Potential Site Characterization and Geotechnical Engineering Aspects on CO2 Sequestration in Korea

Ah-Ram Kim1), *Gye-Chun Cho2), Joo-Yong Lee3) and Se-Joon Kim4)

1), 2) Department of Civil and Environmental Engineering, KAIST, Daejeon 34141, Korea 3), 4) Petroleum and Marine Resource Division, KIGAM, Daejeon 34132, Korea

2) gyechun@kaist.ac.kr

ABSTRACT

Since the Industrial Revolution, CO2 emission rates have increased dramatically due to the increased use of fossil fuels. The geological CO2 sequestration (GCS), which is long-term storage of CO2 in deep geological formations, has the potential to reduce CO2 emissions by 20%, a figure considered necessary to stabilize atmospheric CO2 levels over the next century. Thus, several large-scale GCS projects are in planning or operational stages around the world. The Korean government also aims to reduce CO2 emissions by 30% comparing to the emissions as usual (i.e., Business as usual; BAU) by 2020, and GCS technology is expected to play a critical role in accounting for more than 10% of the reduction of CO2 emissions. However, the research related to CCS in Korea has focused largely on CO2 capture technology since the early 2000s, and less attention has been paid to GCS technology and large-scale pilot demonstrations. The purpose of this paper is to present the current state technologies and strategies related to GCS worldwide, explore potential sites for GCS in Korea and attempt to determine the most suitable basin for GCS in Korea for future direction of geological CO2 sequestration in Korea. Finally, important scientific questions and technical challenges related to CO2 injection, storage, and monitoring processes are discussed from geotechnical engineering perspectives.

1. Introduction

CO2 emission rates have increased dramatically due to the increased use of fossil fuels since the Industrial Revolution. The current CO2 concentration in the atmosphere is ~390 ppm (parts per million) (Fig. 1). An atmospheric concentration of CO2 that exceeds 450 ppm is known to have a significant impact on climate conditions (Espinoza et al., 2011). For instance, scenario A1B reported in Special Report on Emissions Scenarios (SRES; IPCC, 2000) which was developed to represent future greenhouse gas (GHG) emissions predicts atmospheric CO2 concentration of South

1)

Postdoctoral Researcher 2)

Professor 3), 4)

Senior Researcher

Korea to increase to 720 ppm by 2100 (Fig. 2). These scenarios forecast that the mean surface temperature will increase by 1.8–3.4°C and that the sea level will increase by 18–34 cm (IPCC, 2007). In response, several CO2 emission mitigation technologies have been proposed to stabilize the atmospheric CO2 concentrations, including the recycling of materials and the use of renewable energy, nuclear fusion, and biofuels. Among these, carbon capture and storage (CCS) strategies represent a major alternative for reducing atmospheric CO2 concentrations in a relatively short time at a low cost compared to other technologies (Espinoza et al., 2011; Pires et al., 2011). Currently, several large-scale CCS projects are in planning or operational stages around the world.

Korea is not included in the Annex I group of Kyoto Protocol, in which 37 countries agreed to reduce greenhouse gas (GHG) emissions by 5.2% from 1990 levels. However, Korea is currently the seventh largest CO2 producer in the world (BP, 2011), and its increasing rate of CO2 emission by Korea is the fastest among all OECD countries. In discussions at the upcoming Post-Kyoto Protocol, it is likely that Korea will be categorized as an Annex I countries, which will obligate Korea to reduce GHG emissions. The Korean government aims to reduce CO2 emissions by 30% comparing to the emissions as usual (i.e., Business as usual; BAU) by 2020 (Presidential Committee on Green Growth, 2011). It is expected that the BAU CO2 emissions will amount to approximately 813 Mton per year by 2020. 30% of this amount (~244 Mton/yr) is to be reduced. Meanwhile, geologic CO2 storage (GCS) technology will play a critical role in accounting for more than 10% of the reduction of CO2 emissions in the future, i.e., more than 25 Mton/yr.

Figure 1. Atmospheric concentration of CO2 of the world and in Korea. Data were

gathered from Climate Change Information Center (www.climate.go.kr) and National Oceanic and Atmospheric Administration (www.noaa.gov).

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Figure 2. Past temperature records and future surface temperature increases estimated using CO2 emission scenarios (SRES; see IPCC(2000)). (a) SRES scenarios A2, A1B, and B1 of world. A2, A1B, and B1 are representative scenarios considering future and current demographic change, economic development, and technological change: A2 (heterogeneous world), A1B (world of very rapid economic growth with a balanced fossil and non-fossil energy system), and B1 (convergent world). The figure beside

each scenario name means the estimated atmospheric CO2 concentration at the end of the 21st century. (b) A1B scenario of Korea. Data were from Climate Change

Information Center (IPCC, 2000).

The long-term storage of CO2 in deep geological formations, known as geological CO2 storage (GCS), has the potential to reduce CO2 emissions by 20%, which is considered to be the amount necessary to stabilize atmospheric CO2 levels over the next century (Haszeldine, 2009). While the overall concept of GCS is well understood, the most important knowledge gap at present is the long-term (101 to 105 year) integrity of the caprocks, the role of which is to prevent buoyancy and advection-driven escape of CO2 from the storage formations (Benson and Cole, 2008). Furthermore, guaranteeing the integrity of typical caprocks on the scale of kilometers and tens of thousands of years is a daunting task (Benson and Cole, 2008). Although the Korean government has been promoting studies related to carbon capture and storage (CCS), the research has focused largely on CO2 capture technology since the early 2000s. Less attention has been paid to geologic CO2 storage (GCS) technology and large-scale pilot demonstrations. The presented study briefly reviews the site selection for GCS and ongoing GCS projects around world. Then, the current state of GCS projects in Korea are discussed. In particular, the suitability of the potential CO2 storage sites in Korea is evaluated. Finally, important scientific questions and technical challenges related to CO2 injection, storage, and monitoring processes are discussed from geotechnical engineering perspectives. 2. Site Selection for GCS

The strategies and technologies for CO2 sequestration need to be determined depending on the geological conditions of the potential sites. Thus, selecting potential sites for GCS is a preemptive procedure before proceeding further to implementation of a pilot- or commercial-scale project. The site selection is generally conducted by evaluating and ranking potential sedimentary basins using existing data and resources. Thereafter, further characterization for selected sites follows.

2.1 Site-dependent Strategies for GCS

Carbon dioxide can be stored in various geological formations: (1) depleted oil and gas fields, (2) coal beds, (3) deep saline formations, and (4) oil and gas reservoirs during enhanced oil and gas recoveries (EOR and EGR). Storing CO2 in depleted oil and gas fields or using CO2 for EOR (or EGR) have been proven to be favorable for GCS because of geological structures that are suitable for CO2 storage, available geophysical and geological data, and existing infrastructures used for oil and gas production. However, several problems remain unsolved: well plugging, leakage induced by overpressure of pore fluids, and injection depth. Coal beds can physically absorb and contain gaseous CO2 because of the presence of micropores in coal. However, the effects of temperature and pressure conditions at which the CO2 trapping process occurs in coals are not well understood (Larsen, 2003). The most promising sites for safe and effective CO2 storage are deep saline formations because of their vast capacity. The potential storage capacity of deep saline formations are expected to be a minimum of 1000 GtCO2, which is approximately 200 to 300 times higher than the potential storage offered by oil or gas fields and coal seams (IPCC, 2005). In particular, sedimentary basins that have permeable formations (e.g., sandstone) for injecting CO2 and overlying low permeable seals (caprocks) to prevent CO2 escape are considered suitable. The targeted depth is mostly greater than 1000 meters below the ground surface.

2.2 Site Selection Criteria

In order to assess the suitability of deep saline formations (e.g., sedimentary basins) for GCS and select potential sites, several criteria have been proposed. One set of criteria suggested by Gibson-Poole and co-workers (Gibson-Poole et al., 2005) is based on an evaluation of four components: (a) location and geological settings, (b) injectivity (e.g., reservoir’s stratigraphy, porosity, permeability and, mineralogy), (c) sealing capacity (e.g., sealing potential, CO2 migration and trapping mechanisms, fault stability, formation water flow, and maximum pore pressure), and (d) storage capacity. This set of criteria has been applied to evaluate three deep saline formations in Australia (Gibson-Poole et al., 2005). Similarly, Canadian research teams (Bachu, 2003; Bradshaw et al., 2002) have also proposed a set of criteria for assessing and ranking suitability of sedimentary basins. Their methodology evaluates (a) geological characteristics (e.g., tectonic setting, geology, and geothermal), (b) natural resources (e.g., hydrocarbon potential, coal, and salt), (c) basin location (e.g., onshore/offshore, climate, accessibility, CO2 sources), (d) industry maturity and infrastructures, and (e) social and economic issues (e.g., environmental risks, public acceptance, and level of development).

The most important factors for the reliable GCS of deep saline formations (e.g., sedimentary basins) are considered to be (1) adequate injectivity at ~800 m or greater depth, (2) sealing integrity of reservoirs, (3) high storage capacity, and (4) environmental risk of CO2 leakage (Gibson-Poole et al., 2005; IPCC, 2005; DNV, 2010). Injectivity is a function of the geometry, formation connectivity, porosity, and permeability of the reservoir where CO2 is injected. Sealing integrity is determined by

the distribution and continuity of the sealing layer, the seal capacity that determines the maximum pore fluid pressure, and potential migration pathways (Gibson-Poole et al., 2005). Evaluation of the CO2 storage capacity in deep saline aquifers is very complex because various trapping mechanisms that act at different rates are involved and, at times, all mechanisms may be operational simultaneously (Bachu et al., 2007). Several approaches for risk assessment of CO2 leakage are available, including the Features, Events, and Processes (FEP) scenario approach (Savage et al., 2004; Wildenborg et al., 2005), Probabilistic Risk Assessment (PRA; Rish, 2005; Bowden and Rigg, 2004), and the Screening and Ranking Framework (SRF; Oldenburg, 2008).

Since the 2000s, various site assessment and selection methods for geological CO2 storage have been proposed (Bachu, 2000, 2002, 2003; Bradshaw and Rigg, 2001; Bradshaw et al., 2004; Gibson-Poole et al., 2005, 2008; Bachu et al., 2007; Oldenburg, 2008). In each methodology, a wide range of assessment criteria (geological, geotechnical, economic, risk, political and social, and storage capacity) have been suggested and used to characterize and qualify the sedimentary basins. However, the assessment criteria and standards of each methodology need to be standardized, and a considerable number of other criteria such as earthquake potential and transport cost should be added to the assessment criteria.

3. GEOLOGICAL CO2 STORAGE IN KOREA

3.1 The Current State and a Technology Roadmap of Geological CO2 Storage in Korea

Geologic CO2 storage (GCS) projects in Korea are currently being conducted with the aim of finding large storage sites that can store more than a billion tons of CO2 by 2015 (Presidential Committee on Green Growth, 2011). Fig. 3 presents a technology roadmap for GCS development. This effort mostly relies on the existing geology dataset and resources that were gathered during oil explorations and drilling projects. However, the currently existing geologic information on onshore and offshore deep subsurface areas is insufficient. Comprehensive geological exploration and construction of a database are critical activities for selecting, or at least screening, potential sites suitable for GCS. The aim of ongoing CO2 capture technology research is to increase the capture capacity to one million tons by 2017 and to two million tons by 2019. These goals are also objectives stated within the Presidential Committee on Green Growth (Presidential Committee on Green Growth, 2011). Adequate candidate sites for GCS also need to be determined by that time, along with the development of capture technology.

Figure 3. Korean geologic CO2 storage technology roadmap

(Presidential Committee on Green Growth 2010)

3.2 Geologic Characteristics of Sedimentary Basins in Korea

There are several potential geologic formations for GCS on the Korean Peninsula. Fig. 4 shows the potential onshore and offshore sites for GCS and major CO2 sources in Korea.

The onshore basins (e.g., Gyeongsang, Chungnam, Taebaeksan, and Bukpyeong basins) are thought to have relatively stable tectonic settings for GCS because they are situated on the Sino-Korean craton, which is a relatively small continental craton (a craton refers to a stable part of the earth’s crust). Moreover, it has been found that those onshore sedimentary basins have anticline structures and seals made by convergent tectonic movements, which are beneficial for storing CO2 (Hong et al., 2005). For instance, the Gyeongsang basin, the largest onshore basin without a coal bed, is considered a strong candidate site for CO2 storage. Furthermore, it is thought that the site’s shale formations, inter-layered in the sandstone formations in the basin, can function as a caprock. Other on-shore basins that contain coal beds are also potential CO2 storage sites, as the CO2 is likely to be absorbed into the coal. However, the actual storage capacity could be less than the estimated level, because most onshore sedimentary basins have extremely low porosity (less than 5 %). Considering that concurrent CO2 storage projects are mostly being undertaken in formations having porosity of more than 10% and permeability of 0.01‒5 D (Hosa et al., 2010), the low injectivity due to the low porosity would increase costs for injecting CO2, thus diminishing economic feasibility.

The average thickness of Korean offshore sedimentary basins ranges from 3 km to 10 km (MEST, 2008). Their vast coverage area and high porosity of offshore sedimentary basins indicate significantly larger storage capacities than those of onshore basins. Also, Korean offshore sedimentary basins show similar geological structures with natural hydrocarbon reservoirs, consequently, resulting in good

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suitability for GCS. For example, the Gunsan basin and the Jeju basin show high potential for GCS because the geologic structures are similar to that of natural hydrocarbon in analogous Chinese basins (Hong et al., 2005). The Ulleung basin contains natural gas deposits and is more than 1000 m deep, and thus structural trapping may be feasible (Hong et al., 2005).

Figure 4. Potential storage sites and major CO2 sources in South Korea

3.3 Evaluation of suitability of sedimentary basins in Korea for GCS

Bachu (2003) has proposed a method for systematic and quantitative evaluation of candidate sites in terms of their CO2 storage suitability. Fifteen criterias are used with weight factors to assess the suitability. A series of criteria includes not only geological characteristics of basin, but other specific conditions such as basin resources, maturity and infrastructure. In this section, Korean basins were evaluated for their GCS potential using this method, based on parameterization and ranking, and also in comparing with foreign basins in which pilot- and commercial-scale projects are under way.

The results are shown in Fig. 5. As seen in Fig. 5, the scores of the sites investigated in this study range from 0.25 to 0.45. The Chungnam, Taebaeksan, Gyeongsang, and Bukpyeong on-shore sedimentary basins are shown to be relatively adequate candidates due to their large capacities and their proximity to major CO2 sources. Among the offshore basins, the Ulleung basin is thought to be the most suitable site for geologic CO2 storage due to the presence of nearby infrastructure constructed for natural gas recovery.

However, these potential Korean basins are less feasible for geologic CO2 storage compared to several basins in Canada. Specifically, the scores of Korean basins are lower in the following criteria: size, hydrocarbon potential, maturity, and infrastructure. Most of the Korean sedimentary basins, except for the Ulleung basin, are estimated to be of small-to-medium sizes whereas the Alberta and Williston basins in Canada are considered giant-to-large size. Moreover, a lack of boring studies and

geophysical exploration exacerbate the problems of low maturity and insufficient infrastructure.

Meanwhile, given insufficient information available, a number of parameters were assumed for the assessment results shown in Fig 5. To reduce uncertainty, more data aquisition by exploration and more reliable numerical modeling and simulation should be performed in relation to site selection for the first Korean pilot project. Additionally, new alternative methods excluding approaches using deep saline formations are needed to safely and economically sequester carbon dioxide in Korea considering the geological characteristics of Korean basins and limitations.

Figure 5. Scores for screening and ranking of Korean sedimentary basins.

4. GEOTECHNICAL ENGINEERING ASPECTS

Geologic CO2 storage (GCS) involves (1) the selection of a suitable site with an adequate geologic structure, (2) the injection of CO2, (3) the storage of CO2 by physical or geochemical trapping mechanisms, and (4) the monitoring of the stored CO2 to detect any unwanted leakage. Proper technologies must be developed and chosen for each process, taking into account geological characteristics. This section explores each process from injection to monitoring and addresses the geotechnical challenges related to GCS.

4.1 Injection Strategy

An effective and safe injection strategy for dealing with a large quantity of CO2 is an important issue. In commercial-scale projects, the marginal cost for injecting CO2 is estimated to be a maximum of 10 US dollars per CO2 ton (e.g. 2.2 US dollars per CO2 ton for the Weyburn project and 6.3 US dollars per CO2 ton for the In Salah project; Hosa et al., 2010). Constructing infrastructure, such as installing wells, accounts for much of the initial costs. As more CO2 is injected with a given time frame, it becomes more cost-efficient. Thus, a high rate of injection is favorable.

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As the injection pressure should be higher than the pore-fluid pressure in the formation, a larger pressure difference would increase the CO2 injection rate. While a high injection (flow) rate of CO2 is cost-effective, a high injection rate can produce over-pressurization, which can result in opening of pre-existing faults or the creation of cracks. Thus, the maximum allowable injection pressure should be carefully estimated to prevent formations from fracturing.

Injectivity is defined as the injection rate divided by the pressure difference between the well and the reservoir (IPCC, 2005). Interactions among CO2, rock minerals, and pore water (water-rock-CO2 interaction) induce chemical reactions, such as mineral dissolution or precipitation, which can affect porosity and permeability. Therefore, the injectivity can progressively change with time from the area adjacent to an injection well as CO2 causes chemical reactions. Accordingly, CO2 injectivity is affected by various parameters, such as rock mineralogy, pore water chemstry, pressure, temperature, and flow rate of CO2 (Bacci et al., 2011); thus, the CO2 injectivity needs to be identified with consideration of water-rock-CO2 interactions for selecting an adequate storage site.

In the In Salah project, a multiple well injection technique was used to inject CO2 at a high rate because of the low permeability (5 mD) of the site. Meanwhile, the MRCSP R.E. Burger project was cancelled due to the low injectivity (0.0016 Darcy-meters) caused by very low permeability (0.08 mD) and low porosity (3.20%) (Hosa et al., 2011). Likewise, sedimentary basins in Korea with low porosity and permeability should be evaluated to address these concerns.

4.2 Storage Strategy

CO2 injected into a reservoir can be stored via two mechanisms: physical trapping and chemical trapping. CO2 can be physically trapped by overlying impermeable seals (caprocks). The physical seals include capillary, pressure, and permeability seals (Christopher and Iliffe, 2006). Seals keep CO2 in the reservoirs from buoyancy-driven flow. The buoyancy pressure (Pb) can be expressed as follows:

2 2

2

( )Bouyancy Force

Area

w CO CO

b

CO

V gP

A

(1)

where ρco2 is the CO2 density, ρw is the water density, Vco2 is the CO2 plum volume, Aco2 is the contact area between water and CO2, and g is the gravity. Changes in the mass density difference, the volume of injected carbon dioxide, and the contact area of CO2-water in sediments will affect the buoyancy pressure. At the pore throat in the seals, the capillary pressure (Pc) can be described as a function of the interfacial tension (σ), the contact angle (θ) between water and CO2, and the pore throat diameter (d) (Washburn, 1921):

4 coscP

d

(2)

The capillary pressure increases with increasing interfacial tension between water and CO2 at a pore throat and with decreasing diameter of the pore throat. When

buoyancy pressure of CO2 is higher than capillary pressure at a pore throat, CO2 would seep through the pore throat and flow into the next pore.

As chemical trapping mechanisms, CO2 can be geochemically trapped in the form of carbonate minerals as a result of mineral-water-CO2 reactions (mineral trapping), or it can be stored in gas hydrate clathrates. In deep subsurface areas (over 800 m), CO2 can be stored in the form of a dissolved phase in pore water (solubility trapping). Mineral trapping is considered the most stable method (Gunter et al., 1993); however, this may have an impact on subsequent CO2 injectivity as carbonate mineral precipitation decreases porosity and permeability (Izgec and Demiral, 2005; Sayegh et al., 1990).

4.3 Geophysical Monitoring of CO2

CO2 leakage from CO2 storage sites can cause serious environmental problems. Geophysical survey techniques are available for large-scale field applications to detect CO2 leaks and to identify CO2 movement. The general principles of CO2 monitoring include measuring the physical properties (density, stiffness, electrical resistivity, and thermal characteristics) and detecting chemical composition changes or subsidence and displacement of grounds (Espinoza et al., 2011).

The most widely used monitoring methods are the seismic survey methods using P-wave and the electrical resistivity survey methods (Nakatsuka et al., 2010). In particular, P-wave seismic surveys have been commonly used to detect CO2 when it is injected into sediments in laboratory settings (Shi et al., 2007; Siggins et al., 2010; Xue and Lei, 2006) and in fields (Arts et al., 2004; Daley et al., 2008; Lazaratos and Marion, 1997; Mito and Xue, 2011), as CO2-containing formations have less stiffness than brine-saturated formations. Using the bulk modulus and density of pure CO2, the effective bulk modulus of a CO2-containing sediment can be estimated as a function of CO2 pore saturation using the Gassmann equation (Mavko et al., 1998). However, it has been reported that the Gassmann equation underestimates CO2 saturation when using field VP measurements (Azuma et al., 2011). This is because of the patchy distribution of CO2 in a given formation.

Meanwhile, sediment formations in Korean sedimentary basins are typically found to be layered, as opposed to the fact that most of the experimental studies to date have commonly used homogeneous sandstones. The physical behavior of CO2-storing sediments is significantly affected by formation characteristics, such as the porosity, permeability, density, and effective stress. Therefore, an alternative experimental approach is required for geological storage and monitoring of CO2 in Korea.

5. CONCLUSION

The presented study explores the current status and future direction of Korean CO2 storage technology in relation to geological and geotechnical considerations. The geological conditions of on- and off-shore sedimentary basins in Korea were investigated and the suitability of the basins for GCS were evaluated. The Gyeongsang

and the Ulleung basin (respectively on- and off-shore sedimentary basins) were found to be the most suitable site for GCS, although their scores were lower than the scores of some basins where GCS is currently undergoing or pilot-tested in Canada. The process of geologic CO2 storage was also explored and the geotechnical challenges related to GCS were discussed. The first step in the process of geologic CO2 sequestration is to locate suitable geologic sites. Supercritical or liquid CO2 is then injected into the subsurface, the CO2 is stored by physical and geochemical trapping, and the stored CO2 is finally monitored to detect leakages. The injection and storage mechanism strongly depends on various environmental and geological characteristics. Monitoring technology is already available for field applications to detect leaks and identify the movement of CO2. However, further study is required for detecting CO2 behavior in layered formations. ACKNOWLEDGEMENTS

This research was supported by the Basic Research Project of the Korea Institute of Geoscience and Mineral Resources (KIGAM) funded by the Ministry of Knowledge Economy of Korea.Put acknowledgments here.

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