Perspectives of Geological CO2 Storage in South Korea to Cope with Climate Change

Atmospheric and geological CO2 damage costs in energy scenarios

Qatar is the biggest exporter of liquefied natural gas, LNG, in the world and is a main oil-producing member of The Organization of Petroleum Exporting Countries, OPEC. A fossil fuel-based industry emerged around the ports of Ras Laffan and Mesaieed, Qatar's industrial cities, perusing industrial diversity and maximising the huge fossil fuel reserves that serve as the primary feedstock for the industrial sector. LNG, crude oil, and petroleum products has given Qatar a per capita GDP that ranks among the highest in the world with the lowest unemployment. This also has given Qatar a per capita CO 2 emissions among the highest in the world. A recent report from The World Health Organisation, stated that the capital of Qatar, Doha, is one of the world's most polluted cities and its air ranked the 12th highest average levels of small and fine particles which are particularly dangerous to health [1]. The people and wise leadership of Qatar recognizes the significance of the problem and made environmental development one of the four pillars of Qatar National Vision 2030. The vision places environmental preservation for Qatar's future generations at the forefront. Qatar Carbonates and Carbon Storage Research Centre is an example demonstrating Qatar's commitment to preserve the envioronment by investigating and implementing key technologies such as carbon capture and storage (CCS) to address the next step in climate change. CCS in deep saline aquifers is an important process for CO 2 reduction on industrial scales. The aim of CCS is to safely sequester CO 2 generated from stationary sources, such as power-plants, into aquifers and depleted oil reservoirs. It is considered a valuable option to reduce greenhouse gases and has been proposed as a practical technology to tackle climate change [2–4]. The importance of CCS as a key option to mitigate CO 2 emissions and combat climate change has been highlighted also in a report by the International Energy Agency (IEA) and suggests that CCS could contribute to a 17% reduction in global CO 2 emissions by 2035 [5]. Previously, carbon dioxide injection into the subsurface has mainly been used for enhanced oil recovery (EOR) purposes. That gave rise to Carbon capture, utilization and storage (CCUS) processes in mature oil reservoirs where CO 2 is first used to enhance oil recovery and then ultimately stored in the reservoir. The incremental hydrocarbon recoveries associated with CCUS make it more attractive to implement compared to CCS. It have significant energy, economic and environmental benefits and is considered an important component in achieving the widespread commercial deployment of CCS technology. Residual trapping of CO 2 through capillary forces within the pore space of the reservoir is one of the most significant mechanisms for storage security and is also a factor determining the ultimate extent of CO 2 migration within the reservoir. Observations and modelling have shown how capillary, or residual, trapping leads to the immobilisation of CO 2 in saline aquifer reservoirs, limiting the extent of plume migration, enhancing the security and capacity of CO 2 storage [6,7]. In contrast, carbonate hydrocarbon reservoirs are characterised by a mixed-wet state in which the capillary trapping of nonpolar fluids have been observed to be significantly reduced relative to trapping in rocks typical of saline aquifers unaltered by the presence of hydrocarbons [8,9]. There are, however, no observations characterising the extent of capillary trapping that will take place with CO 2 in mixed-wet carbonate rocks, the same rock type found in Qatar's subsurface geological formations and many other giant oil reservoirs in the Middle East that hold most of the oil in the world [10, 11]. Experimental tests of CO 2 and brine in carbonate rocks at reservoir conditions are very challenging due to the complex and reactive nature of carbonates when dealing with corrosive fluids pair of CO 2 and brine. In this study, we compare residual trapping efficiency in water-wet and mixed-wet carbonates systems on the same rock sample before and after wettability alteration by aging with oil mixture of Arabian medium crude oil. The experimental work was conducted using a state of the art multi-scale imaging laboratory (core and pore scale) developed at Imperial College London designed to characterise reactive transport and multiphase flow, with and without chemical reaction for CO 2 -brine systems in both sandstone and carbonate rocks at reservoir conditions [12]. The flow loop included stir reactor to equilibrate rock with fluids, high precision pumps, temperature control, the ability to recirculate fluids for weeks at a time and an x-ray CT scanner and micro x-ray scanner for in situ saturation monitoring. The wetted parts of the flow-loop are made of anti-corrosive material that can handle co-circulation of CO 2 and brine at reservoir conditions with the ability to preserve the rock sample from reacting to carbonic acid. We report the initial-residual CO 2 saturation curve and the resulting parameterisation of hysteresis models for both water-wet and mixed-wet systems. A novel core-flooding approach was used, making use of the capillary end effect to create a large range in initial CO 2 saturation in a single core-flood. Upon subsequent flooding with CO 2 -equilibriated brine, the observation of residual saturation corresponded to the wide range of initial saturations before flooding resulting in a rapid construction of the initial residual curve. Observations were made on a single Estaillades limestone core sample. It was made first on its original water-wet state, then were measured again after altering the wetting properties to a mixed-wet system. In particular, CO 2 trapping was characterized before and after wetting alteration so that the impact of the wetting state of the rock is observed directly on both core and pore scales. A carefully designed wettability alteration programme was designed in this study to replicate a mixed-wet carbonate system similar to those found in Qatari oil reservoirs. At the pore level, oil can precipitate asphaltene and other heavy components after long exposure with the rock changing the wetting state of the surface to oil-wet. A mixture of the evacuated crude oil with an organic precipitant, n-heptane, was used to deposit a stable oil-wet film. The precipitant substituted some of the evaporated and oxidised light hydrocarbon originally existed in the crude and deposited asphaltene to generate a stable strongly oil-wet film layer. Filtration experiments were carried out to sensibly precipitate enough asphaltene for a stable and strong oil-wet film without over precipitating and causing fine migration that can damage the core sample. The weight fraction of asphaltene precipitated with different fractions of crude-precipitant mixtures were measured. The diluent consisted of toluene as the solvent and heptane as the precipitant. 40 ml of the diluent was thoroughly mixed with 1 ml of Arabian Medium crude oil at 11 different precipitant/solvent volume ratios ranging from 0–100% at 10% increments and then left in the dark for 48 hours to allow the system to come to equilibrium. The mass of precipitated asphaltenes was measured in each mixture by vacuum filtration using a 0.45 micron polytetrafluoroethylene hydrophobic filter paper (Millipore) and evaporation of any remaining liquid oil from the filter paper. No asphaltene was precipitated at low precipitant volume fraction and only above the onset of precipitation, a linear relationship was seen between the wt% precipitated asphaltenes and the volume % of the precipitant in the mixture. The onset for asphaltene precipitation for an oil mixture of Arabian Medium crude oil and heptane alone without solvent was calculated at the onset using the volume fractions of the components with the mixing rule. The sample's wettability was altered to a mixed-wet using the appropriate oil mixture as measured using the filtration test and the oil was then removed from the sample by CO 2 enhanced oil recovery injected above the minimum miscibility pressure. This allowed for producing unique dataset and a great complement to the more theoretical analysis. That is if we make a surface oil-wet (to water), how does it behave in the presence of a gas. Here we show that residual CO 2 trapping in mixed-wet carbonate rocks characteristic of hydrocarbon reservoirs is significantly less than trapping in water-wet systems characteristic of saline aquifers. We found that in the native water-wet state of the carbonate sample, the extent of trapping of CO 2 and N 2 were indistinguishable, consistent with past studies of trapping and multiphase flow properties in water-wet sandstones [13, 14]. After alteration of the wetting state of the same rock sample with oil, the residual trapping of N 2 was reduced compared to the amount in the pre-altered rock. Surprisingly, the trapping of CO 2 was reduced even further. The unique results were complemented with pore scale observations to investigate the balance of interfacial tensions and contact angles in three-phase flow. Our results show that one of the key processes for maximising CO 2 storage capacity and security is significantly weakened in hydrocarbon reservoirs relative to saline aquifers. We anticipate this work to highlight a key issue for the early deployment of carbon storage – that

Limits to Paris compatibility of CO2 capture and utilization

The article explores the potential for geological storage of carbon dioxide (CO₂) in Ukraine's geological formations as a promising solution to reduce greenhouse gas emissions. The introduction substantiates the relevance of the issue in the context of global climate change and the need to implement carbon capture and storage (CCS) technologies. The study provides an analysis of existing approaches to reducing CO₂ emissions, including mechanisms for capturing, transporting, and storing CO₂. Publications on the characteristics of CO₂ emission sources are analyzed, and technological options for CCS are described. A review of sedimentary basins worldwide is conducted to assess their suitability for CO₂ storage, alongside an analysis of ongoing international CCS projects. Special attention is given to the classifications of storage capacity assessments, criteria for the commercial viability of CO₂ geological storage, and the potential risks of implementing such projects. Based on literature and the analysis conducted, the prospects of using Ukraine's hydrocarbon-bearing regions, particularly depleted oil and gas reservoirs, as CO₂ storage sites are identified. Key challenges related to the implementation of CCS technologies in Ukraine are highlighted. The results can be utilized for further planning and development of geological CO₂ storage projects in Ukraine.

Use of the clean development mechanism for CO2 capture and storage

Temporal and spatial deployment of carbon dioxide capture and storage technologies across the representative concentration pathways

China-Australia capacity building program on the geological storage of carbon dioxide – results from Phase I

Currently, there is considerable confusion within parts of the carbon dioxide capture and storage (CCS) technical and regulatory communities regarding the maturity and commercial readiness of the technologies needed to capture, transport, inject, monitor and verify the efficacy of carbon dioxide (CO2) storage in deep, geologic formations. The purpose of this technical report is to address this confusion by discussing the state of CCS technological readiness in terms of existing commercial deployments of CO2 capture systems, CO2 transportation pipelines, CO2 injection systems and measurement, monitoring and verification (MMV) systems for CO2 injected into deep geologic structures. To date, CO2 has been captured from both natural gas and coal fired commercial power generating facilities, gasification facilities and other industrial processes. Transportation via pipelines and injection of CO2 into the deep subsurface are well established commercial practices with more than 35 years of industrial experience. There are also a wide variety of MMV technologies that have been employed to understand the fate of CO2 injected into the deep subsurface. The four existing end-to-end commercial CCS projects – Sleipner, Snøhvit, In Salah and Weyburn – are using a broad range of these technologies, and prove that, at a high level, geologic CO2 storage technologies are mature and capable of deploying at commercial scales. Whether wide scale deployment of CCS is currently or will soon be a cost-effective means of reducing greenhouse gas emissions is largely a function of climate policies which have yet to be enacted and the public’s willingness to incur costs to avoid dangerous anthropogenic interference with the Earth’s climate. There are significant benefits to be had by continuing to improve through research, development, and demonstration suite of existing CCS technologies. Nonetheless, it is clear that most of the core technologies required to address capture, transport, injection, monitoring, management and verification for most large CO2 source types and in most CO2 storage formation types, exist.

Public risk perspectives on the geologic storage of carbon dioxide

Policy implications of Monetized Leakage Risk from Geologic CO2 Storage Reservoirs

Concerns about climate change and the need to stabilize atmospheric CO 2 concentrations are driving the development of a lower carbon future. Within this context, carbon dioxide capture and storage (CCS) is gaining momentum as a large-scale option to reduce greenhouse gas emissions. This paper reviews the rationale and potential scale of CCS, the status of geological storage options and lessons from the operating In Salah project. CCS is expected to have applications in the oil and gas industry, and other industries, particularly the coal and power sectors. CO 2 -enhanced oil recovery, depleted oil and gas fields and saline formations are considered the most important geological storage options. Experience with geological storage is being gained at the In Salah project in Algeria. Operating since 2004, it is the world's first industrial-scale project storing CO 2 in the water leg of a gas reservoir. A key challenge for wider deployment is for geological storage to be accepted as a safe and effective option, providing long-term CO 2 containment, with high integrity. This has several associated technical and regulatory challenges, including site characterization and selection, geological and well integrity risk assessment, performance prediction, the design of appropriate monitoring schemes and handling the closure and post-closure phases. The petroleum industry has the capabilities and know-how to deploy CCS and to manage the associated risks. This lends confidence that CCS will be a viable option and that deployment will help enable a low-carbon future.

The Cap-and-Trade and Low Carbon Fuel Standard (LCFS) programs being administered by the California Air Resources Board (CARB) include Carbon Dioxide Capture and Storage (CCS) as a potential means to reduce greenhouse gas (GHG) emissions. However, there is currently no universal standard approach that quantifies GHG emissions reductions for CCS and that is suitable for the quantitative needs of the Cap-and-Trade and LCFS programs. CCS involves emissions related to the capture (e.g., arising from increased energy needed to separate carbon dioxide (CO2) from a flue gas and compress it for transport), transport (e.g., by pipeline), and storage of CO2 (e.g., due to leakage to the atmosphere from geologic CO2 storage sites). In this project, we reviewed and compared monitoring, verification, and accounting (MVA) protocols for CCS from around the world by focusing on protocols specific to the geologic storage part of CCS. In addition to presenting the review of these protocols, we highlight in this report those storage-related MVA protocols that we believe are particularly appropriate for CCS in California. We find that none of the existing protocols is completely appropriate for California, but various elements of all of them could be adopted and/or augmented to develop a rigorous, defensible, and practical surface leakage MVA protocol for California. The key features of a suitable surface leakage MVA plan for California are that it: (1) informs and validates the leakage risk assessment, (2) specifies use of the most effective monitoring strategies while still being flexible enough to accommodate special or site-specific conditions, (3) quantifies stored CO2, and (4) offers defensible estimates of uncertainty in monitored properties. California’s surface leakage MVA protocol needs to be applicable to the main CO2 storage opportunities (in California and in other states with entities participating in California’s Cap-and-Trade or LCFS programs), specifically CO2-enhanced oil recovery (CO2-EOR), CO2 injection into depleted gas reservoirs (with or without CO2-enhanced gas recovery (CO2-EGR)), as well as deep saline storage. Regarding the elements of an effective surface leakage MVA protocol, our recommendations for California are that: (1) both CO2 and methane (CH4) surface leakage should be monitored, especially for enhanced recovery scenarios, (2) emissions from all sources not directly related to injection and geologic storage (e.g., from capture, or pipeline transport) should be monitored and reported under a plan separate from the surface leakage MVA plan that is included as another component of the quantification methodology (QM), (3) the primary objective of the surface leakage MVA plan should be to quantify surface leakage of CO2 and CH4 and its uncertainty, with consideration of best-practices and state-of-the-art approaches to monitoring including attribution assessment, (4) effort should be made to monitor CO2 storage and migration in the subsurface to anticipate future surface leakage monitoring needs, (5) detailed descriptions of specific monitoring technologies and approaches should be provided in the MVA plan, (6) the main purpose of the CO2 injection project (CO2-EOR, CO2-EGR, or pure geologic carbon sequestration (GCS)) needs to be stated up front, (7) approaches to dealing with missing data and quantifying uncertainty need to be described, and (8) post-injection monitoring should go on for a period consistent with or longer than that prescribed by the U.S. EPA.

Climate change is one of the most concern problems currently because of the increase of the amount of greenhouse gases in the atmosphere. CO2, the most important component of greenhouse gases, comes from industries like power generation. Carbon capture and storage (CCS) is the practical technology to mitigate CO2 especially geological storage. In Thailand, the main potential of geological storage is in the Gulf of Thailand. However, the research on this in Thailand is scarce. Consequently, this work is focusing on the simulation of CO2 geological storage in formations at the Gulf of Thailand. The storage capacity and the fracture pressure have been estimated. Also, the pressure buildup and plume migration have been simulated with various conditions. CO2 injection is used from 1,000-4,000 tons per day with the depth from 2,160 – 2,510 meters and the results are studied for 1-50 years for monitoring period. The results show that CO2 storage in this area has potential with the formation characteristics. Moreover, pressure buildup and plume migration are illustrated for the period of 50 years. This study can contribute as a fundamental knowledge for CO2 storage in an offshore area in Thailand.

The United States Department of Energy (DOE) is the lead federal agency for the research, development, demonstration, and deployment (RDD&D) of carbon sequestration technologies. This effort is being implemented through several activities, including applied research and development (R&D), demonstration projects, and technical support to loan guarantee and tax incentives programs. The sequestration program started in 1997 and has grown significantly. In Fiscal Year 2010, $145 million in federal funding was received to support carbon capture and storage (CCS) related R&D. The Sequestration Program also received $80 million in funding from the 2009 American Recovery and Reinvestment Act (ARRA) to support the development of resources for geologic storage of CO2. The goal of the program is to develop a suite of technologies that can support the implementation of commercial CCS projects by 2020. Part of the program funding is being used to assess the potential for storing CO2 in offshore geologic formations. This paper presents an overview of projects awarded to assess the potential for geologic storage in state and federal waters in the Gulf of Mexico (GOM), the Atlantic and Pacific Oceans, and in Texas and California state territorial waters, as well as research efforts DOE is supporting world-wide. These efforts are aimed at capacity assessments; monitoring and modeling of sub-seabed storage projects; characterization of projects that are drilling wells and conducting seismic surveys; and assessment of regulatory gaps relative to storing CO2 in offshore formations. The results are expected to provide a summary of basin-scale suitability and will identify and prioritize potential offshore CO2 geological storage opportunities. Introduction Fossil fuels are projected to be the primary source of energy for the United States and most developed and developing countries over the next several decades, and their consumption is expected to increase. Atmospheric levels of carbon dioxide (CO2) have risen significantly from preindustrial levels of 280 parts per million (ppm) to present levels of around 384 ppm (Tans, 2008). Evidence suggests that the observed rise in atmospheric CO2 levels is the result of expanded use of fossil fuels for energy. The concentration of CO2 in the atmosphere is expected to rise due to the anticipated increase in fossil fuel usage unless major advances in energy management and production are made (Socolow et al., 2004; Greenblatt and Sarmiento, 2004). Carbon capture and storage (CCS) is an emerging strategy for preventing the emission of anthropogenic CO2 into the atmosphere. The long-term storage of anthropogenic CO2 is a promising technology for slowing, and ultimately reversing, the build-up of greenhouse gas (GHG) emissions in the atmosphere (NETL, 2009).

Deep underground rock formations are widely used for geological carbon dioxide (CO2) storage due to their large-scale, long-term capacity. However, geophysical and petrophysical complexities can lead to challenges such as gas migration and potential leaks, posing risks to groundwater and subsurface systems. Recent advancements increasingly integrate Artificial Intelligence (AI) and Machine Learning (ML) to mitigate these risks and enhance CO2 storage efficiency. This review explores ML applications in geological CO2 storage, highlighting recent advancements and their implications. ML has demonstrated effectiveness in enhancing CO2 storage efficiency. However, the complexities of geological storage necessitate further improvements in ML model applicability, particularly in real-world projects. Since ML models depend on the availability of data, ensuring high data integrity and quality is crucial. Moreover, CO2 storage projects involve significant risks and uncertainties, making advanced probabilistic ML models essential for quantifying uncertainties and mitigating associated risks. Lastly, integrating real-time monitoring systems with sensor data and ML algorithms can enhance anomaly detection, provide early warnings, and enable timely interventions. Addressing these challenges will strengthen the adoption of advanced ML techniques in geological CO2 storage, improving efficiency, safety, and reliability.