assessment of co - eor and storage capacity in south

Available online at www.sciencedirect.com

ScienceDirect

Energy Procedia 00 (2017) 000–000

www.elsevier.com/locate/procedia

1876-6102 © 2017 The Authors. Published by Elsevier Ltd.

Peer-review under responsibility of the organizing committee of GHGT-13.

13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland

Assessment of CO2 - EOR and Storage Capacity in South Sumatera

and West Java Basins

Oki Hedrianaa*, Sugihardjo

a, Usman

a

aR&D Center for Oil and Gas Technology “LEMIGAS”, Jl. Ciledug Raya Kav. 109

Kebayoran Lama, Jakarta-12230, Indonesia

Abstract

A study of carbon dioxide-enhanced oil recovery (CO2-EOR) and storage capacity in South Sumatera and West Java

Basins, Indonesia has been conducted in conjunctions with the project plans of Indonesia National Electric

Company to build carbon capture and storage ready coal power plants in Bojonegara of West Java and Muara Enim

of South Sumatera. The Bojonegara power plant comprises 21000 MWe Ultra Super Critical Units, while Muara

Enim consists of 2300 MWe subcritical units. Those two power plants will produce approximately 11 and 4

million tons of CO2 per year. The geology of South Sumatera and West Java Basins are proven to have kept oil and

gas in place safely for long time periods and there are many oil and gas companies production still active in those

basins. Those basins are confirmed to be used as storage of CO2, where capacity, injectivity, and confinement will

be suitable to keep CO2 in place for a period of time. CO2 production from those power plants in South Sumatera and

West Java may be offered to the nearby oil companies and transported to oil fields for CO2-EOR flooding to get

additional revenue. A preliminary CO2-EOR screening has been done for the oil fields surrounding the power plants.

There are two types of mechanisms for CO2-EOR, which depend on the nature of the oilfield: immiscible EOR and

miscible EOR. Immiscible EOR occurs where the injected CO2 does not mix with the oil but instead displaces the oil

from the area where the CO2 is injected and increases the pressure of the oil at the production wells so that it can be

pumped out. Miscible EOR occurs where the supercritical CO2 mixes miscibility with the residual oil to make it less

viscous and facilitating its flow to the production wells. A total of 127 oil fields in South Sumatera has been

analyzed to select which of those fields fulfill CO2-EOR injection criteria. EOR reservoir screenings were performed

on those oil fields on which detailed information was available using the screening criteria proposed by Taber et al.

* Corresponding author. Tel.: +62-21-7394422 ext.1361; fax: +62-21-7246150.

E-mail address: [email protected]

2 Author name / Energy Procedia 00 (2017) 000–000

The criteria include a set of parameters such as API gravity, oil viscosity, current pressure, temperature, oil

saturation, remaining oil, formation depth, thickness, porosity, permeability, and rock type which help to determine

whether or not a reservoir is suitable for CO2-EOR injection. 96 fields are classified as miscible displacement while

the remaining 31 fields are categorized as immiscible. The result shows that the potency of additional recovery from

those fields is around 661 million stock tank barrels with CO2 requirement of approximately 243 million tonnes. In

addition to EOR, pure CCS to inject the CO2 emission into depleted gas fields in West Java and South Sumatera

regions is also considered. The maximum storage capacity of West Java gas fields is approximately 395 million

tonnes, while the storage capacity of South Sumatera is around 537 million tonnes. The potential for storing CO2 in

the saline aquifer was also calculated theoretically. The depleted gas fields and aquifers are considered enough to

store the CO2 emission from the power plants as long as 25 years.

© 2017 The Authors. Published by Elsevier Ltd.

Peer-review under responsibility of the organizing committee of GHGT-13.

Keywords: CO2-EOR, Storage Capacity, Immiscible EOR,Miscible EOR, Saline Aquifer.

1. Introduction

Indonesia has committed to reducing CO2emissions by 29% through its own efforts under the business as usual

scenario by 2030 [1]. Since then Indonesia has promulgated relevant legal and policy instruments, including the

National Action Plan on Greenhouse Gas (GHG) emissions reduction such as research in Carbon Capture and

Sequestration technologies as one of the significant ways to reduce the rate of increasing atmospheric

CO2concentrations. To support the government-owned electric company PT. Perusahaan Listrik Negara (PT. PLN)

building new coal power plants in South Sumatera and West Java with CCS readiness technology, a study of CO2 -

EOR and storage capacity study has been conducted under a World Bank grant [2]. The main objective of this study

is to identify the potential of utilizing the CO2 emission from the new power plants for EOR application and also

pure CCS into depleted gas fields and aquifer where CO2 will be safely stored it in geological basin formations. The

South Sumatra basin is situated within the stable area Tertiary back-arc basin of South Sumatra. This basin covers

almost 78,000 square kilometers of the southern part of the Sumatra Island and divided into four sub-basins, which

are Jambi, North Palembang, Central Palembang and South Palembang (Figure 1). West Java Basin is divided into

two basins, South West Java Basin and North West Java Basin, this basin is one of the many back-arc or foreland

basins developed behind the Java volcanic arc (Figure 1). West Java Basin was formed as a result of the collision

Sunda plate with the Indian-Australian plate during the Early Eocene to Oligocene periods.

2. Methodology

2.1. CO2-EOR and Storage Capacity Assessment

CO2 injection is a proven EOR technology which has been implemented to improve oil recovery. The basic

behavior of CO2 gas is capable of developing multi-contact miscibility with reservoir fluids, then, improving the

fluid properties. CO2 – EOR flooding mechanisms include miscible and immiscible processes. The process is called

miscible if the CO2 dissolves in the oil, which on the one hand, can decrease its viscosity, density, and residual oil

saturation, but on the other hand, it increases its mobility. Meanwhile, the process will be called immiscible when

the CO2 function is only to push the oil bank from a specific well to the existing producing wells. The objective of

the CO2 -EOR screening is to perform screening of existing depleted oil reservoirs which are suitable for CO2

injection. EOR reservoir screenings were performed using EOR Screening Criteria Revisited papers introducing by

J.J Taber et al. 1997 [3]. The criteria include API gravity, oil viscosity, current pressure, temperature, oil saturation,

remaining oil, formation depth, thickness, porosity, permeability, and rock type. All of these reservoirs parameters

should be screened whether they are fulfilled the criteria and suitable for CO2 injection. An example of CO2-EOR

screening for each reservoir data in the fields is shown in Table 1.

Author name / Energy Procedia 00 (2017) 000–000 3

Figure 1. South Sumatera and West Java Basins.

Table 1. CO2 – EOR Reservoir Screening (example)

Company : PT. P

Contract Area : Corridor Block A

Field, Reservoir : Z, A1

No Fluid Characteristic and Reservoir Rock CO2 Flooding

Screening Criteria

Remark

1 Reservoir Pore Volume MM cuft 820 Immiscible Injection

Flooding 2 Formation Thickness ft 82

3 Formation Type Sand Stone Sand Stone/Lime

Stone

4 Reservoir Depth ft, SS 2,133 > 2,500

5 Initial Reservoir Temperature oF 122

6 Initial Reservoir Pressure psig 570

7 Current Reservoir Temperature oF 122 Not critical

8 Current Reservoir Pressure psig -

9 Porosity % 28.8 Not critical

10 Permeability mD -

11 Water Saturation % 41.8

12 Oil Saturation % 58.2 > 20 55

13 Gas Saturation % -

14 Oil Formation Volume Factor RB/STB 1.10

15 Gas Formation Volume Factor cuft/scf -

16 OOIP MSTB 77,260

17 Ultimate Recovery MSTB 29,220

18 Remaining Oil MSTB 51,760

19 Oil Gravity oAPI 25 > 22 36

20 Oil Viscosity cp - < 10 1.5

21 CO2 Consumtion for EOR Ton 1,931,500

22 Aditional Recovery MSTB 3,863

= Suggested for higher reservoir fluid characteristic = Suggested for lower reservoir fluid characteristic

55 = Average application for reservoir fluid characteristic


To determine the CO2 requirement for EOR and the improvement in oil recovery, an assumption normally used

by oil industries is applied [4]. The assumption for miscible fields of CO2 consumption is 0.33 tonnes/stb with 12%

recovery factor and the assumption for immiscible fields is 0.5 tonnes/stb with 5% of recovery factor. For oil fields,

CO2 consumption of EOR may be calculated from reservoir volumes, Recovery Factors, and Original Oil in Place

(OOIP). However, any oil fields are candidates for EOR as they will eventually become depleted as they are

produced. Before the depleted oil fields can be injected with CO2, the reservoir pressures must be raised up to the

original reservoir pressures. To increase the reservoir pressures to the original pressures normally they should be

flooded with water or water flooding techniques since these methods are considered cheaper compared to direct CO2

injection from the beginning. CO2 flooding then is initiated after the reservoirs have been filling up with water. In

this case, it has been assumed that the CO2 injections begin after filling up completely with water and increase the

reservoir pressure to the initial level.

2.2. CO2 Storage Capacity in a Gas Field

CO2 storage in depleted gas fields is preferable compared to the other geological storage. Depleted gas fields

have complete geological and reservoirs models, detailed wells histories, and good infrastructures. To calculate

storage volumes is much easier and therefore CO2 injection programs are much simpler to be planned. On the

contrary, having CCS in depleted gas fields does not bring revenues compared to CCS-EOR in depleted oil fields.

The calculation method for stored CO2 in gas fields is using Bachu et al. [4] formula:

( ) (

) (1)

M : Theoretical storage capacity

: CO2 density at initial reservoir condition

Rf : recovery factor

FIG : the fraction of injected gas, if any injection

P, T, Z : pressure, temperature and the gas compressibility factor

OGIP : original gas in place

r,s : reservoir; surface subscripts

An estimate of the injectivity can be obtained from the production rates divided by the number of production

wells and average pressure drop (i.e. obtained from the difference between reservoir pressure and wellhead

pressure). The data needed to calculate the timing of the availability of the field for storage is the annual production

data and reserve estimates for each field. The timing of the availability of gas field for CO2 storage is calculated

dividing the reserves estimates by the annual production figures which are a rough estimate of the time necessary to

produce all the commercially attractive gas from the reservoir. Basically, the economic limit for gas fields is

approximately 150 psig at the well heads. The injection rate has been assumed around 1.000 tonnes/day/well and

CO2 will be injected through a number of wells which are enough to fill up fully the reservoir storage volume at the

targeted time limit such as 10, 15, and 20 years.

2.3. CO2 Storage Capacity in a Saline Aquifer

CO2 storage capacity in saline formations is categorized as a resource scale. The assessment is divided into four

basic steps: Estimate the volume of the formation to be used as the reservoir.

Estimate the average pore volume of the formation.

Estimate the density of the CO2 at formation depth.

Estimate the percentage of the pore volume that the CO2 will pass through when it is migrating or occupy

when it becomes stationary


These methods were introduced nearly simultaneously and have been applied by many researchers in the CCS

fields. For this assessment, CSLF methodology was used for estimating storage resource in open systems which are

equivalent to USDOE methodologies [4]. This method is a volumetric approach that calculates a mass stored CO2

(GCO2) based on investigation area (A), formation thickness (h), porosity ( ), and CO2 density (ρCO2) with the

application of a storage coefficient (E), and the equation is shown below:

(2)

The USDOE efficiency factor [6] considers a series of variables that may limit the ability of injected CO2 to

occupy 100% of the pore space in a given formation, including geologic heterogeneity, gravity or buoyancy effects,

and sweep efficiency. In conservative values based on simulation, general values for efficiency (E) range from 1 %

to 4 %. This assumed that CO2 injection wells can be placed regularly throughout the formation to maximize

storage and that the saline formation is an open system. Gorecki et al. [7] commissioned by IEA-GHG, introduced

the concept that the storage efficiency coefficient E has a geological volumetric term Egeol that expresses the pore

space available for storage, a volumetric displacement term Ev that expresses the portion of the pore space occupied

by CO2 as a result of macroscopic displacement and term Ed that expresses the effect of microscopic (pore scale)

displacement processes:

(3)

Related to range uncertainty of the efficiency factor the assessment in this study will use the probabilistic

number which is proposed by US Department of Energy [7], with the number consisting of three values, viz P10

(optimistic), P50 (middle), and P90 (pessimistic). The value efficiency factor P10 (7.4% (clastic)-10% (limestone));

P50 (14% (clastic)-15% (limestone)) and P90 (24% (clastic)-21% (limestone)). The other option of efficiency factor

devised by IEA GHG [8] is based on specific reservoirs scale and they propose the value of efficiency factor were

P10 (3,1% (clastic) – 3,5% (limestone)); P50 (6,1% (clastic)- 5,2%(limestone) ) and P90 (10% (clastic) – 7,3%

(limestone)).

3. Result

3.1. CO2 source from coal power plan

PLN has two programs to set up power generations using coal-fired of 21000 MW USC units in West Java

(Bojonegara coal power plant) and 2300 MW in South Sumatra (Sumsel-6 power plant). These two power plants are

assumed to be commissioned in 2020 and 2022, respectively. Under full operational conditions, the quantities of captured

CO2 from Bojonegara are approximately 11 million tonnes CO2 per year, while in Sumsel-6 the total annual

quantities of CO2 captured are estimated to be at the level of 4 million tonnes of CO2 per year. Bojonegara power

plants will be ready go into operation in 2019 or 2020. Therefore, the CCS readiness project will be attached to the

emissions reduction programs in the year of 2025 forward. Moreover power plants in Sumsel-6 will be set up in

2022 or 2 years later. CO2-EOR is the most attractive candidates for CCS projects, besides CCS there is also some

oil that will be produced and can offset the cost of CCS. If CCS were to be implemented five years after

commissioning the power plant, then it would operate for the next 20 years of the initial 25 years of power plant

design. Accordingly, a total of CO2 source available for 20 years commission is 80 million tonnes in South Sumatra

and 220 million tonnes in West Java.

3.2. CO2-EOR and Storage Capacity in South Sumatra Oil Fields

Within the South Sumatera Basin, mature oil fields exist with the potential to recover additional oil and CO2

storage through CO2 EOR application [9]. Total of 127 onshore oil fields that has been screened and considered for

CO2-EOR in this study (Figure 2). About 52 oil fields reservoir data are completely available while the rest of the 75

oil fields are depth data only. For this incomplete reservoir data, oil fields were assumed to have the depth of 3,300ft

have been categorized as miscible EOR injection, while below 3,300ft depth were considered as immiscible EOR


injection. Total of 127 oil fields that each field consisted of more than five reservoirs have been screened. Of all the

oil fields, 96 oil fields are classified as miscible and the remaining as 31 immiscible. The initial reservoir pressures

for the 75 oil fields that have incomplete data are inferred using pressure gradients derived from the 52 oil fields that

have complete reservoir data. The pressure gradient is approximately 0.995 bar/m. The same method has been

applied to calculate the CO2 density gradients of incomplete data of 75 oil fields, the CO2 density gradients are about

0.032 bar/m. Therefore, it can be calculated injection pressures at the well heads.

In order to get distributions of oil production during CO2 injection, they have been using the model of oil

production for CO2 injection of oil fields such as Lost Soldier production history [10]. Therefore, the model has

been divided into three models such as recovery factor below 5 million stock tank barrel (stb) produced in 11 years,

5-10 million stb produced in 16 years, while above 10 million stb produced in 20 years. From this CO2-EOR

injection, models have been concluded that the South Sumatera oil fields have a potency of enhancing oil recovery

production (Table 2) by approximately 661 million stb and require around 243 million tonnes of CO2.

Table 2. Summary of CO2-EOR fields screening

Number of OOIP Miscible Immiscible EOR Recovery CO2 Requirement

Oil Fields MMstb Fields Fields MMstb MM tonnes

127 7,277 96 31 661 243

MM: million; M: thousand

Figure 2. Oil fields location in South Sumatera Basin

3.3. CO2 Storage Capacity in South Sumatera and West Java Gas Fields

Depleted gas fields are considered to be prime locations for the storage of captured CO2 due to the vacant storage

volume which is well defined by the quantity of gas that has been produced and the reservoirs are well sealed by

impermeable rock indicated by the presence of trapped natural gas. A gas field may become available for CO2


storage when all the gas wells penetrated in that field have reached its economic limit and been abandoned. Under

storage conditions in a gas field, the CO2 will be a supercritical fluid because the pressure will be above the critical

pressure of CO2 and, due to the geothermal gradient, the reservoir temperature will be above the critical temperature

of CO2. The density of CO2 and original gas will depend on the reservoir depth.

Due to limited availability of data, only about 45 gas fields in onshore South Sumatera region will be calculated

for being used as CO2 storage after being abandoned following their time in production. Those gas fields in South

Sumatera can store approximately 537 million tonnes of CO2 (Table 3). This volume can accommodate the CO2

emission from Sumsel-6 power plant of about 80 million tonnes for more than twenty years running.

Table 3. Storage Capacity of South Sumatera and West Java Gas Fields

No Location Number of Fields CO2 Storage (MM tonnes) Total (MM tonnes)

1 Onshore South Sumatra 45 537 537

2 Onshore West Java 23 171 395

3 Offshore West Java 28 224

Gas fields in West Java basin are located in onshore as well as offshore areas. Figure-3 is the location map of

those gas fields in West Java. Data from around 51 gas fields in West Java have been collected comprising 23

located onshore and 28 offshore. When the gas productions have declined down to the abandoned time that is when

the cumulative gas production is similar to the ultimate recovery factor (URF). The abandoning times are indicated

that the gas fields are ready for CCS. The storage capacity of offshore West Java gas fields is around 224 million

tonnes. It is a little bit higher compared to the onshore capacity which only around 171 million tonnes CO2. In case

any regulation considering storages in offshore depleted gas fields should be prioritized, therefore, offshore West

Java depleted gas fields are capable of handling CO2 emission from Bojonegara power plants for 20 years running.

The total storage of both onshore and offshore locations is approximately 395 million tonnes (Table 3).

Figure 3. Gas fields location in West Java Basin


3.3. CO2 Storage Capacity of Saline Aquifer in South Sumatra Basin

Generally, the South Sumatra basin can be divided to become four Sub-basin consisting of Jambi Sub-basin,

North Palembang Sub-basin, Central Palembang Sub-basin, and Palembang Sub-basin (Figure 1). Related to the

CO2 storage stability, the South Sumatra basin was emplaced in the back-arc basin. The tectonics of the typical basin

are relatively stable, it was indicated by seismicity in the last 100 years periods with minimum seismicity. The zone

seismicity activity represents earthquake distributions (Figure 4.a) [11]. The map showing the intensity of seismic

earthquake increased gradually to a westerly direction far from South Sumatra Basin. The stability of the area is also

proven by the long period's of production in the oil and gas field in this area, which means the area relatively safe

for a long term period for CO2 storage. In the basin configuration showing various depths, the deepest area is

distributed around Southeast Central Palembang Sub-basin and central part of South Palembang Basin, with a depth

of more than 3 seconds two-way time (Figure 4.b)[12]. The suitable depth for CO2 storage in saline aquifers is

typically more than 1,000 m. They are distributed quite widely in the Central Palembang and South Palembang sub-

basins. The tertiary sediment showing filled as long graben system and the distribution bounded by paleo high. The

distribution of oil and gas seems intensively in South Palembang sub-basin and South Western Central Palembang

near Palembang High.

(a) (b)

Figure 4. (a) South Sumatra earthquakes distributions 1900-2014 (USGS); (b) Basement depth configuration and distribution of South Sumatra basin (Pertamina and Beicip,1985).

Referring to the petroleum system; South Sumatra Selatan Basin can be defined by several components which are

used as an important component in the CO2 storage and saline aquifer system. The component included several

levels of the reservoir, seal potential, and trapping system. In these basins several lithology formations are known as

having proven potential oil and gas reservoirs such as:

Lahat Formation (Tertiary Eocene-Early Oligocene Age) comprises of a thick series of andesitic volcanic

breccias, tuff, lava flow and a remarkable quartz sandstone layer in the middle part of the formation.


Talang Akar Formation (Late Oligocene to Early Miocene) consists mainly of coarse-fine grained clastic

sediment series of conglomerate, coarse sandstone, and thin interbedded of shale and siltstone was deposited

in the fluvial to the deltaic environment.

Baturaja Formation (Early Miocene) widely in the form of platform carbonates, 20 – 75 m thick, with some

carbonate buildup and reefs of 60 – 120 m thick [13].

In terms of the sealing capacity of South Sumatera basin, the Early to Middle Miocene open marine shale

provides the highest quality seal on a regional scale (Upper Talang Akar, Batu Raja equivalent and Gumai

formations).The depositional limit of this sealing facies was during the history of the Early Miocene transgression

(equivalent to each formation age). The Upper Talang Akar Formation seal is most effective in the central parts of

the basin where it is draped over basement highs and has been proven to seal gas columns of over 500 m. The

configuration between reservoir and sealing rock can be formed as hydrocarbon trapping combination with an

anticline, fault or stratigraphic structure. An example of the hydrocarbon storage which can be used as CO2 storage

is illustrated in Figure 5. Overall there appears to be plenty of good quality reservoir-seal pairs that could be

exploited for CO2 storage a well-explored subsurface and the existence of hydrocarbon fields and known reservoir-

seal pairs make the South Sumatra Basin good for CO2 storage prospectively. However, the reservoir quality related

to lateral distribution and porosity possibly decreases in the lower level of Talang Akar. In general, the basin has a

good saline reservoir potential due to an excellent regional seal. Most of the carbonate aquifers occur in the South

Palembang sub-basin while the sandstone aquifers, except for North Palembang, increase steadily in volume from

the south to north. The theoretical storage capacity number for the deep saline aquifers of South Sumatera is large

enough to justify further quantification of South Sumatera’s CO2 geological storage potential. Total calculated CO2

resource potential capacity storage in South Sumatera basin is 7.65 GtCO2 (Table 4).

Figure-5 Geological cross section field in South Sumatra Basin represent the configuration of the reservoir and sealing rock.


Table 4. Resource storage capacity in saline aquifer South Sumatera Basin

No. Sub-Basin Resource

Storage (km

3)

Average

Temp (

oC)

Average

Press.

(psi)

CO2

Density

(kg/m3)

E Corrected Resource

Storage (Gigatonnes of CO2)

1 South

Palembang 759.73 105 1,700 225.41 0.01 1.712

2 Central

Palembang 1,734.39 110 1,200 139.62 0.01 2.422

3 North

Palembang 168.66 110 1,500 184.76 0.01 0.312

4 Jambi 1,632.68 140 1,800 196.28 0.01 3.204

Total 4,295.46 - - - - 7.650

3.4. CO2 Storage Capacity of Saline Aquifer in West Java Basin

The West Java Basin is a grouping of Tertiary sub-basins; Sunda, Asri, Arjuna and several smaller onshore basins

such Jatibarang, Pasir-putih and Ciputat sub-basin (Figure 6). The area is a prolific hydrocarbon province (Noble et

al. 1997) with siliciclastic and carbonates reservoirs present [14]. Sediment is 3,000 m thick. The geothermal

gradient is 40 to 50ºC/km [15]. The area of the basin is 140,870 km2. Plate movement has controlled both the

structural development and sedimentation in the North West Java Basin. The sedimentary section ranges from 3,000

– 4,500 meters in the deepest part to less than 1,000 meters in the shallowest part. The east to west rifting is

responsible for the development of north-south trending horst blocks and grabens. The southern edge of this

structural grain is represented by the Bogor Trough.

Figure 6. Depth-time basement structure, distribution of sub-basin and oil gas field (Noble et al.1997)


Tectonically the West Java basin is relatively aseismic especially in the North part compared to the highly

seismically active Sumatra section, despite both areas being located along the same active subduction margin as

indicated by seismicity earthquake [16] distributions in the last 100 years periods (Figure 7). Intermediate depth (70-

300 km) earthquakes frequently occur beneath Java as a result of intraplate faulting within the Australia slab. Deep

(300-650 km) earthquakes occur beneath the Java Sea and the back-arc region to the north of Java which is the

location of West Java Basin. The stability of the area is also proven by the long period of production in the oil and

gas field in this area (figure 8); this is means the area relatively safe for long-term periods for CO2 storage.

Base on the correlation level stratigraphy unit there is three main reservoir levels in the onshore and offshore

West Java Basin known from hydrocarbon exploration. They include the Late Oligocene Talang Akar siliciclastics,

the Batu Raja Carbonates and the EM Miocene “Massive” and “Main” sandstone formations (Upper Cibulakan

Group). Overall there appear to be plenty of good quality reservoir-seal pairs both onshore and offshore that could

be exploited for CO2 storage. Oil and gas fields are relatively small but very plentiful (figure 8). Many fields in the

Arjuna Basin are onshore and have well-explored subsurface and the existence of hydrocarbon fields and known

reservoir-seal pairs make the West Java Basin good CO2 storage prospectively. Almost 58% of the oil and gas in the

Arjuna sub-basin portion of the assessment unit is from the main massive formations, 23% is from the Talang Akar

Formation and Batu Raja carbonates (Gresko et al. 1995) [17]. The oldest reservoir is within a weathered or

karstified basement limestone remnant of middle Eocene age. To evaluate West Java Basin as CO2 saline aquifer

storage there is only very limited data (15 fields), therefore the result of theoretical probabilistic calculation of this

field need to be multiplied by a factor to cover the real extent of the basin. There are 15 field oil and gas data which

cover 1/3 of the real basin area and are distributed mainly in the offshore area, including the Sunda Asri sub-basin,

Central Arjuna sub-basin, North Arjuna sub-basin, and Jatibarang sub-basin. The total probabilistic (P10, P50, and

P90) capacity CO2 saline aquifer storage of West Java Basin is shown in Table 5.

Figure 7. West Java earthquakes distributions 1900-2012 (USGS)


Figure 8. Oil and Gas fields of North West Java Basin (Noble et al.1997)

Table 5. Probabilistic resource storage capacity in saline aquifer of West Java Basin (MM tonnes)

No Method Resource storage (15 fields) Total estimate

P10 P50 P90 P10 P50 P90

1 US DOE, 2011

P10 (10%), P50(15%), P90(21%) 1645.73 2380.59 2380.59 4937.19 7141.77 7141.77

2 IEA GHG, 2013

P10(3,5%), P50(5,2%), P90(7,3%) 380.55 676.34 856.38 1141.65 2029.02 2569.14

4. Conclusion

The geology of South Sumatera and West Java basins are suitable for CO2 storage. In CCS-EOR case, it will be

implemented intensively for 20 years of injections in depleted oil fields in the South Sumatera region, the potency of

improvement in oil recovery is roughly 661 MMstb and will require 243 million tonnes CO2. The maximum storage

capacity of West Java gas fields is approximately 395 million tonnes, while the storage capacity of South Sumatera

is around 537 million tonnes. The probabilistic resource for storing CO2 in the saline aquifer of South Sumatra and

West Java Basin are very sufficient, but more detail data is needed to reassure the confinement of CO2 without

significant leakage for a long-term period to meet the regulation and environmental policies.


Acknowledgements

The authors wish to thank the World Bank, Research and Development Center for Oil and Gas Technology

“LEMIGAS”, and Indonesian State-Owned Electricity Company, PT. PLN for the research support.

References

[1] Intended Nationally Determined Contribution (INDC) Republic of Indonesia, 2015.

[2] Takahashi, Masaki. Indonesia - The Indonesia carbon capture storage (CCS) capacity building program : CCS for coal-fired power plants in

Indonesia. Washington, D.C. World Bank Group. 2015.

[3] Taber, J.J., Martin, FD., and Seright, R.S.(1977) EOR Screening Criteria Revisited – Part 2: Aplications and Impact of Oil Prices. SPE

Reservoir Engineering; p. 201.

[4] Dr. Stefan Bachu, Estimation of CO2 Storage Capacity, Carbon Sequestration Leadership Forum (CSLF). Mexico, 2012.

[5] IEA Greenhouse Gas R&D Programme, CO2 Storage in Depleted Oilfields: Global Application Criteria for Carbon Dioxide Enhanced Oil

Recovery, Report IEA/CON/08/155, prepared by Advanced Resources International, Inc. and Meizer Consulting, August 31, 2009. p 17.

[6] Goodman, A., et al.”U.S. DOE methodology for the development of geologic storage potential for carbon dioxide at the national and regional

scale”, Elsevier Ltd. 2011

[7] Gorecki, C.D., et al. “Development of Storage Coefficients for Determining the Effective CO2 Storage Resource in Deep Saline Formations”,

SPE No. 126444. 2009.

[8] IEA GHG (International Energy Agency Greenhouse Gas R&D Programme), “Development of Storage Coefficients for CO2 Storage in Deep

Saline Formations”. 2009/13.

[9] Usman, Utomo, P.I., Sugihardjo, and Herru, L.S. “A Systematic Approach to Source-Sink Matching for CO2 EOR and Sequestration in South

Sumatera”, Energy Procedia, 63 (2014), 7750-7760.

[10] Brokmeyer, R.J., Borling, D.C., and Pierson, W.T. Lost Soldier Tensleep CO2 Tertiary Project, Performance Case History; Bairoil,

Wyoming. Presented at the Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 27-29 March 1996. SPE-35191-MS.

[11] http://earthquake.usgs.gov/earthquakes/eventpage/usp000d0v4#region-info, Southern Sumatra Indonesia.

[12] Pertamina - Beicip, The Hidrocarbon of Western Indonesia. 1985.

[13] Hutchinson, C.S. “South-East Asian Oil, Gas, Coal, and Mineral Deposits”. Oxford Monographs on Geology and Geophysics, Clarendon

Press, p. 265. 1996.

[14] Noble, et al., J.V.C. Petroleum systems of Northwest Java, Indonesia. In: Howes, J V C & Noble, R A (eds.), Proceedings of the conference

on Petroleum systems of SE Asia and Australasia. Indonesian Petroleum Association. Jakarta, Indonesia , 585-600. 1997.

[15] Soenandar, H.B. Thermal history of the western Indonesian basins (Sunda-Asri, Northwest Java, and Southwest Java); evidence from fission

track geochronology apatite. In: Howes, J V C & Noble, R A (eds.), Proceedings of the conference on Petroleum systems of SE Asia and

Australasia. Indonesian Petroleum Association. Jakarta, Indonesia , 601-629. 1997.

[16] http://earthquake.usgs.gov/earthquakes/eventpage/usp000d0v4#region-info, West Java Indonesia.

[17] Gresko, M., C. Suria dan Sinclair, S., “Basin Evolution of the Ardjuna Rift System and Its Implications for Hyrdocarbon Exploration,

Offshore Northwest Java, Indonesia”. Proceedings of Indonesian Petroleum Association, 24th Annual Convention. 1995.

http://earthquake.usgs.gov/earthquakes/eventpage/usp000d0v4#region-info

http://earthquake.usgs.gov/earthquakes/eventpage/usp000d0v4#region-info

assessment of co - eor and storage capacity in south

Documents