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Energy Procedia 63 (2014) 6335 – 6343

GHGT-12

Reservoir characterization for site selection in the Gundih CCS

project, Indonesia
Takeshi Tsujia*, Toshifumi Matsuokab, Wawan Gunawan A. Kadirc, Masami Hatod,
Toru Takahashie, Mohammad Rachmat Sulec, Keigo Kitamuraa, Yasuhiro Yamadab,
Kyosuke Onishif, Djedi S. Widartog, Rio I. Sebayangg, Agung Prasetyog, Awali
Priyonoc, Tutuka Ariadjic, Benyamin Sapiiec, Eko Widiantog, Ariesty Ratna Asikinc, and
Gundih CCS project team
a
International Institute for Carbon-Neutral Energy Research, Kyushu University, 744 Motooka Fukuoka, 819-0395, Japan
b
Faculty of Engineering, Kyoto University, Kyotodaigaku-Katsura, Kyoto, 615-8540, Japan
c
Institut Teknologi Bandung, Bandung, 40132, Indonesia
d
Waseda University, 3-4-1 Shinjyuku-ku Okubo, Tokyo, 169-8555, Japan
e
Fukada Geological Institute, 2-13-12 Bunkyo-ku Honkomagome, Tokyo, 113-0021, Japan
f
Faculty of International Resource Sciences, Akita University, 1-1 Tegatagakuen-cho. Akita, Akita, 101-0852, Japan
g
Pertamina, Jakarta, 12950, Indonesia

Abstract

A pilot CCS project in Indonesia will be implemented in Gundih area, Central Java Province in Indonesia. Before the CO2
injection, the reservoirs for CO2 injection must be characterized carefully by conducting geophysical exploration as well as
reservoir simulation, in order to make sure that the reservoir is suitable for CO2 storage. Here we report results of reservoir
characterization and simulation for the determination of CO2 injection site in the Gundih area. Subsurface structures imaged on
seismic reflection profiles indicate that the Ngrayong formation is one of the candidates for CO2 injection. We observed the
outcrop of the Ngrayong formation and measured hydrological and geophysical properties (e.g., permeability, seismic velocity)
of the rock samples obtained from outcrop and wells. The Ngrayong formation has layered structure and heterogeneous
characteristics. Using (1) hydrological properties, (2) subsurface structures (i.e., geometry of the Ngrayong formation) and (3)
physical properties predicted by integrating seismic and logging data via acoustic impedance inversion, we applied reservoir
simulation and evaluated security of the CO2 injection sites.
© 2013The
© 2014 TheAuthors.
Authors. Published
Published by Elsevier
by Elsevier Ltd. Ltd.
This is an open access article under the CC BY-NC-ND license
Selection and peer-review under responsibility of GHGT.
(http://creativecommons.org/licenses/by-nc-nd/3.0/).
Peer-review under responsibility of the Organizing Committee of GHGT-12

* Corresponding author. Tel.: +81- 92-802-6875; fax: +81-92-802-6875.

E-mail address: tsuji@i2cner.kyushu-u.ac.jp

1876-6102 © 2014 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license
(http://creativecommons.org/licenses/by-nc-nd/3.0/).
Peer-review under responsibility of the Organizing Committee of GHGT-12
doi:10.1016/j.egypro.2014.11.666
6336 Takeshi Tsuji et al. / Energy Procedia 63 (2014) 6335 – 6343

Keywords: Gundih CCS project; Reservoir characterization; Reservoir simulation; Heterogeneous formation; Pore pressure

1. Introduction

Carbon Capture and Storage (CCS) has near-term impact on CO2 emissions. Since the CO2 in the atmosphere has
been significantly increasing, we should decrease the CO2 emissions from human activities as soon as possible. CCS
is attractive way to reduce the CO2 emissions using the almost established technology. The roadblocks for
implementation of CO2 storage are (a) risk of CO2 leakage, (b) risk of injection-induced seismicity, and (c) high-
cost. Because these roadblocks are strongly related to the highly uncertain local geological characteristics of
potential storage sites, (1) reservoir characterization and simulation and (2) monitoring/modeling of injected CO2 are
crucial procedures in the development of CCS. Especially, the CCS projects in tectonically active area near from the
plate convergent margins (e.g., Japanese Island or Indonesia) have some difficulties, compared to those in the stable
continental crust. To overcome these roadblocks, we have developed methods of reservoir characterization and
monitoring /modeling of injected CO2.
For the CO2 storage for the tectonically active regions, the following issues should be considered.
(a) Heterogeneous geological formation:
Because geological formations in plate convergent margins are heterogeneous compared to the large-scale
reservoirs in the central part of the continental plates, we need to consider the heterogeneity (e.g., fractures) in
constructing geologic models for reservoir simulation and in designing monitoring surveys. Furthermore, it is
difficult to find stable structural closure (i.e., anticline structure) for CO2 injection, thus we need to use the
mechanisms of residual trapping, dissolution trapping and mineralogical trapping [1]. Even if we use reservoirs
without structural closure for CO2 storage, reservoirs around Japanese islands have a capacity of over 100
billion tons of CO2 [2]. This volume is corresponding to ~100 years of total CO2 emission from Japan.
(b) Limited information for CO2 storage:
Geophysical data including well data are intensively acquired in CCS-EOR projects. However, there is
limited geophysical data available that can be brought to bear for CO2 injection into aquifer formations or new
reservoir. Therefore, we need to characterize the reservoir (or construct geologic model) from limited
geophysical /geological data.
(c) Awareness for earthquakes:
Natural earthquakes are frequently occurred along the plate convergent margins. There is a possibility that
the stress state within the crust is close to the critical state (failure threshold stress), over which the earthquake
is generated (i.e., critically stressed nature) [3]. The increased pore pressure due to CO2 injection reduces the
frictional resistance to fault slip. Therefore, we must accurately monitor and control pore pressure variations
due to CO2 injection. As discussed later, the estimation of stress state (including pore pressure) before the CO2
injection is crucial procedure.
(d) Long-term monitoring and modeling:
Since monitoring in CCS projects should extend about hundred years, the requirements are much different
from the conventional approaches in oil production. Especially we should continuously monitor the injected
CO2 if the lithology has heterogeneous characteristics (fractures). We need to develop the capability to monitor
injected CO2 using effective methods (e.g., seismic monitoring using ambient noise [4]).
To establish the methods of reservoir characterization as well as monitoring/modeling of injected CO2 in
tectonically active regions, the Nagaoka CCS project was conducted in Japan. The pilot CCS project demonstrated
that the injected CO2 can be clearly monitored by seismic data [5, 6], logging data [7] and geochemical data [8].
Using these monitoring data, we confirmed that the injected CO2 is safely stored within injection reservoir
(<~100m).
Here, we focus on “Gundih CCS project” in Indonesia. This project will be a first pilot CCS project in Indonesia
for research and development of technologies for assessing deep strata at CO2 injection and for monitoring of
underground distribution of CO2. Indonesia has a plan to reduce CO2 emission by 26% by 2020 [9]. Since CO2
emission from gas production fields is a major problem in Indonesia, we plan to inject CO2 in the Gundih gas field,
central Java Island (Fig. 1). The CO2 content within the produced gas is more than 20% in the Gundih gas field, so
 Takeshi Tsuji et al. / Energy Procedia 63 (2014) 6335 – 6343 6337

that CO2 injection near the gas production wells could be effective way to avoid abundant CO2 emission from this
area. In this study, we characterized reservoirs of the Gundih gas field mainly using seismic data, and applied
reservoir simulation in order to evaluate the potential and security of CO2 injection sites. Presently we have two
candidate sites for CO2 injection around the Gundih gas field; (1) Central Gundih Gas field and (2) Northern Gundih
field (yellow circles in Fig 1b).

Fig. 1 (a) Map of the Java Island, Indonesia, provided by Google. (b) Locations of two candidates for CO2 injection (yellow circles): Central
Gundih gas field and Northern Gundih field. The red and green stars indicate the locations of outcrops and shallow boreholes we drilled in this
project, respectively. From these locations (stars), we obtained discrete samples for laboratory measurements. (c) Lithology around the East Java
Basin [13]. Tuban formation deeper than the Ngrayong formation is known as overpressure zone.
6338 Takeshi Tsuji et al. / Energy Procedia 63 (2014) 6335 – 6343

2. Geologic setting

The Gundih gas field is located at the vicinity of the east Java basin (Fig. 1), where contains of thousands
meters of Tertiary sedimentary sequences. This sedimentary sequence has a good potential of hydrocarbon source
rock and reservoir rock. The east Java basin is a back-arc basin [10]. Basement configuration of east Java basin is
controlled by two main structural trends, that NE-SW trend are generally only found in northern shelf and E-W
trend contained in Mandala Central high and south basin. Indeed, the geologic structures (e.g., fault) observed
around the Gundih gas field are extended mainly for E-W (or NE-SW) direction (Fig. 2). The E-W or NE-SW trends
would be influenced to the injected CO2 behavior within reservoir.
The lithology we will inject CO2 is the Ngrayong formation (Fig. 1b), because the formation is sandstone and
because the depth of this formation is ~1 km in the Gundih area. Since the depth of the formation is deeper than
~800m in the candidates for CO2 injection reservoir [11], we can effectively inject CO2 as a supercritical state. The
pore pressure at the Ngrayong formation is known as almost hydrostatic condition from previous wells. The physical
and hydrological properties of the Ngrayong formation are much different between northern and southern regions;
the northern Ngrayong formation is sandy and well sorted (Figs. 1 and 3). The permeability of the outcrop samples
obtained in the northern Ngrayong formation is high. Whereas, in the southern formation, the lithology is mud
dominant and has low permeability [12].
The Ngrayong formation is overlaid by the Wonocolo formation, composed by massive grey fossiliferous
sandy marl (Fig. 1c). This formation is deposited during late Miocene in the outer neritic environment. Since this
formation has low permeability, it may work as a seal layer. Indeed, the rock samples obtained from this lithology
using the shallow borehole drilled in this project (Fig. 3) have low permeability. The Tuban formation deeper than
the Ngrayong formation is known as overpressure zone.

Fig. 2 Geological structures extracted from 2D seismic profiles at (a) the central Gundih gas field and (b) the northern Gundih field. These
profiles are acquired for north-south direction. The red lines indicate the candidate for well location in panel (a) and the JEPON-1 site in panel
(b). Light blue lines indicate the faults extending for east-west direction. Blue arrow in panel (a) shows the 3D seismic survey area.
 Takeshi Tsuji et al. / Energy Procedia 63 (2014) 6335 – 6343 6339

3. Reservoir characterization and simulation

There are two main candidate sites for CO2 injection around the Gundih gas field; (1) Central Gundih Gas field
and (2) Northern Gundih field (yellow circles in Fig 1b). Both candidates have advantages and disadvantages, so we
summarize them by conducting reservoir characterization and simulation. We then provide information for the
decision of CO2 injection site. Here we mainly use seismic reflection data, logging data and discrete rock samples
for reservoir characterization. To construct geologic model from these geophysical data, we apply acoustic
impedance (AI) inversion to the post-stack data [14] and Common Reflection Surface (CRS) stacking analysis to the
pre-stack data [15]. To characterize the hydrological properties of the Ngrayong formation, furthermore, we obtain
rock samples from outcrops as well as shallow boreholes (stars in Fig.1; Fig.3). We then apply reservoir simulation
using the constructed geologic models.

Fig. 3 Pictures of outcrops of the Ngrayong formation (A-C) and shallow drilling operation (right). The location of each outcrop is noted in Fig.
1b. Hydrological properties (e.g., permeability) of this formation are much different between northern region (A and B) and southern region (C).

3.1 Central Gundih Gas field

The high-resolution 3D seismic reflection data and several 2D seismic data were acquired in this region and can
be used for reservoir characterization. This site is located within the gas field and is close to CO2 capture facility
(Fig. 1b), therefore CO2 can be supplied using pipelines. However, because of no borehole for CO2 injection, we
need to drill new borehole if we inject CO2 in this region.
We could not find large-scale structural closure (i.e., anticline) for the Ngrayong formation within the 3D
seismic survey area (Fig. 2a). Therefore, we need to store the CO2 using the residual trapping mechanism. Although
the reverse faults are developed at the southern side of this region, the relatively stable formations are observed at
the northern half of the 3D seismic area (Fig. 2a). The horizon of top of the Ngrayong formation extracted from 3D
seismic data demonstrates that dislocation plane (i.e., fracture or fault) is not observed in the stable region [11].
Whereas, the strike-slip fault is developed at the north of the central Gundih gas field (Fig. 2a).
We applied reservoir simulation using realistic hydrological properties constructed by AI inversion and
considering residual and dissolution trappings. Reservoir simulation is crucial step in CCS project to check the
storage capacity of the reservoir and the risk of leak through faults. Because the field observation demonstrates that
the lithology of the Ngrayong formation is fine grain in this region (Fig. 3c), the injectivity of this lithology is low
6340 Takeshi Tsuji et al. / Energy Procedia 63 (2014) 6335 – 6343

[12]. The reservoir simulation demonstrates that the injected CO2 is not arrived at the strike-slip fault over 1000
years and safely trapped within the CO2 injection reservoir [16], when CO2 is injected at the northern side of the
reverse faults (red bar in Fig 2a).

3.2 Northern Gundih field

We can use the suspended well (i.e., JEPON-1 site) for CO2 injection in the Northern Gunidh field. The
geological formations imaged on seismic profiles indicate that the JEPON-1 is located at the top of anticline
structure whose axis is continued for E-W direction (Fig. 2b). The shallower part of the Ngrayong formation is shale
dominant, but the logging data (gamma ray log) indicates several interbedded sand layers. Sidewall core samples of
JEPON-1 show that the sandstones are well sorted, indicating the high permeability (good injectivity). These sand
layers could be used for the CO2 injection. In the Gundih pilot CCS project, the injection amount of CO2 is limited
(~10,000 tons/year), thus these thin sand layers could be enough for injection.
At the northern side of the anticline (JEPON-1 site), the strike-slip fault is existed [11]. The fault is dipping to
south and extends beneath the well. In the depth of injection formation (~900m), the distance between the injection
well and the closest fault is ~400 m. Therefore, we need to carefully consider the fault by performing reservoir
simulation in order to estimate CO2 saturation as well as pore pressure. The pore pressure is believed to be nearly
hydrostatic conditions in this site because the Pertamina drilled through the Ngrayong formation in many locations
and did not observe overpressure in the Ngrayong formation. However, the overpressure zone is expected at deeper
lithology (e.g., Tuban formation).
We characterized reservoir and constructed geologic model using AI inversion (Fig 4a). The AI estimated via
inversion is well consistent with the value of logging-derived AI value. We further classified sand and mud layers
by considering the relationship between AI and gamma ray log data. We then identified four sand dominant layers
within the Ngrayong formation (red arrow in Fig 4b), and these sand layers continuously exist for horizontal
direction. By considering depth and temperature of the injection reservoir, the depth of the shallowest sand layer is
closed to the supercritical phase transition. Therefore, the deeper three sand layers would be candidates for CO2
injection.
To estimate future CO2 distribution as well as pore pressure, we have applied reservoir simulation around the
Ngrayong formation. The geologic model includes four thin sandstone layers (with high permeability) in the
Ngrayong formation as classified in AI inversion, and the other zones are assumed as mud rock layers (with low
permeability). We calculate CO2 behavior in the case of high horizontal permeability (200 md) and low horizontal
permeability (50 md) for sand layers, in order to recognize the CO2 behavior of the two extreme cases. The CO2
behavior would be within the range of these predictions. The horizontal permeability is assumed to be 10 times
larger than the vertical permeability because the outcrop observations demonstrate sand-mud layered structure (Fig.
3c). We conducted the reservoir simulation at several reservoir conditions (temperature, porosity) as well as
injection rates. Underground temperature is not strongly influenced to the flooding area of injected CO2. Here we
show the results of the reservoir simulation of CO2 injection during 1 year with rate of ~10,000 tons/year (Fig 5).
The simulation results demonstrated that the injected CO2 is located around the borehole (within ~100m from
borehole) in the low permeability case (Fig. 5a) and is stored far from the fault located at northern side (Fig 2b). In
high permeability case (200 md), the injected CO2 migrates for shallower direction (western direction) along the
axis of anticline (Fig. 5b), thus the injected CO2 would not move to northern direction (i.e. the closest fault).
Flooding area and direction are strongly influenced by permeability of sandstone layers. Therefore, the acquisition
of permeability of reservoir rock must be important task for CO2 injection project. Furthermore, since the formation
geometry significantly controls the CO2 movement, it is important to know the detailed geological structures around
the injection site. Pore pressure predicted by reservoir simulation is not much increased at the fault zone in the
condition of the small amount of injection rate (~10,000 tons/year).
 Takeshi Tsuji et al. / Energy Procedia 63 (2014) 6335 – 6343 6341

Fig. 4 Geologic model used for reservoir simulation. (a) Acoustic impedance (AI) profile derived from inversion. (b) Lithology classified into
sand (yellow) and mud (green) from AI model by defining the threshold. Red arrows indicate four dominant sand layers within the Ngrayong
formation.

Fig. 5 Examples of reservoir simulations (map view of CO2 saturation) for two permeability cases (50md for horizontal absolute permeability in
panel a; 200md in panel b). This figure show the CO2 saturation after 1 year from CO2 injection. Red indicates the higher CO2 saturated region.
Black circles indicate the well location (JEPON-1). Yellow lines indicate the location of seismic profile displayed in Fig .4. These simulations
demonstrate that the injected CO2 is distributed around the injection well (<150m) in lower permeability case (panel a) and moves along the axis
of the anticline (west direction) in higher permeability case (panel b). The strike-slip fault is located at the northern side of the JEPON-1 site.
6342 Takeshi Tsuji et al. / Energy Procedia 63 (2014) 6335 – 6343

4. Discussion

The most significant concerns in CO2 storage are CO2 leakage and injection-induced earthquakes. The shear
stress at failure߬௙ is obtained by the following equation;

߬௙ ൌ ‫ ܥ‬൅ ߤሺߪ௡ െ ‫݌‬௙ ሻ (1)

where C is cohesive strength, ߤ is coefficient of friction, ߪ௡ is normal stress, and ‫݌‬௙ is pore pressure. If pore
pressure increases due to CO2 injection, the shear stress at failure is decreased. When the shear stress along fault is
higher than the critical value ߬௙ , the fault could be ruptured. Therefore, the pore pressure is one of the most
important parameters to evaluate the stability of lithology (or fault) and should be accurately monitored during and
after CO2 injection. From equation (1), furthermore, we recognize that the background stress state (ߪ௡ ǡ ߬) is also
crucial information to evaluate stability of the faults. If the shear stress along the fault is close to (a little lower than)
the shear stress at failure ߬௙ (critically stressed nature; [3]) before the CO2 injection, the small increase in pore
pressure due to CO2 injection could generate fault rupture. Therefore, we should accurately estimate background
stress state including pore pressure before CO2 injection.
Recent earthquake observations in fluid injection experiments indicate that the earthquakes are sometime
occurred in the basement deeper than the injection reservoir [17]. The earthquakes in deep lithology could be
occurred by CO2 injection-induced earthquakes. Even if the injection-induced earthquakes occurred around the
injection interval are small, they can change the stress state around the reservoir (even deep crust). Because there is
a possibility that CO2 injection indirectly generates large earthquake, the earthquake prediction in the CO2 storage is
difficult issue. Although the northern Gundih field seems to be better environment (less pore pressure), the deeper
lithology (i.e., Tuban formation) may be high pore pressure conditions. Therefore, we should carefully characterize
the stress state, in order not to disturb the stress state around the reservoir.
As discussed above, the stress state (including pore pressure) estimation is the priority work in the CO2 storage.
Pore pressure can be directly measure at the borehole, and its spatial distribution can be estimated from seismic
velocity [18]. Stress state can be estimated from the borehole breakout [19], earthquake source mechanisms and
shear-wave splitting analysis [20]. From the GPS or InSAR observation [21], furthermore, the strain could be
estimated. By using the geomechanical modeling [22], furthermore, we should evaluate the influence of CO2
injection to the stress state around the injection reservoir. By using these available methods, we should estimate
stress state around the injection site in near future.

Acknowledgements

 We acknowledge support of the SATREPS project by JICA-JST. Because of limited space, we cannot describe all
contributors as authors. But, many other scientists contribute to this CCS project. Especially we thank Pertamina and
MIGAS for this project. T. Tsuji and K. Kitamura gratefully acknowledge the support of the I2CNER, sponsored by
the World Premier International Research Center Initiative (WPI), MEXT, Japan, and Sumitomo Foundation
(Environment).

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