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Abstract: The U.S. Department of Energy Big Sky Regional Carbon Sequestration Partnership completed drilling the world’s first continental flood basalt sequestration pilot borehole to a total depth (TD) of 1253 m at a paper mill site near the town of Wallula located in Southeastern Washington State. Site suitability was assessed prior to drilling by acquisition, processing and analysis of a four-mile, five-line, three component seismic swath, which was processed as a single data-dense line. Analysis of the seismic survey data indicated absence of major geologic structures that would preclude CO2 injection at the site. Drilling of Wallula pilot borehole was initiated on January 13, 2009 and reached TD on April 6, 2009. Hydrogeologic information was obtained primarily during borehole drilling/advancement utilizing a progressive drill-and-test characterization strategy. A general decreasing transmissivity trend with depth pattern was observed, which is consistent with results exhibited for Columbia River basalt interflow zones at a number of other deep wells in the region. Based on the comparative results from 10 test intervals, a candidate injection test zone was identified between the general depth interval of ∼828 and 875 m bgs. Over this interval, three brecciated interflow zones were intersected and isolated for CO2 injection. The flow tops have moderate permeability (75 to 150 millidarcies) and are bounded by thick flow interiors that have extremely low (microdarcy) permeability. The borehole configuration established at the Wallula pilot site provides a unique opportunity to scientifically study the reservoir behaviour of three connected reservoir intervals confined between primary and secondary caprock zones. The permitting process for the CO2 injection has proceeded in accordance with formal rules for geologic sequestration projects enacted in June 2008 into the underground injection control program administered by the Washington State Department of Ecology. The permitting process is expected to conclude in October 2010 and injection would begin soon thereafter. Post-injection monitoring includes long-term sampling of water retrieved from the injection zone, shallow groundwater and soil gas monitoring, and PSInSAR. [Copyright &y& Elsevier]

Abstract: This paper presents a summary of the main international and national regulations for geologic storage of carbon dioxide. The international group includes the EU Directives, London Convention, and OSPAR. For the national regulations, three countries were covered in this study: United States, Canada, and Australia. In addition to these regulations, a group of guidelines and best practice manuals were also included in this study. As discussion, although this paper recognizes that current legislations have contributed for the regulation of this technology, it is still necessary the development of new rules in other regions. Industry will not invest in large CCS plants without such regulations because of high CCS costs and large financial risks related to CCS. [Copyright &y& Elsevier]

Abstract: According to the forecast of the International Energy Agency (IEA), CCS has the potential to reduce carbon dioxide emissions and could contribute to 19% of global carbon dioxide mitigation by 2050. Korean government recently announced that Korea has set its voluntary 2020 emissions reduction target to a 30% reduction from its forecast under a ”business as usual” scenario, which is equivalent to 4% less than the 594 million tons of carbon that was emitted in 2005. CCS is included to achieve this target. This paper first explains the CO2 storage potential both in onshore and offshore areas in Korea. While onshore sedimentary basins seem to have unfavorable physical properties such as porosity and permeability, offshore sedimentary basins exhibit very good physical properties in sand thickness and porosity. In order to implement CCS project at the scale needed to achieve a meaningful reduction of carbon dioxide emissions, the knowledge of the available CO2 storage capacity obtained by detailed matching of large stationary CO2 sources with geological storage sites is required. Most CCS programs in Korea, however, are not integrated with capture and storage projects. This paper considers the feasibility of CO2 capture and storage in Korea and shows several conceptual business models for CCS projects with the recent E&P activities in the continental shelf. [Copyright &y& Elsevier]

Abstract: To date, hardly any field study results are available on responses from lay people in communities that are confronted with the possibility of a local CO2 storage project. This paper describes one of the first of such studies, presenting a case description of an onshore CCS demonstration project in Barendrecht, the Netherlands. The aim of this study is twofold. First, we provide an in-depth analysis of the development of public awareness of an onshore CCS demonstration project in Barendrecht, the Netherlands. Second, by analyzing practices and outcomes, and by linking these to existing knowledge about stakeholder involvement and public communication, we identify a set of conditions for effective communication and involvement strategies. Findings indicate that one important cause of the lack of local acceptance of the project was the absence of a cohesive and timely involvement strategy for discussing the project with local stakeholders as part of the formal decision-making process rather than apart from it. The paper concludes with a list of recommendations for stakeholder involvement in future CCS operations. [Copyright &y& Elsevier]

Abstract: We incorporate CO2 dissolution due to convective mixing into a sharp-interface mathematical model for the post-injection migration of a plume of CO2 in a saline aquifer. The model captures CO2 migration due to groundwater flow and aquifer slope, as well as residual trapping and dissolution. We also account for the tongued shape of the plume at the end of the injection period. We solve the model numerically and identify three regimes in CO2 migration with dissolution, based on how quickly the brine beneath the plume saturates with dissolved CO2. When the brine saturates slowly relative to plume migration, dissolution is controlled by the dimensionless dissolution rate. When the brine saturates “instantaneously” relative to plume migration, dissolution is instead controlled by the solubility of CO2 in brine. We show that dissolution can lead to a several-fold increase in storage efficiency. In a companion paper, we study migration and pressure limitations on storage capacity [Szulczewski et al., GHGT-10, Paper 917 (2010)]. [Copyright &y& Elsevier]

Abstract: This paper offers a broad summary of the most common risk assessment methodologies for the geologic storage of carbon dioxide. We believe it is valuable to compare these methodologies, particularly in the areas where they lead to similar conclusions. The objective of this paper is to provide a better understanding of the current similarities and differences of these proposed methodologies. Since CCS was proposed as a mitigation option for reducing anthropogenic CO2 emissions, several attempts have been made to study the potential risks of long-term storage of CO2 in geological formations. Various worldwide projects have tried different industrial methods adapted to GSC. In spite of these efforts, currently there is no standardised method or set of methods for evaluating risk and/or uncertainty for GSC projects. Application or adaptation of advanced industrial quantitative risk assessment methods seems not convenient at this point because of lack of specific data. The development of frameworks and qualitative methods looks the most trustable for current projects. [Copyright &y& Elsevier]

Abstract: This paper summarizes the capabilities of geographical information system (GIS) in CO2 capture and geological storage (CCS). GIS is emerging as a useful tool for the spatio-temporal analysis, techno-economic feasibility and environmental assessment of CCS projects. A review on the recent case studies reveals the applicability of geo-information technology to the screening and analysis of emission sources, transportation and storage possibilities of CO2. This paper presents a survey on the methodologies, techniques and tools for modeling of the CO2 emission form stationary sources, CCS-GIS database development, spatial source-sink matching, and economic assessment. [Copyright &y& Elsevier]

Abstract: The main role of INERIS (French National Institute for Industrial Environment and Risks) is to assess and avert accidental and chronic risks to both people and the environment linked to industrial installations, chemical substances and underground operations. INERIS is thus involved in research consortiums for underground storages of wastes, hydrocarbons or carbon dioxide. Concerning carbon dioxide storage, INERIS works for many years on defining and testing monitoring methods. As a French expert, the institute also performs integrated risk assessment studies. This paper focuses on the last improvements concerning the monitoring methods developed or patented by INERIS. Because the institute was created from the research centre of the former French national coal mining company, it has a well-established know-how in monitoring gas atmospheres. Having developed monitoring methods for mining contexts, INERIS has tools to constrain gas migrations in subsurface: [1.] to determine gas flux between soil and atmosphere with dynamic accumulation chambers; [2.] to determine gas concentrations in unsaturated zones through integrated gas sensor systems linked to subsurface boreholes (from 0 to about 300 meters depth). Initially designed for mining context, these two methods have been tested and proven for the monitoring of CO2 geological storage contexts. For example between 2005 and 2007, INERIS was one of the five partners involved in the “GeoCarbone MONITORING” research project. This project was funded by the French Research Agency and aims at defining methods to monitor CO2 storage sites. Today the institute is involved in other projects studying pilot sites. In this paper we present results collected in analog contexts to CO2 storage sites. We will discuss in which conditions the carbon isotopic signature can help to determine the possible origins of the gas analyzed in our devices and to better understand the physical and chemical processes which can have led to the studied gas compositions. We will also highlight the fact that in some cases, there is a real need of using isotopic tracing methods otherwise the identification of these different processes cannot be done easily. [Copyright &y& Elsevier]

Abstract: Making new coal-fired power plants carbon capture ready (Carbon Capture Ready) in China has been recognised as a crucial by a number of stakeholders academics, energy companies and regional government, based on a study in EU-UK-China NZEC project. A number of publications have investigated the definition, engineering requirements, economic and finance of CCR for China. However there remain a number of questions regarding the extent to which a plant’s physical location might constrain the feasibility of CCS retrofit. To address this issue, a Geographical Information System (GIS) has been used as a tool for mapping current and planned large carbon dioxide sources in Guangdong, also illustrating potential storage sites and calculating possible carbon dioxide transportation route. This paper investigates the location factors that should be considered when locating new build CCR power plants and demonstrates the methodology of using GIS software with spatial analysis in planning new build power plant in Guangdong. A preliminary study has identified over 30 large power plants within the region, with plant locations and historical emission data collected and presented in ArcGIS. Factors such as distance to potential storage site, route of CO2 pipeline, extra space on site and potential development plan etc. were investigated in the modelling and calculated the potential source and sink solution. The study then moves on to suggest possible new build plant locations which can be easily fitted in to the current network, based on economic optimisation. The scope for future coal plant development combined with a possible nuclear plant siting plan is discussed towards the end of the paper. Guangdong province, which owns the third largest coal-fired power installed capacity out of 31 provinces, generated over 8% of China’s total electricity every year for the past 15 years. CO2 storage opportunities could be found in the surrounding South China Sea, where Guangdong has a total of 4,300 km of coastline and some small scale oil fields on shore within the region. It is also among the first places to start the national open and reform policy in China. The province is one of the richest in China, with the highest GDP among all other provinces since 1989, and the foreign trade accounts for more than a quarter of China’s total amount. It also contributes around 12 of the total national economic output. Currently, the provincial government is proposing a low carbon roadmap, which is the first of its kind in China. The work has created a totally new thinking on capture ready power plant planning. This differs from existing studies (e.g., which aim to investigate the existing carbon dioxide emission sources at specified location and provide source and sink matching analysis. Instead the study focuses on policy implementation for new build capture ready power plants. Three clusters within Guangdong province are identified as potential temporary CO2 storage hubs before transporting the gas to a long term storage site. When officials are planning new power plant locations from a capture ready perspective, the plants should not necessarily be close to storage sites in straight line, but rather should be within a reasonable distance of a cluster. Transport of the captured CO2 will not be limited to pipelines, but could be extended to road and rail tankers. Power plant parameters and storage site data were collected for this research. Public transportation, utilities, landscapes, river, land used and population data were referenced from various sources; therefore, some of the data could be out of date. Nevertheless, it should still provide enough information when deciding the location of the transport cluster. Any future work could build on the existing model with updated data. Moreover, it could fit in with the national natural gas transportation network and utility planning network to provide long term integrated energy system analysis. The paper could provide policy makers, investors and urban planning officials with a view on how conventional thermal power plant investment and planning could be optimised, using Carbon Capture Ready designs, to keep the CCS retrofitting option open. [Copyright &y& Elsevier]

Abstract: Underground gas storage (UGS) facilities provide a wealth of information, which can be used to better understand various aspects of CO2 storage in depleted reservoirs. In some cases UGS facilities can provide important site specific information for carbon storage projects that are planned in similar formations in close proximity. In this paper, we discuss the various ways in which UGS facilities can be used to extract important information, and when possible we draw upon information from the Iona gas storage facility in Australia’s Otway basin. The Iona facility is located 20 km away from the CO2CRC Otway Project, in which CO2 65445 tonnes of 77 mole% carbon dioxide, 20 mole% methane and 3 mole% other gas components (containing about 58000 tonnes of carbon dioxide) was injected into the Waarre C formation over a 17 month period. In this paper, we compare the factors that control CO2 seal capacity and discuss how UGS facilities can provide information on sustainable column heights either limited by faults or by cap rocks. We also present dynamic modeling results in which information is gained regarding injectivity, pressure evolution of the reservoir, storage capacity and maximum fluid pressures sustained by the faults. Understanding such parameters is important for the safe operation of any carbon storage project, be it on a demonstration or industrial scale. [Copyright &y& Elsevier]

Abstract: Portland cement can play a major role in providing cost-effective, long-term zonal isolation for CO2 capture and storage (CCS) used to mitigate climate change. However, achieving zonal isolation with Portland cement under supercritical CO2 environment for the required 1,000 year trapping period may be challenging. Some laboratory researchers report that Portland cement disintegrates when exposed to CO2, leading to potential leakage into the atmosphere or other to underground zones. Other researchers cite Portland cement samples from 30–50 year old CO2 EOR wells where sealing integrity was maintained, even though carbonation was found. In this paper we will discuss reasons likely for this disparity between research lab test results and actual well performance data. Carbonation of Portland cement is a thermodynamically favorable process and therefore difficult to avoid. But the effects can be minimized by various reactive chemical components optimized for the specific thermodynamic conditions. Our research shows partial carbonation of Portland cement is not detrimental unless the mechanical integrity is insufficient to provide effective zonal isolation. For these studies we have developed CO2 treatment test cells capable of producing conditions up to 200 °F and 2,000 psi. In addition, various analytical instruments including x-ray diffraction (XRD), thermo-gravimetric analysis (TGA) and mechanical properties measurement devices have been used for this study. In this paper we will discuss the importance of understanding the percentage of carbonation and depth of CO2 penetration, and how to control these factors by optimizing the cement blend. Interestingly, we found the amount of Portlandite { Ca(OH)2} that forms due to cement hydration and the cement-to-water ratio dictates the depth of penetration as well as percentage carbonation. The implications of this in relation to the long term chemical integrity of the cement sheath under downhole CCS conditions is discussed. This paper also includes the results of recent studies on the changes in mechanical properties of a properly optimized Portland cement blend for a period of up to one year. During this period, measurements were made at different time intervals to examine cement specimen treated with CO2 at 200 °F and 2,000 psi in the presence of water. The results show carbonation without any sign of loss of mechanical or sealing integrity that could lead to zonal isolation failure. Results from a separate set of experiments show the following: (1) Carbonation could be minimized by reducing the Portland cement content by adding Pozzolanic materials and by reducing the permeability and (2) Carbonation could help heal micro-cracks that may be caused by various well operations or ageing. However, such carbonation-induced healing is limited only to a certain width of cracks. In summary of this research, it is recommend that: (1) a high quality primary cement job be performed in adherence to all industry best practices; (2) the cement blend be properly optimized to minimize long-term CO2 corrosion; and (3) the sheath be designed for long-term mechanical integrity. This paper will discuss a comprehensive approach that may be taken to help ensure longer-term effective zonal isolation in new CO2 wells and remedial solutions for old wells and for plugging and abandoning wells. [Copyright &y& Elsevier]

Abstract: This paper deals with the electrical resistivity monitoring of the Ketzin CO2 injection pilot (CO2ReMoVe EC project) through time-lapse CSEM measurements. There, 3 boreholes about 800 m deep have been especially designed for current injection at reservoir (sandstone) depth. CO2 is directly injected in a saline (∼240 g/l) aquifer. Prior modelling results indicated that the increase of electrical resistivity generated by the CO2 plume (gaseous and liquid CO2 phases) supposed to be highly resisitive, would generate measurable changes in the EM fields on the surface, when injecting current directly inside the reservoir. In order to highlight and follow these expected resistivity changes, 3 CSEM surveys were performed in August 2008 (baseline prior to injection), June 2009 and August 2010. Each time, 13 EM stations have been recorded during current injection of a square wave at 3 frequencies (0.125 Hz, 0.5 Hz and 4 Hz) in two configurations (“double mise à la masse” (2×MAM) and “mise à la masse–surface” (MAM-Surface)). This paper only presents results of the 2×MAM configuration at 0.5 Hz. In spite of a very noisy area (gas pipes, high voltage power lines), we measured signal amplitude 10 times higher than noise amplitude. We show that EM fields vectors (both inphase and quadrature components) measured on the surface are very similar to the forward modelling EM responses computed with COMSOL Multiphysics ® . Models also show that electric field spatial distribution is strongly affected by a thin and resistive layer (35 m–200 Ωm) of anhydrite above the reservoir, making E field diverging from the boreholes whereas a dipolar pattern was expected for the dipole current injection used here. Moreover, while June 2009 survey highlighted the expected strong increase of electric field (increase of resistivity), August 2010 survey showed electric field amplitudes similar to the 2008 baseline survey, revealing therefore major changes of the reservoir properties. Finally, the directional sensitivity of the 2×MAM array is tested through modelling residuals computed for five CO2 plume spatial distributions. Results show that a north-eastward migration of the CO2 plume is expected to fit field data. [Copyright &y& Elsevier]

Abstract: One of the work packages of MUSTANG (MUltiple Space and Time scale Approach for the quaNtification of deep saline formations for CO2 storaGe) EU project is dedicated to developing a generic methodology for risk assessment related to CO2 in saline aquifers and applying the methodology to an experimental site. This paper presents the work done by OXAND regarding risk assessment and the application of a risk-based approach to the qualification of the storage site ultimately to provide guidelines for further industrial storage projects. The risk assessment process is presented, and illustrated with the data of an experimental site. The eight steps of the risk assessment process highlighted in the ISO 31000 are described in this paper: Risk management policy, establishment of the context, risk identification, risk estimation, risk evaluation, risk treatment, communication and consultation, and monitoring and review. [Copyright &y& Elsevier]

Abstract: The IEA CCS Roadmap highlighted the significance that CCS will play in achieving an atmospheric CO2 stabilization on 450 ppm. In the scenario it is based on, CCS will provide approximately 20% of the total CO2 emissions reductions out to 2050. To achieve this contribution it will require an ambitious CCS growth path with 100 projects needed globally by 2020 and over 3000 by 2050. In both 2020 and 2050 the major developing countries will need to contribute to this deployment. Brazil has a unique electricity and emissions profile. Over 80% of Brazils electricity is produced from hydropower with the rest being made up by a combination of fossil fuels, biomass, and nuclear. This means the energy emissions in Brazil are relatively low. Many people within Brazil see stopping the deforestation of the Amazon as the key emissions reduction mechanism for Brazil. However, the contribution to CO2 emissions from coal is expected to increase due to 6000 MW of coal power that is planned to be installed in Brazil by 2030, although this still only represents 2.7% of grid compared to 83% from renewables. CCS in Brazil will be more relevant to industry rather than for electricity generation. In particular CCS could be crucial for the development of some of the “Pre-salt” petrol eum fields which bring new challenges. Although there are no conclusive studies on the concentration o f carbon dioxide (CO2) in the region, some wells have shown concentrations of CO2 above those found in the Campos Basin, while others showed concentrations close to zero. Still, Petrobras have proactively committed to not releasing to the atmosphere, the CO2 associated with the natural gas produced in the pre-salt layer. In addition, the pre-salt oil is considered of good quality, light oil and therefore, the refining process consumes less energy and will emit less CO2 when compared to the processing of heavier crude. This paper looks to discuss the current status of CCS in Brazil. This includes looking at the current status of a number of demonstration projects that are already underway in Brazil as well as additional ones that are planned. The paper will also discuss the. Public awareness and engagement about CCS given the crucial role the public play in the smooth progress of projects. [Copyright &y& Elsevier]

Abstract: The Midwest Geological Sequestration Consortium, Schlumberger Carbon Services, and Archer Daniels Midland has implemented a comprehensive communications plan at the Illinois Basin–Decatur Project (IBDP), a one million metric tonne Carbon Capture and Storage project in Decatur, IL, USA funded by the U.S. Department of Energy’s National Energy Technology Laboratory. The IBDP Communication Plan includes consortium information, funding and disclaimer citations, description of target audiences, media communications guidelines, paper and presentations guidelines, site visit information, crisis communication, on-site photography regulations, and other components. The creation, development, and implementation processes for the IBDP Communication Plan (the Plan) are shared in this paper. New communications challenges, such as how to address add-on research requests, data sharing and management, scope increase, and contract agreements have arisen since the Plan was completed in January 2009, resulting in development of new policies and procedures by project management. Integrating communications planning, risk assessment, and project management ensured that consistent, factual information was developed and incorporated into project planning, and constitutes the basis of public communications. Successful integration has allowed the IBDP to benefit from early identification and mitigation of the potential project risks, which allows more time to effectively deal with unknown and unidentified risks that may arise. Project risks and risks associated with public perception can be managed through careful planning and integration of communication strategies into project management and risk mitigation. [Copyright &y& Elsevier]

Abstract: The technological option of capturing CO 2 from large point sources, compressing, transporting, and injecting it for long -term storage holds the potential for playing a key role in reducing greenhouse gas (GHG) emissions while providing affordable energy. The oil and natur al gas industry experience and expertise provide confidence in carbon capture and geological storage (CCS) as an effective GHG emission mitigation option. However, companies need consistent, reliable, and credible methodologies to derive GHG emission and emission reduction estimates. Harmonizing the quantification of GHG emission reductions, by applying common principles and criteria, supports efficient and consistent development of additional project activities. This paper provides an overview of the P etroleum Industry Guidelines for Greenhouse Gas Emission Reduction Projects (referred to as the Project Guidelines), a collaborative effort between the American Petroleum Institute (API) and the International Petroleum Industry Environmental Conservation Association (IPIECA) to develop guidelines for accounting and reporting of GHG emission reduction projects of interest to the oil and natural gas industry. Key concepts from the Project Guidelines for evaluating, quantifying, documenting, and reporting GHG emission reductions are presented with a specific focus on CCS activities. The paper draws from the Project Guidelines in add ressing the selection of appropriate baseline candidates, boundaries for scenario assessment, and compatible monitoring considerations. Case studies are used to demonstrate the application of commonly accepted emission reduction principles for CCS projects. Through the Project Guidelines, API and IPIECA aim to assist the petroleum industry in identifying, assessing, and developi ng CCS projects. By working toward consistent standards for GHG emissions reductions, our industry demonstrates its commitments toward environmental improvements and p romotes the development of real and sustainable actions to reduce GHG emissions. [Copyright &y& Elsevier]

Abstract: This paper examines two questions: (1) in a high oil price (and operating cost) environment what are typical breakeven prices for CO2? and, (2) are these prices sufficient to incentivize development of large-scale CCS projects? To address these questions we have developed an engineering-economic model for geological storage of CO2 through EOR. In this paper we briefly describe the performance and cost models for CO2-flood EOR, and use them to estimate the breakeven price for CO2 as a function of significant variables. In particular, the relationship between breakeven CO2 price and oil price is developed for four illustrative cases, all of which are, or were, operating EOR projects in North America. The sensitivity of the breakeven CO2 price to variability and uncertainty in reservoir characteristics and other model input parameters is also examined in detail for one of the cases. [Copyright &y& Elsevier]

Abstract: Studies of the cost of carbon capture and storage (CCS) frequently make a single set of assumptions about the characteristics of the source of CO2and the injection site (the sink). However, in practice, the design of the whole CCS system will require optimisation involving selecting the appropriate pipeline sizes, the pipeline route, the number, type and placing of injection wells. This study reports the optimisation of a possible CCS project in Australia and examines the effects of different parameters in designing the system. The area in and surrounding Gladstone, Rockhampton, Stanwell and Callide (“Gladrock”) in Central Queensland Australia emits over 40.5 million tonnes (Mt) of carbon dioxide (CO2) from fixed sources every year. The study examines least cost solutions for CCS technologies in the Gladstone and Rockhampton area. The study optimises the cost of transporting CO2from power stations in the Gladrock region and injecting the CO2in the Aramac coal measures. Basic engineering results together with the capital and operating costs of the whole project and individual sets of equipment are assessed. Large compressors of several hundred megawatts are required at each source to raise the CO2to supercritical conditions for transport and storage. Carbon dioxide is maintained in a supercritical state by booster pumps. The paper analyses the effect of the following aspects of the CCS process - network configurations, flow rates, well types, permeability and best combinations of compressors and pipelines. The paper shows that the cost depends mainly on pipeline characteristics, permeability, flow rate and the type of wells used. [Copyright &y& Elsevier]

Abstract: Work on Carbon Sequestration in subterranean formations has renewed interest in investigating the long term effects of CO2 on Portland cements. Portland cement will react with the injected CO2, and while recent research indicates these conventional cements are not a concern, additional work is ongoing to further improve the long term effectiveness of the wellbore sealant. This paper discusses various solutions to the challenges of selecting a proper wellbore sealant for a CO2 injection well. Additionally, the paper reviews the available sealant technologies, their application, and includes a discussion of stress modelling for these wells. A brief case history review of the design considerations for two high-rate acid gas injection wells in Wyoming is discussed. [Copyright &y& Elsevier]

Abstract: We present a sharp-interface mathematical model of CO2 migration in saline aquifers, which accounts for gravity override, capillary trapping, natural groundwater flow, and the shape of the plume during the injection period. The model leads to a nonlinear advection–diffusion equation, where the diffusive term is due to buoyancy forces, not physical diffusion. For the case of interest in geological CO2 storage, in which the mobility ratio is very unfavorable, the mathematical model can be simplified to a hyperbolic equation. We present a complete analytical solution to the hyperbolic model. The main outcome is a closed-form expression that predicts the ultimate footprint on the CO2 plume, and the time scale required for complete trapping. The capillary trapping coefficient emerges as the key parameter in the assessment of CO2 storage in saline aquifers. The expressions derived here have immediate applicability to the risk assessment and capacity estimates of CO2 sequestration at the basin scale. In a companion paper [Szulczewski and Juanes, GHGT-9, Paper 463 (2008)] we apply the model to specific geologic basins. [Copyright &y& Elsevier]

Abstract: The geological storage of CO2 usually considers 4 stages such as exploration, operation, closure and post closure. To ensure safe behavior during the closure and post-closure stages, long term migration scenarios must be considered. In particular, the fate of CO2 will be controlled by the pressure behavior of the storage reservoir and the regional hydrodynamics. The main migration mechanisms such as buoyancy, dissolution, capillary and mineral trapping will be enhanced depending on the local conditions in the storage reservoir and its geosphere. This paper aims at estimating the long term behavior of CO2 for a proposed injection in an on shore brine aquifer. This work will consider the whole storage cycle (injection and post closure). To estimate the post-closure migration of CO2, the comprehensive geological and dynamical knowledge must be integrated for the reservoir and its geosphere. This 3-D model must also account for regional hydrodynamics of the aquifers and encompass all formations between reservoir and surface along with their petrophysical description to catch the key geological features that might influence the CO2 migration thus defining the storage complex. This paper will focus on the definition of the storage complex (c.a. 205x205 km2 and 2–3 km thick depending on the storage depth). The storage is in hydraulic communications with neighboring oil fields through a common aquifer. The flow model should encompass all these oil reservoirs to enable proper modeling of the pressure and CO2 interference. Such large scale model imply hypothesis on the boundary and initial (at storage closure) conditions within the domain e.g. pressure and fluid description in the different oil fields due to their independent industrial oil operations which influence the CO2 migration. This paper illustrates the regional interactions that may take place around a CO2 storage due to competing activities. It reviews the key features and assumption required to establish the reservoir complex model given its scale both in space and time. [Copyright &y& Elsevier]

Abstract: This paper examines, with reservoir simulation, the impact of applying “best practices” and capitalizing on reservoir architecture to restrict CO2 plume movement and maximize reservoir storage capacity. Specifically, the paper explores the value gained from using horizontal CO2 injection wells and taking advantage of any existing shale “baffles” in conjunction with other reservoir characteristics that influence flow such as capillary pressure, pore volume trapping, and CO2 dissolution. Recent geologic and reservoir data collected from the Tuscaloosa Formation at the Mississippi Test Site (a Southeastern Regional Carbon Sequestration Partnership CO2 sequestration pilot test) will be used as the case study for evaluating alternative CO2 injection and storage engineering concepts. The Tuscaloosa Formation is a thick, porous, permeable, regionally extensive saline reservoir occurring throughout the Gulf Coast and is considered a high priority setting for large-scale CO2 storage. [Copyright &y& Elsevier]

Abstract: This paper proposes an alternative theoretical methodology to evaluate the risks of CO2 leakage from reservoirs using a stochastic approach. The methodology suggested here makes use of three main concepts: [–] Features, Events and Processes (FEPs) [–] Interaction Matrix, IM [–] Stochastic Representation Both, FEPs and Interaction Matrix have been introduced by other researchers but for different objectives. The methodology that is proposed here modifies the original concept of Interaction Matrix in such a way that it may produce probabilistic results as outcome. A practical example is given at the end of this paper. [Copyright &y& Elsevier]

Abstract: This paper is the first of a series that attempts to assess the possible health and safety risks associated with large scale CO2 sequestration in deep brine reservoirs. The approach is based on analysis of available data on the operational track record from CO2 transportation and injection associated with enhanced oil recovery (CO2-EOR) in the US. This paper is particularly concerned with identification of the main business risks facing a company engaged in geological sequestration. Such risks include both the operational risks of capturing, compressing, transporting and injecting CO2, as well as the risk of accidental, rapid CO2 release from wells (including an analysis of blow out data from CO2 injection wells, worked over wells as well as abandoned wells). Observations of the outcomes from accidents in real pipelines and CO2 injection wells in CO2-EOR projects provide the most concrete basis to predict the future safety of the above ground operations of CO2 sequestration in deep brine reservoirs. [Copyright &y& Elsevier]

Abstract: For carbon dioxide capture and geologic storage to be deployed commercially and in a widespread manner will require well thought out approaches for transporting the CO2 in a pipeline system from the capture facility to the injection site. Establishing a widespread CO2 transportation infrastructure will require strategic long-term planning, taking into account the potential magnitude of future deployment scenarios for CCS, up to a scale of infrastructure that could be comparable to the scale of oil & gas infrastructure. This paper outlines the results of a study, commissioned by the CO2 Capture Project (CCP) and completed by Environmental Resources Management (ERM) that evaluated the benefits and risks of two approaches to developing CO2 pipeline systems. The two basic approaches are described in the paper as: 1. On a point-to-point basis, which matches a specific source to a specific storage location; or 2. Via the development of pipeline networks, including backbone pipeline systems, which allow for common carriage of CO2 from multiple sources to multiple sinks. An integrated approach to pipeline infrastructure approach offers the lowest average cost on a per ton basis for operators over the life of the projects if sufficient capacity utilization is achieved relatively early in the life of the pipeline. Integrated pipelines also reduce the barriers to entry and are more likely to lead to faster development and deployment of CCS. Without incentives to encourage the development of optimized networks project developers are likely to build point to point pipelines because they offer lower costs for the first movers and do not have the same capacity utilization risk. [Copyright &y& Elsevier]

The first CO 2 Field Lab built in Brazil was developed at the Ressacada Farm, in Florianopolis, SC with the goal of diminishing technical gaps in CO 2 storage covering research in Measuring, Monitoring and Verification (MMV) techniques, a need identified in the PETROBRAS Strategic Plan. Through the Company R&D Center (CENPES), and the Climate Change Mitigation Technological Program (PROCLIMA), PETROBRAS is sponsoring a joint 4-year research Project, in which both company and local academia personnel are collaborating to deploy, test and assess multiple near-surface CO 2 detection technologies. Longer term objectives include the validation of accurate and efficient detection, measurement and quantification tools to be deployed in large scale commercial CGS (Carbon Geological Storage) sites scheduled to be installed in the country to assist in validating storage efficiency and minimizing risk. In September 2013, the first CO 2 injection campaign was carried out, in which small volumes of gaseous food-grade industrial CO 2 (with a delta 13 C signature of ca.-32 ppmil) were injected into the ground at shallow levels through a vertical 3 m depth well and then migrated into the atmosphere. The campaign was run over 12 days, for 24 hours a day, at injection rates low enough not to offer any risks to the formation integrity and enabled the simultaneous assessment of CO 2 behavior in the soil, in the groundwater, at the surface and in the air. This paper presents an overview of the atmospheric measurements carried out at Ressacada, covering the background, injection and post-injection scenarios. [ABSTRACT FROM AUTHOR]

Abstract: This paper presents the experimental plans and designs as well as examples of predictive modeling of a pilot-scale CO2 injection experiment at the Heletz site (Israel). The overall objective of the experiment is to find optimal ways to characterize CO2 -relevant in-situ medium properties, including field-scale residual and dissolution trapping, to explore ways of characterizing heterogeneity through joint analysis of different types of data, and to detect leakage. The experiment will involve two wells, an injection well and a monitoring well. Prior to the actual CO2 injection, hydraulic, thermal and tracer tests will be carried out for standard site characterization. The actual CO2 injection experiments will include (i) a single well injection-withdrawal experiment, with the main objective to estimate in-situ residual trapping and (ii) a two-well injection-withdrawal test with injection of CO2 in a dipole mode (injection of CO2 in one well with simultaneous withdrawal of water in the monitoring well), with the objective to understand the CO2 transport in heterogeneous geology as well as the associated dissolution and residual trapping. Tracers will be introduced in both experiments to further aid in detecting the development of the phase composition during CO2 transport. Geophysical monitoring will also be implemented. By means of modeling, different experimental sequences and injection/withdrawal patterns have been analyzed, as have parameter uncertainties. The objectives have been to (i) evaluate key aspects of the experimental design, (ii) to identify key parameters affecting the fate of the CO2 and (iii) to evaluate the relationships between measurable quantities and parameters of interest. [Copyright &y& Elsevier]

Abstract: Perceptions of the potential of emerging technologies like carbon capture and storage (CCS) are constructed not just through technical and economic processes but also through discourse, i.e. through compelling narratives about what a technology is, what a technology might become and why it is needed and preferable to competing technologies. The influence of discourse is particularly important in the innovation phases prior to commercialization when innovation activities are focused on research, development and demonstration, and when feasibility and costs of alternatives systems cannot yet be tested by market dynamics. This paper provides a state-level comparative analysis of CCS discourse in the U.S. to provide insights about the socio-political context in which CCS technology is advancing and being considered in four different states: Massachusetts, Minnesota, Montana, and Texas. This research combines analysis of interviews of state-level energy stakeholders and media analysis of state-level newspapers. In semi-structured interviews, state-level energy policy stakeholders were asked to explain their perceptions of the potential opportunities and risks of CCS technology within their unique state context. Interview texts were coded to assess the frequency and extent of various different frames of CCS opportunities and risks including technical, political, economic, environmental, aesthetic, and health/safety. A similar coding scheme was applied to analysis of state-level newspaper coverage of CCS technology. Here, the frequency of these different framings of CCS opportunities and risks in state-level print media was assessed. This analysis demonstrates wide variation in state-level CCS discourse and perceptions of the potential opportunities and risks associated with CCS technology. This mixed-methods approach to characterizing the socio-political context for CCS advancement in these four states contributes to improved understanding of state-level variation in energy technology innovation, provides valuable information about energy technology development in these specific states, and also offers insight into the very different sub-national discourses associated with emerging low-carbon energy technologies in the U.S. [Copyright &y& Elsevier]

Abstract: The storage potential of selected sites within the Bahaiwan Basin was evaluated, the storage capacity estimated and the selection criteria considered for the COACH project. This paper examines the two methods used during the project for calculation of the storage capacity in the Shengli oilfield complex within the Bahaiwan Basin. Both methodologies were used to quantify the potential CO2 storage capacity of the depleted oil hydrocarbon reservoirs of the Shengli oilfield complex. They can both be considered as “simple” equation models which try to capture an “approximation” of a possible storage capacity. Nevertheless, between these models several differences exist. The CSLF methodology works with replacement of oil, gas or formation water, but does not incorporate dissolution of CO2 in formation water. The EOR methodology of CUPB developed from methodology of Tanaka et al. on the other hand includes dissolution of CO2 into the formation water, but does not consider the time period needed for the dissolution. [Copyright &y& Elsevier]

Abstract: Widespread adoption of carbon [dioxide] capture and storage (CCS) is limited by infrastructure, market, and cost barriers. Like most nascent technologies, it will be critical to overcome these barriers to fully realize the potential of CCS. Capturing CO2 from the oil refining process and using this CO2 for enhanced oil recovery (EOR) is an appealing scenario for knocking down these barriers, jumpstarting a CCS industry, and driving down the cost of CCS technology. CO2 capture from oil refineries can be relatively inexpensive when compared to other stationary sources (supply), EOR provides a market for CO2 (demand), and the spatial proximity of oil fields and refineries reduces transportation issues (cost, right of way, etc.). The oil industry should play a key role in the evolution of CCS since it has vested interests and experience with capturing, transporting, and injecting (and storing) CO2 underground. In this paper we study the deployment of CCS infrastructure to support CO2 capture from the oil refining industry and EOR and long term geologic storage of the CO2 for the US Gulf States. This region accounts for approximately 45% of US refining capacity, a large percentage of active EOR projects, and an extensive network of pipeline rights-of-way (natural gas, crude and refined oil) including over 80% of the existing CO2 pipelines. Presently, the oil industry predominantly uses natural sources of CO2 for EOR; an obvious goal of integrating CCS technology into the oil industry is displace the natural CO2 sources with anthropogenic CO2. The region is also responsible for approximately 450 Mt CO2 emissions annually from fossil-fuel electricity generation; an oil industry-driven CO2 market and CCS infrastructure could provide the necessary stimulus for capturing this CO2 in the coming decades. Our approach uses an economic-engineering model to geospatially deploy CCS infrastructure (capture, transportation, and storage) in response to a price on CO2 or a desired CO2 capture amount. The model considers and integrates each of the interdependent CCS components. It calculates at which oil refineries it is cost -effective to capture CO2, where and how new CO2 pipelines should be networked together, and which EOR oil fields balance CCS costs and CO2 credit as well as providing the best long term storage potential. The combination of capture, transport, and storage infrastructure is highly dependent on the CO2 price, both as an inducement (for EOR) and disincentive (price to emit CO2). Consequently, we examine how the expansion of CCS infrastructure could develop given differing CO2 scenarios, including variation in capture and storage costs. Our results show how a CO2 management network (capture, transport, and storage infrastructure) could develop given a set of oil refineries and EOR reservoirs in the US Gulf Coast region. The model outputs and results can be used to help plan policy and regulation for CO2 capture and storage, and help guide how the oil industry could jumpstart a CCS industry. [Copyright &y& Elsevier]

Abstract: This paper reports a numerical simulation study of a full CO2 core flooding and imbibition cycle on a Berea sandstone core (measured 14.45 cm long and 3.67 cm in diameter). During the test, supercritical CO2 (at 10 MPa and 40 °C) and CO2-saturated brine was injected into one end of the horizontal core and a X-ray CT scanner (with a resolution of 0.35 mm × 0.35 mm) was employed to monitor and record changes in the fluid saturations, which enabled 3D mapping of the saturation profiles throughout the core during the course of core flooding test. From the digital CT saturation data, mean saturation profiles along the core length were plotted with time. A 1D model of the core was constructed to simulate the core flooding test and attempt was made to history match core test results, particularly the evolution of the mean CO2 saturation profiles during CO2 injection. Curve-fitting of the centrifugal air-water capillary pressure data (drainage) for the Berea core showed that the core test data could be adequately described by the Van Genuchten equation. The matched set of parameters (, , ) were 0.09, 20 KPa, 0.425 respectively. In the absence of the relative permeability for the Berea core, it was decided to use the parameters obtained from matching the air-water capillary pressure data as a first approximation for the CO2-brine system in the model. [Copyright &y& Elsevier]

Abstract: To ensure safe behavior during the whole lifetime of the geological storage of CO2, site selection and its characterization are essential corner stones. This paper presents the different milestones and the results of each step of the site characterization implemented on a potential storage site in the Triassic deep saline aquifer of the Paris Basin. It addresses a well known theory and practical aspects and challenges of the first phase of real site identification carried out by Veolia Environnement and Geogreen. The initial static and dynamic characterization of the storage complex will mainly rely on available public or proprietary data. Different challenges related to the gathering and validation of existing data are discussed. The characterization methodology should aim at re-interpreting the available data in order to populate a dynamic model at semi-regional scale of the storage complex. 2D Seismic data reprocessing made it possible to determine the local structure of the storage. Regional structural information must also been considered since industrial scale injection impacts a significant area with respect to overpressure extension. To complete the storage complex description, upper laying structures and aquifers must be adequately described up to the ground level. When elaborating such a 3D model, data consistency at the different scales should be carefully checked. Facies variations, porosity and both vertical and horizontal permeabilities will control storage capacity and well injectivity. Thus, an extensive log analysis is a major step in the characterization methodology. When available, core samples and flow tests must also be reconsidered to enhance the model quality. Furthermore, petrophysical interpretation of logs will improve site characterization and enable mineral trapping assessment. The consistent re-interpretation of available well logs will ensure proper site characterization in terms of reservoir and containment. Some examples are provided to illustrate the relevance of re-interpretation work. Building a 3-D geological model is a major integrating step of the available dataset on the area of interest both in terms of structure and heterogeneities at different scales (facies, mineral, petrophysical …). At this stage, the different assumptions should be carefully revisited in light of the available data. The geological uncertainties can then be estimated using a statistical approach, which highlights key petrophysical characteristics of the storage along with main risks that need to be assessed. The final step in the characterization methodology includes a dynamic assessment of the short term effects on injectivity and capacity, and of long term trapping mechanism. On the short term, potential interference with other sub-surface activities needs to be investigated along with the potential migration pathways (existing wells and faults). Models were elaborated at different scales. A near-wellbore model helped to estimate chemical induced effects. A storage site model helped to estimate overpressure and CO2 plume behaviors, and a model larger than the storage complex helped to identify migration pathways and constraint boundary conditions. Different assumptions and operational constraints were supposed to ensure the robustness of different injection scenarios. The results of corresponding dynamic simulations are presented and discussed. [Copyright &y& Elsevier]

Abstract: Monitoring is the major challenge in CO2 geological sequestration. At the first Japanese pilot CO2 injection site (Nagaoka), CO2 was injected into a thin permeable zone at a depth of 1100 m and the total amount of injected CO2 was 10,400 tons during the injection period from July 2003 to January 2005. After ceasing of CO2 injection, well loggings which mainly consist of neutron logging, sonic logging and induction logging have been continued for 5 years. The Nagaoka site may provide the first field data set of post-injection monitoring and essential information on long-term CO2 behaviour in a saline aquifer. In this paper reports the results of formation pressure, well logging and fluid sampling aiming to improve understanding of CO2 long term behaviour in the reservoir. The results of time-laps well logging provide the evidences of the solubility trap and residual trap in progress at Nagaoka, suggesting CO2 is stored safely in a complex sandstone reservoir. [Copyright &y& Elsevier]

Abstract: CO2 capture and storage become an interesting strategy to mitigate climate change by reducing CO2 emission from stationary sources and storing it in geological reservoirs. Taking into account that Brazilian territory contains many sedimentary basins suitable for CO2 storage, the study of the Brazilian potential for carbon sequestration is relevant. This paper aims to present results of the Brazilian Carbon Geological Sequestration Map (CARBMAP Project). CARBMAP’s goal is to identify appropriate sites for long term CO2 storage in petroleum fields, saline aquifers and coal seams by an integrated geographic information system (GIS) and to generate products that will allow direct and detailed analysis regarding the CCS chain (capture, transport and storage) in Brazil, based on the development of a GIS for CO2 source-sink matching. The Phase I of CARBMAP research began in 2006–2007 with the mapping of Brazilian stationary CO2 sources, using a geographic database. The Phase II is underway, and is characterized by quantitative and qualitative improvement of the GIS resulting in more accurate products. [Copyright &y& Elsevier]

Abstract: Geologic carbon dioxide (CO2) storage verification tests by the U.S. Department of Energy’s (DOE’s) seven Regional Carbon Sequestration Partnerships (RCSPs) provided the experience base for the Public Outreach and Education for Carbon Storage Projects, a best practices manual, published in December 2009. This paper summarizes these outreach best practices; discusses their application in Aquistore, a greenfield CO2 storage project under way in western Canada; and reviews the implications for applying the best practices to new projects during the Development Phase of the DOE’s RCSP Program. [Copyright &y& Elsevier]

Abstract: Large-scale implementation of geologic carbon storage (GCS) will require reliable techniques for monitoring the movement of the CO2 plume in the subsurface. The movement of CO2 plumes beyond the region permitted for storage will be of particular interest both to regulators and to operators. However, the cost of many monitoring technologies, such as time-lapse seismic, limits their application. Given that injection data (pressures, rates) from wells are readily available and inexpensive, we examine whether they can be used as a viable alternative for monitoring and predicting plume migration. In this paper, we have implemented a probabilistic history matching approach to creating models of the aquifer for predicting the movement of the CO2 plume. The geologic property of interest for example hydraulic conductivity is updated conditioned to geological information and injection pressures. The resultant aquifer model which is geologically consistent can be used to reliably predict the movement of the CO2 plume in the subsurface. We tailor the method to CO2 sequestration by considering only injection data in the matching process. We also introduce a two-step approach to stochastically simulate high-permeability features such as oriented sets of natural fractures that occupy only a small fraction of the storage formation. We illustrate the approach by applying it to data from the In Salah Gas project. The final history-matched models contain high permeability features consistent with the field observation of rapid arrival of injected CO2 at a suspended well and with surface deformation data obtained by remote sensing. We conclude that the approach can provide a probabilistic assessment of plume migration at the field scale. [Copyright &y& Elsevier]

Abstract: Geological CO2 sequestration is a key technology for mitigating atmospheric greenhouse gas concentrations while providing low carbon energy. Deployment of sequestration at scales necessary for a material contribution to greenhouse gas mitigation poses a number of challenges not encountered in current operations. At the basin scale, injection sites will not be as well characterized as current operations. Predictions of system response to this magnitude of injection are expected to have greater uncertainty and risk. Through an integrated, model based design and assimilation, monitoring provides a platform for mitigating the associated risks. Because footprints of basin scale injection projects are expected to be very large, the high resolution monitoring programs in existing projects are not economically feasible for monitoring at large scales. The acceptable levels of resolution and risk are dependent on the footprint of the network and the monitoring technique employed, which are in turn, constrained by cost of deployment and regulatory requirements. Network design must make an implicit assumption on the size of the leak that is able to be measured. Leak detection at the surface is complicated by the many natural and anthropogenic sources of CO2 that can mask a leak or result in the incorrect assessment of whether a leak has occurred. In this paper, we introduce a Bayesian framework for decision support in discriminating between CO2 detected from a leak and CO2 measured from background fluctuations. For small leakage concentrations, the signal cannot be distinguished from background fluctuations. When complementary observations are jointly considered, the ability to discriminate between a leakage and background concentrations improves, and the number of samples required for confident detection decreases. Incorporation of Bayesian decision support tools into monitoring programs will assist in reducing risk in geological sequestration in a cost effective manner by providing a framework for efficient integration of complementary observations and enhancing the information content of the network. [Copyright &y& Elsevier]

Abstract: The Prime Minister of Japan declared: Japan should positively commit itself to setting a long-term reduction target. For its mid-term goal, Japan will aim to reduce its emissions by 25% by 2020, if compared to the 1990 level, consistent with what the science calls for in order to halt global warming. In order to achieve this target, the government considers CCS (Carbon dioxide Capture and Storage) as an essential method and aims to improve CCS technology to practical levels. Japan CCS Co., Ltd. (JCCS) was established in May, 2008 in order to study the potential and feasibility of CCS demonstration projects in Japan. The company was commissioned by the Ministry of Economy, Trade and Industry (METI) in Japan. Major shareholders of JCCS include electric power companies, upstream to downstream petroleum companies, material companies, engineering companies, etc.. In 2008, an investigation of candidate sites for the CCS demonstration was done over Japan and several promising offshore sites were selected. One of the selected candidate sites is the Tomakomai offshore site in Hokkaido prefecture, located in the northern part of Japan where there are petroleum refineries, paper mills and power plants close to the site. The Yufutsu oil and gas field is located in the eastern part of Tomakomai city where much geological data has been obtained through oil and gas exploration. Basic geological modes were constructed and CO2 reservoir simulation was performed to predict the movement of the stored CO2. Simulation results show us that a sufficient volume of CO2 could be safely stored in the saline aquifers at the Tomakomai site for a demonstration period and afterward. From October to November in 2009, a 3D seismic survey was implemented to confirm the geological potential of the site. Ocean bottom cables enabled us to survey in front of the Tomakomai Port. The survey area (full-stacked area) was 3.0 km (N-S) by 2.7 km (W-E) and about 2 km from the shoreline with several target formations at a depth of about 1,100–3,000 m. This survey was conducted in 4 patches using 2 to 3 sets of ocean bottom cables with the total number of receiver and shot lines being 10 and 26, respectively. Results of this survey were utilized in building the detailed 3D geological model for the CO2 reservoir simulation. Basic plant designing to capture CO2 at the hydrogen process in the petroleum refineries is currently ongoing. The captured CO2 will be injected at 250,000 ton/year for 4–5 years in the demonstration project. Many local organizations, such as the Tomakomai city government and the fisheries cooperative, cooperated to carry out the 3D seismic survey. The Tomakomai government has been strongly willing to invite the CCS demonstration project to the city. By their continuous cooperation is possible to carry forward the feasibility study in order to start the CO2 injection in 3–4 years. [Copyright &y& Elsevier]

Abstract: The Shaanxi Province/Wyoming CCS Partnership (supported by DOE NETL) aims to store commercial quantities of CO2 safely and permanently in the Ordovician Majiagou Formation in the northern Ordos Basin, Shaanxi Province, China. This objective is imperative because at present, six coal-to-liquid facilities in Shaanxi Province are capturing and venting significant quantities of CO2. The Wyoming State Geological Survey and the Shaanxi Provincial Institute of Energy Resource and Chemical Engineering conducted a feasibility study to determine the potential for geological CO2 sequestration in the northern Ordos Basin near Yulin. The Shaanbei Slope of the Ordos Basin is a huge monoclinal structure with a high-priority sequestration reservoir (Majiagou Formation) that lies beneath a 2,000+ meter-thick sequence of Mesozoic rocks containing a multitude of low-permeability lithologies. The targeted Ordovician Majiagou Formation in the location of interest is more than 700 meters thick. The carbonate reservoir is located at depths where pressures and temperatures are well above the supercritical point of CO2. The targeted reservoir contains high-salinity brines (20,000–50,000 ppm) that have little or no economic value. The targeted reservoir is continuous as inferred from well logs, and cores show that porosity ranges from 1 to 15% with average measured porosity of 8%, and that permeability ranges from 1–35 md. This paper focuses on calculations that will help evaluate the capacity estimates through the use of high-resolution multiphase numerical simulation models, as well as a more simple volumetric approach. The preliminary simulation results show that the Ordovician Majiagou Formation in the Ordos Basin has excellent potential for geological CO2 sequestration and could store the CO2 currently emitted by coal-to-liquid facilities in Shaanxi Province for hundreds of years (i.e., 9 Mt/year CO2; 450 Mt over a 50-year period at one injection site). [Copyright &y& Elsevier]

Abstract: This work is part of the CPER Artenay project that aims at quantifying the environmental benefits and the technico-economic feasibility of storing CO2 issued from a bio-ethanol distillery into a deep saline aquifer in the Paris Basin, France. This communication focuses on the geological investigations that ultimately lead to defining an optimal location for an injection site in Carbon Capture and Storage (CCS) project. This paper presents a new approach for the pre-site characterization going from seismic and well data analyses to storage design. First, the general context of the area has been set follow by seismic interpretation. Those investigations leads to a geological surfaces modeling taking into account the basin border location of the project. The next step is the properties modeling made using sequence stratigraphy surfaces and Petrel software. This work will conduct to choose the optimal injection location regarding this geological investigation and the environmental constrains. [Copyright &y& Elsevier]

Abstract: For carbon dioxide capture and storage to make an effective contribution in reducing greenhouse gas emissions, a large number of storage sites will be required. Safety will have to be demonstrated for each of these sites. We present in this paper a simple and flexible framework to assess safety of a CO2 storage site in a time-efficient manner. It includes the identification by an expert panel of the relevant risk scenarios. Their evaluation privileges analytical or semi-analytical modelling with conservative assumptions. Uncertainty is managed in order to thoroughly represent and propagate the nature of information relative to the site properties. We illustrate the application of this framework with a case study in the context of the Paris Basin. The workflow described is not a complete risk assessment framework, but it constitutes a useful tool for an operator at an early stage of a project or to iteratively screen safety issues, or for a regulating authority to review the safety conditions of a project. [Copyright &y& Elsevier]

Abstract: Injection of CO2 into the Weyburn Oil Field, Saskatchewan, Canada, began October 2000 and 10 years later approximately 18 MT of CO2 will have been stored in the geological reservoir. The CO2 injection is part of an ongoing enhanced oil recovery effort that will extend to 2035 and likely beyond. Both Weyburn and the adjacent Midale oil field are highly suitable for CO2-EOR and it is expected that, combined, more than 40 MT CO2 will eventually be stored in these carbonate reservoirs. Currently about 2.4 MT and 0.4 MT CO2/year are being stored in the Weyburn and Midale fields, respectively, which now represent the largest site of monitored geological storage of CO2 globally. The Weyburn Field is operated by Cenovus Energy and the Midale Field by Apache Canada. The anthropogenic CO2 used at Weyburn-Midale is a by-product of coal gasification at the Great Plains Synfuels Plant in North Dakota, USA. The compressed CO2 is delivered to the oil fields through a 323 km pipeline that crosses the international boundary. The IEA GHG Weyburn-Midale CO2 Monitoring and Storage Project was established prior to the onset of CO2 injection at Weyburn to assess monitoring methods and subsurface processes associated with the injection of CO2 into geological storage sites. This research program is now in its second phase of research. Baseline 3D seismic surveys were performed over the Weyburn Field before injection and subsequent repeat 3D seismic surveys have been taken during the course of injection spanning multiple years and have indicated that CO2 distribution within the reservoir can be imaged seismically. Similarly, repeat reservoir fluid sampling surveys have monitored a range of chemical and isotopic parameters to help identify processes associated with CO2-rock interaction. In addition, multiple soil gas and shallow hydrology surveys have been performed during the past 10 years with no indication of CO2 reaching the surface. The current research program is building on many of the results obtained during the first phase of work on the Weyburn Field. For example, some of the current research includes applying stochastic methods to relate fluid chemistry to the seismic data to better characterize the distribution of CO2 in the subsurface. Additional methods of modeling CO2 distribution post-injection are also being demonstrated and integrated into several risk assessment methodologies. A detailed well database has been developed to catalogue characteristics associated with wells drilled at various stages of field development using different cementing practices and completion methods to assist with providing parameters for long-term modeling of well behaviour. In addition, a downhole well integrity testing program to examine cement sheath characteristics will be implemented in two wells in each of the fields. In summary, more than 30 research studies are being performed within this phase of the program to examine aspects of site characterization, well integrity, geochemical and geophysical monitoring methods and risk assessment. One of the goals for the work from this research program is to provide a best practices manual for the transition of CO2-EOR sites into storage sites. This paper provides an overview of the studies and results developing from the research program. [Copyright &y& Elsevier]

Abstract: Carbon capture and storage (CCS) might be an important climate protection technology for coal-rich countries. This paper presents first results of a systemic and long-term analysis of a future CCS implementation in India. It focuses on potential storage formations in the geological subsurface and the geographic match of these sinks with CO2 emissions of current and future largepoint power plants. The analysis is framed by an overview on India’s position on CCS, ongoing Indian research and development projects as well as its international activities. The geological potential for CO2 sequestration in India is subject to large uncertainty because, so far, only few studies estimated it in a vague manner. A first meta-analysis shows that there is a huge variation between 48 Gt and 572 Gt of CO2. The main differences between the evaluated studies are the assumed capacities for deep saline aquifers and basalt formations. Taking the ongoing discussion and the existing uncertainties into account, the storage potential might be provided only by aquifers (in the range of 44 to 360 Gt of CO2) and hydrocarbon fields (2 to 7 Gt of CO2). The amount of CO2 emissions possibly available for sequestration is assessed by applying three substantially different long-term energy scenarios for India. These scenarios, indicating pathways between a ”low carbon” and a ”high carbon” development until 2050, result in cumulated CO2 emissions between 30 and 171 Gt if all new large-scaled power plants will be based on CCS from 2020 on. Compared with the sink capacities, only the CO2 emissions of scenario S2 (30 Gt) could theoretically be stored with high certainty. Considering the scenarios S3 and S1, their CO2 emissions (94 Gt and 171 Gt, respectively) could only be sequestered if the aquifer capacity would prove to be usable. Geological storage sites do not appear to be located close to sources in South West, Central, North and North East India. This first rough analysis means that only those CO2 emissions occurring in the Western parts of North and West India, the Eastern part of South India as well as the South part of East India might be suited for sequestration nearby. A more detailed source-sink matching will follow in the next phase of the project, including results of expert meetings in India. Furthermore, this analysis will be complemented by an additional assessment from economic, ecological and resource-strategic points of view, which might further affect the potential for CCS. [Copyright &y& Elsevier]

Abstract: SUCCESS is a Center for Environmental Energy Research in Norway and performs research related to geological storage of CO2 in the subsurface. The SUCCESS centre is established by the Research Council of Norway together with several Norwegian research institutes and universities. The centre is hosted by Christian Michelsen Research. Through international cooperation and open research the SUCCESS centre will fill gaps in strategic knowledge and provide a system for learning and development of new competency to ensure safe and effective CO2 injection, storage and monitoring. In this paper we briefly present the main focus areas of the centre and some recent results obtained by the research partners. The results relate to geochemical effects, reservoir modeling, monitoring the geomechanical respond and the marine environment. A brief status on the field trial, Longyearbyen CO2 Lab, at Svalbard is also provided. [Copyright &y& Elsevier]

Abstract: Vattenfall is considering a Carbon Capture and Storage (CCS) project in the North Jutland region of mainland Denmark. The project would involve the post-combustion capture of CO2 from the Nordjyllandsværket coal fired power plant at Aalborg followed by geological storage of the CO2 in a nearby, onshore, saline aquifer within the Vedsted structure. A thorough monitoring plan is considered to be an essential element of the start-up phase of the project based on risk evaluation. This paper describes the first design of such a monitoring plan that was developed for Vattenfall by a team from CO2GeoNet in discussions involving the company and the Danish Geological Survey (GEUS). The monitoring methodologies to be deployed include downhole tools via a monitoring well, 2D and 3D surface seismic for subsurface imaging of the plume, shallow geophysics for the fresh-saline water interface and surface, atmospheric and remote sensing tools for leakage integrity. [Copyright &y& Elsevier]

Abstract: This paper describes a site investigation study that has been performed on the Vedsted structure in NW Denmark, where upper Triassic and Lower Jurassic sandy formations are considered potential reservoirs for large-scale CO2 injection. The study presents the updated version 1.0 model using new 2D seismic data from the site and compares to results from the screening stage where only existing vintage data were used for the geological modelling. In this early stage of site investigation, the regional geological model and sequence stratigraphic interpretation are important contributors to the construction of a realistic geo-model. The facies interpretation is critical for understanding the geometry and connectivity of the reservoir layers. The main reservoir is at depths of 1700 to 2000 m, and therefore the CO2 is injected at supercritical conditions. The reservoir rocks are mainly constituted of fluvial to nearshore deposits including shoreface sandstones, interfingering with marine offshore mudstones. The maximum thickness of the sandstone layers of ca. 30 m will restrict the potential for convection of the brine caused by density contrast instability. Therefore the dissolution enhancement normally assumed to be associated with convection must be modified for this geological setting. This is in contrast to the performance predicted for the Sleipner injection site, where convection is interpreted to happen over time, and it therefore illustrates that site specific evaluation is necessary in order to qualify the contribution from enhanced dissolution as storage mechanism. The interpretation of the new 2D seismic data and the resulting revision of the structural model influence the further plans for data collection, drilling planning and injection strategy. [Copyright &y& Elsevier]

Abstract: Before the full implementation of CO2 capture and storage, a demonstration of its safety is needed through the implementation of reliable risk management methods. One important aspect of risk management is the development of mitigation measures that prevent any risk to the environment or human health. This paper presents a database that includes a set of risk mitigation measures, their description and main properties, and references. They are organised in connection with a detailed approach of risk events developed into bow-tie diagrams by BRGM. The goal of the database is to help the setting up of corrective measure plans that will be mandatory for all projects under the European directive on CO2 storage. [Copyright &y& Elsevier]

Abstract: Planning a carbon capture and storage (CCS) project that meets economic criteria and minimizes risk requires a systematic analysis of the full-value chain, including capture, transport, storage, formation characteristics, well number and type, formation integrity, well integrity, and monitoring, as well as abandonment, government regulations, and public constraints. The complex process of planning a CCS project that meets multiple objectives and honors multiple constraints involves a large number and variety of decisions. This paper describes the use of front-end loading (FEL) and a fully-integrated asset model (IAM) to address these issues. It includes a study example of a coal-fired power plant and assessment of multiple storage sites, including saline aquifer and enhanced oil recovery candidates. [Copyright &y& Elsevier]

Abstract: Carbon capture and storage (CCS) is widely accepted as one of main solutions to mitigate global warming in the world. However, the still-high cost of CCS is one of the major concerns, in particular in developing China. In the other hand, emission control of H2S and SO2 has already become the urgent need, and the reduction target has been set in the 11th Five-Year Plan of China. Therefore, co-storage of CO2+SO2 or CO2+H2S may be an effective way to reduce CCS cost, e.g. due to saving the de-sulphur device, and enable CCS to has an earlier deployment opportunity. In this paper, we try to, at first, reveal some key problems, i.e., trapping mechanism, injectivity and leakage risk, for co-injection and co-storage of CO2 and the strong acid SO2 into subsurface spaces in a certain gas field in China. The output of this gas field includes about 6.8% H2S and 4.6% CO2. Then, we want to insight into the possibilities and potentials of co-storage of CO2+SO2 by numerical studies. After widely referring all opened and published scientifical and technical literature, we develop a model to study a porous media system associated with the thermo-hydro-chemical coupling interactions. The hydrogeology and mineralogy of the injected formation are extracted from the historical materials of the gas field. We have performed several numerical simulations with consideration of a sandstone-clay sequence under acid-gas injection conditions. The clay formation is supposed as a sealed cap rock for the co-storage disposal system. The study examines the impact of SO2 co-injection on the pH of formation brine. Co-injection of CO2 with SO2 results in a larger and more strongly acidified zone, and alteration differs substantially from that caused by the injection of CO2 alone. The mineral alteration induced by injection of CO2 with SO2 leads to corresponding changes in porosity. Significant increases in porosity occur in the acidified zones where mineral dissolution dominates. [Copyright &y& Elsevier]

Abstract: In response to anthropogenic CO2 emissions, geological storage has emerged as a practical and scalable bridge technology while renewables and other environmentally friendly energy production methods mature. While an attractive solution, geological storage of CO2 has inherent risk. Two primary concerns are recognized: (1) leakage of CO2 through caprock imperfections, and (2) brine displacement resulting in contamination of drinking water sources. Three mechanisms for both CO2 and brine leakage have been identified: diffuse leakage through the caprock, leakage through faults and fractures in the caprock, and finally, leakage through man-made pathways such as abandoned wells from oil and gas exploration. While the first two leakage mechanisms are important, we emphasize the risks associated with the presence of abandoned wells. This is due to the large number and density of wells from a history of oil and gas exploration around the world, and the high degree of uncertainty surrounding the properties of these abandoned wells. With current proposed legislation in both the United States and Europe, a need is emerging for practical assessment of leakage risk. In order to accurately predict leakage of brine and CO2 from the injection layer, the geological information for the injection site and the location and makeup of the man-made leakage pathways previously alluded to must be taken into account. Unfortunately, both the geology and abandoned well metadata are typically high in uncertainty, which must be accounted for. With such a high number of random variables, the current state of the art is running many realizations of a system, using a Monte Carlo approach. This requires that the underlying solution algorithms be accurate, and efficient. In the past, many researchers in both academia and industry have turned to robust numerical analysis packages used in the oil industry. However, due to the large range of scales important to this problem (domains of tens of kilometers on a side affected by leakage pathways with diameters of tens of centimeters) such modeling techniques become computationally expensive for all but the most basic analysis. A computational model developed at Princeton University, and currently being commercialized by Geological Storage Consultants, LLC has been shown to be efficient with sufficient accuracy to allow for comprehensive risk assessment of CO2 injection projects. The model allows for mixing solution methods- using computationally expensive algorithms for formations of greater importance (e.g.- the injection formation) and more efficient, simplified algorithms in other areas of the domain. This ability to arbitrarily mix solution methods offers significant flexibility in the design and execution of models. This paper addresses the framework and algorithms used, and illustrates the importance of efficiency and parallelism using the case study of an injection site in Alberta, Canada. We show how the framework can be used for project planning, for risk mitigation (insurance), and for regulatory groups. Finally, the importance of flexible analysis tools that allow for efficient and effective management of computational resources is discussed. [Copyright &y& Elsevier]