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 Department of Civil Engineering, Monash University, Clayton, Victoria 3800, Australiab 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 2009Received in revised form 10 May 2010Accepted 11 May 2010Available online 22 May 2010

Keywords:Supercritical carbon dioxideGlobal warmingGeological sequestrationStorage reservoirCaprock integrity

0016-2361/$ - see front matter � 2010 Elsevier Ltd. Adoi:10.1016/j.fuel.2010.05.012

* Corresponding author. Tel.: +61 3 9905 4982; faxE-mail addresses: Richa.Shukla@eng.monash.edu.

Choi@csiro.au (X. Choi).

a b s t r a c t

This review presents a comprehensive overview of the technologies and science of Carbon Capture andStorage (CCS), including a brief description of the key aspects of Carbon Dioxide (CO2) transport and sub-sequent 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 andgeochemical aspects of caprock–CO2–pore fluid interaction, stability of the caprock during and afterinjection of CO2, and the impact of pre-existing fractures and probabilities of fault reopening on sealintegrity are discussed. Also in geosequestration, the injection pressure in conjunction with the upwardpressure exerted by the injected CO2 (due to buoyant forces) leads to perturbation of the stress field in thereservoir. The change in stress, and chemical and physical alteration of the reservoir formation rock andcaprock caused by the carbonic acid which is formed when CO2 dissolves in the groundwater, can lead tostrength reduction and failure of the caprock. The review has identified major research gaps and a needfor 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 withthe brine in the reservoir formations are also needed to be investigated experimentally.

� 2010 Elsevier Ltd. All rights reserved.

Contents

1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2652

1.1. Supercritical carbon dioxide . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26521.2. What is carbon geosequestration? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26531.3. Carbon sequestration options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2653

2. Geological sequestration of CO2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2654

2.1. Major projects in operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2654

2.1.1. The Sleipner project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26542.1.2. The Weyburn project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26542.1.3. The Otway Basin Pilot Project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26542.1.4. The In Salah project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2654

2.2. Geosequestration systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2655

2.2.1. CO2 sequestration in saline aquifers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26552.2.2. Sequestration in depleted oil and gas reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26552.2.3. CO2 sequestration in coal seams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2656

3. Carbon dioxide migration in the reservoir formation rocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2656

3.1. CO2–brine–rock interactions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26573.2. Integrity of the caprock in CO2 sequestration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2658

3.2.1. Stages of fracture formation: Fracture closure and initiation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26593.2.2. Potential role of fractures and pre-existing faults in caprock failure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2660

ll rights reserved.

: +61 3 9905 4944.au (R. Shukla), Ranjith.pg@eng.monash.edu.au (P. Ranjith), asadul.haque@eng.monash.edu.au (A. Haque), Xavier.

2652 R. Shukla et al. / Fuel 89 (2010) 2651–2664

4. Research gaps and required future work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26625. Conclusions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2662

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2663

1. Introduction

There has been a major increase in the atmospheric concentra-tion of carbon dioxide and other GHGs (Green-House Gases) sincethe industrial revolution [1–4]. This increase of GHGs in the atmo-sphere, 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 increaseby 1–6 �C by 2070 (Fig. 1). The inner continental areas warm upfaster than the global average while coastal areas and the tropicswarm up at around the global average rate. There is also predictionof lowering in the intensity of annual average rainfall in the South-Western and South-Eastern parts of Australia [5].

Scientists have been looking into measures for reducing theamount of CO2 emissions, and developing techniques to controlglobal warming to some extent [1,3,5], such as preventing exces-sive anthropogenic CO2 from reaching the atmosphere. Three sig-nificant options towards controlling CO2 emission are beingexplored: (i) Using less carbon intensive fuels, (ii) improving en-ergy efficiency, and (iii) carbon sequestration through differentmeans. CCS in the industrial world, is one of the ways of reducinganthropogenic CO2 emission by storing the CO2 deep under the

2030

0 1 2 3 4 5 6 7 8

Temperature Change ( C)

Fig. 1. Spatial distribution of projected chang

earth surface or deep into the ocean and hence avoiding its green-house effect. Several projects are operating in different parts of theworld, and new and innovative techniques are being developed[3,6].

For geological storage of supercritical CO2 in underground geo-logical 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 abundanceof potential reservoirs all around the world that include salineaquifers, coal seams and depleted oil and gas reservoirs. This re-view focuses on the techniques of geosequestration and highlightssome key research findings and gaps in current understanding,including the mechanisms and science related to the storage ofsupercritical CO2 and the performance of seals and caprocks.

1.1. Supercritical carbon dioxide

Carbon dioxide gas is odourless, colourless and is denser thanair. Although it is a minor constituent of air, high concentrationsof CO2 can be dangerous. In the supercritical state, large gradientsin properties such as density, viscosity and solvent strength can oc-cur at conditions near the phase boundary. Carbon dioxide is in the

2070

0 1 2 3 4 5 6 7 8

Temperature Change ( C)

es in temperature in 2030 and 2070 [5].

R. Shukla et al. / Fuel 89 (2010) 2651–2664 2653

gas phase at atmospheric temperature and pressure. At low tem-peratures (below �78 �C) CO2 is a solid, at a temperature rangingbetween �56.5 and 31.1 �C, CO2 is a gas and at temperatures high-er than 31.1 �C and pressures greater than 7.38 MPa (critical point),CO2 is in the supercritical state. This property of CO2 is importantin terms of its sequestration since CO2 is preferably injected inthe supercritical state, as supercritical CO2 has a higher densitythan gaseous CO2 [1,3]. The temperature and pressure in a typicalsequestration reservoir are generally higher than the supercriticalstate values of CO2 but in some cases, the hydromechanical condi-tions in the reservoir may change leading to change in the phaseand behaviour of the injected CO2. The solubility of CO2 in watergenerally decreases with increasing temperature and increaseswith increasing pressure as shown in Fig. 2 [7]. The physical, chem-ical and thermodynamic properties of CO2 have been discussed indetail by various researchers [1,3,8].

1.2. What is carbon geosequestration?

The geosequestration techniques that have been applied to dateare based mainly on knowledge and experience gained from oiland gas production, coal-bed methane, and underground naturalgas storage. Although these techniques provide reasonable near-term options for sequestration of CO2, enhanced technology forCO2 sequestration in geologic formations may significantly reducecosts, increase capacity, enhance safety, or increase the beneficial

Fig. 2. Solubility of CO2 in water (Modified) [7].

uses of CO2 injection. Such enhanced technologies may includes(1) Enhanced mineral trapping with catalysts or other chemicaladditives, (2) Sequestration in composite formations which aremultilayered geological formations of imperfect rocks, which resultin greater dispersion of the CO2 plume [5], (3) Rejuvenation of de-pleted oil reservoirs through Enhanced Oil Recovery (EOR) and (4)CO2-enhanced production of methane hydrates by injecting CO2

into methane hydrate formations while simultaneously storingCO2 [9,10].

Hydrodynamic and geochemical processes responsible for trap-ping CO2 in geologic formations over large time frames has beenstudied by several researchers around the world [11–13]. However,mineral trapping (i.e., reactions relying on the chemical reactionsbetween the gas/liquid and solid phases) is less understood, partic-ularly with regard to the kinetics of these reactions. Soong et al.[14] analysed mineral trapping of CO2 with brine in the OriskanyFormation in Indiana County, Pennsylvania. They conducted exper-iments and developed models to study the formation of carbonatesand the effect of pH of the brine on the precipitation of calcite andthey found that pressure and temperature play only a small role inthe process. However, Kharaka et al. [15] suggest that rapid min-eral dissolution can have considerable environmental implicationsdue to the creation of pathways for fluid flow in carbonate rockseals and well cements that could facilitate leakage of supercriticalCO2 and brine. This kind of dissolution should be carefully moni-tored in order to prevent the deterioration of caprock integrity.

The factors to be considered in the geological storage of CO2 aresweep efficiency, preferential flow, leakage rates, CO2 dissolutionkinetics, mineral trapping kinetics and microbial interactions withCO2, and the influence of stress changes on caprock and formationintegrity. Bachu et al. [16] studied some of these factors in detailand concluded that hydrodynamic and mineral trapping mecha-nisms of CO2 mitigation may prove to be key mechanisms for thegeological sequestration of CO2.

1.3. Carbon sequestration options

A number of options for mitigating global warming have beenproposed to date. The development of greenhouse gas mitigationmeasures for the energy and carbon intensive industries is of pri-mary importance. The main processes of sequestration operationsare:

1. Capture and separation of CO2 from point sources such as coalfired power plants and other high intensity CO2 emission indus-tries such as the steel and cement manufacturing industries.

2. Transportation of the captured CO2 to the injection sites afterproper treatment (pressurization, liquefaction, or hydrateformation).

Fig. 3. Relative order-of-magnitude potential of the various storage methods for theworld [2].

Table 1Sequestration storage capacities and risks.

Storage option Capacity(Gt-CO2)

Storageintegrity

Environmentalrisk

Depleted oil and gas fields 25–30 High LowActive oil wells (EOR) Low High LowEnhanced coal-bed methane 5–10 Medium MediumDeep aquifers 1–150 Medium MediumOcean (global) 1000–10,000 Medium HighCarbonate storage

(no transport)Very high Highest High

2654 R. Shukla et al. / Fuel 89 (2010) 2651–2664

3. Injection of CO2 in the geological formation (underground) forstorage.

The ZEP (The European Technology Platform for Zero EmissionFossil Fuel Power Plants) [2] provided an estimation of the relativeorder-of-magnitude potential of the various geological storage op-tions for the world as shown in Fig. 3. Table 1 presents the seques-tration opportunities available for the United States of America andalso the level of risks associated with each of the sequestrationstrategies.

The Geosequestration options are discussed in detail inSection 2.2.

2. Geological sequestration of CO2

Geological sequestration is the process of capturing then inject-ing CO2 into the sub-surface. The advantages of the undergroundsequestration options are:

1. The technique has already been established in EOR (EnhancedOil Recovery) and EGR (Enhanced Gas Recovery).

2. The potential capacity of underground sequestration is esti-mated to be as large as 1000–1800 Gt CO2 [17].

3. Due to the lesser bio-complexity of the underground environ-ment compared to oceans, acceptable environmental impactsare greater for underground compared to ocean sequestration[11].

2.1. Major projects in operation

2.1.1. The Sleipner projectThe first commercial scale CO2 injection project was launched in

1996 in a Norwegian offshore saline aquifer (Sleipner project). Bymid 2008, 10 Mt (Million tonnes) of CO2 has been injected intothe formation (injection started in mid of 1996) which is approxi-mately 1000 m below the seabed. The reservoir (Utsira Formation)is a 200–300 m thick sandstone saline aquifer with thinner inter-mediate horizontal mudstone layers in the reservoir body (1100–800 m below sea level). The CO2 is injected and stored in this res-ervoir and is prevented from being released back onto the surfaceby 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 densethan the aquifer brine, it will move upwards due to buoyancy. TheCO2 plume had reached the top of the reservoir by 1999. Seismicprofiling conducted in 2002 revealed increased physical trappingof the CO2 under the individual layers of mudstone in the sand-stone reservoir [21,22]. It has also been established in studies bydifferent researchers that the isolated scattered layers of mudstonein the caprock formation also increase the total storage capacity ofthe reservoir by providing more caps for physical trapping; this hasbeen confirmed in the Sleipner project. Another 50 m deep con-fined wedge of sand has been found in the Utsira formation closer

to the lower seal, which shall also provide additional storagecapacity to the reservoir [20].

2.1.2. The Weyburn projectThe 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 oftwo different aquifers namely; Vuggy (Upper and Lower) bedsand Marly beds. The lower Vuggy bed presents characteristics ofa good reservoir formation while the upper Vuggy bed (limestonedominated) and the Marly bed (Dolostone unit) show characteris-tics like relatively low permeability and high porosity. The twoaquifers are capped by an anhydrite caprock. Complete descriptionof the field’s geology and fault-related features could be found inBurrowes et al. (2001) [23]. The CO2 coming from the Dakota Gas-ification Company facility is injected into the formation at variablerates between 3000–5000 tonnes per day, and over the lifespan ofthe EOR project (20–25 years), it is estimated that about 20 Mt ofCO2 will be stored in the field (around the years 2025–2030) [3,23].

2.1.3. The Otway Basin Pilot ProjectThe initiatives taken by the Australian government after signing

of the Kyoto protocol in 2007 went onto the planning and deploy-ment of the largest geosequestration demonstration project in Aus-tralia, called the Otway Basin Pilot Project (OBPP). The CooperativeResearch Centre for Greenhouse Gas Technologies (CO2CRC) initi-ated 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 inject-ing 100,000 tonnes of CO2 is achieved by a continuous injection ofCO2 at the rate of about 150 tonnes per day for 2 years (starting inApril 2007) [25,26].

The storage reservoir consists of porous sandstone while thecaprock/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 Naylorfault) that acts like a structural trap/closure and provides long-term seal for the injected CO2 plume. There exit two more faultsin the field (the Naylor East fault and Naylor South fault) but theyare located outside the targeted storage reservoir area [27]. How-ever the faults have been supporting some initial natural gas col-umn and the amount of CO2 injected will be less than theamount of methane being produced. Hence the two faults are un-likely to pose any threat and are believed to be having sufficientsealing capacity for restricting the migration of the CO2 plume.There are several barriers between the storage reservoir and theshallow aquifers in the basin [28]. Also there are barriers to pre-vent the vertical migration of the CO2 and ascertain its safe con-tainment in the reservoir as reported by Dance et al. [29].

Geomechanical investigations and plume migration monitoringhave continued since the commencement of injection and researchis still being done on the performance of the caprock and the pos-sibility of fault reactivation in the field. The success of the OBPP hasled to greater confidence with the CCS technology and the projecthas provided the most needed first-hand field experience neces-sary for larger commercial CCS projects in future.

2.1.4. The In Salah projectThe In Salah Gas project (a joint project of Sonatrach, British

Petroleum and Statoil) in Algeria involves injection of about4000 tonnes of CO2 per day into the Krechba Carboniferous sand-stone (a 20 m thick, methane producing reservoir), at a depth of1800 meters near the Krechba gas field. The field has four gas pro-duction wells and three CO2 injection wells [30]. The monitoring ofthe injected CO2, borehole surveys and geochemical, geophysical as

Fig. 4. The solubility of CO2 in Paradox Valley Brine (PVB) in the presence (opensquare symbols) and absence (open circles) of rocks from the Leadville Limestone(LVL) at 25 �C [39].

R. Shukla et al. / Fuel 89 (2010) 2651–2664 2655

well as geomechanical investigations are still underway. The defor-mation of the ground is being assessed using time lapse satelliteimages which could suggest the movement of the CO2 plume[31]. The geological data is being combined now to the seismicand satellite data of the formation to accurately understand thedynamics of the CO2 plume and to assess the comparative reliabil-ity of each of the methods.

Monitoring of CO2 migration in the sub-surface will be impor-tant in future large-scale sequestration projects. Tracking of thedistribution of trapped CO2 in the fluid, dissolved, and solid phasesis needed for plume confirmation, leak detection, and regulatoryoversight. Existing monitoring methods include well testing andpressure monitoring, chemical tracers, chemical sampling, surfaceand borehole seismic analysis, electromagnetic, and other geotech-nical instruments [32,33]. The spatial and temporal resolution ofcurrent methods is unlikely to be sufficient for performance confir-mation and leak detection. Successful remote sensing for CO2 leaksand land surface deformation is expected to need high-resolutionmapping techniques for tracking migration of sequestered CO2

and its by-products as well as deformation and micro-seismicitymonitoring [30].

2.2. Geosequestration systems

2.2.1. CO2 sequestration in saline aquifersKoide et al. [34] suggest that the global sedimentary basins are

capable of holding around 320 gigatons of carbon dioxide. The Uni-ted States can inject approximately 65 percent of CO2 produced bypower plants directly into deep-saline aquifers below the plants[9]. Similar studies on the capacity of saline aquifers are being car-ried out around the world [11,35–37]. Effective long-term storageof CO2 is only possible when the storage basin is large and isolated,and the reservoir caprock has good sealing capacity. This low per-meability caprock formation should be capable of preventing thesupercritical CO2 from migrating out of the intended storage reser-voir or potentially contaminating the surface environment or theexisting natural resources.

CO2 geosequestration in saline aquifers in sedimentary basinscan be achieved by four main mechanisms: (a) CO2 dissolution inthe formation water called solubility trapping, (b) geochemicalreactions with the aquifer fluids and rocks known as mineral trap-ping, (c) structural trapping, where the CO2 rises to the top of geo-logical structures below an impermeable top seal and is storedthere due to capillary pressure and (d) hydrodynamic trappingwhere the aquifer does not allow the CO2 plume to seep out ofthe targeted reservoir zone (in the condition where the densityof the CO2 is very close to that of water) hence increasing its resi-dence time. Bachu [3] explained the hydrodynamic trapping phe-nomenon as an extremely slow hydrodynamic dispersion of theCO2 plume into the saline aquifer because of the low velocitymovement of aquifer water (<0.1 m/year). Bachu and Adams [11]and Bachu et al. [16] describe the UCSCS (Ultimate CO2 Sequestra-tion Capacity in Solution) of an aquifer as the difference betweenthe ultimate capacity for CO2 at saturation and the total inorganiccarbon currently held by the solution in the aquifer. It depends onfluid pressure, temperature and salinity of the aquifer.

Most deep aquifers are highly saline and are situated in sedi-mentary basins and hence can host larger amount of carbon diox-ide due to the high formation pressures. The sequestrated CO2 canbe mineralogically captured in the storage reservoir since it is alsoexpected to react with the water, salts and the formation rocks toeither increase or decrease the capacity of the reservoir dependingupon the type of chemical reaction taking place as well as on thecarbonate or mineral compounds produced during the reactions.The supercritical carbon dioxide injected into the aquifers has den-sity of about 660 kg/m3 which is lower than the saline formation

water and hence will rise towards the cap rock due to buoyancyforces [38].

Considering mineral trapping as another important governingmechanism in carbon dioxide sequestration in saline aquifers,Rosenbauer et al. [39] conducted several experiments in mineraltrapping by reacting supercritical CO2 with different combinationsof host fluids and formation rocks such as the Paradox ValleyBrines (PVB), limestones and sandstones, and confirmed the pre-established fact that the aqueous solubility of CO2 is generally low-er at elevated temperature and salinity and higher at elevatedpressure as shown in Fig. 4. Geochemical reactions of supercriticalCO2 with limestone versus Arkosic sandstone, in CO2 saturatedbrine–rock experiments were carried out to evaluate the effectsof multiphase water–CO2 mixtures on mineral equilibrium. The po-tential of CO2 sequestration as mineral phases within deep-salineaquifers was studied in the experiments. They observed that, witha decrease of temperature from 120 to 25 �C , the solubility of CO2

increased by 6% at 20 MPa pressure, whereas with the presence oflimestone it increased by 5% at 30 MPa, relative to its solubility inPVB alone (Fig. 4). This ionic trapping or enhanced solubility of CO2

was due to the rapid dissolution of the calcite in the presence ofcarbonic acid. Also, they observed that, because of temperature ef-fect on the solubility of calcite, the solubility of CO2 decreased atelevated temperatures [39].

2.2.2. Sequestration in depleted oil and gas reservoirsThe global CO2 sequestration potential of oil and gas reservoirs

is estimated at between 400 Gt (Giga-tonnes) to 900 Gt but thesefigures would increase by 25% if the undiscovered oil and gas res-ervoirs are included [1]. Gas reservoirs are the most suitable sitesfor sequestration of CO2 since they have already proven their capa-bility of holding and safely storing gas for spans of geological timescales.

If surface based compression is used in the natural gas fields,the injection of CO2 can also enhance the natural gas recovery toas high as 95% of the gas initially in place [40]. The injected CO2

within a certain pressure range can move the remaining oil orgas out of the reservoir and hence lead to environmental as wellas commercial benefits in terms of EOR or EGR. It has been sug-gested that the addition of CO2 in gas reservoirs may contaminatethe natural gas. However, Oldenburg and Benson [41] state that,since the CO2 has considerably higher density and viscosity, thereis very low possibility of the CO2 and natural gas getting mixed,and even if they do, it will take them a considerably long periodon geological timescales.

When CO2 is injected into an oil reservoir, it may mix with theoil phase, causing it to swell thereby reducing its viscosity. CO2

2656 R. Shukla et al. / Fuel 89 (2010) 2651–2664

injection also helps to maintain or increase the pressure in the res-ervoir. The combination of these processes allows more of the oil toflow to the production wells. Here, injection of CO2 raises the pres-sure in the reservoir, helping to sweep the oil towards the produc-tion well [42]. Globally, about 130 Gt of CO2 could be disposed as aresult of CO2-EOR operations (variable depending on how muchCO2 was produced with the oil). Specific attention should be paidto the safety issues of CO2 sequestration (applicable for gas as wellas for oil fields) and unintended fracturing of the seal as a conse-quence of the pressure fluctuations in the reservoir.

Statoil has implemented geosequestration techniques in theSleipner field, which extract about one million tonnes of CO2 yearlyfrom its production of commercial gas. It is not meant to enhancethe gas recovery, but to sequester the extracted compressed CO2

gas by injecting it through a separate injection well into the Utsiraformation (sandstone and saline aquifer), which is about 1000 mbeneath the sea bed [21,43].

2.2.3. CO2 sequestration in coal seamsUnmineable coal seams provide another potential reservoir for

sequestration of anthropogenic CO2. The mechanism of storage ofthe CO2 is mainly through adsorption on the surfaces of micro-pores within the coal matrix, which is very different from thehydrodynamic trapping mechanism in saline aquifers or oil andgas reservoirs. Theoretically, the CO2 should stay in the coal as longas the reservoir pressure is above desorption pressure. The sorp-tion 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 simultaneouslysequester CO2 and increase the production of Coal-Bed Methane(CBM). Commercial methane production from deep unmineablecoal beds can be enhanced by injecting CO2 into the coal forma-tions, 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 commercialCBM operations. This method for enhancing coal-bed methane pro-duction is currently being tested at two pilot demonstration sitesin North America (Alberta project and pilot project in the San JuanBasin, New Mexico/Colorado) [45].

Mehic et al. [46] and Viete and Ranjith [47] conducted a series ofexperiments on Australian black coal and south Asian brown coalsamples and observed that, with the adsorption of CO2, the uniaxialcompressive strength of the coal samples decreased. At the sametime the coal behaves in a more ductile manner with a stretchedelastic region in the stress strain curve. Adsorption of CO2 in coalleads to matrix swelling and can cause a decrease in permeability.It was found that stress thresholds were lower for the samples sat-urated with CO2 compared to samples saturated with air. These re-sults suggested a possible correlation between strength of coal andCO2 adsorption under the laboratory test conditions.

Another important factor to be considered for CO2 storage in coalseams is the sensitivity of coal towards moisture. Coal has a ten-dency to swell when it absorbs CO2 or water. The unusual behaviourof coal due to gas sorption has been investigated by many research-ers such as, for example, Busch et al. [48] and Goodman et al. [49].The importance of adsorption isotherms, effects of gas adsorptionon permeability and changes in mechanical properties of coal suchas strength have also been studied. Krooss et al. [45] and Khaledet 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 massis reasonably complex as it involves the effects of the formation’s

lithologies, dynamics of the pore fluid and the geochemical changeslike dissolution and mineral precipitation. In formations with slowmoving pore fluid front, more CO2 gets dissolved into the fluid andhence smaller amount ends up reaching the caprock interface. Themigration of CO2 may also act under free convection between thedenser CO2 saturated water and the lighter unsaturated water.

The caprock, acting as a seal for the rising CO2 plume, must beable to withstand the changes in stress field and changes in phys-ical and chemical properties due to the CO2–brine–rock mineralinteractions. This process goes on for thousands of years until theCO2 is finally immobilized and converted into solid carbonate pre-cipitates. During this period, the rock mass is subjected to com-pression, tension (in some cases), weathering due to mineralprecipitation/dissolution and crack initiation and/or propagationcaused by changing stress patterns and excess overpressure/injec-tion pressure. This can sometimes hamper the strength and sealintegrity of the rock and lead to dynamic structural changes, whichmay undermine the efficiency of the sequestration project. Thereactions can also cause plugging or improvement of fracture per-meability in cases of vein-filling and dissolution, respectively [3,4].

The breakthrough or threshold pressure of a porous medium is amajor factor affecting the capillary sealing of the medium againstthe fluid. When the wetting face is displaced to an extent that thepercolation threshold is exceeded, a continuous flow path of non-wetting phase is formed across the pore system. This flow occursthrough the largest interconnected pores, and with further incre-ment of pressure, flow also occurs in new smaller pathways, hencethe effective permeability is enhanced and the ultimate flow pathsare dominated by the flow properties of the fluid in addition to thegeometric properties of the connected pore spaces of the sample.Fig. 5 presents curves of upstream and downstream pressures fora breakthrough experiment conducted with a closed reservoir andshows the pressure differential Pd for the gas phase. The continu-ously decreasing effective permeability (keff) vs. time (t) plot asso-ciated with the decrease in differential pressure indicates the lossof interconnected flow paths during the latter part of the experi-ment. The residual pressure difference between the upstream anddownstream pressure in the chambers is a measure of the largesteffective pore radius in the sample. This pressure difference deter-mines the capillary-sealing efficiency of the rock and is resultedfrom the loss of interconnectivity of pores in the sample [51].

A number of studies have been conducted and models beendeveloped for fluid flow through rocks and rock fractures [51,52]but there has been very little research done on the flow of super-critical fluids and gases in fractures. Yang et al. [53] produced therelationship between CO2 gas transmissivity, fracture pore pres-sure and fracture volume stress (Figs. 6a and 6b).They presentedthe following empirical formula for seepage of gases through frac-tures in coal under 3-dimensional stress:

Kfg ¼ Kf 0 exp �br1 � bp

Kn

� �� c

1� mr

Erðr2 þ r3Þ �

2mr

Err1

� �� �ð1Þ

where, r1 = maximum principal stress, r2 = intermediate principalstress, r3 = minimum principal stress, b = coefficient reflecting theinfluence of normal deformation, c = coefficient reflecting the influ-ence of tangential deformation, Kfg = coefficient of permeability ofgas, Kf0 = initial permeability of fracture, Kn = normal stiffness offracture, mr = Poisson’s ratio of the rock sample, Er = bulk modulusof the rock sample.

Yang et al. [53] used the least square method to analyse theexperiment data of CO2 and gives the following equation for gasseepage in fractures in coal under 3-dimensional stress:

Tfg ¼ 0:9416p�0:2788 expf�0:0205½r1 � bp� � 0:0053½0:6ðr2 þ r3Þ� 0:8r1�g ð2Þ

where all the constants used are same as listed in Eq. (1).

Fig. 5. Experimental capillary breakthrough curves for absolute pressures, downstream pressures and effective permeability of a CO2 experiment [51].

0.00E+00

5.00E-07

1.00E-06

1.50E-06

2.00E-06

2.50E-06

0 1 2 3 4 5

Fracture pore pressure (MPa)

Tra

nsm

issi

vity

of

CO

2 (m

3/M

Pa.

sec)

11MPa

14MPa

17MPa

Fig. 6a. The relationship of CO2 gas transmissivity and fracture pore pressure [53].

0.00E+00

5.00E-07

1.00E-06

1.50E-06

2.00E-06

2.50E-06

3.00E-06

3.50E-06

4.00E-06

4.50E-06

5.00E-06

80 130 180

Volume stress (kg/cm2)

Tra

nsm

issi

vity

of

CO

2

(m3 /M

Pa.

sec)

1MPa

2MPa

Fig. 6b. The relationship of CO2 gas transmissivity and fracture volume stress [53].

R. Shukla et al. / Fuel 89 (2010) 2651–2664 2657

The above equations take into account gas adsorption of gas andnormal and tangential deformation.

3.1. CO2–brine–rock interactions

Past studies suggest that elevated temperatures and salinity re-duce the solubility of CO2 in water while lower temperaturesgreatly decelerate the rate of chemical reactions. The rate of reac-tion is also affected by the mineral composition, aqueous fluidcomposition, mineral micro-surface area and the brine salt con-tent. Numerical models developed to simulate the geochemicalreactions taking place in CO2–brine–rock mass using only labora-tory experimental results shall not be expected to represent thescenario of real field reservoirs every time, since the natural reac-tion rates could be exponentially lower than that of the laboratoryreaction rates. The geochemical interaction between the CO2–brine–rock is likely to result in acid hydrolysis of the rock mineralsand can have several different effects on the caprock and the over-all migration of the injected CO2 [54].

The injected CO2 dissolves in water and forms carbonic acidwhich may react with alkaline waters and precipitate as carbonate.The CO2 dissolved in brine under high pressure makes the brinehighly acidic, which also results in dissolution of the rock carbon-ate minerals, producing bicarbonate ions. This carbonic acid canalso cause weathering of the silicate rocks as well [34]. The CO2

can therefore be trapped in the form of carbonate minerals and sil-icate minerals. Alkaline groundwater helps in the precipitation ofthe carbonate minerals and this precipitation may seal the frac-tures and reduce the permeability of the over-burden rock strataand thus isolating the CO2 saturated water. This has been pre-sented with detailed experimental and analytical discussion ofCO2–brine–rock reactions by Rosenbauer et al. [39].

Supercritical CO2 may also react with the organic contents ofthe caprock and cause minor changes in the permeability andporosity of the caprock [55]. The viscosity of supercritical CO2

changes with temperature and pressure. During the displacementof the water by the CO2, the rheological properties of the CO2 com-bined with the rock heterogeneity, can lead to flow instability andlocalisation such as the development of fingering [1].

In addition to earlier discussion about the Sleipner project inthe North Sea, the geochemical interaction of the constituents ofthe sequestration system is also of interest. As discussed earlier,the 200 m thick Utsira formation forms the reservoir for CO2 stor-age in the project and is overlain by a rather complex formation ofmudstone layers, which plays the role of caprock. This caprock for-mation is divided into three major units namely the lower, middleand the upper seals. It is highly efficient with thin and relatively

2658 R. Shukla et al. / Fuel 89 (2010) 2651–2664

impermeable layers, and consequently it is unlikely that leakage ofthe stored CO2 will occur. The Utsira formation being sand, the ma-jor storage mechanisms are mainly through physical and dissolu-tion trapping of CO2 [19,20].

3.2. Integrity of the caprock in CO2 sequestration

Mechanisms that may result in CO2 leakage have been dis-cussed, among others, by Bouchard and Delaytermoz [54], Rutqvistand Tsang [55], and Saripalli and McGrail [56]. The leakage-relatedrisks involved in the geosequestration of CO2 are identified asfollows:

� Reactivation of the faults in the caprock: local pressure near afault during injection reduces effective normal stress and thusreduces 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. Itshould be at a desired depth to keep the CO2 in supercritical stateand at the same time it should be away from any major anthropo-morphic penetrations like faults or wells to avoid leakage. The cap-rock mass should be dense and intact, and should possess lowpermeability so as to keep the injected CO2 from seeping throughit over a long period. Although a chemically immature caprockwould be preferable to facilitate and enhance geochemical trap-ping of CO2 in the later stages of the storage phase, the initialbrine–CO2–rock mineral interactions may also result into loweringof the injection rate through blocking of pore-throats in the injec-tion phase [57]. Also the caprock must have high strength underboth compression and tension to be able to bear the change instress fields during and after injection. The above stated propertiesof a good caprock are indispensable for a secure CO2 storage sys-tem and should be thoroughly studied for each project during plan-ning and deployment of CO2 injection process. These experimentaldata of the rock properties and CO2 interaction with the rock min-erals and brine can be used in development of new empirical mod-els or modifying existing models like failure criterion and porousmedia fluid-flow laws. These new empirical models shall then beimplemented in numerical simulation models for geological stud-ies at reservoir level. Such models would predict the mechanismsof CO2 transport and storage in the rocks closer to real casescenarios.

Rutqvist and Tsang [55], mention that the greatest risk of rockfailure is at the lower part of the caprock because of the stronglycoupled hydromechanical changes which are generated as a resultof reduction in the effective mean stress induced in the lower partof the caprock. The TOUGH-FLAC model developed by Rutqvist andTsang [55], demonstrate how a supercritical CO2 plume migratesthrough a brine aquifer overlain by a semi-permeable (zero stresspermeability of 1 � 10�13 m2) caprock in a reservoir formationover 10 years after the injection. The lower layers of the caprockexperience a very high propensity to hydraulic fracturing, sincethe pressure margin, the amount of fluid pressure that the caprockcan take without any considerable failure, is found to be only0.1 MPa after 10 years of injection. Any slight change in the seismicconditions or in permeability of the caprock, could lead to the reac-tivation of an existing faults or slips. The propensity for shear reac-tivation of faults increases due to any increase in the aquiferpressure during the injection period and the development ofporo-elastic stresses in the rocks towards the bottom of the reser-

voir. The supercritical CO2 migrates at an accelerated rate afterreaching the upper part of the caprock. This change in pace couldbe influenced by the combined effects of hydromechanical perme-ability changes (due to reaction and interaction of CO2 and rockminerals, brine or any other material present in the reservoir),relative permeability (in case of heterogeneous rock mass, geolog-ical features like faults or joints, damages in the rock masses,water or brine formations) and viscosity changes (caused whenthe CO2 changes its phase from supercritical to liquid or gaseousphase).

Peacock and Mann [58] discussed various geological factorscontrolling the geometries, frequency, orientation and distributionof fractures in rock and found that the major factors affecting thefracture patterns are; fault orientations, in situ stress field and fluidpressures. Fractures tend to close when they are aligned perpen-dicular to the r1 (maximum principal stress) while those arealigned perpendicular to r3 (minimum principal stress) tend toopen-up. The initiation of the fractures can be affected by thein situ stresses and fluid pressure. It has been determined in paststudies that if the fluid pressure exceeds r3, the effective stress issuch that the effective tension exists in the r3 direction. This iswhen the extension fractures are likely to initiate and remain openin the direction perpendicular to r3 [58].

It is an established fact that any degree of CO2 migrationthrough a fractured cap rock poses a potential risk to the environ-ment [56]. Leakage through caprock may occur due to fracturing ofthe cap rock under pore fluid pressure or due to the upward pres-sure exerted by the CO2 accumulated just beneath the cap rock.Reopening of pre-existing faults or joints in the caprock may occurunder the influence of external forces like seismic activity or due tothe stress changes inside the geological formation. The develop-ment of micro-cracks in the formation may also lead to the even-tual decline in the efficiency of whole sequestration project.There is also a possibility of CO2 leakage through capillaries inthe caprock, when the pressure differences of the fluid phase andthe water phase in the pores adjacent to the cap rock is higher thanthe capillary entry pressure of the caprock [59]. Micro-cracks in therock formation may also lead to the eventual decline in the effi-ciency of whole sequestration project.

Zhang et al. [60] propose a hyperbolic criterion as presented inEq. (3), for the failure through a rock matrix due to tensile fractur-ing extending to pre-existing cracks. The stress curve in the hyper-bolic criteria is curved at low confining stress while it tends tobecome linear with increase in confining stress. The theory of thiscriterion is based on the relationship found between the confiningstress and fracture mechanism of the rock. The rock undergoes ten-sile brittle failure at initial lower confining pressures. The rocktends to fail under tensile-shear failure mechanism and experi-ences crack closing phenomena (which provides more strength tothe rock) at increased confining stress.

ðr1 � r3Þ2 ¼ m2ðr1 þ r3Þ2 þ aðr1 þ r3Þ þ b ð3Þ

where, r1 = maximum principal stress, r3 = minimum principalstress, a and b are coefficients of the criterion, m is the slope ofthe asymptote to the axis r1 = r3.

The hyperbolic criterion assumes the stresses r1 and r3 to becompressive, when r3 = 0, r1 becomes c0 (where, c0 is the uniaxialcompressive strength). The equation consists of only two coeffi-cients (a, m), and in that case is written as:

ðr1 � r3Þ2 ¼ m2ððr1 � r3Þ2 � c20Þ þ aðr1 � r3 � c0Þ þ c2

0 ð4aÞ

The coefficients are determined by optimisation method onf ? min with results of the triaxial tests. Where ‘‘f” is given bythe following equation:

0 0.05 0.1 0.15 0.2 0.25 0.3Strain (%)

0

10

20

30

40

50

60

70

10

0248

Axi

al S

tres

s (M

Pa)

Fig. 7a. Complete stress–strain curves showing the transition from brittle to ductiledeformation of rock specimens [64].

0

10

20

30

40

50

60

70

-5 0 5 10 15 20

Confining Pressure (Mpa)

Un

con

fin

ed C

om

pre

ssiv

e S

tren

gth

(M

pa)

Tension Compression

Fig. 7b. Curve between compressive strength of rock specimens and confiningpressure [64].

R. Shukla et al. / Fuel 89 (2010) 2651–2664 2659

f ¼XN

k¼1

ðr1k � r01kÞ2 ð4bÞ

where, N is the number of total triaxial data, r1k is the predicted va-lue of strength of the rock by the criterion, r01k is the experimentaldata under the same confining stress.

The criterion discussed above, proves to be better than manyother failure criterion because it is valid for different rocks at vary-ing confining conditions [60]. They conclude that the presence ofmicro-cracks results from stress accumulation near the cracks.Wing cracks tend to propagate to the adjacent original cracksand finally lead to the macro-level failures of the rock mass.

The most appealing leakage mechanism in this study is theleakage of CO2 due to hydraulic fracturing, which is caused dueto over pressurization of the cap rock or pressure/stress changesin the system. The risk of leakage through fracturing is low as longas the reservoir pressure does not exceed the initial reservoir pres-sure. Shear deformations caused by seismic activities or due todeep underground structures nearby the reservoir, and fracturingmay also result in enhanced cap rock permeability by creatingpreferential flow paths for CO2 [59]. The chemical interaction be-tween the supercritical CO2 and the rock minerals may lead tothe formation of high permeability zones which could further leadtowards progressive leakage of CO2 [61].

Though remotely possible, a seismic and stress-field interfer-ence due to man made underground structures might also contrib-ute towards deterioration of the intactness of the caprockformation. Sminchak and Gupta [62] suggest that high injectionpressure may trigger some induced seismic activity in the area ofsupercritical CO2 injection, the reason behind this could be thehydraulic fracturing, dissolution or rock mineral precipitation bythe supercritical CO2 rich brine. Their study reveals that the fric-tional resistance declines along the pre-existing faults and contrac-tion of the rock takes place when the fluid is extracted from therock, causing the fault to slip. Since the density of supercriticalCO2 is less than that of the brine and is less viscous too, this enablesit to migrate more easily through pore spaces and fractures. Thiskind of property contrast may produce density-driven flow as theCO2 tends to migrate upwards and impose pressure on the overlay-ing formation leading to minor seismic activities in some cases[3,62].

Min et al. [63] successfully reproduced the experimentally ob-served failure phenomena, using numerical methods and as a re-sult inferred that the rock deforms linearly and elastically ataxial stresses below the yield strength, which is dependent onthe confining pressure. Further compression leads to inelasticdeformation up to the peak strength. At low confining pressures,the curves show defined peak strength and a gradual strength de-crease in the post failure region until final deformation occurs atabout constant axial stress, i.e., residual strength. At higher confin-ing stresses, the rock exhibits work-hardening and the Young’sModulus of the rock is higher than that of the rock at lower confin-ing stress. The transition from brittle to ductile deformation in therock, with an increase in confining stress, is also clearly demon-strated by Tang et al. [64] in Figs. 7a and 7b.

3.2.1. Stages of fracture formation: Fracture closure and initiationThe fracture and deformation characteristics of a reservoir cap-

rock and its response to injection and storage of supercritical CO2 isextremely significant while assessing the storage capacity of a res-ervoir. Extensive testing and experimentation is required to gaugethe suitability of a caprock mass before it is considered for carbonsequestration. The deformation and fracture characteristics ofrocks including initiation, propagation, and interaction of stress-in-duced fractures are extremely complicated to identify but are nec-essary to be considered. Upward pressure is exerted on the caprock

layer when the CO2 changes its phase from supercritical to liquid orto gaseous form, after injection or when a density-driven flowtakes place. This could trigger the initiation of micro-cracks whichcan eventually lead to macro-level fracturing of the caprock.

Both axial and lateral stress components are involved in the clo-sure of cracks. Eberhardt et al. [65] performed uniaxial tests onbrittle rocks and used a combination of moving point regressionanalysis (performed on the axial, lateral, and volumetric stress–strain curves) and acoustic emission responses (including theevent properties and energy calculations) to identify crack initia-tion. Fig. 8 shows the curve of average volumetric stiffness vs. axialstress, indicating the occurrence of major strain rate changes be-tween crack initiation and crack damage in brittle rocks. Eberhardtet al. [65] analysed the axial and lateral stiffness curves to indicatea significant rate change in strain that occurs prior to the crackdamage threshold, possibly marking the small-scale coalescenceof cracks.

The opening of fracture faces parallel to the applied load and theclosure of fracture faces perpendicular to the load cause certainchanges in the relative lateral and axial deformations, respectively.These changes appear as inflections in the stress–strain curveswhich, in turn, can be used to identify the different stages of rockdeformation and failure. Crack closure occurs during the initialstages of loading, when pre-existing cracks close which are orien-tated at an angle to the applied load. The crack closure stress levelindicates the load at which a significant number of pre-existingcracks have closed and from that point an almost linear elastic

Fig. 8. Plot of average volumetric stiffness vs. axial stress, indicating the occurrenceof major strain rate changes between crack initiation and crack damage for a brittlerock. rcs = crack coalescence stress threshold [65].

2660 R. Shukla et al. / Fuel 89 (2010) 2651–2664

behaviour commences. This is approximated by determining thepoint on the stress–strain curve where the initial axial strain ap-pears to change from nonlinear to linear behaviour. Linear elasticdeformation takes place once the majority of pre-existing crackshave closed. Analysis of the axial and lateral stiffness curves indi-cate that a significant rate change in strain occurs prior to the crackdamage threshold, possibly marking the small-scale coalescence ofcracks.

Crack initiation (rci) represents the stress level where micro-fracturing begins and is marked as the point where the lateraland volumetric strain curves depart from linearity. Unstable crackgrowth occurs at the point of reversal in the volumetric straincurve and is also known as the point of critical energy release orcrack damage stress threshold rcd [66,67]. This unstable crackgrowth continues to the point where the numerous micro-crackshave coalesced and the rock can no longer support an increase inload.

A similar study was conducted by Ranjith et al. [68] on coalsamples with single fracture and multiple fractures, the acousticemission counts were recorded and it was observed that thethreshold stresses were higher for the multi-fracture samples

Fig. 9a. Acoustic emission data for a si

when compared to single fracture samples. Figs. 9a and 9b showsacoustic emission counts which clearly depicts the major stressthreshold points. The initial part of the curves, where there arenegligible counts at constant increase of axial stress, denotes thecrack closure phenomena it is then followed by an increase inthe number of counts which indicate the crack initiation and stablecrack propagation processes. It finally ends up into a more unstablepropagation condition denoted by the gradual change in the slopeof the curve and is called the crack coalescence stage. Stressthresholds for crack closure, initiation and propagation occur atconsiderably lower levels of stress in case of multi-fracturedsamples.

Indraratna and Ranjith [69] conducted triaxial testing and anal-ysis of two-phase flow (water and air) at a range of confining pres-sures from 0.5 to 2 MPa, and observed that an increase in confiningstress results in a decrease of the two-phase flow rates due to theclosure of fractures in hard rocks as can be seen in Fig. 10. Pruessand Garcia [70] developed a simplified, one-dimensional flowmodel to model the discharge of CO2 through a semi-vertical faultand suggested that a safe and leak-proof storage of CO2 will requiremultiple barriers, since the process of loss of CO2 from the reservoirappeared to be a self-enhancing process. Fig. 11 shows the growingtrends of CO2 flow rate changing with time (with and without con-sidering salinity of the brine and fugacity of CO2).

3.2.2. Potential role of fractures and pre-existing faults in caprockfailure

One of the most significant factors that can affect the migrationof carbon dioxide through a caprock is the geology of the reservoirformation and the over-burden rock strata. Pre-existing non-trans-missive faults and fractures in the rock formations may provide aneasy path for the CO2 to leak from the intended storage reservoir.Hawkes et al. [71] explain several factors affecting the geologicalstorage of CO2 and state that fault reactivation or opening up ofpre-existing faults/fractures, may occur when the maximum shearstress acting on the fault exceed the shear strength of the faultplane. They also discuss the fault slip tendency and the modifiedslip tendency (Tsm), which is defined by using the Mohr–Coulombcriterion:

sslip ¼ cfault þ ðrn � pÞ tan /fault ð5aÞ

Tsm ¼s

sslipð5bÞ

ngle-fractured rock specimen [68].

Fig. 9b. Acoustic emission data for a multi-fractured rock specimen [68].

R. Shukla et al. / Fuel 89 (2010) 2651–2664 2661

where, s = shear stress, sslip = critical shear stress for slip to occur,cfault = fault cohesion, /fault = fault friction angle, p = pore pressurein the fault plane, rn = normal stress.

The above equations (Eq. (5a) and (5b) suggest that the slip ten-dency of a fault is highly dependent on pore pressure [71]. Depend-ing on the orientation of existing faults and the change in porepressure CO2 injection may induce high shear stresses on the cap-rock above the reservoir. The maximum sustainable CO2 injectionpressure should also be estimated depending on the permeabilityand thickness of the reservoir, and the injection well should be lo-cated as far away from faults as possible to minimise the chancesof fault reactivation near the injection well. Streit and Hillis [72]have also discussed the importance of estimation of maximum sus-tainable formation pressures and developed models of fault stabil-ity which takes account of stress changes.

Soltanzadeh and Hawkes [73] used the DCFS (Coulomb FailureStress) concept to predict fault reactivation tendency for normal

Fig. 10. Effect of confining pressure on two-phase flow rates with inlet w

and thrust fault stress regimes. According to the concept, the faultreactivation factor (k) can be given as:

k ¼ DCFS=ðaDPÞ ð6aÞ

where, DCFS ¼ Ds� lsDr0n, Ds = shear stress on fault plane,Dr0n = effective normal stress on fault plane, ls = coefficient offriction.

Similarly, under plain strain conditions, k can be given by thefollowing relationship:

k ¼ ðdL � caðHÞÞsinhþ ðdF coshþ lS sin hÞ � ðdL � caðVÞÞ

� cos hðdF sin hþ lS cos hÞ þ dDcaðHVÞ ððsin2 hþ cos2 hÞdF

� 2ls sin h cos hÞ ð6bÞ

where dL is allocation index which equals one within the reservoirand zero within the surrounding rock, h is the fault dip angle,ca(H) is the normalized horizontal stress arching ratio, ca(V) is the

ater and air pressure held constant at 0.125, 0.20, and 0.25 MPa [69].

Time (s)10

no s,f

Flo

w r

ate

(kg

/s)

2 104 106 108 101010-2

10-1

100

86

4

2

86

4

2

CO2 rate at inlet

with s,f

no s,fwater rate at outlet

with s,f

CO2 rate at inlet

10

no s,f

2 104 106 108 101010-2

100

86

4

2

86

4

2

CO2 rate at inlet

with s,f

no s,fwater rate at outlet

with s,f

CO2 rate at inlet

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 fugacityeffects) [69].

2662 R. Shukla et al. / Fuel 89 (2010) 2651–2664

normalized vertical stress arching ratio, ca(HV) is the normalizedshear stress arching ratio, dF is the stress regime index, and dD isthe fault dip direction index.

Using the above relationships, Soltanzadeh and Hawkes [73]developed contour maps which can predict the maximum andminimum fault dip angle (at any point in the map in injection aswell as production scenario) in a reservoir. According to generalunderstanding, the fault reactivation in a normal fault stress re-gime during production, the regions within and near the lateralflanks of the reservoir tend towards reactivation, while on theother hand in case of thrust fault stress regime the overlayingand underlaying rocks tend towards reactivation. During injection,the overlaying and underlaying rocks tend towards reactivation innormal fault stress regime while regions within and near the lat-eral flanks of the reservoir tend towards reactivation in the thrustfault stress regime [73].

4. Research gaps and required future work

This paper presents an overview of CCS research around theworld, including the different geosequestration systems, the differ-ent trapping mechanisms involved in the storage of CO2 with ma-jor focus on the importance of caprock integrity.

The results of some past and current geosequestration projectshave demonstrated that it is feasible to store CO2 in sub-surfacegeological formations such as depleted oil and gas reservoirs andsaline aquifers. Also, the injected CO2 can be used to enhance therecovery of oil and coal-bed methane even though the feasibilityof sequestration in deep coal seams still needs further researchmainly due to the problem of low permeability and injectivity.The experience from the projects has also revealed the effects ofthe geological layouts of the cap rocks on the efficiency of a seques-tration project.

The review conducted in this paper shows that the geomechan-ical and geochemical properties of the reservoir and caprock havegreat influence on the outcome of the project, detailed site charac-terization should therefore be conducted before planning anddeployment of any CO2 storage project. If possible, a site withthe optimum characteristics should be chosen. The informationprovided in this paper has been gathered from the experience ofvarious sequestration projects around the world. The understand-ing and experience gained from those projects and research carriedout in the field of CCS will provide some important scientificknowledge for future research and the development of commercialsequestration projects.

Overall, a good quality of knowledge base has been establishedabout the storage science through worldwide research. Althoughfrom the past research and experience, we learn that there still ex-ists an array of gaps in the understanding of CCS such as:

(a) Absence of reliable CO2–brine–rock interaction models tomonitor the kinetics of geochemical trapping through thereservoir and the caprock. Laboratory experiments closelysimulating field conditions over long periods are required.The data from these experiments can be used to test existingmodels. The models need to be validated against both labo-ratory results and field data. However, some new techniquesmay need to be developed as some of reactions occur veryslowly in the field. Without the ability to predict the rockCO2–brine–rock interaction, and any consequent chemicaland mechanical changes, there can be some uncertaintyregarding the long-term performance of the project.

(b) For sequestration of CO2 in deep-saline aquifers or depletedhydrocarbon reservoirs, the reactivity of the dissolved CO2 inthe formation water may alter the reservoir and cap rockproperties, as well as damage the equipments used for injec-tion and monitoring. More research is required in order todetermine maximum sustainable injection pressures toavoid caprock failure.

(c) Incomplete prospective on the geomechanical and geochem-ical behavior of supercritical CO2 in a geological formation athigh pressure and high temperature.

(d) What failure criteria are applicable to model saline aquifersand the cap rock? Can we use existing failure models whichare commonly used in rock mechanics? These need furtherexperimental work and theoretical developments to simu-late rock media by considering the coupled effects of geome-chanical, thermal, geochemical, and flow.

(e) Lack of firm information on safe injection pressure estima-tion and vulnerability of caprock towards hydraulicfracturing.

(f) Lack of research about fracture sealing or caprock strengthdeterioration in relation to weathering of rock minerals inlong term.

(g) Better understanding of potential leakage caused by naturalseismic activities in the future is required.

(h) Better models are needed to model the fate of the injectedCO2 reservoir which takes into account the multiphase flowof CO2 and brine, the effects of stress on permeability, andthe dissolution and chemical interaction of the CO2 withthe rock minerals. Validation of the models may require con-ducting tests on samples collected from different locationsto study the composition of the pore fluids and the rock min-erals, and study how they change with time.

(i) One of the possible leakage paths of CO2 is due to the dete-rioration of well cement and this has received some atten-tion in the recent past. Deterioration of normal Portlandcement may occur when it reacts with CO2 and thereforenew types of cement, such as geo-polymer cement may beneeded in order to prevent leakage.

5. Conclusions

A comprehensive study has been presented on the various tech-niques and mechanisms involved in the mitigation of carbon diox-ide during and after its sequestration into geological formationswith special emphasis on its safe storage in sedimentary basins.For a sequestration project to be successful storage periods areusually over an extensive period of time and hence the importanceof caprock sealing integrity over the required duration isparamount.

R. Shukla et al. / Fuel 89 (2010) 2651–2664 2663

More elaborate laboratory experiments should be conductedunder conditions representative of natural reservoir conditions.The chemical interaction of the carbon dioxide with the rock min-erals and groundwater should be studied with special consider-ation of the effects of other processes on the path and reactionrate. The effects of different natural and human activities such asseismic/tectonic activities, deep oil/gas/coal mining and other deepdriven underground structures, on the integrity of the caprockshould also be careful studied so as to ascertain the long-termsafety of sequestration projects. Hence it is concluded that if suffi-cient amount of consideration is given to the vital points identifiedin the presented research review, the planning and execution of aCCS project could be made more efficient and commendable.

References

[1] Bachu S, Simbeck D, Thambimuthu K. Special report on carbon dioxide captureand storage. IPCC–Intergovernmental Panel on Climate Change 2005.

[2] Strategic Research Agenda. The European technology platform for zeroemission fossil fuel power plants (ZEP); 2007: Available at: <http://cordis.europa.eu/technology-platforms/pdf/zeroemission.pdf>.

[3] Bachu S. Sequestration of CO2 in geological media: criteria and approach forsite selection in response to climate change. Energy Convers Mgmt2000;41:953–70.

[4] Mackenzie FT, Lerman A, Ver LMB. Recent past and future of the global carboncycle. Studies in geology, 47. Tulsa, OK: American Association of PetroleumGeologists; 2001. P. 51–82.

[5] Preston BL, Jones RN. Climate change impacts on Australia and the benefits ofearly action to reduce global greenhouse gas emissions. Climate ChangeImpacts on Australia, CSIRO; 2006: Available at: <http://csiro.au/files/files/p6fy.pdf>.

[6] CO2 capture and storage: a key carbon abatement option. International EnergyAgency. Published by: OECD Publishing, France;2008.

[7] Kohl A, Nielsen R. Gas purification, Houston: Gulf Publishing Company; 1997.[8] Thomas DC. Carbon dioxide capture for storage in deep geologic formations –

results from the CO2 capture project, CO2 capture project. vols. 1 and 2, Europe:Elsevier Science Ltd.;2005.

[9] White CM, Duane HS, Kenneth LJ, Goodman AL, Sinisha AJ, LaCount RB, et al.Sequestration of carbon dioxide in coal with enhanced coalbed methanerecovery: a review. Energy Fuels 2005;19(3):659–724.

[10] Mavor MJ, Gunter WD, Robinson JR, Law DHS, Gale J. Testing for CO2

sequestration and enhanced methane production from coal. In: SPE Proc GasTechnol Symp, Calgary, Alta., Canada; 2002. p. 443–56.

[11] Bachu S, Adams JJ. Sequestration of CO2 in geological media in response toclimate change: capacity of deep saline aquifers to sequester CO2 in solution.Energy Convers Mgmt 2003;44:3151–75.

[12] Gunter WD, Bachu S, Benson S. The role of hydro-geological and geochemicaltrapping in sedimentary basins for secure geological storage of carbon dioxide,vol. 233. Geological Society, London, Spl Pub 2004. p. 129–45.

[13] Xu T, Apps JA, Pruess K. Mineral sequestration of carbon dioxide in asandstone-shale system. Chem Geol 2005;217:295–318.

[14] Soong Y, Goodman AL, McCarthy-Jones JR, Baltrus JP. Experimental andsimulation studies on mineral trapping of CO2 with brine. Energy ConversMgmt 2004;45:1845–59.

[15] Kharaka YK, Cole DR, Hovorka SD, Gunter WD, Knauss KG, Freifeld BM. Gas–water–rock interactions in Frio Formation following CO2 injection:implications for the storage of greenhouse gases in sedimentary basins.Geology 2006;34(7):577–80.

[16] Bachu S, Gunter WD, Perkins EH. Aquifer disposal of CO2: hydrodynamic andmineral trapping. Energy Convers Mgmt 1994;35(4):269–79.

[17] Dooley JJ, Dahowski RT, Davidson CL, Wise MA, Gupta N, Kim SH, Malone EL.Carbon dioxide capture and geologic storage, a core element of a global energytechnology strategy to address climate change. Pacific Northwest NationalLaboratory, Richland, WA; 2006.

[18] Nooner SL, Eiken O, Hermanrud C, Sasagawa GS, Stenvold T, Zumberge MA.Constraints on the in situ density of CO2 within the Utsira formation fromtime-lapse seafloor gravity measurements. Int J Greenhouse Gas Control2007;1(2):198–214.

[19] Lindeberg E, Zweigel P, Bergmo P, Ghaderi A, Lothe A. Prediction of CO2

dispersal pattern improved by geologic and reservoir simulation and verifiedby time lapse seismic. In: Proceedings of the fifth international conference ongreenhouse gas control technologies. Collingwood, VIC, Australia: CSIROPublication; 2000. p. 372–7.

[20] Mackenzie FT, Lerman A, Ver LMB. Recent past and future of the global carboncycle. In: Studies in geology, vol. 47. Tulsa, OK: American Association ofPetroleum Geologists; 2001. p. 51–82.

[21] Torp TA, Gale J. Demonstrating storage of CO2 in geological reservoir: theSleipner and SACS project. Energy 2004;29:1361–9.

[22] Giordano CBM, Vaselli O, Tassi F, Quattrocchi F, Perkins EH. Geochemicalmodeling of CO2 storage in deep reservoirs: the Weyburn project (Canada)case study. Chem Geol 2009;265(1–2):181–97.

[23] Burrowes OG. Investigating CO2 storage potential of carbonate rocks duringtertiary recovery from a billion barrel oil field, Weyburn Saskatchewan: Part 2– reservoir geology, IEA Weyburn CO2 Monitoring and Storage Project,Summary of Investigations 2001, vol. 1, Saskatchewan Geological Survey.Sask. Energy Mines, Misc Rep. 2001;4.1:64–71.

[24] Sharma S, Cook PJ, Berly T, Lees M. The CO2 CRC Otway project: overcomingchallenges from planning to execution of Australia’s first CCS project. EnergyProcedia 2009;1(1):1965–72.

[25] Cook PJ. Demonstration and deployment of carbon dioxide capture and storagein Australia. Energy Procedia 2009;1(1):3859–66.

[26] Watson MN, Boreham CJ, Tingate PR. Carbon dioxide and carbonate cements inthe Otway Basin: implications for geological storage of carbon dioxide. APPEA J2004;44:703–20.

[27] Hortle A, Xu J, Dance T. Hydrodynamic interpretation of the Waarre Fm Aquiferin the onshore Otway Basin: implications for the CO2CRC Otway project.Energy Procedia 2009;1(1):2895–902.

[28] Dodds K, Daley T, Freifeld B, Milovan U, Kepic A, Sharma S. Developing amonitoring and verification plan with reference to the Australian Otway CO2

pilot project. Leading Edge, Tulsa, OK 2009;28(7):812–18.[29] Dance T, Spencer L, Xu JQ. Geological characterisation of the Otway project

pilot site: what a difference a well makes. Energy Procedia 2009;1:2871–8.[30] Rutqvist J, Vasco DW, Myer L. Coupled reservoir-geomechanical analysis of

CO2 injection at in Salah, Algeria. Energy Procedia 2009;1(1):1847–54.[31] Hayek M, Mouche E, Mügler C. Modeling vertical stratification of CO2 injected

into a deep layered aquifer. Adv in Water Res 2009;32(3):450–62.[32] Benson SM, Myer L. Monitoring to ensure safe and effective geologic

sequestration of carbon dioxide. Intergovernment panel on Climate Change,IPCC workshop on carbon capture and storage proceedings, Regina, Can.Petten, The Netherland. The Netherlands: Energy Research Centre; 2002.

[33] Klara SM, Srivastava RD, McIlvried HG. Integrated collaborative technologydevelopment program for CO2 sequestration in geologic formations–UnitedStates Department of Energy R&D. Energy Converse Mgmt 2003;44(17):2699–712.

[34] Koide HG, Tazaki Y, Noguchi Y, Iijirna M, Ito K, Shindo Y. Carbon dioxideinjection into useless aquifers and recovery of natural gas dissolved in fossilwater. Energy Convers Mgmt 1993;34(9–11):921–4.

[35] Gunter WD, Perkins EH, McCann TJ. Aquifer disposal of CO2-rich gases:reaction design for added capacity. Energy Convers Mgmt 1993;34:941–8.

[36] Holloway S, Savage D. The potential for aquifer disposal of carbon dioxide inthe UK. Energy Convers Mgmt 1993;34:925–32.

[37] Holt T, Jensen JI, Lindeberg E. Underground storage of CO2 in aquifers and oilreservoirs. Energy Convers Mgmt 1995;36(6–9):535–8.

[38] Winter EM, Bergman D. Availability of depleted oil and gas reservoirs fordisposal of carbon dioxide in the United State. Energy Convers Mgmt1993;34(9–11):1177–87.

[39] Rosenbauer JR, Koksalan T, Palandri JL. Experimental investigation of CO2–brine–rock interactions at elevated temperature and pressure: Implications forCO2 sequestration in deep-saline aquifers. Fuel Process Tech 2005;86:1581–97.

[40] Bergen van F, Gale J, DamenWildenborg AFB KJ, Wildenborg AFB. Worldwideselection of early opportunities for CO2-enhanced oil recovery and CO2-enhanced coal bed methane production. Energy 2004;29(9):1611–21.

[41] Oldenburg M, Benson SM. CO2 injection for enhanced gas production andcarbon sequestration. Proc SPE Int Pet Conf Exhib Mex, 2002. p. 251–60.

[42] Emberley S, Hutcheon I, Shevalier M, Durocher K, Gunter WD, Perkins EH.Geochemical monitoring of fluid–rock interaction and CO2 storage at theWeyburn CO2-injection enhanced oil recovery site, Saskatchewan, Canada.Energy 2004;29(9–10):1393–401.

[43] Kongsjorden H, Olav K, Torp TA. Saline aquifer storage of carbon dioxide in theSleipner project. Waste Mgmt 1997;17(5–6):303–8.

[44] Mahajan OP. CO2 surface area of coals: the Z-year paradox. Carbon1991;29(6):735–42.

[45] Krooss BM, Bergen van F, Gensterblum Y, Siemons N, Pagnier HJM, David P.High-pressure methane and carbon dioxide adsorption on dry and moisture-equilibrated Pennsylvanian coals. Int J Coal Geol 2002;51(2):69–92.

[46] Mehic M, Ranjith PG, Choi SK, Haque A. The geomechanical behavior ofAustralian black coal under the effects of CO2 injection: uniaxial testing. UnsatSoil, Seep and Env Geotech, GSP 148;2006:290–97.

[47] Viete DR, Ranjith PG. The effect of CO2 on the geomechanical and permeabilitybehaviour of brown coal: implications for coal seam CO2 sequestration. Int J ofCoal Geol 2006;66:204–16.

[48] Busch A, Krooss BM, Gensterblum Y, Bergen van F, Padnier HJM. High-pressureadsorption of methane, carbon dioxide and their mixtures on coals with aspecial focus on the preferential sorption behaviour. J Geochem Expl 2003;78–79:671–4.

[49] Goodman A, Favors RN, Larsen JW. Argonne coal structure rearrangementcaused by sorption of CO2. Energy Fuels 2006;20(6):2537–43.

[50] Khaled AMG, Fitzgerald J, Arumugam AK, Robinson Jr. RL. Sld adsorption modelof pure coalbed gases on dry argonne premium coal matrices. AIChE AnnuMeet Conf Proc,2005. p. 1201.

[51] Hildenbrand SS, Krooss BM, Littke R. Gas breakthrough experiments on peliticrocks: comparative study with N2, CO2 and CH4. Geofluids 2004;4:61–80.

[52] Liu L, Suto Y, Bignall G, Yamasaki N, Hashida T. CO2 injection to granite andsandstone in experimental rock/hot water systems. Energy Convers and Mgmt2003;44(9):1399–410.

[53] Yang D, Zhao Y, Hu Y. The constitute law of gas seepage in rock fracturesundergoing three-dimensional stress. Trans in Por Med 2006;63:463–72.

2664 R. Shukla et al. / Fuel 89 (2010) 2651–2664

[54] Bouchard R, Delaytermoz A. Integrated path towards geological storage.Energy 2004;29:1339–46.

[55] Rutqvist J, Tsang CF. A study of caprock hydromechanical changes associatedwith CO2-injection into a brine formation. Enviro Geol 2002;42:296–305.

[56] Saripalli P, McGrail P. Semi-analytical approaches to modelling deep wellinjection of CO2 for geological sequestration. Energy Convers Mgmt2002;43(2):185–98.

[57] Watson MN, Gibson-Poole CM. Reservoir selection for optimised geologicalinjection and storage of carbon dioxide: a combined geochemical andstratigraphic perspective. In: The fourth annual conference on carboncapture and storage. National Energy Technology Laboratory, US Departmentof Energy, Alexandria, 2–5 May 2005.

[58] Peacock DC, Mann A. Evaluation of the controls on fracturing. J Pet Geol2005;28(4):385–96.

[59] Jimenez JA, Chalaturnyk RJ. Integrity of bounding seals for geologic storage ofgreenhouse gases. Proc SPE ISRM Rock Mech Petrol Eng Conf 2002. p. 340–52.

[60] Zhang MX, Lee XL, Javadi AA. Behaviour and fracture mechanism of brittle rockwith pre-existing parallel cracks. Key Eng Mat 2006;324–325:1055–8.

[61] Kaszuba JP, Janecky DR, Snow MG. Carbon dioxide reaction processes in amodel brine aquifer at 200 �C and 200 bars: implications for geologicsequestration of carbon. App Geochem 2003;18:1065–80.

[62] Sminchak J, Gupta N. Issues related to seismic activity induced by the injectionof CO2 in deep saline aquifers. J Energy Environ Res 2002;2(1):32–46.

[63] Min Ki-Bok, Rutqvist J, Tsang Chin-Fu, Jing L. Stress-dependent permeability offractured rock masses: a numerical study. Int J Rock Mech Min Sci2004;41(7):1191–210.

[64] Tang CA, Xu T, Yang TH, Liang ZZ. Numerical investigation of the mechanicalbehaviour of rock under confining pressure and pore pressure. Int J of RockMech Min Sci 2004;41(3):336–41.

[65] Eberhardt E, Stead D, Simpson B, Read RS. Identifying crack initiation andpropagation thresholds in brittle rock. Can Geotech J 1998;35(2):222–33.

[66] Martin CD, Chandler NA. The progressive fracture of lac du bonnet granite. Int JRock Mech Min Sci 1994;31(6):643–59.

[67] Bieniawski ZT. Stability concept of brittle fracture propagation in rock. EngGeol 1967;2(3):149–62.

[68] Ranjith PG, Fourar M, Pong SF, Chian W, Haque A. Characterisation of fracturedrocks under uniaxial loading states. Int J Rock Mech Sci 2004;41(3):43–8.

[69] Indraratna B, Ranjith PG. Laboratory measurement of two-phase flowparameters in rock joints based on high pressure triaxial testing. J Geotechand Geoenviron Eng 2001;127(6):530–42.

[70] Pruess K, Garcia J. Multiphase flow dynamics during CO2 disposal into salineaquifers. Enviro Geol 2002;42:282–95.

[71] Hawkes CD, Mclellan PJ, Bachu S. Geomechanical factors affecting geologicalstorage of CO2 in depleted oil and gas reservoirs. J Can Pet Tech2005;44(10):52–61.

[72] Streit JE, Hillis R. Estimating fault stability and sustainable fluid pressures forunderground storage of CO2 in porous rock. Energy Convers Mgmt2004;29:1445–56.

[73] Soltanzadeh H, Hawkes CD. Assessing fault reactivation tendency within andsurrounding porous reservoirs during fluid production or injection. Int J RockMech and Min Sci 2009;46(1):1–7.