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Featured Application: This work suggests that horizontal injectors are a safe way to keep CO2 trapped in the storage site and reduce/prevent any unexpected event associated with leakage through the caprock since the horizontal well minimizes or avoids CO2 contact with the caprock. This study used numerical simulations of CO2 storage to identify the benefits of horizontal wells for geological carbon storage, such as enhancing CO2 trapped in porous media due to relative permeability and capillary hysteresis. Two injection schemes were tested: one using a vertical injector and the other employing a horizontal well. The results revealed two main findings. Firstly, the horizontal injection well effectively prevented or minimized CO2 penetration into the caprock across various sensitivity scenarios and over a thousand years of CO2 redistribution. Secondly, horizontal wells provided a safe approach to trapping CO2, increasing its entrapment as a residual phase by up to 19% within the storage site. This, in turn, reduced or prevented any unexpected events associated with CO2 leakage through the caprock. Additionally, the paper proposes a practical method for designing the optimal length of a horizontal well. This method considers a combination of two parameters: the additional CO2 that can be trapped using a horizontal well and the gravity number. In the case of the reservoir model of this study, a horizontal branch with a length of 2000 m was found to be the most effective design in enhancing CO2 entrapment and reducing CO2 buoyancy. [ABSTRACT FROM AUTHOR]

Several technical methods are currently discussed to meet the objectives of the United Nations Framework Convention on Climate Change 21st Conference of the Parties, Paris, France (Paris Agreement) in terms of carbon dioxide (CO2) concentration in the Earth's atmosphere. In addition to efficiency improvements, reduction of energy consumption, and the utilization of renewable energy sources, the application of carbon capture and storage (CCS) technologies seems to be unavoidable. Whereas all these measures aim on the reduction of CO2 that is being newly released, there is the approach to remove CO2 from the atmosphere that has already been emitted. This can be achieved by the utilization of bioenergy in CCS processes. Within this paper, the utilization of alternative fuels in two second-generation CCS processes is assessed. In this regard, chemical looping combustion (CLC) and calcium looping (CaL) are two promising technologies. Both processes have proven their feasibility already in semi-industrial scale. The assessment includes three different types of fuel namely coal, biomass, and solid recovered fuel (SRF). The analysis is twofold: first, a heat and mass balance calculation reveals the specific CO2 emissions of each power system; second, a cost analysis points out the feasibility from an economic point of view. The highest CO2 removal can be achieved by a biomass-fired CLC unit (− 696 gCO2/kWhe). Furthermore, it was found that the co-combustion of SRF even at moderate co-firing rates allows for noteworthy improved economics of the CCS system. Therefore, the utilization of waste-derived fuels in the context of CCS processes should be put more into focus in future research activities. [ABSTRACT FROM AUTHOR]

Abstract: Carbon dioxide capture and storage (CCS) is an effective technology to reduce carbon dioxide (CO2) emissions in China. In this paper, the authors considered storage opportunities offered by oil reservoirs and deep saline aquifers in the Jiyang Depression, in east China. Based on detailed geological analysis and assessment of CO2 storage suitability, the Dongying Sag and Linyi‐Shanghe areas of the Huimin Sag within the Jiyang Depression appear promising for CO2 storage. Following more detailed characterization, the second and third members of the Shahejie Formation located in these two areas appear the most promising for CO2 storage. Within the areas identified as having potential for storage, 55 primary and 62 secondary recommended storage units were defined, with a total theoretical capacity of 5.02 × 108 tonnes (t) CO2. This represents storage of CO2 emissions from large‐scale sources in the Jiyang Depression for more than 30 years at current emission rates. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

To ensure the safety of carbon dioxide (CO 2) geological storage, it is important to effectively monitor the pore pressure, reservoir deformation and fluid plume migration, which poses new challenges to monitoring techniques and tools. In this paper, an innovative monitoring method is presented based on distributed fiber optic strain sensing (DFOSS) to detect the strain response distribution induced by fluid injection in real time. The original strain field distribution in the reservoir rock and the effect of the effective stress on the strain response were obtained for different confining and pore pressure combinations. Then, the rock strain during displacement was measured to dynamically monitor the movement front of the wetting phase. The results showed that the core strain response curves under the influence of the confining and pore pressures exhibit significant edge effects, with lower strain values in the vicinity of the artificial confinement facility than in the reservoir. In addition, the overall strain response exhibited an increase corresponding to the increase in the confining pressure. A higher confining pressure was observed to mitigate the pore pressure expansion-related strain in the rock itself. This proves that the selection of a large-depth subsurface reservoir could help to increase the CO 2 injection pressure and rate, and the formation pressure threshold value identified in this study varied between 6 to8 MPa. Furthermore, the full-field strain history showed that fiber optic technology can be employed to accurately monitor the detailed characteristics of front movement and core deformation during wetting fluid displacement, including the history of the strain distribution due to two-phase motion and the change in the two-phase moving speed. The analysis results collectively validated the applicability of this monitoring technique for core-scale testing. The data and conclusions obtained could contribute to a deeper comprehension of the DFOSS reservoir monitoring capability. Furthermore, these findings hold relevance for subsequent experimental analyses, numerical simulations, and field applications at carbon capture and storage sites. • Distributed fiber optic strain sensing is utilized to observe the strain field and edge effect in a CO 2 storage reservoir. • High formation pressures are effective in reducing reservoir deformation during fluid injection. • The speed of front movement during fluid displacement could be monitored by distributed fiber optic strain sensing. [ABSTRACT FROM AUTHOR]

The planned pilot CO2 storage Zar-3 is an oil field with a gas cap in the final production stage in the SE Czech Republic. It is composed of a dolomite Jurassic reservoir sealed by three different formations that differ significantly in lithology. Previous studies left open questions on the nature of pore space and connectivity and the quality of the seal in the future CO2 storage complex. Microscopic petrography of the reservoir suggests dolomitisation in shallow water followed by karstification and brecciation with fracture-correct-dominated porosity. The seal horizons have porosity limited to the micro- and nanoscales. The oil consists of significantly biodegraded black oil of Jurassic origin mixed with less biodegraded gasoline-range hydrocarbons. Biomarkers in the caprock bitumens trapped in nanopores show a genetic relationship to the reservoir oil. Gas in the not yet fully depleted gas cap of the field is of thermogenic origin with no contribution of microbial methane. The formation water has total dissolved solids typical of isolated brines not diluted by infiltrated fresh water. The geochemical characteristics of the storage system together with the fact that the initial oil column is about 105 m tall with another 150 m of gas cap suggest that the seals are efficient and the Zar-3 future storage complex is tight and safe. [ABSTRACT FROM AUTHOR]

Shear wave velocity (Vs) has significant applications in geoengineering investigations. With the ongoing rise in carbon capture and storage (CCS) initiatives, the role of Vs in monitoring the CO2 sequestration sites is escalating. Although many studies have been conducted to assess CCS-induced risks, no inclusive research has been conducted integrating those investigations. This study strives to collate and integrate the applications of Vs in geoscience with an emphasis on CCS risk assessment. Based on this research, major CCS-induced risks were detected: induced seismicity, caprock failure, groundwater contamination, fault reactivation, and reservoir deformation. These risks were inclusively described, and the mathematical formulations incorporating the Vs parameter in risk analysis were elaborated. It was concluded that Vs applications can be further extended in monitoring CO2 plume migration, optimizing CO2 injection pressures, preventing shallow water contamination, and predicting CCS-induced seismic events. All these applications require fully coupled hydromechanical analysis based on poroelasticity theory. Hence, various factors including pore pressure, in situ stresses, faults distribution, and poroelastic parameters must be carefully determined before the CO2 injection phase. The mathematical formulations presented in the present study are quite applicable for granting the safety and long-term success of subsurface carbon sequestration. [ABSTRACT FROM AUTHOR]

This paper proposes a pressure-monitoring method to warn any possible CO leakage by monitoring pressure change at the upper layer of storage reservoirs within injection wells. The monitoring method is tested with two problems under various scenarios. With a current pressure detection limit, the proposed pressure-monitoring technique can be widely applicable wherever a permeable upper formation exists above the CO storage reservoir and is effective even in offshore storage sites wherever conventional monitoring methods for onshore sites cannot be applied. Meanwhile, the method is limited to apply during injection and is subject to any possible pressure dampening. [ABSTRACT FROM AUTHOR]

This study summarizes the OASIS (Overburden Analysis and Seal Integrity Study for CO 2 Sequestration in the North Sea) project that focuses on assessing the containment risks associated with the geological carbon sequestration (CCS) of the Northern Lights project. CCS is viewed as one of the most effective solutions for reducing carbon emissions, as it captures carbon dioxide from point sources and permanently stores it in suitable geological formations. However, injecting CO 2 into the subsurface may have mechanical consequences, including fault reactivation, top seal fracturing, surface heave, etc. This study proposes an interdisciplinary workflow to characterize the caprock, faults, and overburden associated with CCS projects in the Horda Platform area, to improve injection-induced containment risk assessment. Our findings show that the proposed workflows and tools effectively characterize stress-related mechanical hazards. However, due to the complex nature of rocks, it is challenging to evaluate the top seal integrity using a single method. Therefore, the proposed interdisciplinary approach is more effective for any fluid injection site's characterization, given the complex nature of the subsurface and its behavior under injection-induced stress changes. This research paper adds knowledge about the top seal integrity assessment and the reliability of injected CO 2 , making CCS projects more reliable and safer. Although this study focuses on the northern North Sea, the proposed methods are equally applicable globally to characterize subsurface CO 2 storage sites. Apart from CCS projects, these research results can benefit other subsurface injection projects, such as water injection for reservoir management, wastewater injection for disposal, hydrogen storage, and hydraulic fracturing for unconventional hydrocarbon resources. • Brittleness indices property can reflect the rock integrity. • Seismic inverted properties resolve the data limitation issues within the overburden intervals. • An analytical structural reliability model can help evaluate the top sealing risks quickly. • Overburden interval rock properties must be realistic in any 3D field-scale geological models. • An interdisciplinary workflow is required for subsurface CCS site characterization. [ABSTRACT FROM AUTHOR]

The exponential increase in greenhouse gas emissions necessitates urgent measures to mitigate climate change impacts. Carbon capture and storage (CCS) has emerged as a promising solution, capturing CO2 from industrial processes and storing it underground. However, CCS implementation poses risks that demand sophisticated modeling. This review focuses on the numerical modeling of CO2 plume dispersion from reservoir leaks during offshore CCS projects, including near- and far-field modeling and the comparison between Lagrangian and Eulerian modeling in particular. Near-field modeling examines CO2 behavior in jet plume, considering depth-related changes. Far-field modeling, employing Eulerian and Lagrangian methods, evaluates dispersion in marine environments. Case studies illustrate the complexity and uniqueness of CO2 dispersion events. The Lagrangian approach emphasizes gas bubble tracking, while the Eulerian approach employs fixed grid systems for detailed hydrodynamic modeling. Both approaches contribute valuable insights, with Eulerian models excelling in site-specific complexities and Lagrangian models offering computational efficiency. A hybrid approach may offer a comprehensive understanding of CO2 dispersion. [ABSTRACT FROM AUTHOR]

The paper presents a research study on modeling and computer simulation of injecting CO2 into the coal seams of the Upper Silesian Coal Basin, Poland connected with enhanced coal bed methane (ECBM) recovery. In the initial stage of the research activities, a structural parameter model was developed specifically with reference to the coal-bearing formations of the Upper Carboniferous for which basic parameters of coal quality and the distribution of methane content were estimated. In addition, a lithological model of the overall reservoir structure was developed and the reservoir parameters of the storage site were analyzed. In the next stage of the research, the static model was supplemented with detailed reservoir parameters as well as the thermodynamic properties of fluids and complex gases. The paper discusses a series of simulations of an enhanced coalbed methane recovery process with a simultaneous injection of carbon dioxide. The analyses were performed using the ECLIPSE software designed for simulating coal seam processes. The results of the simulations demonstrated that the total volume of CO2 injected to a designated seam in a coal mine during the period of one year equaled 1,954,213 sm3. The total amount of water obtained from the production wells during the whole period of the simulations (6.5 years) was 9867 sm3. At the same time, 15,558,906 sm3 of gas was recovered, out of which 14,445,424 sm3 was methane. The remaining 7% of the extracted gas was carbon dioxide as a result of reverse production of the previously injected CO2. However, taking into consideration the phenomena of coal matrix shrinking and swelling, the total amount of injected CO2 decreased to approximately 625,000 sm3. [ABSTRACT FROM AUTHOR]

• The topic of waste heat was mentioned in this report, as it represents an important learning. Waste heat issue and audit finding will be addressed in a subsequent publication. To provide clarity to the reader with regards to what data/information was used to write this manuscript, the title of manuscript was revised to "Quest Carbon Capture and Storage Offset Project: findings and learnings from 1 st reporting period". • Replaced "Shell is submitting the serialization packages for Quest to the Offset Registry without a claim for waste heat at this time." with "Shell submitted the serialization packages for Quest to the Offset Registry without a claim for waste heat until the waste heat calculation methodology is approved.". • Within Section 4.2.1 , an example of findings from an audit, namely injection gas compositional data, is discussed. Significant revisions to Section 4.2.1 to address these questions. • The quantification methodology of the emission reduction associated with the Quest project is based on the difference between the mass of CO 2 stored and the sum of CO 2 emissions attributed to project activities (e.g. emissions due to construction and well drilling). The following equations are used to quantify the emission reductions resulting from the Quest carbon capture and storage activities by comparing baseline and project conditions. • Added following footnote to Table 1 : ^ Note that the pipeline design was a 12-inch CO2 pipeline as per CSA Z662 transporting the dehydrated, compressed, and dense-phase CO2 from the capture facility to the injection wells. This should minimize the risk of failure in the transportation of CO2. • Replaced conformance with 'conformance *' and added following footnote: * Ensure Conformance refers to indicating the long-term effectiveness of CO 2 storage by demonstrating actual storage performance is consistent with expectations about injectivity, capacity, and CO 2 behaviour inside the storage complex. • Added following text "Invoices of materials supplied were used to determine the nature and quantity of each material used in the capture process. This information was then used to estimate CO2 emissions per year based on an emissions factor for a specific material". • Added following sentence after "...flow meters and on-line analyzers.": "The project has an online gas analyzer to determine the CO 2 concentration in the injection gas stream. The analyzer is located in a building just before the CO 2 enters the ˜65 km underground pipeline which transports the CO 2 from the capture facility to the injection well pads". • "The key regulatory mandate is the materiality threshold for the absolute value of all errors found by auditors must be less than 2% of the total GHG Assertion for an Offset Project for a specified reporting period. As a result, the onsite lab and third-party lab provide supporting evidence that the ambient pressure compensated CO2 concentration data from the online analyzer are accurate". Quest is a fully integrated Carbon Capture and Storage (CCS) project that started CO 2 injection in August of 2015. The Quest CCS Project is located near Fort Saskatchewan, Alberta, Canada. It includes a capture facility which uses a Shell amine technology, a pipeline of about 65 km length, and three injection well pads. Each injection well pad has an injection well, a deep monitoring well, and shallow groundwater wells. The storage complex is geologically defined by the injection reservoir, a deep saline aquifer called the Basal Cambrian Sand (BCS) (about 45 m thick) and several seals, including the Middle Cambrian Shale (about 50 m thick) and Lotsberg Salts (about 120 m thick). As of August 2018, over three million tonnes of CO 2 have been safely injected and permanently stored in the BCS. The Alberta Carbon Competitiveness Incentive Regulation (CCIR) requires the use of standard methods of quantification for reporting greenhouse gas (GHG) emissions for facilities with over 100,000 tonnes of carbon dioxide equivalent (CO 2 e) per year. An emission offset project is required to comply with CCIR, associated standards and protocols, to demonstrate a reduction in the specified gas emissions and, in the case of Quest, geological sequestration. Quest is the first CCS project to implement an offset project in the context of commercial scale on-shore CO 2 geological sequestration within a saline aquifer. Quest uses the Quantification Protocol for CO 2 Capture and Permanent Storage in Deep Saline Aquifers, from Alberta Environment and Parks. An offset project must develop an offset project plan (OPP) which demonstrates how the project meets the requirement of the protocol, describes how GHG emissions reductions are achieved, identifies risks associated with the quantification of emission reduction benefits, and describes methodologies used to quantify sources and sinks. Subsequent to completing the OPP, an offset project will put together offset project reports (OPR) to report on the net reductions of GHG emissions for a specific period. The intent of this paper is a) to provide an overview of the OPP and OPR for the Quest CCS project, and b) to discuss learnings from the initial compilation and submission of offset project reports. The key learning at this time is associated to the equipment improvements to the injection gas online analyzer. [ABSTRACT FROM AUTHOR]

• Fist application of NRAP-Open-IAM to a Bowtie RA. • Integration of qualitative and quantitative risk management approaches can improve risk quantification. • NRAP-Open-IAM can be used to determine a risk-based AoR for commercial-scale GCS sites. • Results from NRAP-Open-IAM simulations supported an 80% reduction to the approved AoR footprint. This paper documents how tools developed by the National Risk Assessment Partnership (NRAP) complement the Bowtie risk assessment approach through the demonstration of a risk-based Area of Review (AoR) determination for the Quest Carbon Capture and Storage (CCS) facility near Edmonton, Alberta with the NRAP Open-Source Integrated Assessment Model (NRAP Open-IAM). The Bowtie risk assessment for the Quest CCS site was developed by Shell Canada Ltd., who operates the asset on behalf of the Athabasca Oil Sand Project — a joint venture, owned by Canadian Natural Resources Ltd, Chevron Canada and Shell Canada Ltd. The Quest Bowtie treats site risk comprehensively – considering a large set of technical and project risks (e.g., operational risks, above ground infrastructure, public perception, etc.). NRAP tools, methods, and analyses are focused on quantitative assessment of subsurface technical risks. NRAP-Open-IAM was used to evaluate potential groundwater impacts at the Quest site, i.e., a sufficient change above background groundwater quality levels to be measurable, should CO 2 and/or brine leak from the reservoir via a faulty and/or compromised wellbore. Our results show there is a low potential for groundwater impact and support a further reduction (from ∼460 to 100 km2) to the established AoR for the Quest site. Integrating both approaches early in the site characterization period could significantly benefit commercial-scale projects by drastically reducing the region over which leakage risks (e.g., legacy wells) need to be evaluated, i.e., the AoR. This is especially true for brownfield sites, which could contain hundreds to thousands of legacy wells. Further, basing monitoring network design on those regions where impacts are most likely to occur has the potential to facilitate more efficient deployment of monitoring technologies and improve the likelihood of detecting a leak should one occur. [ABSTRACT FROM AUTHOR]

SUMMARY The assessment for realistic CO2-adsorption capacities of different rocks is important for understanding the processes associated with CO2 storage. This paper investigates the adsorption characteristics of rocks for CO2 (limestone, sandstone, marl, claystone, clay, siltstone and metamorphic rock) by using a gravimetric method. The measurements were performed at 21°C with pressures from 1 up to 4 MPa. Sandstone (and clay with sand/sandstone) showed the largest adsorption capacity at 21°C. The highest amount of in situ CO2 contents in measured samples was 21.4 kg/t. The CO2-adsorption capacities were lower than past results in different coal samples. The results indicate that adsorption of CO2 into rocks may play an important role in storing CO2 in subsurface rock. Copyright © 2012 John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

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

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

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

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

Abstract: With rising levels of atmospheric carbon dioxide (CO2), a portfolio of mitigation options is deemed essential as we transition to a low carbon economy. Carbon dioxide capture and storage (CCS) is one technology that has the potential to mitigate large amounts of CO2 and governments around the world, along with industry and researchers working in the technology space, are excited by this. However, the technology still remains relatively unknown in the minds of most lay citizens and is therefore less well accepted than more traditional forms of power generation. This paper reviews a number of CCS communication research activities that have been undertaken internationally since 2002 and synthesizes them into a logical roadmap of activities. The paper also examines the common strengths and weaknesses of the research activities and makes a number of suggestions for industry representatives and policy makers. The paper also outlines a way to segment stakeholder groups for all communication activities into four target audiences including: influential others; community; education and project specific activities. [Copyright &y& Elsevier]

Abstract: This paper investigates the role of CCS technologies as part of a portfolio for reducing CO2 emissions from the European electricity supply system until the year 2050. The analysis is carried out with the aid of a techno-economic model (with the objective to minimize the total system cost) including a detailed description of the present stationary European electricity supply system (power plants) and potential CO2 storage sites as obtained from the Chalmers Energy Infrastructure databases. The ability of different EU Member States and regions to facilitate and to benefit from CCS will most likely depend on local conditions in terms of current energy mix, fuel supply chains and distance to suitable storage locations. Special emphasis is therefore put on analyzing turn-over in capital stock of the existing power plant infrastructure, timing of investments and the infrastructural implications of large scale introduction of CCS on a regional perspective. The paper discusses the role of and the requirements on CCS for meeting strict CO2 emission reduction targets of 85% reduction from power generation by 2050 relative 1990 emissions in three different scenarios. All analysed scenarios apply the same cap on CO2 emissions. The first scenario includes a continued growth in electricity demand (as presented in EU base-line projections). The second scenario includes stated EU targets for 2020 and indicative targets for 2050 with respect to increased energy efficiency, and thus, considers a lower growth in electricity demand compared to the base-line. The third scenario includes EU targets (to 2020 and indicative targets to 2050) on energy efficiency, equal to the second scenario, and EU targets of electricity from renewables. The results show that it is possible for the European electricity generation system to meet an 85% CO2 reduction target by 2050 with a potentially large contribution from CCS. Up to 50% of the electricity generation will come from plants with CCS with a peak capture estimated to 1.8GtCO2 per year and cumulative CO2 capture of about 39GtCO2 between 2020 and 2050 (it is assumed that CCS will be commercially available from 2020). As expected, countries which currently have high carbon intensity and which are located nearby suitable storage sites will benefit the most from CCS implementation. Hence, the results suggest that Italy has the largest demand for CCS with annual peak capture at around 0.5GtCO2 in the base-line scenario. The model results indicate a steep ramp-up of CCS post-2020, which imposes challenges for timely investments in corresponding CCS infrastructure including transportation and storage. A continued growth in electricity demand can lead to demand for CCS to such extent (in the base-line capacity build up is about 300GW of CCS between 2020 and 2050) that the actual penetration level could be limited by fuel markets and power industries’ ability to supply fuel and CCS power plants. [Copyright &y& Elsevier]

This paper explores the adsorption behaviour of geomaterials in the framework of CO 2 sequestration in shallow level coal seams. Manometric adsorption experiments were carried out on two anthracite coal samples, two rock samples from East Irish Sea, MX80-bentonite, Speswhite kaolinite, dry, wet and biofilm-laden (Bascillus mojavensis -laden) sand at subcritical pressure range (up to 6.4 MPa) of isothermal condition at 298.15 K. The experiments were aimed to investigate the influence of the biogeological conditions of coal and caprock constitutions on CO 2 adsorption. At lower pressures, the moisture had an influence on the CO 2 adsorption on coal resulted in reduced adsorption capacity. At elevated pressures, the volume expulsion behaviour and coal-water interaction had an influence on the adsorption capacities of moist coal sample and resulted in comparable adsorption capacities to dry sample. The disparity in the adsorption capacities between the wet powdered and wet intact core samples showed that the results obtained with powder samples may not reflect the field conditions. Wet conditions and Bascillus mojavensis bacteria influenced the adsorption capacity of sand and showed CO 2 chemisorption capacity. The desorption isotherm pattern of wet and biofilm sand showed that the CO 2 was continuously adsorbed independent of the gas phase pressure. Among the clay minerals, bentonite had greater affinity towards CO 2. Despite the fact that the adsorption capacity of the cap rock is smaller than that of the coal samples, the experimental investigation with constituents of the cap rock provides insights into the effect of biogeological conditions of coal and rock sample constituents on CO 2 storage in coal seams. [ABSTRACT FROM AUTHOR]

Geological carbon storage is an effective method capable of reducing carbon dioxide (CO2) emissions at significant scales. Subsurface reservoirs with sealing caprocks can provide long-term containment for the injected fluid. Nevertheless, CO2 leakage is a major concern. The presence of abandoned wells penetrating the reservoir caprock may cause leakage flow-paths for CO2 to the overburden. Assessment of time-varying leaky wells is a need. In this paper, we propose a new semi-analytical approach based on pressure-transient analysis to model the behavior of CO2 leakage and corresponding pressure distribution within the storage site and the overburden. Current methods assume instantaneous leakage of CO2 occurring with injection, which is not realistic. In this work, we employ the superposition in time and space to solve the diffusivity equation in 2D radial flow to approximate the transient pressure in the reservoirs. Fluid and rock compressibilities are taken into consideration, which allow calculating the breakthrough time and the leakage rate of CO2 to the overburden accurately. We use numerical simulations to verify the proposed time-dependent semi-analytical solution. The results show good agreement in both pressure and leakage rates. Sensitivity analysis is then conducted to assess different CO2 leakage scenarios to the overburden. The developed semi-analytical solution provides a new simple and practical approach to assess the potential of CO2 leakage outside the storage site. This approach is an alternative to numerical methods when detailed simulations are not feasible. Furthermore, the proposed solution can also be used to verify numerical codes, which often exhibit numerical artifacts. [ABSTRACT FROM AUTHOR]

Various modeling studies analyzing global 2 °C climate stabilization scenarios have projected penetration of CO 2 capture and storage (CCS) technologies in India alongside a sizable penetration of renewable energy technologies. The assessments of geological storage potential over India have shown wide variation across regions. This paper examines the locations of large point sources of CO 2 emissions in India and matches it with carbon storage locations to minimize the cost of CCS evolving grid. The concept of weighted Euclidean distance and Integrated Environmental Control Model are used to propose suitable pipeline networks for emissions-intensive clusters to optimize the cost of CO 2 avoidance. The computational method estimates proximate storage location for each CO 2 emitting source taking into account the total storage potential at each location. CCS requirement in India would vary depending on the global climate stabilization target. We examine two targets for India that correspond to 2 °C and well below 2 °C global mitigation regimes. According to our estimates, India could mitigate around 780 Mt CO 2 per year below 60 $/t-CO 2 (2005 prices) over 30 years, and another 250 Mt CO 2 per year for up to 75 $/t-CO 2 prices through CCS under these scenarios respectively. [ABSTRACT FROM AUTHOR]

Partition (or distribution) coefficients determine the relative equilibrium concentrations of chemical constituents (or chemical tracers) in each of the phases of a multi-phase system under dilute conditions. The various fluid phases in a reservoir have differing transport properties (e.g. varying relative permeability) and to correctly interpret the behaviour of injected chemical tracers it is essential that accurate partition coefficients are known. In the context of carbon geosequestration or long-term storage of CO 2 , chemical tracers will be predominantly exposed to an environment consisting of supercritical CO 2 and formation water as the main fluid phases. To estimate/simulate the reservoir properties relevant to injected CO 2 tagged with chemical tracers, it is therefore necessary to incorporate high pressure/temperature CO 2 /water partition coefficients into any model/simulation. In this paper, we present a method to determine these partition coefficients for gaseous chemical tracers using a variation of the widely used EPICS (or equilibrium partitioning in a closed system) method. With this method, only the concentration in one phase (in this case, CO 2 ) needs to be measured. We then report these values for a series of representative chemical tracers (i.e. krypton, xenon, sulfur hexafluoride, perdeuterated methane and R134a) at pressure/temperature conditions that have been previously used at the CO2CRC's Otway CCS demonstration project in Victoria, Australia. These values were generally lower than the corresponding Henry's Law coefficients at comparable temperatures. Experiments also examined the impact of adding CH 4 to the system to mimic feedstock gas at the CO2CRC Otway project and provide data pertinent to scenarios where CO 2 is injected into depleted CH 4 gas fields. These values are compared with Henry's Law coefficients and another recently published set of high pressure/temperature partition coefficients. With computational simulations, we have shown that these differences are potentially significant and demonstrate their impact in three typical CO 2 geo-sequestration scenarios (i.e. injection into two types of aquifers and injection into a depleted reservoir with a gas cap). [ABSTRACT FROM AUTHOR]

Natural gas is an indispensable resource not evenly distributed in the world. The gas supply chain is characterized by large imbalances between supply and demand, where the underground gas storage (UGS) application plays a key role for creating strategic reserves, taking advantage of geological structures. On the contrary, human activities will require clean energy with near-zero greenhouse gas emissions to be environmentally viable. A key element of this strategy is the carbon capture and storage (CCS) application useful for confining CO2 into the geosphere to reduce anthropogenic emissions. The development of appropriate injection methods and long-term monitoring systems for leak detection of the underground storage of natural gas and CO2 is important to prevent negative effects, such as ground deformations and micro seismic events. In this work, a variety of monitoring applications were gathered and critically analyzed for a total of 60 scientific contributions spanning the world. This bibliographic work shows an analytical and statistical overview of the most common use of UGS and CCS, representing the different goals of these two applications and analyzing the main monitoring techniques used in the gathered contributions. Currently, UGS monitoring requires further development, especially through multidisciplinary approaches useful for identifying possible effects on the surface and gas leaks at depth; meanwhile, CCS solutions are still at the experimental stage, also because of the high costs for large-scale applications that still need specific research. The state of the art of these two very different practices can improve the further development of new monitoring approaches or additional methods. [ABSTRACT FROM AUTHOR]

• This paper distils the learnings of three research projects that all investigated aspects of marine monitoring for CO 2 storage. • Technologies for detection, location, and quantification of potential leakage from offshore CCS projects were tested with controlled releases • Each project used controlled releases in representative marine environments to verify technology performance and environmental impact. • Impacts of small to medium CO 2 leakages from large scale storage have been assessed to be limited and localised. • Integrated marine monitoring systems can detect even small leakages of 10−50 L/min at unknown locations in a large area of interest. Carbon Capture and Storage (CCS) is a collective term for technologies that allow society to unlock the benefits of energy intensive processes like fertiliser production and combustion of fuels (fossil or biologically sourced) without releasing the CO 2 to the atmosphere. Hence, CCS could assist in accelerating decarbonisation while society pursues a just energy transition. This paper aims to summarise the learnings of three research projects that all investigated aspects of marine monitoring for CCS from a CO 2 storage operator's perspective. The QICS (Quantifying and Monitoring Potential Ecosystem Impacts of Geological Carbon Storage), ETI MMV (Energy Technologies Institute Measurement, Monitoring and Verification of CO 2 Storage), and STEMM-CCS (Strategies for Environmental Monitoring of Marine CCS) projects collectively represent over twelve years of dedicated research to assess environmental impacts and to develop technologies for detection, location, and quantification of potential leakage from offshore geological storage of CO 2. Each project used controlled releases in representative environments to test their methods and technologies. QICS as the first of the three projects, focused on the understanding of sensitivities of the UK marine environment to a potential leak from a CO 2 storage complex and tested technologies to detect such emissions. The ETI MMV project brought together research and industry partners to develop and sea trial an operational, integrated and cost-effective marine monitoring system for geological CO 2 storage. As a commercial project, these results have never been published before and this paper shares for the first-time insights from this work. In February 2020, STEMM-CCS, completed its quest to test techniques for environmental monitoring over a marine CO 2 storage site in the UK North Sea, further improved near seabed leakage characterisation capabilities, and delivered a first marine CCS demonstration level ecological baseline. This paper aims to summarise some of the key insights from the three projects and provides references where available for the interested reader. The key finding of all three projects is that the impacts of small to medium CO 2 leakages from large-scale storage are limited and localised. Technology capabilities exist for integrated marine CO 2 storage monitoring and their performance has been benchmarked at controlled release trials. Even small leakages of 10−50 L/min can be detected at unknown locations in a large area of interest. Finally, the first important steps towards automated monitoring data analysis have been made, including automated leakage signal detection from Side Scan Sonar data (ETI MMV project) and automated species identification from marine biology images (STEMM-CCS project). Some remaining challenges include missed/false alerts because of large variations in the background signal, the cost of monitoring large areas over long periods, and making real-time decisions based on big data. Continued work to reduce the cost of marine monitoring technologies and advancing automation of data processing and analysis will be important in order to support safe and efficient offshore CCS deployment at large scale. [ABSTRACT FROM AUTHOR]

• This paper proposes a dual-tubing CO 2 injection-water production horizontal well (DTHW) pattern. • The DTHW pattern for improving CO 2 storage capacity and reducing CAPEX was studied in a saline aquifer in Pohang basin, Korea. • The DTHW pattern showed promising results in that the CAPEX was reduced by 37.1% compared to a typical CO 2 injection with a water production pattern. Water production is an efficient way of relieving pressure build-up and improving the CO 2 storage capacity (CSC) in the carbon capture and storage process. The additional offshore platforms, production wells, pipelines, and pumps required for water production, however, increase the capital expenditure (CAPEX) of the project. Therefore, a CO 2 injection method that can both improve the CSC and reduce the CAPEX is needed. This paper proposes a dual-tubing CO 2 injection-water production horizontal well (DTHW) pattern for improving the CSC, in which CO 2 is injected at the heel of the horizontal well while water is produced at the toe. The CSC and CAPEX of the proposed DTHW pattern were then compared to those of other cases in a saline aquifer in the Pohang basin, offshore Korea. The CCS Performance (CSC to CAPEX ratio) of the proposed DTHW pattern was larger than that of a typical CO 2 injection with a water production pattern for the all CO 2 injection-water production rate cases. The proposed DTHW pattern showed promising results in that the maximum CSC was improved by 98.2% compared to a single vertical CO 2 injection well pattern and the CAPEX was reduced by 37.1% compared to the typical CO 2 injection with a water production pattern. More CAPEX might be saved if a DTHW pattern is used in an onshore platform near a power plant because an additional offshore platform and pipeline are not required. [ABSTRACT FROM AUTHOR]

Carbon capture, use and geological storage (CCUS) could be feasible when fossil fuel-power plants are close to oil and gas reservoirs where CO 2 -enhanced oil recovery (EOR) technologies are applicable. In this research, we used a novel “well-to-well” approach that included the operations from natural gas production at oil field to CO 2 injection for EOR operations at depleted oil fields. This paper includes estimates for greenhouse gas (GHG) emissions arising from a hypothetical CCUS case with a natural gas combined cycle power plant (NGCC) and Global Warming Potential (GWP) impact, by using Life-Cycle Assessment (LCA) methodology. Our research comprises a comparison with other electricity-generation technologies, including super critical pulverized carbon (SCPC), NGCC without CO 2 capture, geothermal, mini-hydro, wind and nuclear. The LCA stages that were undertaken in this study were natural gas supply system , electricity generation , CO 2 capture, CO 2 transport, EOR operations and environmental monitoring . Three different functional units were used in this study: MJ, kW h and produced oil barrel (bbl). Results indicate that the energy produced by the described CCUS system had an environmental impact on climate change (global warming potential) of 0.044 kg CO 2 e/MJ. The NGCC power plant with carbon capture unit would produce 0.177 kg CO 2 e/kW h, representing about 21% and 36% of the estimated values for the SCPC and NGCC (without CCS) cases respectively, and about 24% less greenhouse gas emissions than the geothermal scenario. The oil produced in the EOR stage had a greenhouse gas emission rate of 38 kg CO 2 e per oil barrel and 251 kg CO 2 e per oil barrel in the whole CCUS system. [ABSTRACT FROM AUTHOR]

Existing monitoring protocols for the storage of carbon dioxide (CO 2 ) in geologic formations are provided by carbon dioxide capture and geological storage (CCS)-specific regulations and bodies including the 2006 Intergovernmental Panel on Climate Change (IPCC) Guidelines for National Greenhouse Gas Inventories, the European Union (EU) CCS and Emission Trading Scheme (ETS) Directives, United States Environmental Protection Agency (US EPA) Final Rules, and the United Nations Framework Convention on Climate Change (UNFCCC) Clean Development Mechanism (CDM) Modalities and Procedures (for developing countries). These protocols have varying levels of detail but similar principles and requirements for monitoring, and all include the need to quantify emissions and measure environmental impacts in the event of leakage to the surface. What they do not all include is the clarification that quantification monitoring should only be undertaken in cases where CO 2 has been attributed to leakage and not when leakage is only suspected. Quantifying suspected emissions is a significant monitoring challenge and undertaking, and may rely on acquiring large data sets over long time periods. This level of effort in monitoring would be unnecessary if the source of CO 2 detected at the surface is attributed to natural sources rather than from leakage, but a step to attribute CO 2 source is either missing from these protocols or is outdated in technical scope. Regulatory bodies call for protocols to be updated based on technical advances, and ongoing technical advances into leakage monitoring have now benefited from a first-ever public claim of leakage over a geologic CO 2 storage site in Saskatchewan, Canada, bringing more emphasis on the role of attribution monitoring. We present a brief update of some of the newest technical advances in attribution and suggest that CO 2 ‘attribution monitoring’ could now be included in monitoring protocols to avoid unnecessary and costly quantification monitoring unless it is fully warranted. In this context, this paper describes an option to improve the existing protocols for monitoring CO 2 at geological storage sites made possible because of recent developments in near-surface attribution monitoring techniques. [ABSTRACT FROM AUTHOR]

[Display omitted] • Various robust AI methods were implemented for predicting IFT of CO 2 -brine system. • A comprehensive database including more than 2184 experiment samples was employed for implementing the AI study. • The newly proposed random forest model for predicting IF outperforms the other AI models. Given the current global climate change, renewable energy sources, carbon capture, utilization, and storage (CCUS) are being considered as a potential solutions to this critical global issue. Structural and capillary processes can be used to store carbon dioxide (CO 2) in deep saline aquifers in a way that is safe and does not harm the environment. Due to this fact, the interfacial tension (IFT) of the CO 2 -brine system is an important factor influencing the capacity of storage formations to sequester CO 2. As a result, IFT is essential for conducting a thorough and accurate evaluation in order to determine the optimal strategy for CO 2 storage projects. This paper used intelligent models such as Gaussian Process Regression (GPR), Radial Basis Function (RBF), and Random Forest (RF) to forecast IFT in the CO 2 -brine system with high precision and substantial time saving. The results reveal that the constructed RF model could deliver excellent performance in predicting IFT with the lowest average absolute percent relative error (AAPRE = 1.9156 percent), highest coefficient of determination (R2 = 0.9907), and lowest root mean squared error (RMSE = 0.7279). Furthermore, a sensitivity analysis was performed to ascertain the most critical parameters in the RF model to be considered. The parametric analysis found that both pure and non-pure CO 2 systems had a significant impact on IFT prediction. Also, the RF model was used to assess the structural trapping capacity of a storage location in the Cuu Long Basin. The estimation results obtained in this study agreed perfectly with the previous ones. The findings of this study can aid in a better understanding of how machine learning models can be applied to predict IFT values for the evaluation of the structural CO 2 storage capacity. [ABSTRACT FROM AUTHOR]

• Stationary CO 2 emission within 1000 km from Singapore is 391 Mtpa. • With this area, subsurface reservoirs can store 386 Gt of CO 2. • Arun gasfield and Minas oilfield are top candidates for CO 2 storage and EGR/EOR. • A CCS corridor connecting Singapore to Sumatra, and the Malay Basin is proposed. In this paper, we evaluate opportunities for CO 2 capture and storage (CCS) within a study area of radius 1,000 km from Singapore. Results show that stationary CO 2 emission from the study area is 391 Mtpa. There is mid CO 2 storage resource of 0.5 Gt in oil reservoirs. In addition, CO 2 enhanced gas/oil recovery (CO 2 -EGR/EOR) can recover 1.86 billion barrels of oil. The largest amount of CO 2 -EOR is found in the Minas oil field (767 MMbbl) in Central Sumatra and the Seligi (119 MMbbl) and Dulang (99 MMbbl) oil fields in the Malay Basin. The mid CO 2 storage resource in gas reservoirs is 6.2 Gt. Of particular importance is the Arun gas condensate reservoir in the North Sumatra Basin with 1.3 Gt CO 2 storage resource and 101 MMbbl condensate recovery by CO 2 -EGR. The mid CO 2 storage resource in saline aquifers is 379 Gt, accounting for the 98% of total CO 2 storage. Furthermore, we propose an ASEAN CCS corridor connecting Singapore with the North Sumatra, Central Sumatra, and Malay basins wherein CO 2 captured from Singapore and the host country can be transported to oil and gas reservoirs or saline aquifers within these basins for permanent storage. [ABSTRACT FROM AUTHOR]

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

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

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

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

Abstract: This paper assesses the issue of monitoring to measure potential emissions from leakage at geologic sequestration (GS) sites for purposes of greenhouse gas (GHG) accounting under an emission reduction program. We find that a GHG accounting program can reasonably assume that there is no atmospheric leakage from GS sites as long as routine subsurface monitoring shows no loss of containment. If loss of containment is detected, current monitoring technology, such as hyperspectral imaging, should be able to detect and locate leakage at levels of concern at some but not all sites. If leakage can be detected, then it can be reliably quantified using existing technology. The disparities in leakage detection capability produced by geologic and ecosystem variations require a flexible GHG accounting policy for GS sites during the operations phase. The potential for leakage emissions during long-term stewardship is low, but mechanisms to account for it, such as an emissions reserve program, are important for building public support for CCS technology and supporting national emission reduction goals. [Copyright &y& Elsevier]

Abstract: Cryogenic air separation is the only available state-of-the-art technology for oxyfuel power plants and represents an important burden to the total plant efficiency. Nowadays, high temperature ceramic membranes, which are associated with significantly lower efficiency losses, are foreseen as the best candidate to challenge cryogenics for high tonnage oxygen production for this type of CCS power stations. In this study, two oxyfuel plant designs were developed, the first based on the state-of-the-art supercritical 600 °C hard coal plant Nordrhein-Westfalen and the second on the advanced ultra-supercritical 700 °C pulverized coal-fired power plant. The membrane-based air separation unit was modeled considering the three-end concept, where oxygen is transported across the membrane aided by a compressor at the feed side and by a vacuum pump at the permeate side. This paper analyzes the influence of both, the cryogenic and high temperature membrane air separation units on the net plant efficiency, considering the same boundary conditions and equivalent thermal integrations. Moreover, the oxygen permeation rate, heat recovery, and required membrane area are also evaluated at different membrane operating conditions. [Copyright &y& Elsevier]

Abstract: BIGCCS Centre is an international research centre aiming at extending and releasing the potentials for large scale deployment of CO2 capture and storage by developing new knowledge, fostering breakthrough technology and promoting innovation and future value creation at all steps along the CO2 chain. The centre is managed by SINTEF Energy Research, it involves 22 partners from industry and academia, and administers a budget amounting to 45 million € over 8 years. The paper presents the objectives of the BIGCCS Centre, outlines the research approach and strategy for promoting innovation, and presents some results after one year of operation. [Copyright &y& Elsevier]

Abstract: For most CCS projects, captured CO2 is transported by pipeline, in contrast to shipping it, which has only been introduced as a secondary option for long distances and small amounts. This paper provides some possible alternatives to reduce the total cost of CCS through CO2 shipping. The benefits of HP pump in power consumption is considered and a new total CCS chain is suggested, which can be divided into capture, liquefaction (or compression to supercritical fluid), transport by ship, compression by HP pump, and storage. With a highly efficient liquefaction process, CO2 shipping costs can be reduced under a new total CCS chain. The results of our study show that an optimal size needs to be adopted for each CCS project, enabling CO2 shipping to be more cost efficient. DSME has developed a concept design for a large CO2 carrier that has the potential to be more cost-effective than conventional transport. Therefore, CO2 transport by ship should now be seriously re-considered as an effective transport method on a project-by-project basis. [Copyright &y& Elsevier]

Abstract: In the eyes of energy analysts and bureaucrats as well as media and environmental NGO’s, CCS now appears to be synonymous with “clean coal”, meaning coal fired power plants with CCS. While recognising the role of coal–emitting nearly 42 percent of man-made CO2 globally–we want to focus on other aspects of CCS that we find are just as, or more important in actually driving the deployment of CCS in the coming years. One of these factors is what we see as an evolving “industry norm” to inject, into geological formations, CO2 extracted from high- CO2 natural gas in gas refineries or LNG plants. A second trend driving CCS in the petroleum sector is the need to produce increasingly acid natural gas (CO2 and/or H2S rich) and heavier oil. This will certainly accelerate the number of petroleum related CCS-projects in the next decades and thus be valuable for geo-storage learning. A third and already important factor is the use of CO2 for enhanced oil recovery (CO2-EOR). Today CO2-EOR is mostly limited to USA - with nearly one hundred operating projects–and a small but increasing number in other countries. In the period to 2030 and beyond, it is the view of the authors that CO2-EOR will fan out across the sedimentary basins of the world. These three factors will not only add to our knowledge of geological storage of CO2, but also be important drivers to develop storage sites, pipeline networks, shipping routes and other infrastructure components for CO2. There are in fact some profitable CCS-projects or at least projects with modest needs for subsidies. With the present electricity-from-coal focus of CCS, it is easy to forget the potential role of other branches of industry with large point sources of CO2. The branches of iron and steel, cement, petrochemicals, refining, fertiliser, biomass-to-energy are examples we should focus more on. This lack of broad focus is regrettable for two reasons. Firstly, some of these are CO2 sources which lend themselves to CCS by having higher CO2 concentrations or higher pressures than power plant flue gas, resulting in potentially lower capture cost. Secondly we need these branches of industry to learn CCS-capture technologies from each other, to progress their own demo-projects and become familiar with the practices of geo-store companies. The main focus in this paper is learning geo-storage by taking available CO2-streams rather than creating such streams through billion dollar investment projects. One such example is that hydrogen today is largely produced and distributed by pipelines and other methods by a small group of specialised industrial gas companies. The connection between these companies and CO2-storage operators are, however, nearly non-existent. Hydrogen–except for pre-combustion to electricity - has been put on the back-burner in connection with CCS. We here argue for focussing more on hydrogen from fossil fuels with CCS aimed at end-use in industry. [Copyright &y& Elsevier]

Abstract: This paper presents an environmental assessment of three scenarios postulating a national deployment of the Carbon Capture and Storage (CCS) chain by 2020–2050 on the French biggest industrial CO2 emitters (41 emitters among 9 industrial sectors) that had been carried out as part of the SOCECO2 project. 1 [1] SOCECO2 project, funded by the French National Research Agency, 2006–2009, involving the following partners: ALSTOM Power, APESA, BRGM, CNRS-CIRED, GDF Suez, IFP Energies nouvelles, INERIS, TOTAL. This analysis is based on the comparison of these CCS scenarios with reference scenarios without CCS at the same timeframe. Results detailed below focus on greenhouse gas (GHG) emissions and energy consumption, although NOx and SOx emissions balances have also been evaluated in the same project. Conclusions of this study provide information about the extent and main contributing factors of potential environmental outcomes (negative or positive) associated to CCS deployment. [Copyright &y& Elsevier]

Abstract: Stakeholder involvement (SI) can include many activities, from providing information on a website to one-on-one conversations with people confronting an issue in their community. For carbon dioxide capture and storage (CCS), there are now quite a few surveys of public attitudes towards CCS that are being used to inform the design of SI efforts. These surveys, focused on the nascent commercial deployment of CCS technologies, have demonstrated that the general public has little knowledge about CCS—yet the surveys go on to collect what are known as “pseudo opinions” or “non-attitudes” of respondents who know little or nothing about CCS. Beyond establishing the lack of knowledge about CCS, the results of these surveys should not be relied upon by the larger CCS community and public and private decision makers to inform the critical task of implementing and executing SI activities. The paper discusses the issues involved in providing information as part of the survey, maintaining that such information is never unbiased and thus tends to produce pseudo opinions that reflect the pollster''s or researcher''s bias. Other content and methodological issues are discussed, leading to the conclusion that most of the survey results should be used neither as a gauge of public attitudes nor as an indication of public acceptance. Then the framing of SI in CCS is examined, including the assumptions that clear stakeholder acceptance is a realistic goal and that the public has a decisive say in choosing the energy technologies of the present and the future. Finally, a broader suite of SI activities is recommended as more suited to realistic and contextual goals. [Copyright &y& Elsevier]

Abstract: The International Energy Agency Energy Technologies Perspectives (ETP) model is used to assess the prospects for carbon abatement options, including carbon capture and storage, up to 2050. Three main scenarios are considered: a Baseline scenario with current energy policies, an accelerated technology scenario that seeks to return energy-related CO2 emissions in 2050 to their level in 2005, and a scenario for which CO2 emissions are reduced at 50% of current levels by 2050. To reach these emissions reduction targets, annual global CO2 emissions in the year 2050 must be reduced by 35 GtCO2 to 48 GtCO2 compared to the Baseline scenario. The analysis presented here shows that a broad portfolio of emissions reducing technologies will need to be deployed across all economic sectors of the global economy to reach these targets. Carbon dioxide capture and storage (CCS) is one of the suite of technologies employed across the globe to reach these targets. CCS adoption occurs in many aspects of the global economy and accounts for 14–19% of all emissions reductions. The total amount of CO2 captured and stored in deep geologic reservoirs up to 2050 ranges between 5.1 GtCO2 and 10.4 GtCO2 in these two climate policy scenarios. Up to 2030, more than half of total CCS deployment takes place in OECD countries. After 2035, emerging economies account for more than half of total CCS use. This paper also demonstrates that as the climate policy becomes more stringent it will be necessary for CCS to deploy more extensively in many different industries outside of the electric power sector which often receives the most attention in discussions of CCS''s role in addressing climate change. [Copyright &y& Elsevier]

Abstract: This paper deals with recent assessments and results of the EU-based DYNAMIS 1 [1] EU/EC Contract #019672 under the 6th Framework Programme, “Towards Hydrogen and Electricity Production with Carbon Dioxide Capture and Storage”, in brief: DYNAMIS. Start-up date: 01 March 2006. Coordinator: SINTEF Energy Research, Trondheim, Norway. project, which - since March 2006 - has been investigating decarbonisation of fossil fuels (bituminous coal, lignite and natural gas), with the inclusion of carbon capture and geological storage of the CO2 (CCS). The project was established by leading European RTD providers and industries, and sponsored by the European Commission under its 6th Framework Programme. Main deliverables of the DYNAMIS project comprise pre-engineering studies and a subset of recommendations to the European Commission with regards to its HYPOGEN Demonstrator Programme. According to prerequisites established by the European Commission, the HYPOGEN Demonstrator is planned to offer electricity, hydrogen and CO2 at large scale - scheduled for commercial operations to commence by 2012–2015. [Copyright &y& Elsevier]

Abstract: The European DYNAMIS project is part of the HYPOGEN quick-start programme and aims at investigating viable routes for large-scale cost-effective combined hydrogen and electricity production with integrated CO2 Capture and geological Storage. This paper presents the environmental evaluation carried out for each technology option studied, producing Hydrogen and Electricity with CCS. The methodology used is based on Life Cycle Analysis (LCA) principles and concentrates on the assessment of two criteria: GHG emissions and non renewable primary energy consumption. As with other evaluations performed in DYNAMIS (mainly focused on technical and economic aspects), these results lead to the selection of best concepts in terms of environmental efficiency by comparing and weighing up positive and negative effects (i.e GHG emissions reduction and increase of non-renewable primary energy consumption). [Copyright &y& Elsevier]

Abstract: CO2 storage in depleted gas fields is attractive but gas fields are unequally distributed geographically and can be utilized only within a restricted window of opportunity. Therefore, CO2 storage in saline aquifers can be expected to become an important element of CO2 capture and storage (CCS) systems. CO2 storage in saline aquifers is studied in the European DYNAMIS project, where special attention was paid to the relation between the geological structure, geological properties and achievable injection rates. This paper presents the results from simulations of CO2 storage in two aquifer structures. One aquifer structure is located in the English sector of the Southern North Sea and one aquifer structure located in Northern Germany. The geological model of the Southern North Sea structure was built using existing knowledge of facies geometry and distribution from literature and well logs and the overall geometry from interpreted horizons. The distributions of properties like lithology, net-to-gross ratios, porosity and permeability were stochastically modelled to represent the braided and meandering river and fan systems within the Bunter Sandstone Formation. High-porosity and high-permeability zones model fluvial channels running through the reservoir. A different approach was chosen for the North German structure. Because there is no information on the facies or petrophysical parameter distribution of the aquifer, three different model scenarios were generated. One model was created with homogeneous properties throughout the aquifer. Two other model scenarios were generated allowing the porosity and permeability to vary within certain ranges. This was done using a sequential Gaussian simulation with the known mean, minimum and maximum values of porosity and permeability, respectively. Due to the size of the aquifer structures and computing limits, up-scaling of the geological model of the Southern North Sea was required. The up-scaling was aimed to retain as much as possible of the modelled geological features such as braided river and fan systems. Several reservoir simulations were carried out in collaboration between TNO and IFP to assess CO2 injection. Given the injection rate constraints, the aim of the injection simulations was to: [•] assess the achievable rate of injection; [•] study the migration and behavior of the CO2 in the reservoir; [•] assess the most appropriate location(s) for the CO2 injection wells using alternate injection strategies. The injection strategy is relevant especially for the Southern North Sea structure, where river and fan systems may results in high-permeability zones through the reservoir. Accessing such systems may significantly improve a reservoir’s value for CO2 storage. The effect of such systems on the injection rates is demonstrated. The reservoir simulations also demonstrate the injection rates that can be achieved in tight reservoirs as in the North Germany case, and the effect of spatial variability of geological parameters. This will show whether it is reasonable to assume spatial geological homogeneity, when data on the reservoir formation are scarce. [Copyright &y& Elsevier]

Abstract: The creation of a robust Baseline, Monitoring, and Verification (BMV) plan is key to assuring containment integrity in CO2 geological storage projects. A BMV plan has three main aims: Monitor CO2 movement in the subsurface, Calibrate dynamic earth models and finally, Verify volume of stored CO2. Wide ranges of potential BMV technologies available are currently tested in CCS pilots and industrial scale projects. This paper describes how to optimize the BMV plan design by adopting a risk-based approach and how the value of information (VOI) of specific monitoring technologies needs to be assessed to meet program objectives. [Copyright &y& Elsevier]

Underground and ocean CO 2 storage is facing a series of hazard like leakages, earth movement and seismic activity, which has attracted more international attention on CO 2 utilization. It can potentially not only reduce the anthropogenic carbon emissions which is the main cause of climate change, but produce valuable fuels and chemicals through synthesis. This paper explored the environmental benefits of CO 2 utilization through the reverse water gas shift into syngas for the production of liquid fuel and power. CO 2 source is an ideal three-stage hydrogen production unit based on the Fe-based chemical looping combustion, which can capture carbon with nearly zero-energy-consumption. The life cycle emission was calculated as 129.98 kg CO 2 -eq/MW h, and the proportion of carbon emissions that correspond to the production of liquid fuel is 60% (taking exergy allocation as an example). Compared with the conventional NGCC and GTL standalone production system with carbon capture at same outputs, this system could achieve an energy savings of 18.19% and a life-cycle carbon emission reduction rate of 46.87%. Carbon emissions mainly came from natural gas mining and transportation, and the CO 2 recompression process, which accounts for 74.54% and 15.12% of life cycle emissions, respectively. In addition, the effects of key parameters, such as CCU/CCS , solid inventory and lifetime of oxygen carrier, and different allocation methods, on these LCA results were discussed in detail to further reveal the system carbon emission reduction potential. • An energy-efficiency and environmental-friendly CO 2 -to-liquid fuel pathway is proposed. • Quantifying the carbon emissions allocation in polygeneration system by different allocation methods. • Effects of main regions and key parameters on life cycle carbon emissions are investigated. [ABSTRACT FROM AUTHOR]

One of the most promising, cost‐effective, and readily available technologies for reducing greenhouse gas emissions to the atmosphere is the capture and separation of CO2 from large stationary sources and storage in geological formations. Storage security, especially in the early stages of operation, is mostly guaranteed by caprock formations with very low permeability overlying the reservoir, capable of containing the injected fluid. Chemical alterations of the formation brine, caused by CO2 injection may cause dissolution and precipitation of secondary minerals, potentially increasing the risks of leakage from the reservoir. In order to evaluate these processes and their potential to induce the formation of leakage pathways in ultrafine fault gouges, a series of batch experiments was performed on crushed and sheared samples from three different caprock formations from Northern Europe (Sollingen, Röt and Opalinus claystones). The experiments were supported by numerical models of the kinetics of mineral dissolution and precipitation simulating the same experimental conditions, and over a longer time (10 000 years). Minor mineral alterations were observed after the batch experiments, the most important being: illite dissolution for the Opalinus and Röt formation samples, and dolomite dissolution and the transformation of illite and chlorite into kaolinite for the Sollingen sample. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

• Developed life cycle assessment model for biomass co-firing power plants with CCS. • Given detailed process-level input-output table based on mass and energy balances. • Co-firing of 25% biomass with coal can achieve near-zero emissions in CCS plants. • Environmental burden shifts significantly as the co-firing ratio. • Uncertainty analysis was carried out for the environmental burden shift. As a carbon-neutral renewable energy source, biomass co-firing with coal contributes to reducing the carbon intensity of pulverized coal power plants with CO 2 capture and storage; thus, this process significantly reduces the greenhouse gas emissions of the power industry. However, various types of environmental impacts caused by co-firing have hindered the large-scale deployment of this technology. In this study, ten life cycle assessment models were developed based on the Integrated Environmental Control Model and GaBi software to quantify the performance parameters of different power plants and the influence of the co-firing ratio on various environmental impact categories. The system boundaries included raw material acquisition, raw material transport, energy conversion of power plants, CCS and brine treatment. The results indicated that a pulverized biomass/coal co-firing power plant with CCS can achieve near-zero emissions at a co-firing ratio of 25% and negative emissions of 877 kg CO 2 -e/MWh from a life-cycle perspective when coal is totally replaced. Co-firing biomass and coal in power plants has a passive impact on seven environmental categories, such as the eutrophication potential and toxicity potential, rather than on the global warming potential, abiotic resource depletion potential and acidification potential. The major causes of environmental burden shifting are energy penalties and indirect emissions from high-energy-consumption processes, especially emissions of N 2 O, NH 3 and ethylene oxide released during biomass extraction and solvent preparation. The conclusions and recommendations presented in this paper may have implications for deep decarbonization in other industrial sectors. [ABSTRACT FROM AUTHOR]

The article presents a comprehensive economic analysis of a CO2 injection project in one of the Polish oil fields for both increased production (CO2-EOR) and underground storage (CCS). An interesting differentiator of this work is the use of a multilayered reservoir, which is actually not one reservoir but several located in the same place, as an example. It allows the optimization of the processes of injection, production and storage. Such projects are becoming more and more important because recently, after a period of long-term stagnation, costs of carbon allowances have started to rise which affects e.g. the electricity market in Poland. This can be an important incentive for the development of CCS technology, especially in combination with CO2-EOR. In the case of very high costs of carbon emissions rights CCS may turn out to be a cheaper solution. Economic efficiency is the main determinant of the EOR project's success, as well as a very significant factor influencing the potential development of CO2 underground storage. Results are based on the numerical simulation of a combined CO2-EOR and CCS project. This analysis has been divided into two parts. The first uses a standard, deterministic approach, based on the DCF method and NPV indicator. It also provides a detailed sensitivity analysis, with particular reference to the impact of oil prices and the cost of carbon emissions rights on a project's profitability. The second part of the economic analysis is probabilistic and involves estimating the maximum amount of CAPEX using the Monte Carlo method. Two cases were taken into account. The first assumes that the CO2 emitter pays for CO2 storage and the price is equal to 80% of the emissions rights price (with storage revenue). In the second one the emitter does not pay for storage (without storage revenue). [ABSTRACT FROM AUTHOR]