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• Black liquor gasification was coupled with calcium looping. • Calcium looping for CO 2 capture and H 2 production was compared. • CO 2 capture route (39 €/t) was less expensive than H 2 production route (48.8 €/t). • CO 2 avoided cost was highly dependent on capital cost of black liquor gasification. • Export of H 2 had the lowest CO 2 avoided cost among black liquor gasification cases. Although considered one of the major energy-intensive industries (EIIs), the pulp and paper industry has also the potential for energy production from an industrial waste, black liquor. This study proposes black liquor gasification (BLG) coupled with calcium looping (CaL) as a CO 2 capture route for the pulp and paper industry. BLG with H 2 production (BLG-CaL-H 2), BLG with gas turbine combined cycle (BLG-CaL-GT) or with solid oxide fuel cell (BLG-CaL-SOFC) were considered. The dependence of carbon capture and storage (CCS) cost on the natural gas, limestone, electricity imported and H 2 sale prices aside the expenditures related with BLG-CaL were evaluated. The CCS route, based on CaL retrofitted to the pulp and paper plant, was found to have a lower cost of CO 2 avoided (39.0 €/tCO 2) when compared with BLG-CaL (48.8–57.1 €/tCO 2). Between the BLG-CaL scenarios, BLG-CaL-H 2 presented the lowest cost of CO 2 avoided (48.8 €/tCO 2) but the highest energy penalty. Based on the thermodynamic performance, it was shown that CaL retrofit and BLG-CaL-SOFC presented the best overall performance, turning the electricity importer reference plant into electricity exporter. The economic sensitivity showed that the capital requirement of BLG-CaL has a strong effect on the cost of CO 2 avoided for all alternatives. The H 2 production is also strongly affected by the H 2 sale price while BLG-CaL-SOFC and BLG-CaL-GT are strongly dependent on natural gas price. [ABSTRACT FROM AUTHOR]

Post-combustion capture (PCC) of CO 2 from fossil fuel-fired power station flue gas is one of many technologies that are being developed to reduce anthropogenic greenhouse gas emissions in the medium term. Wet-gas scrubbing using aqueous amines is currently the most mature PCC technology suitable for separating CO 2 from coal-fired power station flue gases. In this study, a series of twelve samples of a degraded 30% (w/w) MEA absorbent were obtained over a six month pilot scale PCC campaign at a brown coal-fired power station in Australia. These samples were used to investigate the accumulation of heat-stable salts, inorganics and minerals. The heat-stable salts concentration increased from 0.80 to 2.29% (w/w, as MEA) and organic acids from the oxidative degradation of MEA were the largest component of heat-stable salts. Acid gases such as SO x and NO x , make-up water, ultra-fine fly-ash and corrosion were all sources of the minerals and inorganics that accumulated in the aqueous MEA absorbent. Corrosion was the single biggest contributor of transition metals and the abrupt change in ratios of Fe, Cr and Mo suggests that the dominant corrosion mechanism may have changed towards the end of the campaign. The rapid accumulation of minerals and inorganics during this PCC campaign highlights the importance of continuing research into the interactions between amine absorbents and inorganic or mineral contaminants. The data presented in this study are an important resource for design of laboratory scale experiments to investigate these physical and chemical interactions between aqueous amines, minerals and inorganics. [ABSTRACT FROM AUTHOR]

• Novel methodology for variable flow CO 2 pipeline design optimisation. • Utilises logit-normal distribution to describe variable flow scenarios. • Methodology is validated for different flow rates and transport lengths. • Oversized pipeline diameter minimises unitised transport cost. • Oversized design yields lower cost compared to buffer tanks. Pipeline transport has emerged as the most cost-effective method for transporting CO 2 onshore. The CO 2 flow rate is a key factor driving transport costs, underscoring the need to understand the impact of flow rate variability in CO 2 pipeline networks on their design and economics. This paper presents an optimal pipeline design methodology for CO 2 pipelines operating under variable flow that considers the probability distribution of CO 2 flow rate and the pipeline length. The results imply that pipelines designed for optimal performance under variable flow rates often demand a higher level of overdesign compared to pipelines intended for steady-state conditions. Decision-makers must balance the trade-offs between pipeline oversizing and installing multiple pressure boosting stations, especially applicable to large transportation distances and projects of extended duration. The examination of different approaches to pipeline design reveals that a variable flow pipeline design based on mean flow rate is not recommended, because it is incapable of handling the maximum flow rate. This drawback is overcome by adopting the variable flow stochastic pipeline design presented in this paper. [ABSTRACT FROM AUTHOR]

• The paper presents critical perspective of the DFI research technique. • Presented empirical data may modify the findings formulated by other researchers of communicating about CC(U)S. • The analysed argumentation is based on presenting the innovative usage of captured CO2 as a cushion for stored natural gas. The paper presents the results of deliberative group interviews with the representatives of local communities in West Pomeranian Province (Poland) on the opportunities and challenges related to the theoretical location of combined CO 2 and natural gas underground storage (CC(U)S and UGS) in their immediate vicinity. The research has been conducted within AGaStor Project that focuses on innovative usage of captured CO 2 as a cushion for stored natural gas. Therefore, there are two possible benefits: active limitation of CO 2 emissions (Poland is and will be dependent on conventional energy sources) and reduction of gas storage costs (by using waste CO 2 as so-called cushion gas). However, previous experiences in these types of projects show the key role of local public opinion in the final shape of the investment. CC(U)S projects are usually located in less developed, less populated areas, with smaller, more rural local communities facing serious socio-economic challenges. This is the case presented in this paper. In such communities, socially expressed uncertainty and dissent are mechanisms of emancipation and articulating community's subjectivity, and a strategy for articulating fears of distrust and inadequacy of empowerment. The presented results of the research lead to four significant mechanisms of building trust for CC(U)S and UGS in West Pomeranian Province communities: a) communicating safety, b) communicating the lack of nuisances, c) communicating the benefits and d) transparent and competent knowledge transfer. [ABSTRACT FROM AUTHOR]

• Step-by-step procedure to develop the tabulation and map component of UIC class VI permit. • Qualitative risk assessment methodology for all types of wells within AoR penetrating the confining zones. • Highlights the need for crossflow modelling of CO 2 leakage through improperly plugged wells. • Generalized categorization of legacy wells based on geologic penetrations and protections. Carbon Capture & Storage (CCS) refers to capturing the anthropogenic carbon dioxide (CO 2) at a source followed by injecting and storing it safely in the subsurface. The success of the CCS projects therefore heavily relies on how efficiently the confining zones (containment seals) prevent migration of the CO 2 to the surface and/or to the underground sources of drinking water (USDW) through leakage pathways. CCS projects requires drilling of Underground Injection Control (UIC) Class VI wells for permanent storage of CO 2 in subsurface. Detailed information of all the wells within the Area of Review (AoR) is needed to develop the map and tabulation components of the Class VI well permit application. This paper discusses the generic process that can be used by permit applicants to develop the dataset necessary for preparing the map and tabulation components of the Class VI permit application and perform qualitative risk assessment of all the wells within the AoR. This methodology directs the corrective action plans as well as monitoring plans to some extent. Results of the application of the newly developed methodology for wells in Illinois basin is discussed in detail. This methodology can be applied to all wells including orphaned wells, abandoned wells, active oil and gas wells, stratigraphic wells, disposal wells, etc. This methodology generalized categorization of legacy wells that will help in easier comparison of different CCS projects across the globe. The qualitative risk assessment methodology discussed in this paper is a good starting point for developing crossflow modeling. [ABSTRACT FROM AUTHOR]

• Lithuanian deep saline aquifers and depleted oil reservoirs are characterized to assess their potential for effective carbon. • Uncertainty management workflow is presented and used for modelling the three saline acquires and one depleted oil field for CO2 storage potential estimatesAssessing the geological storage potential. • Mechanistic modelling approach is used for creating simulation models for assessing the storage potentials in the three saline acquires and one depleted oil field for CO2 storage potential estimates. The need to reduce carbon emissions, via exploring the CO 2 storage potential in the depleted subsurface hydrocarbon and the deep saline aquifers in the Baltic Basin region of Lithuania, is discussed. The paper presents a unique methodology, using multi-deterministic numerical models, for evaluating the CO 2 storage potential of the deep saline aquifers and the depleted hydrocarbon fields of Lithuania. Such an approach has never been presented before for evaluation of Lithuanian subsurface reservoirs for CO 2 storage potential. The paper also explains the limitations of previous estimates of CO 2 storage potential computed for deep saline aquifers in Lithuania and introduces a new study that uses uncertainty quantification principle and numerical modelling to estimate the maximum CO 2 injection and storage potential in the region. Three deep saline aquifers D11 (offshore), Syderiai and Vaskai (on shore) are evaluated along with depleted hydrocarbon reservoirs of Gargzdai residual oil zone. Evaluation estimates presented in this paper suggest a maximum theoretical storage potential in range of 96 –407 Mt. of CO 2 for the three deep saline aquifers and in range of 64–267 Mt. of CO 2 for Gargzdai residual oil zone. Although the primary focus of this paper is on the storage capacity estimation, a high-level analysis of the risks associated with CO 2 injection and storage are also presented. [ABSTRACT FROM AUTHOR]

• Trapping indices stabilization is lagged as injection period is active. • Greater CO 2 cumulative volume occurs as reservoir pressure is far from caprock fracture pressure. • Larger closures will require pressure management-based brine production to reach theoretical storage capacity. • ML-based CO 2 storage modelling preliminary de-risked saline aquifers lacking numerical models. This paper presents a machine learning (ML) model designed to speed up the appraisal of geologic CO 2 storage sites by predicting the effectiveness in trapping and accommodating CO 2 in saline aquifers. Considering the urgency of de-risking as much geologic CO 2 storage resources as possible to help with CO 2 emission reduction Paris' goal, ML-based reservoir modelling has been documented as proper tool when a faster, good approximate, and less expensive approach is needed to surrogate multiple assessments of storage sites traditionally performed by long-timeframe and multi-stage geologic CO 2 storage numerical modelling approach. In this paper, a case study is presented. It consisted of a dataset comprised of six geologic aquifer parameters (CO 2 residual saturation, horizontal permeability, vertical to horizontal permeability ratio, porosity, brine salinity, and CO 2 flow rate) and elapsed time as input data, and as output data the CO 2 trapping mechanism indices (Solubility Trapping Index, Residual Trapping Index, and Structural Trapping Index) along with the dynamic storage capacity (CO 2 injected volume). Such dataset was used to train and test the artificial neural network (ANN) model. The dataset was generated from thousands of post-processed numerical realizations at several injection periods by applying design of experiment using a synthetic aquifer model derived from the Bunter Sandstone Closure 36 aquifer numerical model, from the Southern North Sea. The ANN architecture designed in Python consisted of 3 hidden layers and 40 nodes and its performance was assessed using the coefficient of determination (R2) and root mean squared error (RMSE). The ANN performance showed accuracies (R2) for training and testing with 96% and 95% of precision respectively. Practical application of the ANN model was successfully implemented to CO 2 storage aquifer sites selected from CO2Stored® database which lacking numerical models (Bunter Closure 3, 9, 35, and 40), obtaining at the end of 100-years injection case a Structural, Residual, and Solubility Trapping Index averaging 83%, 11%, and 6% respectively, with low variation coefficient indicating that trapping indices were predicted properly because aquifers selected for ANN model application have similar structures (dome-like shape) and reservoir properties. In addition, CO 2 injected volume predictions for 100-years injection case were ranging from 397 to 456 million ton (Mt) totalling 2.1 giga ton (Gt) of potential storage capacity which represents 70% of total theoretical volumetric capacity. These results show the significant impact to accelerate geologic CO 2 storage sites assessment by implementing ML-based modelling to preliminary de-risking groups of saline aquifers and reasonably consider them technically feasible CO 2 storage sites in UK. [ABSTRACT FROM AUTHOR]

• A new method for quantitatively monitoring CO 2 saturation in depleted gas reservoirs is proposed. • The ratio of the near detector's neutron capture gamma-ray count rate to the far detector's thermal neutron count rate measured by a four-detector pulsed neutron logging tool can effectively differentiate between CO 2 and CH 4. • The new method has higher CO 2 sensitivity compared to conventional count ratio methods. With favorable trap conditions and comprehensive infrastructure, depleted gas reservoirs create ideal spaces for the economic and efficient storage of carbon dioxide (CO 2). Accurate monitoring of CO 2 saturation is important for understanding CO 2 storage efficiency and distribution status. This paper proposes a new method for the quantitative monitoring of CO 2 saturation in CO 2 sequestration projects within depleted gas reservoirs. The new method uses the ratio of the near detector's neutron capture gamma-ray count rate to the far detector's thermal neutron count rate (RCN) measured by a four-detector pulsed neutron logging tool. In this paper, the RCN responses for different CO 2 saturation levels are studied using the Monte Carlo method, and the methods for roughly and accurately calculating CO 2 saturation are given. Moreover, the effects of formation factors such as lithology, clay mineral content, bound water salinity, and borehole environment on the RCN response are studied. Finally, the applicability of the RCN method is verified through a simulation example. The results show that the RCN method not only has high CO 2 sensitivity, but it also can accurately determine CO 2 saturation in depleted gas reservoirs and control the error of CO 2 saturation calculation within 2%. This study offers robust technical support for the evaluation of CO 2 saturation in depleted gas reservoirs. In addition, the proposed method has been proved applicable in the evaluation of CO 2 saturation in low-porosity reservoirs. [ABSTRACT FROM AUTHOR]

• CCUS development among EU countries with the latest progress in the field. • Realization of EGD targets with CCUS technology in EU. • Applicability of benchmarking method to compare environmental profiles. • UK and the Netherlands are among top countries with rapid CCUS development. • Poland and Germany with a high level of difficulty in achieving the EGD targets. Carbon Capture Utilization and Storage (CCUS) is a technology highlighted as one of the tools in climate change mitigation and one of the ways to reach the goal of 1.5℃ set by the Paris Agreement. The European Commission (EC) developed this goal by creating and implementing the European Green Deal (EGD) – the European Union's (EU) environmental policy. This paper provides an analysis of environmental policies and an overview of crucial CCUS projects of selected member states based on a benchmarking analysis of 27+ UK member states. An overall review of a total of 28 countries was undertaken based on economic and environmental factors. Afterward, a benchmarking analysis was performed ranking the countries according to the TOP10 for the selected five categories: total net emissions with international transport, percentage share of the energy sector, percentage share of fossil fuels, percentage share of fossil fuels in the Gross Electricity Production (GEP), and numbers of CCUS projects. Subsequently, a detailed and comprehensive overview of four selected member states was done, with a special focus on the national energy policy towards net-zero emission goals, the role of CCUS in domestic environmental policy, with current projects and facilities development. Finally, this paper outlines how the EGD has reformed the national energy policies of selected member states, and what is the part of CCUS technology in the national efforts towards climate neutrality. [ABSTRACT FROM AUTHOR]

System modelling efforts have shown that carbon capture is a key technology to enable a cost-effective reduction of hard-to-abate emissions in energy-intensive industries. The CO 2 that is captured can either be utilised (CCU), or stored with carbon capture and storage (CCS). This paper examines the implications of both European carbon pricing mechanisms (ETS I & ETS II) on the level-playing field between CCS and CCU investments. Our contribution is threefold. First, we develop an equilibrium model that enables us to mimic market outcomes under different regulatory conditions. With a numerical case study applied to a fuel production chain, the model confirms that the current ETS regulation can have an adverse effect on CCU uptake. Especially with zero or low ETS II prices a lock-in effect can occur on CCS, potentially prolonging conventional refinery activities. Second, we propose an alternative approach to better integrate CCUS into the EU ETS. Results show that this approach maintains the level-playing field between CCU and CCS, regardless of any carbon price differentials. That results in a closer to Pareto optimal outcome in terms of welfare and emission abatement. Third, we present an analytic analysis to express the CCUS trade-off from a theoretical point of view. This provides generalised and concrete insights into how EU ETS influences the profitability and likelihood of CCUS. Our results help policymakers to gain a better understanding of the impact of ETS regulations on decarbonisation efforts in the industry. [ABSTRACT FROM AUTHOR]

• We quantify wettability of resedimented clay mudrocks immersed in scCO2 at t ≥ 60 °C and P C O 2 ≥ 25 MPa. • Imbibition results indicate mudrocks remain water-wet to CO2 at typical storage conditions. • Results validate expectations of buoyant CO2 structural trapping by capillary forces. Structural trapping provided by seals is one of the key components of CO 2 geological storage systems. Clay-rich caprocks and fault gouge are expected to be water-wet at supercritical CO 2 conditions and to create a positive capillary pressure P C O 2 − P w > 0 MPa to ensure trapping of buoyant CO 2. This paper presents the results of water imbibition experiments in resedimented clay mudrocks immersed in supercritical CO 2 at temperature T ≥ 60 °C and pressure P C O 2 ≥ 25 MPa. The samples used in this work include kaolinite clay and Anahuac shale from the Gulf of Mexico Coast. Additional validation tests include Berea sandstone and silane-treated Berea sandstone. The results show spontaneous and rapid imbibition of water droplets into resedimented and rock samples initially saturated with wet supercritical CO 2 for all cases. This outcome provides indirect evidence that typical siliciclastic caprock building minerals remain water-wet to CO 2 at typical storage pressure and temperature conditions. The results and analysis indicate that siliciclastic caprock and fault gouge are expected to develop a positive capillary entry and breakthrough pressure to hold buoyant CO 2 by capillary forces. These results validate expectations of buoyant CO 2 structural trapping and field observations from natural analogues. [ABSTRACT FROM AUTHOR]

• Group Method of Data Handling (GMDH) was used to develop a deep neural network • The developed model was used to estimate the brine/CO 2 interfacial tension (IFT) • IFT values were measured in a wide range of pressures, temperatures, and salinities • The proposed method produced reasonable results with no large errors • The proposed method outperformed other brine/CO 2 IFT estimation methods Capillary/residual CO 2 trapping is one of the main mechanisms of CO 2 storage in underground formations. Therefore, it is required to estimate the brine/CO 2 interfacial tension under different conditions. Although many methods have been proposed so far, the error of estimation is still high. This paper proposes a novel deep learning method to estimate the brine/CO 2 interfacial tension at various temperatures, pressures, and salinities. The proposed method is a neural network with the Group Method of Data Handling (GMDH) learning method. The GMDH has the advantage of handling the structural and parametric optimization of the network automatically. The proposed method is tested on an experimental dataset of brine/CO 2 interfacial tension with CalCl 2 and MgCl 2 salts. The results of the proposed method were compared with four of the best performing methods in the literature. The Average Absolute Percentage Error (AAPE) of the method on the training, testing and all data was 1.3 %, 2.95 %, 1.73 %, respectively, while the best method from the literature could reach an AAPE of 8.16 % on all data. Therefore, the proposed method performs far better than the existing methods. Also, a sensitivity analysis was done to determine the most influential inputs to estimate the output. The contribution of this work is to show the applicability of the GMDH method to construct more optimal data-driven models to estimate the brine/CO 2 interfacial tension. Also, the utilized dataset is collected under a wide range of pressure, temperature and salinity conditions that increases the generality of the model. [ABSTRACT FROM AUTHOR]

• The damage of CO 2 transport infrastructure stems from the characteristics of working fluid and environment. • The development of damage is influenced by many factors like pressure, temperature, flow rate, impurities and materials. • Corrosion perforation, erosion, cracking, debonding and physical-chemical coupling accelerate damage. Carbon dioxide capture and storage (CCS), the bottom covering technology for environmental protection and energy transformation, plays a vital role in reducing CO 2 emissions and has become an international research hotspot. The safe operation of CO 2 transport infrastructure is crucial to ensure the smooth implementation of carbon reduction actions. However, the understanding of disasters in carbon transmission infrastructure is not comprehensive and profound enough since CCS is still developing, which leads to few engineering standards on disaster prevention and mitigation of CO 2 transport infrastructure. This paper provides detailed reviews, including the composition and characteristics of carbon transmission infrastructure, failure mechanisms. It is concluded that the characteristics of CO 2 transport infrastructure damage fundamentally stems from the working fluid and environment, and novelty pointed out that future research hotspots are damage under multi-field coupling, damage detection and monitoring, design to reduce damage and repair after damage. The summary of existing research will be helpful for future academic research and engineering practice of CO 2 transport infrastructure disaster prevention and mitigation. [ABSTRACT FROM AUTHOR]

• Introduction, explain the development in CCS industry (fast groing challenge of hub project mixing different sources of CO2, causing effects of impurities from different sources cause impact on integrity and interact to cause even more issues. • Impurities (H2O, SO2, H2S, O2 and NO2) chemical interactions and their limits, testing background, solubility limits and model. • Results, identified limits from testing and medelling. • Review oif results and put them in perspective, when and how do impurtities react and what are the identified limits and potential results of acid drop out. • Explaining the corrosion mechanism bridging the results toward practical applications and potential consequences (corrosion rates). • Corrosion control options. • Summary and guidance, including identified safe limits, testing and modelling, corrosion management and gaps and way forward. Carbon Capture and Storage (CCS) involves capturing, treating, transporting and storage of CO 2 to ensure long-term isolation from the atmosphere. In recent years there has been a significant increase in CCS project proposed and initiated. A number of these proposed projects aim to capture CO 2 from multiple industrial emitters (sources) to reduce the carbon footprint for these emitters. Depending on the CO 2 composition and operating conditions, separate phases may be formed. It has been identified that these separate phases can comprise of water or reaction products including strong acids, or sulphur that can cause severe corrosion. To ensure long term integrity of the facilities, a safe project CO 2 specification needs to be identified. Tight control of CO 2 stream composition and operating conditions together with the selection of suitable materials are essential to ensure the integrity for all operating scenarios including upsets. This paper focuses on identification of impurity limits for a CCS project, which are captured in a project's CO 2 specification. Special attention is given to one specific group of impurities that can react and cause drop-out of a highly corrosive phase. Sound understanding of the mechanisms that stand behind these chemical reactions, thermodynamics, the role of phase behaviour and potential consequences are needed to be able to identify or/and adjust impurity limits for a CO 2 specification in projects. This work aims to improve understanding provide guidance and to reveal knowledge gaps that require addressing in order to identify a safe CO 2 specification for a CCS project. [ABSTRACT FROM AUTHOR]

Policies that incentivize the capture and geological storage of CO 2 from large point sources ('CCS'; and more recently, atmospheric removals), have so far tended to reward the resultant avoided CO 2 emissions (or CO 2 removals) achieved by operators at the point of capture. The expectation has been that geological CO 2 storage sites, as well as the connecting infrastructure, will be developed and operated based upon the funding delivered from the single point of incentive (e.g. under an emissions trading system or a carbon tax, only CO 2 capture installation operators are absolved of the obligation to acquire and surrender CO 2 emission rights or to pay the tax). Project-based crediting mechanisms (e.g. in the voluntary carbon market) tend to treat the entire chain of operations as a single entity to be supplied with emission reduction or removal credits. Consequently, there has been minimal explicit financial incentive to store CO 2. Yet a multiple gigaton-per-year scale capture and storage industry requires complex CO 2 networks to evolve, with multiple sources connecting to multiple sinks, with installations owned by different operators with different technical expertise, climate mitigation goals and obligations. This multiplicity of goals and incentives can create agency problems and cross-chain risks, which impact negatively upon investment decisions. In this paper, we review the history, evolution and potential of geological net zero (GNZ) and carbon storage (or takeback) obligation concepts applied to fossil carbon producers and suppliers as a means to address these risks alongside policies aimed at atmospheric net zero (ANZ) and fossil carbon emitters. [ABSTRACT FROM AUTHOR]

• New carbon-sequestration geosystem paradigm proposed for screening CO 2 repositories. • Deposition, burial history 1st-order controls on repository attributes, traps, etc. • Genetic understanding of geology enables property prediction away from data control. • Case-study application to heavily industrialized region of onshore Canada. In this paper, I propose a new geoscience paradigm for evaluating potential carbon-sequestration targets. I introduce the term carbon-sequestration geosystem to study and describe portions of sedimentary basins where all the geologic components necessary for the safe and long-term storage of CO 2 are present. The purpose of this type of analysis, most appropriately applied at a basin-screening stage, is to derive a holistic, genetic, and predictive understanding of the geology – the depositional systems, structural setting and other factors that are direct controls on storage, injectivity, potential for induced seismicity, and other critical factors. To illustrate the concepts, I present a re-evaluation of the geologic carbon-sequestration options in Southern Ontario (Canada) where business and environmental needs, mostly associated with hard-to-abate industries, require urgent action. Legacy wireline-logs, core, and outcrop data are the main data sources available in this onshore setting. The results of this new, independent study are broadly similar to those of previous studies: the Cambrian section, a saline aquifer, is the most likely candidate to be a CO 2 repository. However, the methodology used identified several issues (e.g., stratigraphic heterogeneity, proximity to basement) that will need addressing by targeted data collection and/or analysis before site-selection for a test should be undertaken. [ABSTRACT FROM AUTHOR]

• It maps the CO 2 storage potentials in shale basins in China comprehensively. • Both shale oil and gas basins are quantitatively estimated via different equations. • Basins are classified into three tiers for carbon storage with varied time scales. • The equations for the estimations of CO 2 storage potentials are optimised. • The density variation of CO 2 at different conditions was considered. China is the second largest shale gas and oil producing country possessing large and significant shale basins, and it is also one of the top carbon emitting countries. Therefore, there is significant potential to store CO 2 in shales in China to remove the carbon emission and enhance and gas recovery simultaneously. This research provides a comprehensive prediction of potentials of CO 2 storage in major shale gas/oil basins in China based on most recent publications where density variation of CO 2 at different subsurface conditions is considered and the different stages of development are classified. We optimise the calculation equations for shale gas and oil respectively, and further classified the three tiers (i.e. commercial, potential and possible reservoirs) in the calculation to prioritise the sequestration site selection. A total of around 6194 Gt, CO 2 sequestration in shales, including 172 Gt for commercial, 849 Gt for potential and 5147 Gt for possible storage, equivalent to a total of 620 years' carbon emissions in China is expected. These can be realised in around 20 years, 20–50 years and 50–100 years respectively. For future applications, more concerns should be on the evaluation criteria of sequestration sites in shales, CO 2 fracturing mechanisms and potential leakage, multi-phase seepage and reactions, and environmental monitoring systems. As a comprehensive assessment of potentials of CO 2 storage in shale basins in China, this paper will provide an important guide for future academic studies, industrial operations and government policy making. [ABSTRACT FROM AUTHOR]

• Experiment at upper-temperature limit for CO 2 sequestration in basalt. • CO 2 sequestration experiment in metasedimentary rocks. • PHREEQC modeling compared to experimental results. • Numerical models might overestimate CO 2 sequestration at high temperatures. The potential for in-situ CO 2 sequestration was analyzed experimentally for one basaltic hyaloclastite sample from the Nesjavellir geothermal reservoir in Iceland and three metasedimentary rock samples from the Kızıldere geothermal field in Turkey. Based on batch reaction experiments, this paper demonstrates the interaction between a CO 2 gas-charged fluid and rock samples from these reservoirs. The experiments were conducted at 260 °C and 0.8 MPa, and 105 °C and 17 MPa for the basaltic and metasedimentary rocks, respectively. The experimental results indicate that CO 2 sequestration within the glassy basaltic rocks is hampered by zeolite, chlorite, and anhydrite, which compete with carbonate minerals to uptake divalent cations at the P-T conditions applied. In contrast, the carbonation process for the metasedimentary rocks is inhibited by their mineralogical composition. Generally, these rocks are less reactive and provide an insufficient supply of divalent cations. The batch reactor experiments were numerically simulated with the PHREEQC geochemical modeling program. The simulations indicate that CO 2 sequestration is feasible at the tested P-T conditions, provided that silicate and SO 4 mineralization is suppressed for the basaltic rocks and that there is an effective source of divalent cations for the metasedimentary rocks. [ABSTRACT FROM AUTHOR]

• • Three approaches are compared for dynamic simulations of CO 2 capture. • • The influence of key operating factors of CHP plants on approaches is studied. • • The influence of time step on the amount of captured CO 2 is studied for each approach. • • Recommendations are given for the selection of approaches. Integrating CO 2 capture with biomass/waste fired combined heat and power (CHP) plants is a promising method to achieve negative emissions. However, the use of versatile biomass/waste and the dynamic operation of CHP plants result in bigger fluctuations in the properties of flue gas (FG), e.g. CO 2 concentration (CO 2 vol%) and flowrates, and the heat that can be used for CO 2 capture, when comparing with coal fired power plants. To address such a challenge, dynamic modelling is essential to accurately estimate the amount of captured CO 2 and optimize the operation of CO 2 capture. This paper compares three dynamic approaches commonly used in literature, namely using the ideal static model (IST) and using dynamic models without control (Dw/oC) and with control (DwC), for MEA based chemical absorption CO 2 capture. The performance of approaches is assessed under the variations of key factors, including the flowrate and CO 2 vol% of FG, and the available heat for CO 2 capture. Simulation results show clear differences. For example, when the CO 2 vol% drops from 15.7 % to 9.7 % (about 38 %) within 4 hours, DwC gives the highest amount of captured CO 2 , which is 7.3 % and 22.3 % higher than IST and Dw/oC, respectively. It is also found that the time step size has a clear impact on the CO 2 capture amount, especially for DwC. Based on the results, suggestions are also provided regarding the selection of dynamic modelling approaches for different purposes of simulations. [ABSTRACT FROM AUTHOR]

Ca-Looping technology has experienced a substantial development in the technical readiness level in the last years, especially in its application as post-combustion CO 2 capture technology in power plants. Experimental results from MW-scale power plants worldwide have confirmed post-combustion Ca-Looping process using interconnected circulating fluidised bed reactors as a promising technology for CO 2 capture. Among the different fields of research having contributed to this breakthrough, modelling activity aiming at assessing sorbent properties, interpreting results from experimental reactors or assessing technology scale-up through large-scale reactors and process integration have played a crucial role. This paper aims at reviewing and discussing findings obtained by different research groups worldwide about post-combustion Ca-Looping process modelling. Assumptions made with respect to sorbent performance, reactor operating conditions and process integration between different components are crucial when evaluating the performance of the Ca-Looping process as a post-combustion technology for CO 2 capture. With the aim of understanding the importance of these assumptions, this paper covers particle reaction and reactor models for carbonation and calcination steps, assessing the impact of the conditions used for their determination into their reactivity predictions, as well as process modelling works that assess performance obtained when integrating a Ca-Looping process into a power plant. Indications on the research needs detected among the reviewed works have also been highlighted in this work to contribute to the advancement of the knowledge on the Ca-Looping technology. [ABSTRACT FROM AUTHOR]

The growing concerns over global warming and carbon dioxide emissions have driven extensive research into novel ways of capturing carbon dioxide in power generation plants. In this regard, oxy-fuel combustion has been considered as a promising technology. One unconventional fuel that is considered is sour gas, which is a mixture of methane, hydrogen sulfide and carbon dioxide. In this paper, carbon dioxide is used as the dilution medium in the combustor and different combined cycle configurations were considered and analyzed, each with a different way of dealing with the harmful sulfur products in the working fluid. Out of these options, which included acid resistance, no-condensation and SO x removal cycles, it is found that the cycle using acid resistant materials to have the best efficiency at 45.2%. However the cost of electricity (COE) of the cycle incorporating SO x removal is about 3% lower. Comparing these combined cycles to the sour gas water cycles discussed in our previous paper ( Chakroun and Ghoniem, 2015 ), it is evident that sour gas based oxy-combustion combined cycles generally perform better in terms of both technical and economical performance. Therefore, it is concluded that the best process cycle to use for this sour gas fuel to be the combined cycle with the SO x removal system. This high-efficiency cycle has the lowest COE out of all of the five cycles studied. [ABSTRACT FROM AUTHOR]

This paper evaluates the effect of CO 2 on protozoan communities, a neglected group in CO 2 related studies, despite their potential role in influencing bacterial communities, and vegetation growth. For this purpose, the effect of increased CO 2 in the soil upon the abundance of protozoa (amoebae, flagellates, and ciliates) and diversity of ciliates was experimentally studied in two soils. Twelve mesocosms were created with 8 m 2 cells filled with the upper layer of one of the two soils. The cells were equipped with systems that controlled injection of CO 2 at different depths. Two different flows of CO 2 (20 and 40 l/h) were studied simulating a potential CO 2 leakage from early CSS sites. Water content and pH levels were measured by continuous monitoring systems. There were no clear patterns in the abundance of amoebae, ciliates, or flagellates in response to the injection of CO 2 . The analysis used to evaluate the community structure of ciliates, such as Equitability, Margalef index, or the Colpodea to Polyhymenophorea ratio showed significant differences with increases in CO 2 . The results of this study indicate that controlled increments of CO 2 in the soil influence the composition of the ciliate community, but have no effect on their total abundance. This paper supports the use of ciliates as promising biological indicators of CO 2 effects in Carbon Capture and Storage operations. [ABSTRACT FROM AUTHOR]

• Established a non-equilibrium phase transition CFD decompression model considering real gas behavior in ANSYS Fluent. • The effects of initial flow velocity on transient behavior of gas-liquid equilibrium CO 2 decompression in upstream pipeline is studied. • The effect of phase slip on the CO 2 decompression characteristics of the upstream pipeline with initial flow velocity is studied. • The CO 2 decompression characteristics in the upstream and downstream pipes of the rupture plane and the corresponding flow fields in the under-expansion area outside the pipe are compared. During the transportation of high-pressure liquefied CO 2 , the CO 2 may be in a gas-liquid equilibrium state (GLE) in the pipeline due to the harsh environment or the sudden opening and closing of the source valve. Research on the transient decompression characteristics of CO 2 under various conditions is helpful to improve the prediction accuracy of pipeline cracks and the establishment of far-field models of CO 2 leakage to improve accurate boundary conditions. In this paper, a nonequilibrium liquid-gas phase transition decompression model is established, and the Span-Wagner equation of state (S-W EoS) and Lee model are embedded to accurately predict the thermophysical properties of CO 2. Then, the simulation results obtained by the decompression model established in this paper are compared with the experimental data and the prediction results of decompression models used by other scholars for verification. The results showed that the predicted results were in good agreement with the experimental data. Finally, the effects of the initial flow velocity and phase slip on CO 2 decompression characteristics are studied. The phase slip has a minor effect on the CO 2 transient behaviours, but the initial flow velocity has significant effects on the CO 2 decompression characteristics inside and outside the pipeline. In addition, it was found that the decompression wave speed in downstream pipeline was relatively faster, and the pressure plateau value was lower. [ABSTRACT FROM AUTHOR]

• Quest CCS facility has been operating since 2015 and has stored upwards of 6 million tonnes of CO2 permanently. • A comprehensive MMV plan is in place to monitor data conformance to model and containment. • 5 key seismic campaigns have occurred during the project and operate phase of the facility with 3 of these campaigns acquiring time-lapse datasets. • Optical Fiber cemented in place has been an effective technology to allow for more data collection at lower cost, lower exposure and higher data repeatability. • Processing enhancements have increased data quality. • Advancements in imaging and interpretation techniques are leading to better understanding of time-lapse seismic utility at quest. • DAS VSP life expectancy is likely coming to an end at quest as the plume grows. Surface seismic is now under assessment. • This paper provides an overview of time-lapse campaigns at quest with the purpose of covering many aspects of the monitoring strategy, data collection and improvements. In August 2015, CO 2 injection commenced at the Quest Carbon Capture and Storage (CCS) Facility located near Fort Saskatchewan, Alberta, Canada. Quest is a fully integrated CCS operation with a capture target of just over one million metric tonnes of CO 2 per year. CO 2 is injected into a deep saline aquifer, the Basal Cambrian Sandstone (BCS), at a depth of about two kilometers below ground. In order to demonstrate containment and conformance of the injected CO 2 , a Measurement, Monitoring and Verification (MMV) plan has been implemented. Multiple domains are monitored as part of the plan, including the atmosphere, biosphere, hydrosphere, geosphere, and wells. Time-lapse seismic methods are utilized primarily for conformance monitoring and secondarily for containment monitoring of the CO 2 plume within the Geosphere domain. These methods currently include 3D surface seismic (SEIS3D), 2D surface seismic (SEIS2D) and 2D multi-azimuth walk-away borehole vertical seismic profiles with distributed acoustic sensing (VSP2D). The first goal of this paper is to summarize the role of seismic, subsurface modeling efforts and the different baseline and monitor datasets that have been acquired at the Quest CCS Facility. The second goal is to describe the current Quest time-lapse strategy. Five key seismic acquisition campaigns have occurred at Quest through the pre- and post-start of injection periods, including an initial SEIS3D acquisition, a pre-injection baseline VSP2D acquisition, and three monitor VSP2D acquisitions. SEIS2D acquisitions have also been acquired as part of two of the most recent monitor campaigns. All campaigns have occurred over the winter season, to facilitate surface access, minimize impact on the land and farming/harvest activities, and to ensure maximum repeatability. Time-lapse seismic methods yield an image of the CO 2 that is injected into the BCS pore space, displacing some of the brine in the saline aquifer. Since the injected CO 2 is more compressible and less dense than brine, the velocity of seismic primary-waves traveling through the BCS is reduced in those places containing CO 2 and remain unchanged elsewhere. Petrophysical data from the injection wells (IWs) were used to calculate the acoustic properties of the BCS. Gassmann fluid substitution was used to model the effect of CO 2 saturation on the expected seismic response. Modeling showed that differences in the seismic images of the BCS obtained before and during CO 2 injection should be seen in two characteristics ways: 1) Travel-times across the BCS increase due to the slower primary-wave velocity inside the BCS. 2) Reflections from the base of the BCS become stronger as the impedance contrast with the underlying granite basement increases. The contrast between the BCS and underlying basement is much larger than between the BCS and the overlying sediments. The large contrast between the BCS and basement produces a prominent reflection which is easily mapped during baseline and monitor surveys and is more practical for amplitude extractions. Modeling also indicated that, while the acoustic changes are sufficient to define the CO 2 front qualitatively, it is unlikely that they can be used to quantify the distribution of CO 2 saturations within the plume. The initial time-lapse seismic strategy called for SEIS3D to be employed after a few years of injection. Borehole distributed acoustic sensing (DAS) VSPs were proposed as a cost-effective and flexible alternative to SEIS3D while injection volumes are small. With the optical fiber cemented in place behind the casing, data can be acquired at any time without suspending injection, something not achievable with conventional VSPs that use retrievable downhole geophone arrays. The effectiveness of VSPs is inherently dependent upon the injection volume, plume offset from the IWs and acquisition geometry. After evaluating the concentric plumes predicted from dynamic modeling results and considering the acquisition logistics at the Quest CCS well sites, a VSP2D program was executed. In 2017 and 2019, SEIS2D was recorded in addition to the VSP2D surveys. Surface geophones were deployed along the VSP2D shot locations, recording a pseudo-3D or cross-spread survey. SEIS2D will be evaluated as another seismic method to potentially monitor CO 2 plume development in the BCS. [ABSTRACT FROM AUTHOR]

This paper continues the investigation of a 37.6 wt% piperazine solution (7 molal) in a PCC-test facility on the power plant in Dürnrohr, Austria. The use of real power plant flue gas and the well-conceived dimensions of the test facility enable industry-related conditions for full scale applications. A minimum specific energy for solvent regeneration of 3.17 GJ/ t CO 2 was determined in Part I of this paper. The optimal solvent flow rate is 20% lower in comparison to that of 30 wt% MEA. Part II tries to reduce the energy consumption further by carrying out a detailed parameter study. Especially at high flue gas flow rates, piperazine shows a good performance because of its fast kinetics. If the maximum achievable flue gas flow rate of 120 m 3 /h (F-factor ∼2 Pa 0.5 ) is set, the specific energy for solvent regeneration drops to 3 GJ/ t CO 2 . The fast kinetics has also a positive effect by reduction of the absorber height. Halving the absorber height still allows a performance similar to that of 30 wt% MEA. Due to the high thermal stability, piperazine enables an operation with high desorber pressures. Higher desorber pressures, resulting in a lower CO 2 compression work. In addition, the regeneration energy can be further reduced. An energy saving can also be achieved by the temperature reduction of the incoming flue gas. By operation with flue gases of a natural gas-fired boiler, the minimal energy consumption rises to 3.6 GJ/ t CO 2 . The optimal solvent flow rate decreases as with 30 wt% MEA. An emission measurement shows a direct correlation between NH 3 concentration of the treated flue gas and the solvent flow rate. Because of low water circulation in the water washing section, the NH 3 emissions in the treated flue gas increase at high solvent flow rates. [ABSTRACT FROM AUTHOR]

The potential for implementing carbon capture in Nordic industry sectors such as iron and steel production, cement and lime production, onshore and offshore oil and gas activities and pulp and paper production has been addressed. In Norway, much of the CO 2 is emitted from the oil and gas sector. In Denmark the power and heat production comprises the largest share while in Sweden and Finland biomass based industry such as power and heat production in CHP plants and pulp and paper production generates most of the CO 2 emissions. Iceland emits most CO 2 from metal industry, in particular non-ferrous metal production. In a Nordic perspective, the oil and gas industry has a high potential for implementation of CCS along with iron and steel production and cement production. Only cement production and pulp and paper production industries seem to have potential to decrease the CO 2 emissions close to zero. Capturing biogenic CO 2 from pulp and paper production could remove CO 2 from the atmosphere and create a carbon sink. Clustering of emission sources and implementing a joint CCS (Carbon Capture and Storage) chain could possibly lower the CCS unit costs. Process alterations and industry specific solutions due to the implementation of CCS in industry could improve existing processes. However, the possibility for carbon leakage could decrease the competitiveness of Nordic industries significantly as long as there is no global agreement on reduction of CO 2 emissions. [ABSTRACT FROM AUTHOR]

Large-scale CCS projects with multiple CO 2 sources will require large investments. Optimising the pipeline network design for cost reduction has been proposed as a potential way to reduce overall CCS costs. This paper presents a two-step methodology for the optimal design of on-shore pipelines with a projected increase in CO 2 flow rate. The first step involves determining whether an oversized design is preferable over a duplicate pipeline design, on the basis of the levelised CO 2 transport cost. This is performed through a simple correlation that depends on key parameters including the length of the pipeline, the timing and magnitude of the flow increase. If the oversized design is preferred, the second step of the proposed method determines the optimal diameter for the oversized pipeline. The approach, based on modelling of a wide range of generic cases, provides a two-step method to quickly verify whether an oversized pipeline is necessary, to assess the costs of using an oversized design against those of building duplicate pipelines, and to identify the pipeline design that minimises levelised cost of CO 2 transport. A sensitivity analysis shows that the correlations are applicable for a wide-range of values for flow rate, transport distance, discount rate, steel price, booster pump and electricity costs. In addition, the correlations for pipeline cost and optimal diameter developed in this paper can be integrated into and accelerate the existing large scale, staged CO 2 pipeline network optimisation models. [ABSTRACT FROM AUTHOR]

This paper continues the illustration of the methodology and the functionality of the CCS value chain tool developed within the BIGCCS Research Centre through the use of two new transport assessment modules for offshore pipeline and shipping to an offshore site. Technical, costs, and climate impact characteristics of each transport infrastructure are assessed and used to benchmark offshore pipeline and CO2 shipping to an offshore site transports in a base case for a range of distances and capacities. As expected, the base case illustrates that short distances and large capacities favour pipeline transport while ship transport is favoured by long distances and small capacities. The results show that the distance effect is stronger in the case of transport to an offshore site than in the case of transport between harbours, due to both higher pipeline investment costs and the pipeline pressure drop limitation for offshore. The base case is used to draw conclusions regarding specific case studies under the hypotheses described in this paper. Our methodology also appears to lead to results consistent with cases available in the literature when the same cost hypotheses are taken into consideration. Sensitivity analyses are used to quantify the impact of several important parameters and show that the four most influential parameters regarding the transport technology selection are: (1) the geographical context through the distance ratio, (2) the regional effect of pipeline costs and uncertainties in pipeline investment costs through the pipeline investment costs, (3) the project ownership effect through the discount rate, and (4) the First Of A Kind effect and uncertainties on investments through the overall investment costs. The CO2 avoided transport costs of the two transport technologies are illustrated in order to emphasise the importance of selecting the most efficient transport technology. The evaluation of costs underlines the fact that knowing the actual costs and limiting uncertainties is very important for the selection of the cost-optimal technology, to avoid cost overruns, and limit financial risks. The cost evaluation is also used to demonstrate the impact of limiting transport cost on the conditions in which CO2 transport is economically viable. The results demonstrate that the stronger the cost constraint, the more "long" distances and "small" capacities should be ruled out. The methodology and results are also used to illustrate how constraint on initial investment, in order to limit financial exposure, is to the disadvantage of pipeline transport due to the large investments required for transport via pipeline. [ABSTRACT FROM AUTHOR]

• The dissolved inorganic carbon can indicate the migration of supercritical carbon dioxide. • The dissolution pattern of chlorite is related to the content of dissolved inorganic carbon. • The contour maps of carbon dioxide are proposed to quantitatively evaluate its migration. • Three-stage of the evolution of calcium represent the three types of carbon sequestration minerals. A monitoring method that uses the variation in water chemical characteristics of the deep storage layer was studied by a three-dimensional numerical model under the background of a CO 2 -enhanced water recovery (CO 2 -EWR) site in the Junggar Basin. The effect of water chemical characteristics on the migration of CO 2 in different phases and the transformations of major sequestered carbon minerals were determined from the resulting mechanism. The results show that the evolution of water chemical characteristics, such as pH, Ca2+ and dissolved inorganic carbon (DIC), can effectively indicate the migration distance and time of dissolved CO 2 and supercritical CO 2. The times corresponding to the turning points of the pH and DIC change curves at the monitoring points can plot the isochronal maps of dissolved and supercritical CO 2 migration, which can be used to quantitatively evaluate CO 2 migration in the reservoir. The changes of DIC and Ca2+ can be used to infer the main carbon sequestration minerals: at the rapidly falling stage of Ca2+ concentrate over time and the low concentrate of DIC, the main carbon sequestration mineral is calcite, and in other conditions is ankerite. Water chemical characteristics can identify the extent of injected CO 2 impact in the corresponding region. This paper provides an alternative method for monitoring CO 2 migration and conversion in different phases and determining the extent of injected CO 2 impact in a region by the type of sequestered carbon minerals. [ABSTRACT FROM AUTHOR]

• Design study of a 10,000 tons/a CO 2 power-to-lower olefin plant in a cement factory. • Comparison of lower olefin production via FT syncrude and methanol as intermediates. • Technical evaluation of the defined process routes via process-related KPIs. • Calculation of the net production cost of lower olefins. This paper describes the simulation and techno-economic evaluation of a carbon dioxide capture and utilization unit integrated in a cement plant with a capacity of 10,000 tons of CO 2 per year. The aim is to utilize CO 2 along with hydrogen to produce lower olefins (C 2 –C 4), the feedstock for polyolefin production. In a first step, three process routes, namely a Fischer–Tropsch synthesis with steam cracker, a methanol synthesis with rWGS syngas production and a methanol synthesis with direct hydrogenation of CO 2 , latter two followed by a methanol-to-propylene unit, are simulated in ASPEN Plus V12.1®. Furthermore, the effect of a high- and a low-temperature electrolysis on key performance indicators are also considered in the evaluation. Additionally, an estimation of investment, operating and specific net production costs (NPC PR) of the different process routes is made. The evaluation is based on the comparison of calculated global efficiencies, specific energy consumption (SEC), NPC Pr and yields of the lower olefine products (C 2 –C 4). The power-to-lower olefin plant, consisting of an amine scrubber unit, a PEM electrolysis and a Fischer–Tropsch synthesis with downstream steam cracker proves to be the most efficient process route for polyolefin production, resulting in a global efficiency of 38.2 %, an SEC of 34.4 kWh/kg and an NPC Pr of 14.92 EUR/kg of lower olefine product. [ABSTRACT FROM AUTHOR]

• CO 2 seal experiments were conducted under super/trans-critical conditions. • Traditional theoretical models of seal were collected, derived and examined. • Temperature and specific heat ratio can result in large errors in calculation. • 3 models were recommended for CO 2 seal under super/trans-critical conditions. In the supercritical CO 2 Brayton cycle, dynamic sealing of rotating machines is one of the critical technologies. Under drastic variations of physical properties, the flow characteristics, sensitivity of parameters to leakage, and feasibility of theoretical models are not well understood. Experimental parameters of labyrinth seals include upstream parameters (302.15 K to 379.15 K, 7 MPa to 14 MPa) and pressure ratios (1.05 to 1.60, below the critical flow) covering trans-critical and pseudo-critical conditions. A comparison between experiments and traditional models leads to the following conclusions: In terms of linear correlation with the leakage, the upstream parameters in the density form are significantly superior to those in the temperature form. For the expansion factor part, the isentropic form can lead to errors ranging from -25% to 45%. In model prediction, the use of both temperature-based and isentropic-based parameters can result in significant prediction errors ranging from -41% to 67%. This paper recommends Martin's model with the density-based upstream parameters, the iterative isentropic model, and the Childs model, each with an error of ±10% or less. [ABSTRACT FROM AUTHOR]

• CCS injection well metallurgy and corrosion. • Impurities in the CO 2 are most important. • The chloride content and temperature of the reservoir must be considered. Carbon capture and sequestration (CCS) and carbon capture utilization and storage (CCUS) projects continue to develop as an effective method to reduce anthropogenic CO 2 emissions. Injection wells for these projects are often required to retain integrity over long operational lives, sometimes 50 years or longer. When it is determined from process conditions that free water may or will be present, either condensing from the CO 2 injectate itself or due to injection into a water-bearing formation, the need for a corrosion resistant alloy (CRA) is required to ensure sufficiently long service life. For well designers and operators, there is a growing need for comprehensive guidelines for the selection of suitable corrosion resistant alloys (CRAs). This paper summarizes important parameters developed through the Plains CO 2 Reduction (PCOR) Partnership that need to be considered for general materials selection for use within CO 2 injection wells based on available data. [ABSTRACT FROM AUTHOR]

• Existing oil and gas pipeline third-party external interference failure frequency models have been reviewed to assess whether they could be applied to dense phase CO 2 pipelines. • It was found that the high design pressure requirement for a dense phase CO 2 pipeline typically necessitates the use of high wall thickness linepipe in pipeline construction. • The research indicates that wall thickness of typical dense phase CO 2 pipelines is beyond the known range of applicability for the pipeline failure equations used within existing failure frequency models. • There is a limitation to existing UK fault databases with regards to their application to CO 2 pipelines because there are currently no dense phase CO 2 pipelines operating in the UK. • Further work needs to be conducted to confirm the most appropriate approach for calculating failure frequency for dense phase CO 2 pipelines. • It is recommended that a new failure frequency model suitable for dense phase CO 2 pipelines is developed that can be readily updated to the fault database version In Carbon Capture, Usage and Storage (CCUS) schemes, Carbon Dioxide (CO 2) is captured from large scale industrial emitters and transported to geological sites for storage. The most efficient method for the transportation of CO 2 is via pipeline in the dense phase. CO 2 is a hazardous substance which, in the unlikely event of an accidental release, could cause people harm. To correspond with United Kingdom (UK) safety legislation, the design and construction of proposed CO 2 pipelines requires compliance with recognised pipeline codes. The UK code PD-8010-1 defines the separation distance between a hazardous pipeline and a nearby population as the minimum distance to occupied buildings using a substance factor. The value of the substance factor should be supported by the results of a Quantitative Risk Assessment (QRA) approach to ensure the safe design, construction and operation of a dense phase CO 2 pipeline. Failure frequency models are a major part of this QRA approach and the focus of this paper is a review of existing oil and gas pipeline third-party external interference failure frequency models to assess whether they could be applied to dense phase CO 2 pipelines. It was found that the high design pressure requirement for a dense phase CO 2 pipeline typically necessitates the use of high wall thickness linepipe in pipeline construction; and that the wall thickness of typical dense phase CO 2 pipelines is beyond the known range of applicability for the pipeline failure equations used within existing failure frequency models. Furthermore, even though third party external interference failure frequency is not sensitive to the product that a pipeline transports, there is however a limitation to the application of existing UK fault databases with to onshore CO 2 pipelines as there are currently no dense phase CO 2 pipelines operating in the UK. Further work needs to be conducted to confirm the most appropriate approach for calculating failure frequency for dense phase CO 2 pipelines, and it is recommended that a new failure frequency model suitable for dense phase CO 2 pipelines is developed that can be readily updated to the latest version of the fault database. [ABSTRACT FROM AUTHOR]

• Potassium taurate aqueous solution used for post-combustion CO 2 removal. • simulations performed in ASPEN Plus®, properly user customized. • detailed analyses of the performance of the system. • examination of the influence of the solid-liquid separator. • high level comparison with some key competitor solvent systems. One of the most mature technologies for removal of carbon dioxide from gaseous streams is chemical absorption. Among these, aqueous solutions of amino acids have been considered because of the advantages associated with their being precipitating solvents. This paper presents detailed analyses of the performance of the potassium taurate absorption system by means of a rigorous simulation in a commercial process software (ASPEN Plus®). The profiles of temperature, heat transfer, compositions, and molar flows of carbon dioxide and water have been examined. The operating line and the equilibrium curve for different lean loadings of the solvent are reported and show that the minimium reboiler duty occurs at a lean loading of 0.27. Examination of the influence of the solid-liquid separator on the reboiler duty shows that a recycle split fraction of 0.2 results in the lowest reboiler duty. Different minimum temperature approaches in the lean-rich cross heat exchanger have also been investigated. [ABSTRACT FROM AUTHOR]

• DTS allows real-time monitoring of subsurface conditions • DTS and warmback analysis can show presence of fluids in formations • Warmback analysis can be useful to detect fluid migration along vertical wellbore • Arrival of CO2 plume can be detected by DTS at monitoring well A Distributed Temperature Sensing (DTS) system, along with a five-level, behind-casing pressure sensing array was installed as part of the Midwest Regional Carbon Sequestration Partnership (MRCSP) large-scale carbon dioxide (CO 2) storage test in a depleted Niagaran pinnacle reef oil reservoir in Northern Michigan. The reef is being monitored during its initial reservoir fill-up period as CO 2 is being injected to raise the reservoir pressure for enhanced oil recovery (EOR). DTS data are analyzed with results from the initial injection of ˜101,000 metric tons of CO 2 , injected between January 2017 and December 2018. This paper discusses the results of real-time DTS combined with multi-level pressure monitoring. The collection, processing, and interpretation of large amounts of data from fiber-optic-based DTS provides an opportunity to obtain high-resolution information on migration of CO 2 in the reservoir. [ABSTRACT FROM AUTHOR]

Highlights • Seismic data collected at Cranfield, MS CO 2 -EOR project with three different interpretations is presented. • Results obtained from these 3 different methods are mapped and compared among each other. • A fluid flow numerical simulation study carried out and saturation profiles obtained from simulations were compared to seismic data interpretations. • Selection of 3D seismic interpretation methods has large impact on the final results. Distribution of fluids (oil, gas, water) has an important role and can be very useful in integrated studies. Abstract This paper discusses strengths and weaknesses of 4D seismic interpretation as a technique for monitoring carbon dioxide that was injected as part of a large scale test associated with commercial enhanced oil recovery (EOR) at Cranfield Field, Mississippi, USA. The goals of the monitoring effort are 1) to make measurements to verify that the CO 2 is contained in the reservoir according to operational designs and model predictions, and 2) that if there are deviations, to provide data which can be used to update the earth models and determine if any mitigation is needed. The current work uses a compositional numerical simulation to model CO 2 flow in the reservoir and compares the results with estimates of changes in seismic properties between a pre-injection and a survey after more than 2 million metric tons injected. The complicated physics of the problem in Cranfield field present challenges to seismic interpretations. Our results show partial agreement between the results of the numerical simulation and the seismic interpretations. Possible causes of discrepancies among the fluid flow model and multiple interpretations of the same seismic data sets performed with different work flows illuminates the types of uncertainties that should be considered to achieve the goals of monitoring. [ABSTRACT FROM AUTHOR]

Abstract: Carbon dioxide (CO2) injection into saline aquifers is one of the promising options to sequester large amounts of CO2 in geological formations. During as well as after injection of CO2 into an aquifer, CO2 migrates towards the top of the formation due to density differences between the formation brine and the injected CO2. The time scales of CO2 migration towards the top of an aquifer and the fraction of CO2 that is trapped as residual gas depends strongly on the driving forces that are acting on the injected CO2. When CO2 migrates to the top of an aquifer, brine may be displaced downwards in a counter-current flow setting particularly during the injection period. A majority of the published work on counter-current flow settings have reported significant reductions in the associated relative permeability functions as compared to co-current measurements. However, this phenomenon has not yet been considered in the simulation of CO2 storage into saline aquifers. In this paper we study the impact of changes in mobility for the two-phase brine/CO2 system as a result of transitions between co- and counter-current flow settings. We have included this effect in a simulator and studied the impact of the related mobility reduction on the saturation distribution and residual saturation of CO2 in aquifers over relevant time scales. We demonstrate that the reduction in relative permeability in the vertical direction changes the plume migration pattern and has an impact on the amount of gas that is trapped as a function of time. This is to our best knowledge the first attempt to integrate counter-current relative permeability into the simulation of injection and subsequent migration of CO2 in aquifers. The results and analysis presented in this paper are directly relevant to all ongoing activities related to the design of large-scale CO2 storage in saline aquifers. [Copyright &y& Elsevier]

Highlights • Neglection of the capillary pressure hysteresis in the simulation may result in a large overestimation of the amount of trapped CO 2. • If the imbibition capillary pressure tends towards zero, only effective seals are able to trap free and potentially mobile CO 2. • If the imbibition capillary curve includes a threshold pressure, mobile CO 2 is trapped below low-permeable layers at above-endpoint values. • The maximum attained drainage saturation and thus the residual gas saturation in a given region is reduced when a tighter region is located upstream • Using the maximum residual CO 2 saturation to estimate CO 2 storage capacity may lead to a large overestimation of the residual CO 2. Abstract This paper presents a simulation study on the influence of rock heterogeneity on the distribution and magnitude of trapped CO 2 resulting from a drainage/imbibition sequence in a saline aquifer with buoyant CO 2. Four scenarios are studied, three simple 1D cases and a 2D case with heterogeneity derived from realistic architecture inspired by tidal sand deposits, having combined layering and crossbedding and sediment property contrasts. The four cases are examined in order to understand which underlying mechanisms are responsible for the results observed and therefore also which processes it is necessary to reflect in the simulation procedure. It is shown that it is important to take into account hysteresis in the capillary pressure. During the imbibition the capillary pressure decreases and the ability to capillary trap the CO 2 is reduced and it may in some cases completely vanish. Thus, the capillary pressure hysteresis has a major impact on the amount of trapped CO 2. If the imbibition curve has a threshold pressure the sealing power of the barrier is not completely lost, which leads to hyper-trapping, characterised by mobile CO 2 being trapped with above end-point saturations. If the imbibition capillary pressure reaches zero, only local barriers constituting effective seals are able to trap free and potentially mobile CO 2 and the trapping mechanism is exactly the same as the one acting beneath the top seal. The neglection of capillary pressure hysteresis may result in a large overestimation of the amount of trapped CO 2. [ABSTRACT FROM AUTHOR]

Abstract: Large-scale, dedicated commercial biomass energy systems are a potentially large contributor to meeting global climate policy targets by the end of the century. We use an integrated assessment model of energy and agriculture systems to show that, given a climate policy in which terrestrial carbon is appropriately valued equally with carbon emitted from the energy system, biomass energy has the potential to be a major component of achieving these low concentration targets. A key aspect of the research presented here is that the costs of processing and transporting biomass energy at much larger scales than current experience are explicitly incorporated into the modeling. From the scenario results, 120–160EJ/year of biomass energy is produced globally by midcentury and 200–250EJ/year by the end of this century. In the first half of the century, much of this biomass is from agricultural and forest residues, but after 2050 dedicated cellulosic biomass crops become the majority source, along with growing utilization of waste-to-energy. The ability to draw on a diverse set of biomass-based feedstocks helps to reduce the pressure for drastic large-scale changes in land use and the attendant environmental, ecological, and economic consequences those changes would unleash. In terms of the conversion of bioenergy feedstocks into value added energy, this paper demonstrates that biomass is and will continue to be used to generate electricity as well as liquid transportation fuels. A particular focus of this paper is to show how climate policies and technology assumptions – especially the availability of carbon dioxide capture and storage (CCS) technologies – affect the decisions made about where the biomass is used in the energy system. The potential for net-negative electric sector emissions through the use of CCS with biomass feedstocks provides an attractive part of the solution for meeting stringent emissions constraints; we find that at carbon prices above $150/tCO2, over 90% of biomass in the energy system is used in combination with CCS. Despite the higher technology costs of CCS, it is a very important tool in controlling the cost of meeting a target, offsetting the venting of CO2 from sectors of the energy system that may be more expensive to mitigate, such as oil use in transportation. CCS is also used heavily with other fuels such as coal and natural gas, and by 2095 a total of 1530GtCO2 has been stored in deep geologic reservoirs. The paper also discusses the role of cellulosic ethanol and Fischer–Tropsch biomass derived transportation fuels as two representative conversion processes and shows that both technologies may be important contributors to liquid fuels production, with unique costs and emissions characteristics. [Copyright &y& Elsevier]

Abstract: This paper explores the integration and evaluation of a power plant with a CaO-based CO2 capture system. There is a great amount of recoverable heat in the CaO-based CO2 capture process. Five cases for the possible integration of a 600MW power plant with CaO-based CO2 capture process are considered in this paper. When the system is configured so that recovered heat is used to replace part of the boiler heat load (Case 2), modelling not only shows that this is the system recovering the most heat of 1008.8MW but also results in the system with the lowest net power output of 446MW and the second lowest of efficiency of 34.1%. It is indicated that system performance depends both on the amount of heat recovery and the type of heat utilization. When the system is configured so that a 400MW power plant is built using the recovered heat (Case 4), modelling shows that this is the system with the most net power output of 846MW, the highest efficiency of 36.8%, the lowest cost of electricity of 54.3€/MWh and the lowest cost of CO2 avoided of 28.9€/tCO2. This new built steam cycle will not affect the operation of the reference plant which vents its CO2 to the atmosphere, highly reducing the connection between the CO2 capture process and the reference plant which vents its CO2 to the atmosphere. The average cost of electricity and the cost of CO2 avoided of the five cases are about 58.9€/kWh and 35.9€/tCO2, respectively. [Copyright &y& Elsevier]

Abstract: Emissions from electricity generation will have to be reduced to near-zero to meet targets for reducing overall greenhouse gas emissions. Variable renewable energy sources such as wind will help to achieve this goal but they will have to be used in conjunction with other flexible power plants with low-CO2 emissions. A process which would be well suited to this role would be coal gasification hydrogen production with CCS, underground buffer storage of hydrogen and independent gas turbine power generation. The gasification hydrogen production and CO2 capture and storage equipment could operate at full load and only the power plants would need to operate flexibly and at low load, which would result in substantial practical and economic advantages. This paper analyses the performances and costs of such plants in scenarios with various amounts of wind generation, based on data for power demand and wind energy variability in the UK. In a scenario with 35% wind generation, overall emissions of CO2 could be reduced by 98–99%. The cost of abating CO2 emissions from the non-wind residual generation using the technique proposed in this paper would be less than 40% of the cost of using coal-fired power plants with integrated CCS. [Copyright &y& Elsevier]

Abstract: Alberta is the province with the largest CO2 emissions in Canada, with approximately two-thirds of emissions originating from large stationary sources. Due to the fortuitous association of large CO2 sources with the storage capacity offered by the underlying Alberta basin, it is expected that large-scale CO2 geological storage in Canada will occur in Alberta first, and both levels of governments are contemplating measures to facilitate implementation. A review of the current provincial and federal legislation and regulations presented in this paper indicates that the existing legal and regulatory regime is reasonably sufficient, with some modifications, to accommodate the active injection phase of CO2 capture and storage (CCS) operations, and the early takers of this new technology. However, governments in Alberta and Canada, and likely everywhere, need to address several pressing issues dealing mainly with the CCS post-operational phase. These issues, reviewed in this paper from an Alberta and Canadian perspective, fall into several categories: jurisdictional, property (ownership), regulatory and liability. Because Alberta is a landlocked province, matters relating to CO2 storage under the seabed will not be addressed here except when discussing matters of jurisdiction and CO2 classification. Possible models for post-injection liability transfer to the state are also presented. Although this review is focused on western Canada conditions, the issues are broad enough to be of interest in other jurisdictions, which may also adopt parts of the legal and regulatory framework that is quite well developed in Alberta. [Copyright &y& Elsevier]

Abstract: Carbon dioxide capture and storage (CCS) involves the capture of CO2 at a large industrial facility, such as a power plant, and its transport to a geological (or other) storage site where CO2 is sequestered. Previous work has identified pipeline transport of liquid CO2 as the most economical method of transport for large volumes of CO2. However, there is little published work on the economics of CO2 pipeline transport. The objective of this paper is to estimate total cost and the cost per tonne of transporting varying amounts of CO2 over a range of distances for different regions of the continental United States. An engineering-economic model of pipeline CO2 transport is developed for this purpose. The model incorporates a probabilistic analysis capability that can be used to quantify the sensitivity of transport cost to variability and uncertainty in the model input parameters. The results of a case study show a pipeline cost of US$ 1.16 per tonne of CO2 transported for a 100km pipeline constructed in the Midwest handling 5 million tonnes of CO2 per year (the approximate output of an 800MW coal-fired power plant with carbon capture). For the same set of assumptions, the cost of transport is US$ 0.39 per tonne lower in the Central US and US$ 0.20 per tonne higher in the Northeast US. Costs are sensitive to the design capacity of the pipeline and the pipeline length. For example, decreasing the design capacity of the Midwest US pipeline to 2 million tonnes per year increases the cost to US$ 2.23 per tonne of CO2 for a 100km pipeline, and US$ 4.06 per tonne CO2 for a 200km pipeline. An illustrative probabilistic analysis assigns uncertainty distributions to the pipeline capacity factor, pipeline inlet pressure, capital recovery factor, annual O&M cost, and escalation factors for capital cost components. The result indicates a 90% probability that the cost per tonne of CO2 is between US$ 1.03 and US$ 2.63 per tonne of CO2 transported in the Midwest US. In this case, the transport cost is shown to be most sensitive to the pipeline capacity factor and the capital recovery factor. The analytical model elaborated in this paper can be used to estimate pipeline costs for a broad range of potential CCS projects. It can also be used in conjunction with models producing more detailed estimates for specific projects, which requires substantially more information on site-specific factors affecting pipeline routing. [Copyright &y& Elsevier]

• This paper discusses major technical challenges of using brine extraction to manage CO 2 storage. • Keywords discussed include: CO 2 storage; brine extraction; pressure management; plume location; brine handling. Developing and deploying commercial-scale carbon dioxide (CO 2) storage at a site requires operational strategies to manage pressure and CO 2 plume distribution. In the natural gas storage and oil and gas industries, fluid extraction has been successfully implemented as a strategy to manage pressure and control fluid distribution (i.e., hydrocarbon recovery and natural gas storage efficiency, respectively). The technical challenges of integrating brine extraction at CO 2 storage sites are expected to be similar, if not identical, to those in the natural gas storage and petroleum industries. Major technical challenges of using brine extraction to manage storage in a storage unit include (1) designing and completing the brine extraction wells, (2) locating the brine extraction well, (3) assessing the efficacy of brine extraction, and (4) handling the extracted brine. The design and completion of the brine extraction well include the well type (i.e., vertical or horizontal) and perforated interval. The location of the well is influenced by the timing of extraction operations (i.e., prior or after CO 2 injection starts) and project objectives (i.e., desired directional movement of the CO 2 plume and avoid or minimize CO 2 extraction). The efficacy of brine extraction requires a baseline projection of the pressure and CO 2 plume distribution. Options for handling extracted brine include subsurface disposal, surface disposal, and industrial use. This paper addresses means of overcoming technical challenges that may likely be encountered before or after CO 2 injection starts. [ABSTRACT FROM AUTHOR]

[Display omitted] • The paper discusses research progress and future directions on solvent development for post-combustion carbon capture processes 2015-2020. • The paper reviews research related to solvent chemistry, including solubility, reaction kinetics, magnetic resonance for ion specification. • The paper presents studies on development of catalyst, enhancement of current solvents with the aid of catalysts, and alternative solvents. • The paper discusses research on the electrochemically mediated amine regeneration process and applications of AI to carbon capture processes. The research conducted in the last five years can potentially paint a picture of the next generation's research related to solvent development for post-combustion carbon dioxide capture. This paper presents a comprehensive summary of the research work in this field conducted in the period from 2015 to 2020. The work includes research efforts in the areas of: (i) solvent chemistry, which refers to the work conducted on solubility, reaction kinetics, nuclear magnetic resonance or NMR analysis for ion speciation, and alternative solvents, (ii) development of amine solvents, which includes development of catalyst and enhancement of current solvents with the aid of catalysts, (iii) a novel regeneration process called Electrochemically Mediated Amine Regeneration, and (iv) applications of artificial intelligence technologies to the carbon dioxide capture process. The paper can be considered an update discussion and summary of the research work conducted in diverse areas related to solvent development for post-combustion carbon dioxide capture since our review of the research area published in 2015. [ABSTRACT FROM AUTHOR]

• Application of three approaches for analyzing transient pressure and rate data from CCUS projects in depleted reef reservoirs in Michigan, USA. • Methods are: injection-falloff, injectivity/productivity index, and pressure pulse arrival time analysis. • All three methods widely used in oil industry; but latter two hitherto not used for CCS projects. • Theory behind each technique presented and its applicability demonstrated via illustrative examples from multiple wells in different reefs. • Discussion of the relative merits of each interpretive technique, as well as recommendations that could be useful for other field projects. Pressure and rate data are commonly recorded as part of a basic monitoring program in CCS projects. This paper discusses the application of multiple analytical techniques to interpret pressure and rate transient data from CO 2 injection and storage operations. The techniques of interest, i.e., injection-falloff analysis, injectivity/productivity index analysis and pressure pulse arrival time analysis, are commonly used in the oil and gas industry to assess reservoir properties, but not well known in the CCS literature (especially the last two). Injection-falloff analysis involves log-log pressure derivative plotting for the falloff data and history-matching of the entire injection-falloff sequence to determine permeability. In the injectivity/productivity index analysis, rate-normalized pressure buildup is plotted against material balance time or ratio of cumulative injection to injection rate to determine the injectivity index (ratio of injection rate to stabilized pressure buildup) which can be related to the permeability-thickness product. The arrival time analysis identifies the arrival of a pressure disturbance (∼0.1 psi change from ambient) to determine the hydraulic diffusivity from which permeability can be estimated. The applicability of these techniques is demonstrated via illustrative examples from multiple wells in different pinnacle carbonate reefs undergoing CO 2 -EOR in Northern Michigan. The paper ends with a discussion of the relative merits of each interpretive technique, as well as recommendations that could be useful for other field projects. [ABSTRACT FROM AUTHOR]

• This paper revisits the Communication and Engagement Toolkit for CCS projects proposed by Ashworth and colleagues. • The limitations of the strategic component of the toolkit are examined. • An improved method based on artificial intelligence (AI) is proposed and tested. This paper revisits the Communication and Engagement Toolkit for CO 2 Capture and Storage (CCS) projects proposed by Ashworth and colleagues in collaboration with the Global CCS Institute. The paper proposes a new method for understanding the social context where CCS will be deployed based on the toolkit. In practice, the proposed method can be used to harness social data collected on the CCS project. The outcome of this application is a development of a predictive tool for gaining insight into the future, to guide strategic decisions that may enhance deployment. Methodologically, the proposed predictive tool is an artificial intelligence (AI) tool. It uses fuzzy deep neural network to develop computational ability to reason about the social behavior. The hybridization of fuzzy logic and deep neural network algorithms make the predictive tool an explainable AI system. It means that the prediction of the algorithm is interpretable using fuzzy logical rules. The practical feasibility of the proposed system has been demonstrated using an experimental sample of 198 volunteers. Their perceptions, emotions and sentiments were tested using a standard questionnaire from the literature, on a hypothetical CCS project based on 26 predictors. The generalizability of the algorithm to predict future reactions was tested on, 84 out-of-sample respondents. In the simulation experiment, we observed an approximately 90 % performance. This performance was measured when the algorithm's predictions were compared to the self- reported reactions of the out of sample subjects. The implication of the proposed tool to enhance the predictive power of the conventional CCS Communication and Engagement tool is discussed © 2020 xx. Hosting by Elsevier B.V. All rights reserved. [ABSTRACT FROM AUTHOR]

• Geological storage potential of CO 2 emissions for China's coal-fired power plants is estimated. • Daqing, Ordos and Bayin'gholin Mongol have the largest CO 2 storage capacity of enhanced water/oil/gas recovery respectively. • The mismatch of coal-fired power plants and CO 2 storage sites restrict the emission reduction potential of cities in China. • Ordos has the largest CO 2 emission reduction potential through CO 2 geological storage projects of coal-fired power plants. To mitigate global warming to temperatures no higher than 2 °C or even less than 1.5 °C, carbon capture and storage (CCS) is indispensable. This is especially true for China, which relies heavily on coal-fired power plants. In China, CCS could play an important role in removing CO 2 emissions from coal-fired power plants and establishing low-carbon cities. Clarifying the emissions reduction potential of cities using CO 2 geological storage will help to identify site suitable for carrying out CCS projects in a technically and economically feasible way. In this paper, we assessed CO 2 storage capacity in three geological structures between 800 to 3000 m underground: (1) the nationwide on-shore CO 2 storage capacity of 705 oil fields in terms of both depleted oil reservoirs (DOR) and enhanced oil recovery (EOR); (2) 754 gas fields in terms of both depleted gas reservoirs (DGR) and enhanced gas recovery (EGR); (3) China's deep saline aquifers (DSA), including 17 large basins ; and (4) the CO 2 emissions of coal-fired plants of 300 MW and over. After completing all of these assessments, this paper presents an emissions reduction potential estimate. The results show that: 1) the total CO 2 storage capacity of DOR, EOR, DGR, EGR and DSA is 21,287 Mt, 5191 Mt, 15,321 Mt, 9018 Mt and 1,004,319 Mt, respectively; 2) 76 cities can sequester their existing CO 2 emissions from coal-fired power plants in situ within their administrative boundaries for over 10 years, and their contribution is 634.43 Mt per year. 3) Ordos City has priority to carry out CO 2 geological storage for coal-fired power plants due to the volume of its annual captured CO 2 (52.13 Mt), and it can operate for about 123 years if its CO 2 emissions remain unchanged. [ABSTRACT FROM AUTHOR]