A review of studies on CO2 sequestration and caprock integrity

Fuel 89 (2010) 2651–2664

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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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2652 2652 2653 2653 2654 2654 2654 2654 2654 2654 2655 2655 2655 2656 2656 2657 2658 2659 2660

* Corresponding author. Tel.: +61 3 9905 4982; fax: +61 3 9905 4944. E-mail addresses: [email protected] (R. Shukla), [email protected] (P. Ranjith), [email protected] (A. Haque), Xavier. [email protected] (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.

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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].

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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

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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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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

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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

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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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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

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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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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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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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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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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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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.

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