Geological Survey of Denmark and Greenland Bulletin 20, 2010, 95–98

Beijing

Jinan

Tianjin

Tangshan

Tianjin GreenGen
power plant

Dagang
oilfield
complex

Shengli oilfield
complex

Kailuan coalfields

Jiyang
aquifers
(Huimin

sub-basin)

50 km

116°E 118°E

40°N

38°N

China

Pipelines, fluid conveyed
Gas
Gas under construction
or planned
Oil
Oil under construction
or planned
Other pipelines under
construction or planned
Aquifers
Oilfields

Kailuan coalfields status

Projected

Proved

City

Fig. 1. Map of the study area in eastern China

showing CO2 sources, proposed pipeline net-

work and potential storage sites. Based on data

from the Energ y, Environment and Economy

Research Institute, Tsinghua University;

Institute of Geolog y and Geophysics, Chinese

Academy of Sciences; China University of

Mining and Technolog y; Research Institute

of Petroleum Exploration and Development,

PetroChina and the China University of

Petroleum (CUP). The outline of the Shengli

oilfield complex and the pipeline data are

from ‘Energ y Map of China 2008’, © The

Petroleum Economist Ltd, London. © British

Geological Survey. British Geological Survey

produced the GIS map.

The challenge of climate change demands reduction in

global CO2 mission. Carbon dioxide capture and storage

(CCS) technology can be used to trap and store carbon di-

oxide gas emitted by coal-burning plants and this can reduce

the world’s total CO2 emission by about one quarter by 2050

(IEA 2008, 2009; IPCC 2005). Experience from the storage

sites of Sleipner in the Norwegian North Sea, Salah in Alge-

ria, Nagaoka in Japan, Frio in USA and other sites shows that

geological structures can safely accommodate CO2 produced

and captured from large CO2 point sources. CCS is regarded

as a technology that will make power generation from coal

sustainable, based on cost-effective CO2 capture, transport

and safe geological storage of the released CO2 .

China has large coal reserves (DeLaquil et al. 2003), and

is not about to give up on this reliable source of fossil fuel.

Hence a large production of CO2 can be expected to continue

for many years. China also has a large theoretical geological

carbon dioxide storage capacity in onshore areas with deep

saline formations (Dahowski et al. 2009). In an extensive

collaborative research effort between Chinese and European

scientists, the COACH project (Cooperation Action within

CCS China-EU) was successful in building the expertise, de-

veloping the capture technologies and mapping transportation

routes for CO2, and it produced two scenarios for geological

storage of CO2 in China.

The aim of the COACH project was to initiate a durable

cooperation between Europe and China in response to Chi-

na’s rapidly growing energy demand. The project ran from No-

vember 2006 to October 2009 and was set up and funded by

the European Commission under the memorandum of under-

standing on Near Zero Emissions Coal, to build demonstration

plants in China. Twenty partners consisting of eight Chinese

and twelve European partners evaluated the feasibility of es-

tablishing CCS in China (COACH 2009). COACH had four

work packages dealing with (1) knowledge sharing and capac-

ity building, (2) capture technologies, (3) permanent geologi-

cal storage of CO2 and (4) recommendations and guidelines

for implementation. Three tasks were carried out under the

Potential for permanent geological storage of CO2
in China: the COACH project

Niels E. Poulsen

9696

third work package: (a) capacity estimates at regional level,

(b) mapping of the geology and emission point sources and

site selection criteria. The Geological Survey of Denmark

and Greenland and Tsinghua University in Beijing shared

the leadership of the third work package. This short article

presents the results of the work conducted on the potential

for geological storage of CO2 in China.

Background and methods
Aims of the Carbon Sequestration Leadership
Forum

The aim of CO2 storage is the permanent removal of CO2

from the atmosphere. The European Union has supported

current research on CO2 capture and storage methods for

more than a decade, with emphasis on capture techniques,

transport and geological storage. The results of the research

on geological storage are summarised in a comprehensive

manual by Chadwick et al. (2008). Internationally recog-

nised standards for capacity assessments were established

by the Carbon Sequestration Leadership Forum (CSLF) in

2004–2005 and a task force on capacity estimation stand-

ards has been active since presenting comprehensive defini-

tions, concepts and methods (Bachu et al. (2007a, b). These

capacity standards were reviewed for the COACH project by

Poulsen et al. (2009) and were used for the work on perma-

nent CO2 storage estimates in China (Zeng et al. 2009).

Comparison of methods

Various methods are available for calculation of CO2 stor-

age capacity in a geological environment (Koide et al. 1992,

1995; Tanaka et al. 1995; Shafeen et al. 2004) . The methods

used in the COACH project (Poulsen et al. 2009) were based

on Bachu et al. (2007a, b) and used in the COACH database

to estimate the storage capacity of hydrocarbon fields. Esti-

mates made by the China University of Petroleum applied

Tanaka et al.’s (1995) method for computing the storage ca-

pacity in the Shengli oilfield complex (Zeng et al. 2009).

The two methods proposed by the CSLF task force and

Tanaka et al. (1995) are basically identical in their approach.

Both methods are based on a volumetric approach and are

applicable to site, regional and basin-scale CO2 storage ca-

pacity estimates. Both can be considered as ‘simple’ equation

models, which try to calculate an ‘approximation’ of a pos-

sible storage capacity. The methods gave almost identical re-

sults when applied to the Shengli oilfield complex (Table 1).

There are, however, some differences in the approach to CO2

behaviour in the storage site. The CSLF method works with

replacement of oil, gas or formation water but does not incor-

porate dissolution of CO2 in formation water. The method

of Tanaka et al. (1995), on the other hand, operates with a

free phase of CO2 and takes into account dissolution of CO2

in the formation water, but it does not considerer the time

period needed for the dissolution (Poulsen et al. 2009).

Long term behaviour of CO2 in a storage site

The long term behaviour of CO2 in a storage site depends on

(1) a number of reservoir parameters (temperature, pressure,

capillary pressure, porosity, permeability, and the cap rock

permeability and capillary entry pressure), (2) the CO2 com-

position, (3) the formation water and (4) time (Chadwick et al.

2008). The solubility of CO2 in formation water varies with

salinity, temperature and pressure of the formation water (the

brine). The dissolution of CO2 in pure water increases with

increasing pressure (and thus increasing depth) up to approxi-

mately 7 Mpa. On the other hand, the CO2 solubility in a brine

decreases with increasing temperature and salinity and thus in

most cases decreases with depth (Bachu & Adams 2003). The

Fig. 2. An example of a Shengli oilfield production site.

result is that in general, the solubility of CO2 in the brine de-

creases with increasing salinity (Shafeen et al. 2004).

The buoyancy of injected supercritical CO2 leads to an

upward gravity-driven f low of CO2 towards the top of the

formation where it forms a plume below the cap rock. CO2

(liquid or supercritical) and water are immiscible, but CO2

can dissolve to a certain extent in water. Due to the slow solu-

bility of CO2 in brine, a large volume of brine is necessary

to dissolve a given amount of CO2. The density of the brine

increases with increasing CO2 dissolution and a downward

gravity-driven f low will be induced by the increased density

of the CO2-saturated brine. On the initiation of storage, be-

fore the plume of saturated brine has reached the bottom,

the overall dissolution rate is essentially constant due to rap-

id convective overturn (Ennis-King & Paterson 2007). At a

later stage during storage the saturated brine forms a gravity

current propagating outwards from the CO2 source.

Activities and results

The main purpose of the COACH project was to prepare the

way for CO2 capture and storage in China. In order to achieve

this, the COACH partners developed an integrated gasifica-

tion combined cycle capture technique. This is a coal-based

energy system with hydrogen production using coal gasifica-

tion, electricity generation from a combined cycle hydrogen

turbine and fuel cell system, and capture of the CO2.

The partners have mapped emission sources and investi-

gated potential CO2 storage sites in eastern China (Fig. 1, Ta-

ble 1). The storage potential of the selected sites was evaluated

using published data or data provided by the Research Insti-

tute of Petroleum (PETROCHINA). Particular oilfields, sa-

line aquifers and un-exploitable coal beds were investigated.

Several test sites are available in some of the oilfields. The

storage potential in oilfields is 10–500 Mt, (pilot scale level;

Fig. 1, Table 1). Following this, a CO2 transport infrastruc-

ture based on connecting CO2 sources and storage sites by

pipeline or ship has been suggested (Fig. 1; Table 1).

The saline Jiyang aquifers in the Huimin sub-basin show

storage capture at an industrial scale (around 50 Gt; Fig. 1,

Table 1), but further geological investigations are required.

The security of energy supply is a key consideration in China,

and enhanced oil recovery (EOR) could be an option. Some

of the oilfields in the Dagang and Shengli oilfield complexes

may be suitable for an enhanced oil recovery pilot project.

Injecting CO2 into oilfields approaching depletion will not

only store CO2, but may also enhance or prolong oil recovery

(COACH 2009).

The coals of the Kailuan coalfield have low permeability

and probably low injectivity, but a high theoretical ability to

adsorb CO2 (Fig. 1, Table 1). In general, however, the stor-

age capacity in coal seams is uncertain. On the other hand, it

has been demonstrated that injection of CO2 into coal beds

can lead to methane production (enhanced coal bed methane

recovery; Yu et al. 2007). At the same time it is a very at-

tractive option for geological CO2 storage as CO2 is strongly

absorbed onto the coal.

Two scenarios for possible CO2 capture and storage dem-

onstration projects have been proposed by work package 4,

based on the mapping of emission point sources, geology,

and capacity estimates by work package 3 together with eco-

nomic analyses. The first scenario is for a pilot scale site with

0.1–1 Mt CO2/year stored in the Dagang or Shengli oilfield

complexes. The second scenario is intended for industrial-

scale storage at 2–3 Mt CO2/year, which could be accom-

modated in the Shengli oilfield complex or potentially in the

saline formations in the Huimin sub-basin. The pilot scale

scenarios focus initially on enhanced oil recovery for storage

where this is feasible. The large-scale option could begin with

enhanced oil recovery but would need to switch to saline

472 Mt using CSLF methodology
and 463 Mt using CUP method

Table 1. Summary of geological sites assessed for geological storage of CO2 after Zeng et al. (2009)

Storage site Capacity Injectivity Seal

Dagang oilfield complex Selected 7 fields 22 Mt
Largest Gangdong field 10 Mt

1000 mD
Some compartmentalisation by
faulting and stratigraphy

Mudstones

Shengli oilfield complex 1000–2500 mD
Some compartmentalisation
by faulting and stratigraphy

Lower Jurassic
mudstones

Huimin Sag aquifers
(Jiyang)

For Huimin sub-basin 50 Gt
For selected troughs in sub-basin 0.7 Gt

Permeability around 1600 mD
in neighbouring oilfields

Mudstones of
Minghuanzhen Fm

Kailuan coalfield 504 Gt adsorbed onto coal and
38 100 Mt void capacity

Permeability generally low
3.7 mD in Taiyuan Formation and
0.1 mD in Shanxi and Xiashihezi Fm

Mudstones

9898

aquifer storage once the potential reservoir and sealing for-

mations have been adequately investigated. Both scenarios

are based on capture of CO2 from the Tianjin GreenGen

power plant (COACH 2009).

Final remarks
In 2005 construction began of the coal-based Tianjin Green-

Gen power plant (Fig. 1) and electricity production started

in 2009. It will be the first near-zero emission power plant in

China. Research over the next decade is expected to develop

and demonstrate the efficiency of coal-based power genera-

tion, mostly by recycling energy lost in the process. The goal

is to achieve sustainability of coal-based power generation.

The project concludes that there is significant potential to

develop carbon dioxide capture and storage technologies in

China and to make major reductions in CO2 emissions over

the next century.

Experience from the storage sites Sleipner in the Norwe-

gian North Sea, In Salah in Algeria, Nagaoka in Japan, Frio

in USA and other sites shows that geological structures can

safely accommodate CO2 produced and captured from large

point sources. Thus, geological storage of CO2 can contri-

bute considerably to the reduction of CO2 emission in China

and other countries.

Acknowledgements
COACH was funded as part of the 6th framework programme for re-

search by the European Commission (project no. 038966). Nikki Smith

from the British Geological Survey is thanked for producing the map used

in Fig. 1.

References
Bachu, S., & Adams, J. J. 2003: Sequestration of CO2 in geological me-

dia in response to climate change: capacity of deep saline aquifers to

sequester CO2 in solution. Energ y Conversion and Management 44,

3151–3175.

Bachu, S., Bonijoly, D., Bradshaw, J., Burruss, R., Christensen, N.P. Hollo-

way, S., & Mathiassen, O.M. 2007a: Estimation of CO2 storage capacity

in Geological Media – Phase 2. Work under the auspices of the Carbon

Sequestration Leadership Forum (www.cslforum.org). Final report

from the task force for review and identification of standards for CO2

storage capacity estimation, 43 pp. Washington: Carbon Sequestration

Leadership Forum.

Bachu, S., Bonijoly, D., Bradshaw, J., Burruss, R., Holloway, S., Chris-

tensen, N.P. & Mathiassen, O.M. 2007b: CO2 storage capacity estima-

tion: methodolog y and gaps. International Journal of Greenhouse Gas

Control 1, 430–443.

Chadwick, A., Arts, R., Bernstone, C., May, F., Thibeau, S. & Zweigel,

P. (eds) 2008: Best practice for the storage of CO2 in saline aquifers –

observations and guidelines from the SACS and CO2STOR E projects.

British Geological Survey Occasional Publication 14, 267 pp.

COACH 2009: Project N° 038966: COACH, Cooperation Action with-

in CCS China-EU, Executive Report, 38 pp.

Dahowski, R.T., Li, X., Davidson, C.L., Wei, N., Dooley, J.J. & Gentile,

R.H. 2009: A preliminary cost curve assessment of carbon dioxide cap-

ture and storage potential in China. Energ y Procedia 1, 2849–2856.

DeLaquil, O., Wenying, C., & Larson, E.D. 2003: Modeling China’s en-

erg y future. Energ y for Sustainable Development 7, 40–56.

Ennis-King, J. & Paterson, L. 2007: Coupling of geochemical reactions

and convective mixing in the long-term geological storage of carbon di-

oxide. International Journal of Greenhouse Gas Control 1, 86–93.

IEA (International Energ y Agency) 2008: Energ y technolog y perspec-

tives: scenarios and strategies to 2050, 650 pp. Paris, France.

IEA (International Energ y Agency) 2009: Technolog y roadmap. Wind

energ y, 52 pp. Paris: International Energ y Agency.

Koide, H., Tazaki, Y., Noguchi, Y., Nakayama, S., Iijima, M., Ito, K., &

Shindo, Y. 1992: Subterranean containment and long term storage of

carbon dioxide in unused aquifers and in depleted natural gas reser-

voirs. Energ y Conversion Management 33, 619–626.

Koide, H., Takahashi, M., Tsukamoto. H. & Shindo, Y. 1995: Self-trap-

ping mechanism of carbon dioxide in aquifer disposal. Energ y Conver-

sion Management 36, 505–508.

Metz, B. et al. (eds) 2005: Carbon dioxide capture and storage. IPCC 2005,

431 pp. Cambridge University Press.

Poulsen, N.E., Chen, W., Dai, S., Ding, G., Kirk, K., Li, M., Zeng, R.,

Vangkilde-Pedersen, T., Vincent, C.J. & Vosgerau, H.J. 2009: D3.3. Im-

proving methodologies for storage capacity assessment and site selection

criteria. EU project no. 038966. COACH work package 3 report. EU

deliverable D3.3, 45 pp. EU COACH project, Brussels.

Shafeen, A., Croiset, E., Douglas, P.L. & Chatzis, I. 2004: CO2 sequestra-

tion in Ontario, Canada. Part I: storage evaluation of potential reser-

voirs. Energ y Conversion and Management 45, 2645–2659.

Tanaka, S., Koide, H. & Sasagawa, A. 1994: Possibility of underground

CO2 sequestration in Japan. Energ y Conversion and Management 36,

527–530.

Yu, H., Zhou, G., Fan, W. & Ye, J. 2007: Predicted CO2 enhanced coalbed

methane recovery and CO2 sequestration in China. International Jour-

nal of Coal Geolog y 71, 345–357.

Zeng, R., Li M., Dai, S., Zhang, B., Ding, G. & Vincent, C. 2009: Assess-

ment of CO2 storage potential in the Dagang oilfield, Shengli oilfield

and Kailuan coalfield. COACH work package 3 report. EU deliverable

D3.1, 45 pp. EU COACH project, Brussels.

Author’s address

Geological Survey of Denmark and Greenland, Øster Voldgade 10, DK-1350 Copenhagen K, Denmark. E-mail: nep@geus.dk