728 2500m 2000 1500 1000 500 0

1:47728 2500m 2000 1500 1000 500

0 0

1:47728

500 1000 1500 2000 2500m

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0.7000 0.6000 0.5000 0.4000 0.3000 0.2000 0.1000 0.0000

INJ-2

0.7000 0.6000 0.5000 0.4000 0.3000 0.2000 0.1000 0.0000

INJ-2 INJ-2

(c)100 years after injection (b) Breakthrough:

15 years after injection (a)Initial

Figure 10

Figure 11

9201600 9200800 9200000 9199200 92024000 92032000 92040000 920480092056000 92064000 92072000

556000 556800 554400 555200 553600 552800 552000 551200

548800 550400

2500m 549600

9199200 9200000 9200800 9201600 9202400 9204000 9203200 9204800 9205600 9206400

9199200 9200000 9200800 92024000 9201600 92032000 92040000 920480092056000 92064000 92072000

556800 556000 555200 554400 553600 552800 552000 551200 550400

92032000 92024000 9201600 9200800 92000009199200

9199200 9200000 9200800 9201600 9202400 9203200 92040000 92048000 92056000 92064000

9204000 9204800 9205600 9206400 92072000

9207200

2000 1500 1000 500

1:47728

0 500 1000 1500 2000 2500m 0

1:47728

0 500 1000 1500 2000 2500m

1:47728

556800 548800

548800

9200800 9200000 9199200 9201600 9202400 9203200 9204000 9204800 9205600 9206400

555200 556000 554400 553600 552800 552000 550400 551200 549600 549600

552800 554400 555200 556000 556800

552800 552000 551200 550400 549600 548800

556800 556000 555200 554400 553600 552800 552000 551200 550400 549600 548800 556800 556000 555200 554400 553600 552800 552000 551200 550400 549600 548800

��100 ��

9207200

�� 15 ��

2500m

Increase Gas Produc�on up to 5.4%

(36 BSCF)

Field

Date

CASE_2, Gas produc�on cumula�ve

CASE_3_15MMSCFD_10YEARS, Gas produc�on rate CASE_2, Gas produc�on rate

Observed, Gas produc�on cumula�ve CASE_3_15MMSCFD_10YEARS, Gas produc�on cumula�ve Observed, Gas produc�on rate

2020 2040 2060 2080 2100

0 2E+05 4E+05 6E+05 8E+05 1E+06 1.2E+06 1.4E+06 Gas produc�on rate [sm3/d]

0 2E+09 4E+09 6E+09 8E+09 1.2E+10 1.4E+10 2E+10 1E+10 1.4E+101.6E+10 Gas produc�on cumula�ve [sm3]

Increase Gas Produc�on up to 5.4%

(36 BSCF)

Field

Date

CASE_2, Gas produc�on cumula�ve

CASE_3_15MMSCFD_10YEARS, Gas produc�on rate CASE_2, Gas produc�on rate

Observed, Gas produc�on cumula�ve CASE_3_15MMSCFD_10YEARS, Gas produc�on cumula�ve Observed, Gas produc�on rate

2020 2040 2060 2080 2100

0 2E+05 4E+05 6E+05 8E+05 1E+06 1.2E+06 1.4E+06 Gas produc�on rate [sm3/d]

0 2E+09 4E+09 6E+09 8E+09 1.2E+10 1.4E+10 2E+10 1E+10 1.4E+101.6E+10 Gas produc�on cumula�ve [sm3]

Figure 12

Incremental gas produced from case 3

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DOI.org/10.29017/SCOG.46.1.1321 | 27 (Prasandi Abdul Aziz, et al.)

The results of the study has indicated that En- hanced Gas Recovery (EGR) Mechanism can be applied also in B Field, which corroborates the result from Muslim et al (2013) publication.

CONCLUSIONS

A new method of CCUS is presented in this publication where CO₂ is injected into natural gas reservoir as a method to maintain reservoir pressure.

Simulation study performed on B Field in East Java, Indonesia has shown that sequestering 27 million tonnes of CO₂ generates incremental 36 BSCF of gas and 383 MSTB of condensate. Further study should enquire the effects of varying injection schedule as well as the effects of impurities in injected CO₂ to reservoir performance.

GLOSSARY OF TERMS

Figure 13

Incremental condensate produced from case 3

Increase Condensate Produc�on up to 8.7% (382.7 MSTB)

Field

Date

CASE_2, Oil produc�on cumula�ve

CASE_3_15MMSCFD_10YEARS, Oil produc�on rate CASE_2, Oil produc�on rate

Observed, Oil produc�on cumula�ve CASE_3_15MMSCFD_10YEARS, Oil produc�on cumula�ve Observed, Oil produc�on rate

2020 2040 2060 2080 2100

0 20 40 60 80 100 120 140 Oil produc�on rate [sm3/d]

0 1E+05 2E+05 3E+05 4E+05 5E+056E+05 7E+05 8E+05 Oilproduc�oncumulate[sm3]

ACKNOWLEDGEMENTS

This work was supported by the Institut Teknolo- gi Bandung and Universitas Pembangunan Nasional

“Veteran” Yogyakarta. The author acknowledges the support that has been given during research, publication and presented this paper. Writer too receive input and recommendations.

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