Fuel 89 (2010) 2651–2664
Contents lists available at ScienceDirect
Fuel
journal homepage: www.elsevier.com/locate/fuel
Review article
A review of studies on CO2 sequestration and caprock integrity
Richa Shukla a, Pathegama Ranjith a,*, Asadul Haque a, Xavier Choi b
a
b
Department of Civil Engineering, Monash University, Clayton, Victoria 3800, Australia
CSIRO, Division of Earth Science and Resource Engineering, Private Bag 10, Clayton South, Victoria 3169, Australia
a r t i c l e
i n f o
Article history:
Received 10 February 2009
Received in revised form 10 May 2010
Accepted 11 May 2010
Available online 22 May 2010
Keywords:
Supercritical carbon dioxide
Global warming
Geological sequestration
Storage reservoir
Caprock integrity
a b s t r a c t
This review presents a comprehensive overview of the technologies and science of Carbon Capture and
Storage (CCS), including a brief description of the key aspects of Carbon Dioxide (CO2) transport and subsequent trapping. It focuses on the various methods that have been employed for the sequestration of CO2
in geological media and the different carbon mitigation processes that occur after injection of the CO2.
For a geosequestration project, high degree leak-proof, large storage capacity with effective sealing and
non-faulting stratum are ideal characteristics of the target reservoir and caprock. The geophysical and
geochemical aspects of caprock–CO2–pore fluid interaction, stability of the caprock during and after
injection of CO2, and the impact of pre-existing fractures and probabilities of fault reopening on seal
integrity are discussed. Also in geosequestration, the injection pressure in conjunction with the upward
pressure exerted by the injected CO2 (due to buoyant forces) leads to perturbation of the stress field in the
reservoir. The change in stress, and chemical and physical alteration of the reservoir formation rock and
caprock caused by the carbonic acid which is formed when CO2 dissolves in the groundwater, can lead to
strength reduction and failure of the caprock. The review has identified major research gaps and a need
for further study on caprock integrity under the combined effects of high pressure and high temperature.
The changes in pressure and stress field caused by CO2 injection, and interaction of supercritical CO2 with
the brine in the reservoir formations are also needed to be investigated experimentally.
Ó 2010 Elsevier Ltd. All rights reserved.
Contents
1.
2.
3.
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.1.
Supercritical carbon dioxide . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.2.
What is carbon geosequestration? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.3.
Carbon sequestration options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Geological sequestration of CO2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.1.
Major projects in operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.1.1.
The Sleipner project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.1.2.
The Weyburn project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.1.3.
The Otway Basin Pilot Project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.1.4.
The In Salah project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.2.
Geosequestration systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.2.1.
CO2 sequestration in saline aquifers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.2.2.
Sequestration in depleted oil and gas reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.2.3.
CO2 sequestration in coal seams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Carbon dioxide migration in the reservoir formation rocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.1.
CO2–brine–rock interactions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.2.
Integrity of the caprock in CO2 sequestration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.2.1.
Stages of fracture formation: Fracture closure and initiation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.2.2.
Potential role of fractures and pre-existing faults in caprock failure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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* Corresponding author. Tel.: +61 3 9905 4982; fax: +61 3 9905 4944.
E-mail addresses: Richa.Shukla@eng.monash.edu.au (R. Shukla), Ranjith.pg@eng.monash.edu.au (P. Ranjith), asadul.haque@eng.monash.edu.au (A. Haque), Xavier.
Choi@csiro.au (X. Choi).
0016-2361/$ - see front matter Ó 2010 Elsevier Ltd. All rights reserved.
doi:10.1016/j.fuel.2010.05.012
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4.
5.
R. Shukla et al. / Fuel 89 (2010) 2651–2664
Research gaps and required future work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2662
Conclusions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2662
References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2663
1. Introduction
There has been a major increase in the atmospheric concentration of carbon dioxide and other GHGs (Green-House Gases) since
the industrial revolution [1–4]. This increase of GHGs in the atmosphere, has led to a rise in the average global surface temperature.
The annual average temperature is expected to increase by 0.4–
2.0 °C over most of Australia from 1990 to 2030 and may increase
by 1–6 °C by 2070 (Fig. 1). The inner continental areas warm up
faster than the global average while coastal areas and the tropics
warm up at around the global average rate. There is also prediction
of lowering in the intensity of annual average rainfall in the SouthWestern and South-Eastern parts of Australia [5].
Scientists have been looking into measures for reducing the
amount of CO2 emissions, and developing techniques to control
global warming to some extent [1,3,5], such as preventing excessive anthropogenic CO2 from reaching the atmosphere. Three significant options towards controlling CO2 emission are being
explored: (i) Using less carbon intensive fuels, (ii) improving energy efficiency, and (iii) carbon sequestration through different
means. CCS in the industrial world, is one of the ways of reducing
anthropogenic CO2 emission by storing the CO2 deep under the
earth surface or deep into the ocean and hence avoiding its greenhouse effect. Several projects are operating in different parts of the
world, and new and innovative techniques are being developed
[3,6].
For geological storage of supercritical CO2 in underground geological formations, the safety of the long-term storage of the CO2
requires careful consideration. One of the main sources of CO2
for geosequestration is from power plants. There is an abundance
of potential reservoirs all around the world that include saline
aquifers, coal seams and depleted oil and gas reservoirs. This review focuses on the techniques of geosequestration and highlights
some key research findings and gaps in current understanding,
including the mechanisms and science related to the storage of
supercritical CO2 and the performance of seals and caprocks.
1.1. Supercritical carbon dioxide
Carbon dioxide gas is odourless, colourless and is denser than
air. Although it is a minor constituent of air, high concentrations
of CO2 can be dangerous. In the supercritical state, large gradients
in properties such as density, viscosity and solvent strength can occur at conditions near the phase boundary. Carbon dioxide is in the
2030
0
1
2
3
4
5
6
7
Temperature Change ( C)
2070
8
0
1
2
3
4
5
6
7
Temperature Change ( C)
Fig. 1. Spatial distribution of projected changes in temperature in 2030 and 2070 [5].
8
R. Shukla et al. / Fuel 89 (2010) 2651–2664
gas phase at atmospheric temperature and pressure. At low temperatures (below 78 °C) CO2 is a solid, at a temperature ranging
between 56.5 and 31.1 °C, CO2 is a gas and at temperatures higher than 31.1 °C and pressures greater than 7.38 MPa (critical point),
CO2 is in the supercritical state. This property of CO2 is important
in terms of its sequestration since CO2 is preferably injected in
the supercritical state, as supercritical CO2 has a higher density
than gaseous CO2 [1,3]. The temperature and pressure in a typical
sequestration reservoir are generally higher than the supercritical
state values of CO2 but in some cases, the hydromechanical conditions in the reservoir may change leading to change in the phase
and behaviour of the injected CO2. The solubility of CO2 in water
generally decreases with increasing temperature and increases
with increasing pressure as shown in Fig. 2 [7]. The physical, chemical and thermodynamic properties of CO2 have been discussed in
detail by various researchers [1,3,8].
1.2. What is carbon geosequestration?
The geosequestration techniques that have been applied to date
are based mainly on knowledge and experience gained from oil
and gas production, coal-bed methane, and underground natural
gas storage. Although these techniques provide reasonable nearterm options for sequestration of CO2, enhanced technology for
CO2 sequestration in geologic formations may significantly reduce
costs, increase capacity, enhance safety, or increase the beneficial
2653
uses of CO2 injection. Such enhanced technologies may includes
(1) Enhanced mineral trapping with catalysts or other chemical
additives, (2) Sequestration in composite formations which are
multilayered geological formations of imperfect rocks, which result
in greater dispersion of the CO2 plume [5], (3) Rejuvenation of depleted oil reservoirs through Enhanced Oil Recovery (EOR) and (4)
CO2-enhanced production of methane hydrates by injecting CO2
into methane hydrate formations while simultaneously storing
CO2 [9,10].
Hydrodynamic and geochemical processes responsible for trapping CO2 in geologic formations over large time frames has been
studied by several researchers around the world [11–13]. However,
mineral trapping (i.e., reactions relying on the chemical reactions
between the gas/liquid and solid phases) is less understood, particularly with regard to the kinetics of these reactions. Soong et al.
[14] analysed mineral trapping of CO2 with brine in the Oriskany
Formation in Indiana County, Pennsylvania. They conducted experiments and developed models to study the formation of carbonates
and the effect of pH of the brine on the precipitation of calcite and
they found that pressure and temperature play only a small role in
the process. However, Kharaka et al. [15] suggest that rapid mineral dissolution can have considerable environmental implications
due to the creation of pathways for fluid flow in carbonate rock
seals and well cements that could facilitate leakage of supercritical
CO2 and brine. This kind of dissolution should be carefully monitored in order to prevent the deterioration of caprock integrity.
The factors to be considered in the geological storage of CO2 are
sweep efficiency, preferential flow, leakage rates, CO2 dissolution
kinetics, mineral trapping kinetics and microbial interactions with
CO2, and the influence of stress changes on caprock and formation
integrity. Bachu et al. [16] studied some of these factors in detail
and concluded that hydrodynamic and mineral trapping mechanisms of CO2 mitigation may prove to be key mechanisms for the
geological sequestration of CO2.
1.3. Carbon sequestration options
A number of options for mitigating global warming have been
proposed to date. The development of greenhouse gas mitigation
measures for the energy and carbon intensive industries is of primary importance. The main processes of sequestration operations
are:
1. Capture and separation of CO2 from point sources such as coal
fired power plants and other high intensity CO2 emission industries such as the steel and cement manufacturing industries.
2. Transportation of the captured CO2 to the injection sites after
proper treatment (pressurization, liquefaction, or hydrate
formation).
Fig. 2. Solubility of CO2 in water (Modified) [7].
Fig. 3. Relative order-of-magnitude potential of the various storage methods for the
world [2].
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R. Shukla et al. / Fuel 89 (2010) 2651–2664
to the lower seal, which shall also provide additional storage
capacity to the reservoir [20].
Table 1
Sequestration storage capacities and risks.
Storage option
Capacity
(Gt-CO2)
Storage
integrity
Environmental
risk
Depleted oil and gas fields
Active oil wells (EOR)
Enhanced coal-bed methane
Deep aquifers
Ocean (global)
Carbonate storage
(no transport)
25–30
Low
5–10
1–150
1000–10,000
Very high
High
High
Medium
Medium
Medium
Highest
Low
Low
Medium
Medium
High
High
3. Injection of CO2 in the geological formation (underground) for
storage.
The ZEP (The European Technology Platform for Zero Emission
Fossil Fuel Power Plants) [2] provided an estimation of the relative
order-of-magnitude potential of the various geological storage options for the world as shown in Fig. 3. Table 1 presents the sequestration opportunities available for the United States of America and
also the level of risks associated with each of the sequestration
strategies.
The Geosequestration options are discussed in detail in
Section 2.2.
2. Geological sequestration of CO2
Geological sequestration is the process of capturing then injecting CO2 into the sub-surface. The advantages of the underground
sequestration options are:
1. The technique has already been established in EOR (Enhanced
Oil Recovery) and EGR (Enhanced Gas Recovery).
2. The potential capacity of underground sequestration is estimated to be as large as 1000–1800 Gt CO2 [17].
3. Due to the lesser bio-complexity of the underground environment compared to oceans, acceptable environmental impacts
are greater for underground compared to ocean sequestration
[11].
2.1. Major projects in operation
2.1.1. The Sleipner project
The first commercial scale CO2 injection project was launched in
1996 in a Norwegian offshore saline aquifer (Sleipner project). By
mid 2008, 10 Mt (Million tonnes) of CO2 has been injected into
the formation (injection started in mid of 1996) which is approximately 1000 m below the seabed. The reservoir (Utsira Formation)
is a 200–300 m thick sandstone saline aquifer with thinner intermediate horizontal mudstone layers in the reservoir body (1100–
800 m below sea level). The CO2 is injected and stored in this reservoir and is prevented from being released back onto the surface
by the impermeable 200–300 m thick layer of shale caprock [3,18–
20]. The CO2 is injected in supercritical state and as it is less dense
than the aquifer brine, it will move upwards due to buoyancy. The
CO2 plume had reached the top of the reservoir by 1999. Seismic
profiling conducted in 2002 revealed increased physical trapping
of the CO2 under the individual layers of mudstone in the sandstone reservoir [21,22]. It has also been established in studies by
different researchers that the isolated scattered layers of mudstone
in the caprock formation also increase the total storage capacity of
the reservoir by providing more caps for physical trapping; this has
been confirmed in the Sleipner project. Another 50 m deep confined wedge of sand has been found in the Utsira formation closer
2.1.2. The Weyburn project
The other early and largest project is the Weyburn project,
started in the year 2000, in south central Saskatchewan, Canada.
The project involved the injection of CO2 into an oil field for EOR.
The Midale carbonate reservoir of the Weyburn field consists of
two different aquifers namely; Vuggy (Upper and Lower) beds
and Marly beds. The lower Vuggy bed presents characteristics of
a good reservoir formation while the upper Vuggy bed (limestone
dominated) and the Marly bed (Dolostone unit) show characteristics like relatively low permeability and high porosity. The two
aquifers are capped by an anhydrite caprock. Complete description
of the field’s geology and fault-related features could be found in
Burrowes et al. (2001) [23]. The CO2 coming from the Dakota Gasification Company facility is injected into the formation at variable
rates between 3000–5000 tonnes per day, and over the lifespan of
the EOR project (20–25 years), it is estimated that about 20 Mt of
CO2 will be stored in the field (around the years 2025–2030) [3,23].
2.1.3. The Otway Basin Pilot Project
The initiatives taken by the Australian government after signing
of the Kyoto protocol in 2007 went onto the planning and deployment of the largest geosequestration demonstration project in Australia, called the Otway Basin Pilot Project (OBPP). The Cooperative
Research Centre for Greenhouse Gas Technologies (CO2CRC) initiated the injection of CO2 from a nearby gas well (Buttress-1 well),
into the saline aquifer (CRC-1 well in the Naylor field, Otway Basin)
at a depth of about 2000 m underground [24]. The target of injecting 100,000 tonnes of CO2 is achieved by a continuous injection of
CO2 at the rate of about 150 tonnes per day for 2 years (starting in
April 2007) [25,26].
The storage reservoir consists of porous sandstone while the
caprock/seal is a thick layer of low-porosity Belfast mudstone.
The Naylor CCS field consists of three different wells (the CRC-1,
Naylor-1 and Buttress-1) and has a major fault (called the Naylor
fault) that acts like a structural trap/closure and provides longterm seal for the injected CO2 plume. There exit two more faults
in the field (the Naylor East fault and Naylor South fault) but they
are located outside the targeted storage reservoir area [27]. However the faults have been supporting some initial natural gas column and the amount of CO2 injected will be less than the
amount of methane being produced. Hence the two faults are unlikely to pose any threat and are believed to be having sufficient
sealing capacity for restricting the migration of the CO2 plume.
There are several barriers between the storage reservoir and the
shallow aquifers in the basin [28]. Also there are barriers to prevent the vertical migration of the CO2 and ascertain its safe containment in the reservoir as reported by Dance et al. [29].
Geomechanical investigations and plume migration monitoring
have continued since the commencement of injection and research
is still being done on the performance of the caprock and the possibility of fault reactivation in the field. The success of the OBPP has
led to greater confidence with the CCS technology and the project
has provided the most needed first-hand field experience necessary for larger commercial CCS projects in future.
2.1.4. The In Salah project
The In Salah Gas project (a joint project of Sonatrach, British
Petroleum and Statoil) in Algeria involves injection of about
4000 tonnes of CO2 per day into the Krechba Carboniferous sandstone (a 20 m thick, methane producing reservoir), at a depth of
1800 meters near the Krechba gas field. The field has four gas production wells and three CO2 injection wells [30]. The monitoring of
the injected CO2, borehole surveys and geochemical, geophysical as
R. Shukla et al. / Fuel 89 (2010) 2651–2664
well as geomechanical investigations are still underway. The deformation of the ground is being assessed using time lapse satellite
images which could suggest the movement of the CO2 plume
[31]. The geological data is being combined now to the seismic
and satellite data of the formation to accurately understand the
dynamics of the CO2 plume and to assess the comparative reliability of each of the methods.
Monitoring of CO2 migration in the sub-surface will be important in future large-scale sequestration projects. Tracking of the
distribution of trapped CO2 in the fluid, dissolved, and solid phases
is needed for plume confirmation, leak detection, and regulatory
oversight. Existing monitoring methods include well testing and
pressure monitoring, chemical tracers, chemical sampling, surface
and borehole seismic analysis, electromagnetic, and other geotechnical instruments [32,33]. The spatial and temporal resolution of
current methods is unlikely to be sufficient for performance confirmation and leak detection. Successful remote sensing for CO2 leaks
and land surface deformation is expected to need high-resolution
mapping techniques for tracking migration of sequestered CO2
and its by-products as well as deformation and micro-seismicity
monitoring [30].
2.2. Geosequestration systems
2.2.1. CO2 sequestration in saline aquifers
Koide et al. [34] suggest that the global sedimentary basins are
capable of holding around 320 gigatons of carbon dioxide. The United States can inject approximately 65 percent of CO2 produced by
power plants directly into deep-saline aquifers below the plants
[9]. Similar studies on the capacity of saline aquifers are being carried out around the world [11,35–37]. Effective long-term storage
of CO2 is only possible when the storage basin is large and isolated,
and the reservoir caprock has good sealing capacity. This low permeability caprock formation should be capable of preventing the
supercritical CO2 from migrating out of the intended storage reservoir or potentially contaminating the surface environment or the
existing natural resources.
CO2 geosequestration in saline aquifers in sedimentary basins
can be achieved by four main mechanisms: (a) CO2 dissolution in
the formation water called solubility trapping, (b) geochemical
reactions with the aquifer fluids and rocks known as mineral trapping, (c) structural trapping, where the CO2 rises to the top of geological structures below an impermeable top seal and is stored
there due to capillary pressure and (d) hydrodynamic trapping
where the aquifer does not allow the CO2 plume to seep out of
the targeted reservoir zone (in the condition where the density
of the CO2 is very close to that of water) hence increasing its residence time. Bachu [3] explained the hydrodynamic trapping phenomenon as an extremely slow hydrodynamic dispersion of the
CO2 plume into the saline aquifer because of the low velocity
movement of aquifer water (<0.1 m/year). Bachu and Adams [11]
and Bachu et al. [16] describe the UCSCS (Ultimate CO2 Sequestration Capacity in Solution) of an aquifer as the difference between
the ultimate capacity for CO2 at saturation and the total inorganic
carbon currently held by the solution in the aquifer. It depends on
fluid pressure, temperature and salinity of the aquifer.
Most deep aquifers are highly saline and are situated in sedimentary basins and hence can host larger amount of carbon dioxide due to the high formation pressures. The sequestrated CO2 can
be mineralogically captured in the storage reservoir since it is also
expected to react with the water, salts and the formation rocks to
either increase or decrease the capacity of the reservoir depending
upon the type of chemical reaction taking place as well as on the
carbonate or mineral compounds produced during the reactions.
The supercritical carbon dioxide injected into the aquifers has density of about 660 kg/m3 which is lower than the saline formation
2655
water and hence will rise towards the cap rock due to buoyancy
forces [38].
Considering mineral trapping as another important governing
mechanism in carbon dioxide sequestration in saline aquifers,
Rosenbauer et al. [39] conducted several experiments in mineral
trapping by reacting supercritical CO2 with different combinations
of host fluids and formation rocks such as the Paradox Valley
Brines (PVB), limestones and sandstones, and confirmed the preestablished fact that the aqueous solubility of CO2 is generally lower at elevated temperature and salinity and higher at elevated
pressure as shown in Fig. 4. Geochemical reactions of supercritical
CO2 with limestone versus Arkosic sandstone, in CO2 saturated
brine–rock experiments were carried out to evaluate the effects
of multiphase water–CO2 mixtures on mineral equilibrium. The potential of CO2 sequestration as mineral phases within deep-saline
aquifers was studied in the experiments. They observed that, with
a decrease of temperature from 120 to 25 °C , the solubility of CO2
increased by 6% at 20 MPa pressure, whereas with the presence of
limestone it increased by 5% at 30 MPa, relative to its solubility in
PVB alone (Fig. 4). This ionic trapping or enhanced solubility of CO2
was due to the rapid dissolution of the calcite in the presence of
carbonic acid. Also, they observed that, because of temperature effect on the solubility of calcite, the solubility of CO2 decreased at
elevated temperatures [39].
2.2.2. Sequestration in depleted oil and gas reservoirs
The global CO2 sequestration potential of oil and gas reservoirs
is estimated at between 400 Gt (Giga-tonnes) to 900 Gt but these
figures would increase by 25% if the undiscovered oil and gas reservoirs are included [1]. Gas reservoirs are the most suitable sites
for sequestration of CO2 since they have already proven their capability of holding and safely storing gas for spans of geological time
scales.
If surface based compression is used in the natural gas fields,
the injection of CO2 can also enhance the natural gas recovery to
as high as 95% of the gas initially in place [40]. The injected CO2
within a certain pressure range can move the remaining oil or
gas out of the reservoir and hence lead to environmental as well
as commercial benefits in terms of EOR or EGR. It has been suggested that the addition of CO2 in gas reservoirs may contaminate
the natural gas. However, Oldenburg and Benson [41] state that,
since the CO2 has considerably higher density and viscosity, there
is very low possibility of the CO2 and natural gas getting mixed,
and even if they do, it will take them a considerably long period
on geological timescales.
When CO2 is injected into an oil reservoir, it may mix with the
oil phase, causing it to swell thereby reducing its viscosity. CO2
Fig. 4. The solubility of CO2 in Paradox Valley Brine (PVB) in the presence (open
square symbols) and absence (open circles) of rocks from the Leadville Limestone
(LVL) at 25 °C [39].
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R. Shukla et al. / Fuel 89 (2010) 2651–2664
injection also helps to maintain or increase the pressure in the reservoir. The combination of these processes allows more of the oil to
flow to the production wells. Here, injection of CO2 raises the pressure in the reservoir, helping to sweep the oil towards the production well [42]. Globally, about 130 Gt of CO2 could be disposed as a
result of CO2-EOR operations (variable depending on how much
CO2 was produced with the oil). Specific attention should be paid
to the safety issues of CO2 sequestration (applicable for gas as well
as for oil fields) and unintended fracturing of the seal as a consequence of the pressure fluctuations in the reservoir.
Statoil has implemented geosequestration techniques in the
Sleipner field, which extract about one million tonnes of CO2 yearly
from its production of commercial gas. It is not meant to enhance
the gas recovery, but to sequester the extracted compressed CO2
gas by injecting it through a separate injection well into the Utsira
formation (sandstone and saline aquifer), which is about 1000 m
beneath the sea bed [21,43].
2.2.3. CO2 sequestration in coal seams
Unmineable coal seams provide another potential reservoir for
sequestration of anthropogenic CO2. The mechanism of storage of
the CO2 is mainly through adsorption on the surfaces of micropores within the coal matrix, which is very different from the
hydrodynamic trapping mechanism in saline aquifers or oil and
gas reservoirs. Theoretically, the CO2 should stay in the coal as long
as the reservoir pressure is above desorption pressure. The sorption properties of CO2 and matrix swelling associated with CO2
adsorption have been reported by several researchers, for example,
Mahajan [44] and Krooss et al. [45].
Coal formations also provide an opportunity to simultaneously
sequester CO2 and increase the production of Coal-Bed Methane
(CBM). Commercial methane production from deep unmineable
coal beds can be enhanced by injecting CO2 into the coal formations, where the adsorption of CO2 causes desorption of methane.
This process has the potential to sequester large volumes of CO2
while improving the efficiency and profitability of commercial
CBM operations. This method for enhancing coal-bed methane production is currently being tested at two pilot demonstration sites
in North America (Alberta project and pilot project in the San Juan
Basin, New Mexico/Colorado) [45].
Mehic et al. [46] and Viete and Ranjith [47] conducted a series of
experiments on Australian black coal and south Asian brown coal
samples and observed that, with the adsorption of CO2, the uniaxial
compressive strength of the coal samples decreased. At the same
time the coal behaves in a more ductile manner with a stretched
elastic region in the stress strain curve. Adsorption of CO2 in coal
leads to matrix swelling and can cause a decrease in permeability.
It was found that stress thresholds were lower for the samples saturated with CO2 compared to samples saturated with air. These results suggested a possible correlation between strength of coal and
CO2 adsorption under the laboratory test conditions.
Another important factor to be considered for CO2 storage in coal
seams is the sensitivity of coal towards moisture. Coal has a tendency to swell when it absorbs CO2 or water. The unusual behaviour
of coal due to gas sorption has been investigated by many researchers such as, for example, Busch et al. [48] and Goodman et al. [49].
The importance of adsorption isotherms, effects of gas adsorption
on permeability and changes in mechanical properties of coal such
as strength have also been studied. Krooss et al. [45] and Khaled
et al. [50] studied the effects of CO2 storage on coal.
3. Carbon dioxide migration in the reservoir formation rocks
The migration of the CO2 plume through the reservoir rock mass
is reasonably complex as it involves the effects of the formation’s
lithologies, dynamics of the pore fluid and the geochemical changes
like dissolution and mineral precipitation. In formations with slow
moving pore fluid front, more CO2 gets dissolved into the fluid and
hence smaller amount ends up reaching the caprock interface. The
migration of CO2 may also act under free convection between the
denser CO2 saturated water and the lighter unsaturated water.
The caprock, acting as a seal for the rising CO2 plume, must be
able to withstand the changes in stress field and changes in physical and chemical properties due to the CO2–brine–rock mineral
interactions. This process goes on for thousands of years until the
CO2 is finally immobilized and converted into solid carbonate precipitates. During this period, the rock mass is subjected to compression, tension (in some cases), weathering due to mineral
precipitation/dissolution and crack initiation and/or propagation
caused by changing stress patterns and excess overpressure/injection pressure. This can sometimes hamper the strength and seal
integrity of the rock and lead to dynamic structural changes, which
may undermine the efficiency of the sequestration project. The
reactions can also cause plugging or improvement of fracture permeability in cases of vein-filling and dissolution, respectively [3,4].
The breakthrough or threshold pressure of a porous medium is a
major factor affecting the capillary sealing of the medium against
the fluid. When the wetting face is displaced to an extent that the
percolation threshold is exceeded, a continuous flow path of nonwetting phase is formed across the pore system. This flow occurs
through the largest interconnected pores, and with further increment of pressure, flow also occurs in new smaller pathways, hence
the effective permeability is enhanced and the ultimate flow paths
are dominated by the flow properties of the fluid in addition to the
geometric properties of the connected pore spaces of the sample.
Fig. 5 presents curves of upstream and downstream pressures for
a breakthrough experiment conducted with a closed reservoir and
shows the pressure differential Pd for the gas phase. The continuously decreasing effective permeability (keff) vs. time (t) plot associated with the decrease in differential pressure indicates the loss
of interconnected flow paths during the latter part of the experiment. The residual pressure difference between the upstream and
downstream pressure in the chambers is a measure of the largest
effective pore radius in the sample. This pressure difference determines the capillary-sealing efficiency of the rock and is resulted
from the loss of interconnectivity of pores in the sample [51].
A number of studies have been conducted and models been
developed for fluid flow through rocks and rock fractures [51,52]
but there has been very little research done on the flow of supercritical fluids and gases in fractures. Yang et al. [53] produced the
relationship between CO2 gas transmissivity, fracture pore pressure and fracture volume stress (Figs. 6a and 6b).They presented
the following empirical formula for seepage of gases through fractures in coal under 3-dimensional stress:
r1 bp
1 mr
2mr
c
K fg ¼ K f 0 exp b
ðr2 þ r3 Þ r1
Kn
Er
Er
ð1Þ
where, r1 = maximum principal stress, r2 = intermediate principal
stress, r3 = minimum principal stress, b = coefficient reflecting the
influence of normal deformation, c = coefficient reflecting the influence of tangential deformation, Kfg = coefficient of permeability of
gas, Kf0 = initial permeability of fracture, Kn = normal stiffness of
fracture, mr = Poisson’s ratio of the rock sample, Er = bulk modulus
of the rock sample.
Yang et al. [53] used the least square method to analyse the
experiment data of CO2 and gives the following equation for gas
seepage in fractures in coal under 3-dimensional stress:
T fg ¼ 0:9416p0:2788 expf0:0205½r1 bp 0:0053½0:6ðr2 þ r3 Þ
ð2Þ
0:8r1 g
where all the constants used are same as listed in Eq. (1).
R. Shukla et al. / Fuel 89 (2010) 2651–2664
2657
Fig. 5. Experimental capillary breakthrough curves for absolute pressures, downstream pressures and effective permeability of a CO2 experiment [51].
Transmissivity of CO2 (m3/MPa.sec)
3.1. CO2–brine–rock interactions
2.50E-06
2.00E-06
1.50E-06
1.00E-06
11MPa
5.00E-07
14MPa
17MPa
0.00E+00
0
1
2
3
4
5
Fracture pore pressure (MPa)
Fig. 6a. The relationship of CO2 gas transmissivity and fracture pore pressure [53].
5.00E-06
Transmissivity of CO2
(m 3/MPa.sec)
4.50E-06
1MPa
4.00E-06
2MPa
3.50E-06
3.00E-06
2.50E-06
2.00E-06
1.50E-06
1.00E-06
5.00E-07
0.00E+00
80
130
180
Volume stress (kg/cm2 )
Fig. 6b. The relationship of CO2 gas transmissivity and fracture volume stress [53].
The above equations take into account gas adsorption of gas and
normal and tangential deformation.
Past studies suggest that elevated temperatures and salinity reduce the solubility of CO2 in water while lower temperatures
greatly decelerate the rate of chemical reactions. The rate of reaction is also affected by the mineral composition, aqueous fluid
composition, mineral micro-surface area and the brine salt content. Numerical models developed to simulate the geochemical
reactions taking place in CO2–brine–rock mass using only laboratory experimental results shall not be expected to represent the
scenario of real field reservoirs every time, since the natural reaction rates could be exponentially lower than that of the laboratory
reaction rates. The geochemical interaction between the CO2–
brine–rock is likely to result in acid hydrolysis of the rock minerals
and can have several different effects on the caprock and the overall migration of the injected CO2 [54].
The injected CO2 dissolves in water and forms carbonic acid
which may react with alkaline waters and precipitate as carbonate.
The CO2 dissolved in brine under high pressure makes the brine
highly acidic, which also results in dissolution of the rock carbonate minerals, producing bicarbonate ions. This carbonic acid can
also cause weathering of the silicate rocks as well [34]. The CO2
can therefore be trapped in the form of carbonate minerals and silicate minerals. Alkaline groundwater helps in the precipitation of
the carbonate minerals and this precipitation may seal the fractures and reduce the permeability of the over-burden rock strata
and thus isolating the CO2 saturated water. This has been presented with detailed experimental and analytical discussion of
CO2–brine–rock reactions by Rosenbauer et al. [39].
Supercritical CO2 may also react with the organic contents of
the caprock and cause minor changes in the permeability and
porosity of the caprock [55]. The viscosity of supercritical CO2
changes with temperature and pressure. During the displacement
of the water by the CO2, the rheological properties of the CO2 combined with the rock heterogeneity, can lead to flow instability and
localisation such as the development of fingering [1].
In addition to earlier discussion about the Sleipner project in
the North Sea, the geochemical interaction of the constituents of
the sequestration system is also of interest. As discussed earlier,
the 200 m thick Utsira formation forms the reservoir for CO2 storage in the project and is overlain by a rather complex formation of
mudstone layers, which plays the role of caprock. This caprock formation is divided into three major units namely the lower, middle
and the upper seals. It is highly efficient with thin and relatively
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R. Shukla et al. / Fuel 89 (2010) 2651–2664
impermeable layers, and consequently it is unlikely that leakage of
the stored CO2 will occur. The Utsira formation being sand, the major storage mechanisms are mainly through physical and dissolution trapping of CO2 [19,20].
3.2. Integrity of the caprock in CO2 sequestration
Mechanisms that may result in CO2 leakage have been discussed, among others, by Bouchard and Delaytermoz [54], Rutqvist
and Tsang [55], and Saripalli and McGrail [56]. The leakage-related
risks involved in the geosequestration of CO2 are identified as
follows:
Reactivation of the faults in the caprock: local pressure near a
fault during injection reduces effective normal stress and thus
reduces the shear strength of the fault.
Reactivation of other faults that are hydraulically connected to
the reservoir.
Induced shear failure of caprock.
Hydraulic fracturing (Prior to injection and during injection).
Leakage via the injection well.
Capillary membrane seal pressure exceeded.
The caprock is an integral part of a geosequestration project. It
should be at a desired depth to keep the CO2 in supercritical state
and at the same time it should be away from any major anthropomorphic penetrations like faults or wells to avoid leakage. The caprock mass should be dense and intact, and should possess low
permeability so as to keep the injected CO2 from seeping through
it over a long period. Although a chemically immature caprock
would be preferable to facilitate and enhance geochemical trapping of CO2 in the later stages of the storage phase, the initial
brine–CO2–rock mineral interactions may also result into lowering
of the injection rate through blocking of pore-throats in the injection phase [57]. Also the caprock must have high strength under
both compression and tension to be able to bear the change in
stress fields during and after injection. The above stated properties
of a good caprock are indispensable for a secure CO2 storage system and should be thoroughly studied for each project during planning and deployment of CO2 injection process. These experimental
data of the rock properties and CO2 interaction with the rock minerals and brine can be used in development of new empirical models or modifying existing models like failure criterion and porous
media fluid-flow laws. These new empirical models shall then be
implemented in numerical simulation models for geological studies at reservoir level. Such models would predict the mechanisms
of CO2 transport and storage in the rocks closer to real case
scenarios.
Rutqvist and Tsang [55], mention that the greatest risk of rock
failure is at the lower part of the caprock because of the strongly
coupled hydromechanical changes which are generated as a result
of reduction in the effective mean stress induced in the lower part
of the caprock. The TOUGH-FLAC model developed by Rutqvist and
Tsang [55], demonstrate how a supercritical CO2 plume migrates
through a brine aquifer overlain by a semi-permeable (zero stress
permeability of 1 1013 m2) caprock in a reservoir formation
over 10 years after the injection. The lower layers of the caprock
experience a very high propensity to hydraulic fracturing, since
the pressure margin, the amount of fluid pressure that the caprock
can take without any considerable failure, is found to be only
0.1 MPa after 10 years of injection. Any slight change in the seismic
conditions or in permeability of the caprock, could lead to the reactivation of an existing faults or slips. The propensity for shear reactivation of faults increases due to any increase in the aquifer
pressure during the injection period and the development of
poro-elastic stresses in the rocks towards the bottom of the reser-
voir. The supercritical CO2 migrates at an accelerated rate after
reaching the upper part of the caprock. This change in pace could
be influenced by the combined effects of hydromechanical permeability changes (due to reaction and interaction of CO2 and rock
minerals, brine or any other material present in the reservoir),
relative permeability (in case of heterogeneous rock mass, geological features like faults or joints, damages in the rock masses,
water or brine formations) and viscosity changes (caused when
the CO2 changes its phase from supercritical to liquid or gaseous
phase).
Peacock and Mann [58] discussed various geological factors
controlling the geometries, frequency, orientation and distribution
of fractures in rock and found that the major factors affecting the
fracture patterns are; fault orientations, in situ stress field and fluid
pressures. Fractures tend to close when they are aligned perpendicular to the r1 (maximum principal stress) while those are
aligned perpendicular to r3 (minimum principal stress) tend to
open-up. The initiation of the fractures can be affected by the
in situ stresses and fluid pressure. It has been determined in past
studies that if the fluid pressure exceeds r3, the effective stress is
such that the effective tension exists in the r3 direction. This is
when the extension fractures are likely to initiate and remain open
in the direction perpendicular to r3 [58].
It is an established fact that any degree of CO2 migration
through a fractured cap rock poses a potential risk to the environment [56]. Leakage through caprock may occur due to fracturing of
the cap rock under pore fluid pressure or due to the upward pressure exerted by the CO2 accumulated just beneath the cap rock.
Reopening of pre-existing faults or joints in the caprock may occur
under the influence of external forces like seismic activity or due to
the stress changes inside the geological formation. The development of micro-cracks in the formation may also lead to the eventual decline in the efficiency of whole sequestration project.
There is also a possibility of CO2 leakage through capillaries in
the caprock, when the pressure differences of the fluid phase and
the water phase in the pores adjacent to the cap rock is higher than
the capillary entry pressure of the caprock [59]. Micro-cracks in the
rock formation may also lead to the eventual decline in the efficiency of whole sequestration project.
Zhang et al. [60] propose a hyperbolic criterion as presented in
Eq. (3), for the failure through a rock matrix due to tensile fracturing extending to pre-existing cracks. The stress curve in the hyperbolic criteria is curved at low confining stress while it tends to
become linear with increase in confining stress. The theory of this
criterion is based on the relationship found between the confining
stress and fracture mechanism of the rock. The rock undergoes tensile brittle failure at initial lower confining pressures. The rock
tends to fail under tensile-shear failure mechanism and experiences crack closing phenomena (which provides more strength to
the rock) at increased confining stress.
ðr1 r3 Þ2 ¼ m2 ðr1 þ r3 Þ2 þ aðr1 þ r3 Þ þ b
ð3Þ
where, r1 = maximum principal stress, r3 = minimum principal
stress, a and b are coefficients of the criterion, m is the slope of
the asymptote to the axis r1 = r3.
The hyperbolic criterion assumes the stresses r1 and r3 to be
compressive, when r3 = 0, r1 becomes c0 (where, c0 is the uniaxial
compressive strength). The equation consists of only two coefficients (a, m), and in that case is written as:
ðr1 r3 Þ2 ¼ m2 ððr1 r3 Þ2 c20 Þ þ aðr1 r3 c0 Þ þ c20
ð4aÞ
The coefficients are determined by optimisation method on
f ? min with results of the triaxial tests. Where ‘‘f” is given by
the following equation:
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R. Shukla et al. / Fuel 89 (2010) 2651–2664
f ¼
N
X
ðr1k r01k Þ2
70
ð4bÞ
k¼1
3.2.1. Stages of fracture formation: Fracture closure and initiation
The fracture and deformation characteristics of a reservoir caprock and its response to injection and storage of supercritical CO2 is
extremely significant while assessing the storage capacity of a reservoir. Extensive testing and experimentation is required to gauge
the suitability of a caprock mass before it is considered for carbon
sequestration. The deformation and fracture characteristics of
rocks including initiation, propagation, and interaction of stress-induced fractures are extremely complicated to identify but are necessary to be considered. Upward pressure is exerted on the caprock
0
2
4
8
10
Axial Stress (MPa)
60
50
40
30
20
10
0
0
0.05
0.1
0.15
0.2
0.25
0.3
Strain (%)
Fig. 7a. Complete stress–strain curves showing the transition from brittle to ductile
deformation of rock specimens [64].
70
Unconfined Compressive
Strength (Mpa)
where, N is the number of total triaxial data, r1k is the predicted value of strength of the rock by the criterion, r01k is the experimental
data under the same confining stress.
The criterion discussed above, proves to be better than many
other failure criterion because it is valid for different rocks at varying confining conditions [60]. They conclude that the presence of
micro-cracks results from stress accumulation near the cracks.
Wing cracks tend to propagate to the adjacent original cracks
and finally lead to the macro-level failures of the rock mass.
The most appealing leakage mechanism in this study is the
leakage of CO2 due to hydraulic fracturing, which is caused due
to over pressurization of the cap rock or pressure/stress changes
in the system. The risk of leakage through fracturing is low as long
as the reservoir pressure does not exceed the initial reservoir pressure. Shear deformations caused by seismic activities or due to
deep underground structures nearby the reservoir, and fracturing
may also result in enhanced cap rock permeability by creating
preferential flow paths for CO2 [59]. The chemical interaction between the supercritical CO2 and the rock minerals may lead to
the formation of high permeability zones which could further lead
towards progressive leakage of CO2 [61].
Though remotely possible, a seismic and stress-field interference due to man made underground structures might also contribute towards deterioration of the intactness of the caprock
formation. Sminchak and Gupta [62] suggest that high injection
pressure may trigger some induced seismic activity in the area of
supercritical CO2 injection, the reason behind this could be the
hydraulic fracturing, dissolution or rock mineral precipitation by
the supercritical CO2 rich brine. Their study reveals that the frictional resistance declines along the pre-existing faults and contraction of the rock takes place when the fluid is extracted from the
rock, causing the fault to slip. Since the density of supercritical
CO2 is less than that of the brine and is less viscous too, this enables
it to migrate more easily through pore spaces and fractures. This
kind of property contrast may produce density-driven flow as the
CO2 tends to migrate upwards and impose pressure on the overlaying formation leading to minor seismic activities in some cases
[3,62].
Min et al. [63] successfully reproduced the experimentally observed failure phenomena, using numerical methods and as a result inferred that the rock deforms linearly and elastically at
axial stresses below the yield strength, which is dependent on
the confining pressure. Further compression leads to inelastic
deformation up to the peak strength. At low confining pressures,
the curves show defined peak strength and a gradual strength decrease in the post failure region until final deformation occurs at
about constant axial stress, i.e., residual strength. At higher confining stresses, the rock exhibits work-hardening and the Young’s
Modulus of the rock is higher than that of the rock at lower confining stress. The transition from brittle to ductile deformation in the
rock, with an increase in confining stress, is also clearly demonstrated by Tang et al. [64] in Figs. 7a and 7b.
60
50
40
30
20
10
0
-5
Tension
0
5
10
15
20
Compression
Confining Pressure (Mpa)
Fig. 7b. Curve between compressive strength of rock specimens and confining
pressure [64].
layer when the CO2 changes its phase from supercritical to liquid or
to gaseous form, after injection or when a density-driven flow
takes place. This could trigger the initiation of micro-cracks which
can eventually lead to macro-level fracturing of the caprock.
Both axial and lateral stress components are involved in the closure of cracks. Eberhardt et al. [65] performed uniaxial tests on
brittle rocks and used a combination of moving point regression
analysis (performed on the axial, lateral, and volumetric stress–
strain curves) and acoustic emission responses (including the
event properties and energy calculations) to identify crack initiation. Fig. 8 shows the curve of average volumetric stiffness vs. axial
stress, indicating the occurrence of major strain rate changes between crack initiation and crack damage in brittle rocks. Eberhardt
et al. [65] analysed the axial and lateral stiffness curves to indicate
a significant rate change in strain that occurs prior to the crack
damage threshold, possibly marking the small-scale coalescence
of cracks.
The opening of fracture faces parallel to the applied load and the
closure of fracture faces perpendicular to the load cause certain
changes in the relative lateral and axial deformations, respectively.
These changes appear as inflections in the stress–strain curves
which, in turn, can be used to identify the different stages of rock
deformation and failure. Crack closure occurs during the initial
stages of loading, when pre-existing cracks close which are orientated at an angle to the applied load. The crack closure stress level
indicates the load at which a significant number of pre-existing
cracks have closed and from that point an almost linear elastic
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R. Shukla et al. / Fuel 89 (2010) 2651–2664
Fig. 8. Plot of average volumetric stiffness vs. axial stress, indicating the occurrence
of major strain rate changes between crack initiation and crack damage for a brittle
rock. rcs = crack coalescence stress threshold [65].
behaviour commences. This is approximated by determining the
point on the stress–strain curve where the initial axial strain appears to change from nonlinear to linear behaviour. Linear elastic
deformation takes place once the majority of pre-existing cracks
have closed. Analysis of the axial and lateral stiffness curves indicate that a significant rate change in strain occurs prior to the crack
damage threshold, possibly marking the small-scale coalescence of
cracks.
Crack initiation (rci) represents the stress level where microfracturing begins and is marked as the point where the lateral
and volumetric strain curves depart from linearity. Unstable crack
growth occurs at the point of reversal in the volumetric strain
curve and is also known as the point of critical energy release or
crack damage stress threshold rcd [66,67]. This unstable crack
growth continues to the point where the numerous micro-cracks
have coalesced and the rock can no longer support an increase in
load.
A similar study was conducted by Ranjith et al. [68] on coal
samples with single fracture and multiple fractures, the acoustic
emission counts were recorded and it was observed that the
threshold stresses were higher for the multi-fracture samples
when compared to single fracture samples. Figs. 9a and 9b shows
acoustic emission counts which clearly depicts the major stress
threshold points. The initial part of the curves, where there are
negligible counts at constant increase of axial stress, denotes the
crack closure phenomena it is then followed by an increase in
the number of counts which indicate the crack initiation and stable
crack propagation processes. It finally ends up into a more unstable
propagation condition denoted by the gradual change in the slope
of the curve and is called the crack coalescence stage. Stress
thresholds for crack closure, initiation and propagation occur at
considerably lower levels of stress in case of multi-fractured
samples.
Indraratna and Ranjith [69] conducted triaxial testing and analysis of two-phase flow (water and air) at a range of confining pressures from 0.5 to 2 MPa, and observed that an increase in confining
stress results in a decrease of the two-phase flow rates due to the
closure of fractures in hard rocks as can be seen in Fig. 10. Pruess
and Garcia [70] developed a simplified, one-dimensional flow
model to model the discharge of CO2 through a semi-vertical fault
and suggested that a safe and leak-proof storage of CO2 will require
multiple barriers, since the process of loss of CO2 from the reservoir
appeared to be a self-enhancing process. Fig. 11 shows the growing
trends of CO2 flow rate changing with time (with and without considering salinity of the brine and fugacity of CO2).
3.2.2. Potential role of fractures and pre-existing faults in caprock
failure
One of the most significant factors that can affect the migration
of carbon dioxide through a caprock is the geology of the reservoir
formation and the over-burden rock strata. Pre-existing non-transmissive faults and fractures in the rock formations may provide an
easy path for the CO2 to leak from the intended storage reservoir.
Hawkes et al. [71] explain several factors affecting the geological
storage of CO2 and state that fault reactivation or opening up of
pre-existing faults/fractures, may occur when the maximum shear
stress acting on the fault exceed the shear strength of the fault
plane. They also discuss the fault slip tendency and the modified
slip tendency (Tsm), which is defined by using the Mohr–Coulomb
criterion:
sslip ¼ cfault þ ðrn pÞ tan /fault
T sm ¼
s
sslip
Fig. 9a. Acoustic emission data for a single-fractured rock specimen [68].
ð5aÞ
ð5bÞ
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R. Shukla et al. / Fuel 89 (2010) 2651–2664
Fig. 9b. Acoustic emission data for a multi-fractured rock specimen [68].
where, s = shear stress, sslip = critical shear stress for slip to occur,
cfault = fault cohesion, /fault = fault friction angle, p = pore pressure
in the fault plane, rn = normal stress.
The above equations (Eq. (5a) and (5b) suggest that the slip tendency of a fault is highly dependent on pore pressure [71]. Depending on the orientation of existing faults and the change in pore
pressure CO2 injection may induce high shear stresses on the caprock above the reservoir. The maximum sustainable CO2 injection
pressure should also be estimated depending on the permeability
and thickness of the reservoir, and the injection well should be located as far away from faults as possible to minimise the chances
of fault reactivation near the injection well. Streit and Hillis [72]
have also discussed the importance of estimation of maximum sustainable formation pressures and developed models of fault stability which takes account of stress changes.
Soltanzadeh and Hawkes [73] used the DCFS (Coulomb Failure
Stress) concept to predict fault reactivation tendency for normal
and thrust fault stress regimes. According to the concept, the fault
reactivation factor (k) can be given as:
k ¼ DCFS=ðaDPÞ
ð6aÞ
where, DCFS ¼ Ds ls Dr0n , Ds = shear stress on fault plane,
Dr0n = effective normal stress on fault plane, ls = coefficient of
friction.
Similarly, under plain strain conditions, k can be given by the
following relationship:
k ¼ ðdL caðHÞ Þsinh þ ðdF cosh þ lS sin hÞ ðdL caðVÞ Þ
2
cos hðdF sin h þ lS cos hÞ þ dDcaðHVÞ ððsin h þ cos2 hÞdF
2ls sin h cos hÞ
ð6bÞ
where dL is allocation index which equals one within the reservoir
and zero within the surrounding rock, h is the fault dip angle,
ca(H) is the normalized horizontal stress arching ratio, ca(V) is the
Fig. 10. Effect of confining pressure on two-phase flow rates with inlet water and air pressure held constant at 0.125, 0.20, and 0.25 MPa [69].
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R. Shukla et al. / Fuel 89 (2010) 2651–2664
Overall, a good quality of knowledge base has been established
about the storage science through worldwide research. Although
from the past research and experience, we learn that there still exists an array of gaps in the understanding of CCS such as:
10 0
8
6
Flow rate (kg/s)
4
CO2
rateatatinlet
inlet
CO
2 rate
no s,f
with s,f
2
10-1
8
6
4
water rate at outlet
no s,f
with s,f
2
10 -2
10 2
10 4
10 6
10 8
10 10
Time (s)
Fig. 11. Simulated flow rates for the fault discharge problem (brine with 10%
salinity (s) and including CO2 fugacity (f) effects and for pure water and no fugacity
effects) [69].
normalized vertical stress arching ratio, ca(HV) is the normalized
shear stress arching ratio, dF is the stress regime index, and dD is
the fault dip direction index.
Using the above relationships, Soltanzadeh and Hawkes [73]
developed contour maps which can predict the maximum and
minimum fault dip angle (at any point in the map in injection as
well as production scenario) in a reservoir. According to general
understanding, the fault reactivation in a normal fault stress regime during production, the regions within and near the lateral
flanks of the reservoir tend towards reactivation, while on the
other hand in case of thrust fault stress regime the overlaying
and underlaying rocks tend towards reactivation. During injection,
the overlaying and underlaying rocks tend towards reactivation in
normal fault stress regime while regions within and near the lateral flanks of the reservoir tend towards reactivation in the thrust
fault stress regime [73].
4. Research gaps and required future work
This paper presents an overview of CCS research around the
world, including the different geosequestration systems, the different trapping mechanisms involved in the storage of CO2 with major focus on the importance of caprock integrity.
The results of some past and current geosequestration projects
have demonstrated that it is feasible to store CO2 in sub-surface
geological formations such as depleted oil and gas reservoirs and
saline aquifers. Also, the injected CO2 can be used to enhance the
recovery of oil and coal-bed methane even though the feasibility
of sequestration in deep coal seams still needs further research
mainly due to the problem of low permeability and injectivity.
The experience from the projects has also revealed the effects of
the geological layouts of the cap rocks on the efficiency of a sequestration project.
The review conducted in this paper shows that the geomechanical and geochemical properties of the reservoir and caprock have
great influence on the outcome of the project, detailed site characterization should therefore be conducted before planning and
deployment of any CO2 storage project. If possible, a site with
the optimum characteristics should be chosen. The information
provided in this paper has been gathered from the experience of
various sequestration projects around the world. The understanding and experience gained from those projects and research carried
out in the field of CCS will provide some important scientific
knowledge for future research and the development of commercial
sequestration projects.
(a) Absence of reliable CO2–brine–rock interaction models to
monitor the kinetics of geochemical trapping through the
reservoir and the caprock. Laboratory experiments closely
simulating field conditions over long periods are required.
The data from these experiments can be used to test existing
models. The models need to be validated against both laboratory results and field data. However, some new techniques
may need to be developed as some of reactions occur very
slowly in the field. Without the ability to predict the rock
CO2–brine–rock interaction, and any consequent chemical
and mechanical changes, there can be some uncertainty
regarding the long-term performance of the project.
(b) For sequestration of CO2 in deep-saline aquifers or depleted
hydrocarbon reservoirs, the reactivity of the dissolved CO2 in
the formation water may alter the reservoir and cap rock
properties, as well as damage the equipments used for injection and monitoring. More research is required in order to
determine maximum sustainable injection pressures to
avoid caprock failure.
(c) Incomplete prospective on the geomechanical and geochemical behavior of supercritical CO2 in a geological formation at
high pressure and high temperature.
(d) What failure criteria are applicable to model saline aquifers
and the cap rock? Can we use existing failure models which
are commonly used in rock mechanics? These need further
experimental work and theoretical developments to simulate rock media by considering the coupled effects of geomechanical, thermal, geochemical, and flow.
(e) Lack of firm information on safe injection pressure estimation and vulnerability of caprock towards hydraulic
fracturing.
(f) Lack of research about fracture sealing or caprock strength
deterioration in relation to weathering of rock minerals in
long term.
(g) Better understanding of potential leakage caused by natural
seismic activities in the future is required.
(h) Better models are needed to model the fate of the injected
CO2 reservoir which takes into account the multiphase flow
of CO2 and brine, the effects of stress on permeability, and
the dissolution and chemical interaction of the CO2 with
the rock minerals. Validation of the models may require conducting tests on samples collected from different locations
to study the composition of the pore fluids and the rock minerals, and study how they change with time.
(i) One of the possible leakage paths of CO2 is due to the deterioration of well cement and this has received some attention in the recent past. Deterioration of normal Portland
cement may occur when it reacts with CO2 and therefore
new types of cement, such as geo-polymer cement may be
needed in order to prevent leakage.
5. Conclusions
A comprehensive study has been presented on the various techniques and mechanisms involved in the mitigation of carbon dioxide during and after its sequestration into geological formations
with special emphasis on its safe storage in sedimentary basins.
For a sequestration project to be successful storage periods are
usually over an extensive period of time and hence the importance
of caprock sealing integrity over the required duration is
paramount.
R. Shukla et al. / Fuel 89 (2010) 2651–2664
More elaborate laboratory experiments should be conducted
under conditions representative of natural reservoir conditions.
The chemical interaction of the carbon dioxide with the rock minerals and groundwater should be studied with special consideration of the effects of other processes on the path and reaction
rate. The effects of different natural and human activities such as
seismic/tectonic activities, deep oil/gas/coal mining and other deep
driven underground structures, on the integrity of the caprock
should also be careful studied so as to ascertain the long-term
safety of sequestration projects. Hence it is concluded that if sufficient amount of consideration is given to the vital points identified
in the presented research review, the planning and execution of a
CCS project could be made more efficient and commendable.
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