KOH-based CO2 absorption was integrated with Ca(OH)2-triggered mineralization under ambient conditions. CO2 is chemically absorbed into the aqueous KOH solution in two consecutive absorption stages, reacting rapidly with OH- to produce CO32- and slowly with CO32- to produce HCO3- in the 1st and 2nd stage, respectively. The total CO2 loading reaches 0.95 mol CO2/mol KOH. CO2 absorption rate in the 1st stage is determined by the diffusion of CO2 and is thus independent of the OH- concentration and enhanced by increasing inlet CO2 concentration. In the 2nd stage, CO2 absorption rate is determined by the absorption reaction and linearly decreased with decreasing CO32- concentration. The prepared K2CO3 and KHCO3 solutions exhibited similar performance toward mineralization by Ca(OH)2. After 20 min of reaction under a Ca/C molar ratio of 1.0, KOH regeneration efficiency reached 75.9 % from K2CO3 and 76.1 % from KHCO3. Mineralization of the CO2-rich absorption solution occurred rapidly. Under a Ca/C molar ratio of 1.1, KOH regeneration efficiency reached 73.3 % after 5 min and 83.9 % at steady state after 20 min of reaction. Dissolution of Ca(OH)2 is likely the rate-controlling step and XRD and SEM analysis confirmed the selective conversion of Ca(OH)2 (portlandite) to CaCO3 (calcite) during the mineralization process.
{"title":"Integration of KOH-based CO2 absorption and Ca(OH)2-triggered mineralization: Process tracking and kinetic analysis","authors":"Xing Fan , Yonne Syu , Firman Bagja Juangsa , Tomohiro Nozaki","doi":"10.1016/j.ijggc.2025.104339","DOIUrl":"10.1016/j.ijggc.2025.104339","url":null,"abstract":"<div><div>KOH-based CO<sub>2</sub> absorption was integrated with Ca(OH)<sub>2</sub>-triggered mineralization under ambient conditions. CO<sub>2</sub> is chemically absorbed into the aqueous KOH solution in two consecutive absorption stages, reacting rapidly with OH<sup>-</sup> to produce CO<sub>3</sub><sup>2-</sup> and slowly with CO<sub>3</sub><sup>2-</sup> to produce HCO<sub>3</sub><sup>-</sup> in the 1st and 2nd stage, respectively. The total CO<sub>2</sub> loading reaches 0.95 mol CO<sub>2</sub>/mol KOH. CO<sub>2</sub> absorption rate in the 1st stage is determined by the diffusion of CO<sub>2</sub> and is thus independent of the OH<sup>-</sup> concentration and enhanced by increasing inlet CO<sub>2</sub> concentration. In the 2nd stage, CO<sub>2</sub> absorption rate is determined by the absorption reaction and linearly decreased with decreasing CO<sub>3</sub><sup>2-</sup> concentration. The prepared K<sub>2</sub>CO<sub>3</sub> and KHCO<sub>3</sub> solutions exhibited similar performance toward mineralization by Ca(OH)<sub>2</sub>. After 20 min of reaction under a Ca/C molar ratio of 1.0, KOH regeneration efficiency reached 75.9 % from K<sub>2</sub>CO<sub>3</sub> and 76.1 % from KHCO<sub>3</sub>. Mineralization of the CO<sub>2</sub>-rich absorption solution occurred rapidly. Under a Ca/C molar ratio of 1.1, KOH regeneration efficiency reached 73.3 % after 5 min and 83.9 % at steady state after 20 min of reaction. Dissolution of Ca(OH)<sub>2</sub> is likely the rate-controlling step and XRD and SEM analysis confirmed the selective conversion of Ca(OH)<sub>2</sub> (portlandite) to CaCO<sub>3</sub> (calcite) during the mineralization process.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"143 ","pages":"Article 104339"},"PeriodicalIF":4.6,"publicationDate":"2025-03-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143577949","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-01DOI: 10.1016/j.ijggc.2025.104338
Andrea Callioli Santi , Philip Ringrose , Jo Eidsvik , Tor Andre Haugdahl
Potential CO2 storage sites need to perform risk assessments on the likelihood of anomalous events such as leakage. The intrinsic heterogeneity of the rock system with uncertain values for the capillary threshold pressures of the various rock elements is the most likely reason for unexpected vertical migration of CO2 within a storage complex. This study shows how the Invasion Percolation Markov Chain approach can be used to address this concern. We tested the approach using detailed 3D models of the multi-layer plume at Sleipner showing that even small variations in the threshold pressures of the shales can impact the flow of CO2 into multiple accumulations. Models with and without shale breaks reveal the importance of vertical feeders and/or faults, and the geometry of the shale layers is also crucial as the CO2 strongly conforms to topography. We demonstrate that the vertical migration of CO2 at Sleipner follows a Markovian model in which the probability of later migration events is highly dependent of the probability of preceding events. This case study illustrates how the initial migration events, which have the highest probability of occurring, should be the focus of CO2 storage risk assessments.
{"title":"Invasion percolation Markov Chains – A probabilistic framework for assessing vertical CO2 migration","authors":"Andrea Callioli Santi , Philip Ringrose , Jo Eidsvik , Tor Andre Haugdahl","doi":"10.1016/j.ijggc.2025.104338","DOIUrl":"10.1016/j.ijggc.2025.104338","url":null,"abstract":"<div><div>Potential CO<sub>2</sub> storage sites need to perform risk assessments on the likelihood of anomalous events such as leakage. The intrinsic heterogeneity of the rock system with uncertain values for the capillary threshold pressures of the various rock elements is the most likely reason for unexpected vertical migration of CO<sub>2</sub> within a storage complex. This study shows how the Invasion Percolation Markov Chain approach can be used to address this concern. We tested the approach using detailed 3D models of the multi-layer plume at Sleipner showing that even small variations in the threshold pressures of the shales can impact the flow of CO<sub>2</sub> into multiple accumulations. Models with and without shale breaks reveal the importance of vertical feeders and/or faults, and the geometry of the shale layers is also crucial as the CO<sub>2</sub> strongly conforms to topography. We demonstrate that the vertical migration of CO<sub>2</sub> at Sleipner follows a Markovian model in which the probability of later migration events is highly dependent of the probability of preceding events. This case study illustrates how the initial migration events, which have the highest probability of occurring, should be the focus of CO<sub>2</sub> storage risk assessments.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"142 ","pages":"Article 104338"},"PeriodicalIF":4.6,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143534913","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-01DOI: 10.1016/j.ijggc.2025.104337
Hyonjeong Noh, Kwangu Kang
This study presents a comprehensive techno-economic analysis of large-scale CO2 transport by ship over long distances, with a focus on the economic impact of onboard boil-off gas (BOG) reliquefaction. Besides ship size and transport distance, this study includes an extended analysis of the effect of varying seawater temperatures on the reliquefaction system. Various scenarios involving three different ship sizes (40 K, 80 K, 120 K m³) and transport distances ranging from 1,000 to 20,000 km were examined to evaluate the cost implications for cross-border Carbon Capture and Storage (CCS) projects. The analysis shows that larger ships reduce costs significantly for long distances and large annual CO2 transport amounts. While the absolute cost of BOG reliquefaction increases with larger ship sizes and longer transport distances, its proportion relative to the total transport cost remains fairly constant at about 5 % of total CO2 transport costs. Additionally, seawater temperature plays a crucial role in system performance, with higher temperatures significantly increasing cost of reliquefaction system. The study also finds that BOG reliquefaction costs account for approximately 15.1 % to 17.0 % of the ship capital expenditure (CAPEX). Sensitivity analysis identifies the fuel prices and ship CAPEX as the most significant factors influencing overall transport costs. These findings underscore the importance of optimizing ship size and managing fuel costs to design economical CO2 maritime transport systems, particularly for long-distance CCS applications.
{"title":"Techno-economic analysis of large-scale CO2 ship transport with onboard boil-off gas reliquefaction","authors":"Hyonjeong Noh, Kwangu Kang","doi":"10.1016/j.ijggc.2025.104337","DOIUrl":"10.1016/j.ijggc.2025.104337","url":null,"abstract":"<div><div>This study presents a comprehensive techno-economic analysis of large-scale CO<sub>2</sub> transport by ship over long distances, with a focus on the economic impact of onboard boil-off gas (BOG) reliquefaction. Besides ship size and transport distance, this study includes an extended analysis of the effect of varying seawater temperatures on the reliquefaction system. Various scenarios involving three different ship sizes (40 K, 80 K, 120 K m³) and transport distances ranging from 1,000 to 20,000 km were examined to evaluate the cost implications for cross-border Carbon Capture and Storage (CCS) projects. The analysis shows that larger ships reduce costs significantly for long distances and large annual CO<sub>2</sub> transport amounts. While the absolute cost of BOG reliquefaction increases with larger ship sizes and longer transport distances, its proportion relative to the total transport cost remains fairly constant at about 5 % of total CO<sub>2</sub> transport costs. Additionally, seawater temperature plays a crucial role in system performance, with higher temperatures significantly increasing cost of reliquefaction system. The study also finds that BOG reliquefaction costs account for approximately 15.1 % to 17.0 % of the ship capital expenditure (CAPEX). Sensitivity analysis identifies the fuel prices and ship CAPEX as the most significant factors influencing overall transport costs. These findings underscore the importance of optimizing ship size and managing fuel costs to design economical CO<sub>2</sub> maritime transport systems, particularly for long-distance CCS applications.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"142 ","pages":"Article 104337"},"PeriodicalIF":4.6,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143510740","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-01DOI: 10.1016/j.ijggc.2025.104342
Uzezi D. Orivri , Piyali Chanda , Liz Johnson , Lars W. Koehn , Ryan M. Pollyea
Within the last three decades, there has been a remarkable increase in both the adoption and implementation of geologic CO2 sequestration, a mature and well-established method for reducing greenhouse gas emissions. Numerous research efforts have been geared toward subsurface engineering for effective containment and project scale-up in various types of geologic reservoirs, including sandstones, shales, carbonates, ultramafic, and basalts. However, only a handful of full-scale or pilot projects have been conducted in carbonate reservoirs despite their favorable petrophysical characteristics and wide prevalence across the globe. The principal challenge for CO2 sequestration in carbonate reservoirs includes concerns surrounding the effective containment of CO2 due to geologic complexities, such as high reactivity, petrophysical heterogeneity, structural compartmentalization, and mineralogical variability. Nonetheless, carbonate reservoirs are often characterized by porosity and permeability that are favorable for CO2 sequestration, and they frequently occur below low-permeability cap rock. Moreover, carbonate formations are prevalent in many geologic basins worldwide and in close proximity to anthropogenic CO2 sources. Thus, with proper engineering, carbonate formations will play a significant role in geologic CO2 sequestration to achieve the global emissions reduction target.
This paper presents a comprehensive review of carbonate reservoirs in the context of geologic CO2 sequestration. We explore their unique opportunities and challenges, including their geology, global distribution, and natural CO2 accumulations. Insights are drawn from a wide range of sources, including experimental studies, numerical and reactive transport modeling, and pilot projects. We highlight the various factors that influence effective CO2 storage, providing recommendations for successful geologic CO2 sequestration.
{"title":"Opportunities and challenges for geologic CO2 sequestration in carbonate reservoirs: A review","authors":"Uzezi D. Orivri , Piyali Chanda , Liz Johnson , Lars W. Koehn , Ryan M. Pollyea","doi":"10.1016/j.ijggc.2025.104342","DOIUrl":"10.1016/j.ijggc.2025.104342","url":null,"abstract":"<div><div>Within the last three decades, there has been a remarkable increase in both the adoption and implementation of geologic CO<sub>2</sub> sequestration, a mature and well-established method for reducing greenhouse gas emissions. Numerous research efforts have been geared toward subsurface engineering for effective containment and project scale-up in various types of geologic reservoirs, including sandstones, shales, carbonates, ultramafic, and basalts. However, only a handful of full-scale or pilot projects have been conducted in carbonate reservoirs despite their favorable petrophysical characteristics and wide prevalence across the globe. The principal challenge for CO<sub>2</sub> sequestration in carbonate reservoirs includes concerns surrounding the effective containment of CO<sub>2</sub> due to geologic complexities, such as high reactivity, petrophysical heterogeneity, structural compartmentalization, and mineralogical variability. Nonetheless, carbonate reservoirs are often characterized by porosity and permeability that are favorable for CO<sub>2</sub> sequestration, and they frequently occur below low-permeability cap rock. Moreover, carbonate formations are prevalent in many geologic basins worldwide and in close proximity to anthropogenic CO<sub>2</sub> sources. Thus, with proper engineering, carbonate formations will play a significant role in geologic CO<sub>2</sub> sequestration to achieve the global emissions reduction target.</div><div>This paper presents a comprehensive review of carbonate reservoirs in the context of geologic CO<sub>2</sub> sequestration. We explore their unique opportunities and challenges, including their geology, global distribution, and natural CO<sub>2</sub> accumulations. Insights are drawn from a wide range of sources, including experimental studies, numerical and reactive transport modeling, and pilot projects. We highlight the various factors that influence effective CO<sub>2</sub> storage, providing recommendations for successful geologic CO<sub>2</sub> sequestration.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"142 ","pages":"Article 104342"},"PeriodicalIF":4.6,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143549668","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In the pursuit of developing efficient aqueous solutions for reversible CO2 capture in post-combustion carbon capture processes, the blending of amine solvents with advanced properties has emerged as a strategic approach. Regardless of several advantages of this method, challenges persist, particularly under high oxidative feed conditions, including amine component degradation, foaming, and low rich and lean loading. In this study, we address these inherent issues by investigating the potential of carbon dots (CDs) as additives to augment the performance of mixed amines consisting of Methyl diethanolamine (MDEA), 2-amino-2-methyl-1-propanol (AMP) and Piperazine. Pilot scale operations at a 30 L solvent scale revealed that the CDs-additized mixed amine formulation exhibited robust performance over a continuous 200 h operation. The CDs-additized solvent exhibited a 23% higher rich loading than the non-additized counterpart, primarily due to enhanced mass transfer rather than the change in equilibrium loading. Additionally, the CDs-additized mixed amine solvent exhibited reduced foaming tendencies and approximately 16% lower regeneration energy consumption, even after prolonged continuous operation under oxidative flue gas condition. To evaluate the component degradation of the mixed amine solvent, a rapid and accurate Ionic chromatography (IC)-based method was developed. The present findings suggest that the CDs-additized mixed amine system holds promise as an efficient solvent for low-cost CO2 capture processes, ultimately contributing to the reduction of operational expenses in the CO2 capture process.
{"title":"Carbon dot-blended mixed amine for efficient CO2 capture under highly oxidative flue gas conditions","authors":"Prakash C․ Sahoo, Ravindra Singh, Periyasamy Sivagurunathan, Dheer Singh, Manoj Kumar, R․P Gupta, Umish Srivastava","doi":"10.1016/j.ijggc.2025.104340","DOIUrl":"10.1016/j.ijggc.2025.104340","url":null,"abstract":"<div><div>In the pursuit of developing efficient aqueous solutions for reversible CO<sub>2</sub> capture in post-combustion carbon capture processes, the blending of amine solvents with advanced properties has emerged as a strategic approach. Regardless of several advantages of this method, challenges persist, particularly under high oxidative feed conditions, including amine component degradation, foaming, and low rich and lean loading. In this study, we address these inherent issues by investigating the potential of carbon dots (CDs) as additives to augment the performance of mixed amines consisting of Methyl diethanolamine (MDEA), 2-amino-2-methyl-1-propanol (AMP) and Piperazine. Pilot scale operations at a 30 L solvent scale revealed that the CDs-additized mixed amine formulation exhibited robust performance over a continuous 200 h operation. The CDs-additized solvent exhibited a 23% higher rich loading than the non-additized counterpart, primarily due to enhanced mass transfer rather than the change in equilibrium loading. Additionally, the CDs-additized mixed amine solvent exhibited reduced foaming tendencies and approximately 16% lower regeneration energy consumption, even after prolonged continuous operation under oxidative flue gas condition. To evaluate the component degradation of the mixed amine solvent, a rapid and accurate Ionic chromatography (IC)-based method was developed. The present findings suggest that the CDs-additized mixed amine system holds promise as an efficient solvent for low-cost CO<sub>2</sub> capture processes, ultimately contributing to the reduction of operational expenses in the CO<sub>2</sub> capture process.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"142 ","pages":"Article 104340"},"PeriodicalIF":4.6,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143510741","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-21DOI: 10.1016/j.ijggc.2025.104326
Andressa Nakao, Diego Morlando, Hanna K. Knuutila
To meet the goals of the Paris Agreement, decarbonization across all sectors, including industrial facilities with multiple CO2 emission sources, is essential. Post-combustion capture, despite its high energy demands, is a promising technology for reducing carbon emissions. This study explores the feasibility of CO2 capture using a multi-absorber/combined-stripper system at an industrial refinery. CO2 capture was modeled using 30 wt.% MEA for four stacks, optimizing each to minimize energy use while achieving 95 % capture. The study also examines CO2 capture costs, operational expenses, and unit size requirements.
Results indicate that the multi-absorber/combined-stripper configuration required less solvent and had lower reboiler duties compared to individual absorber setups, though it required higher initial investment for larger equipment. Compared to flue gas mixing, the multi-absorber/combined-stripper system had higher equipment costs but lower operating expenses. While flue gas mixing had lower equipment costs, it incurred significantly higher transportation costs depending on the distance between sources and the capture site.
A sensitivity analysis on packing and steam costs showed that a 50 % reduction in packing costs could lower capital expenses by 10–30 %, while reduced steam costs could cut operating expenses by 25 %. This analysis highlights areas where cost reductions could make CO2 capture more economically viable.
{"title":"Techno-economic assessment of the multi-absorber approach at an industrial site with multiple CO2 sources","authors":"Andressa Nakao, Diego Morlando, Hanna K. Knuutila","doi":"10.1016/j.ijggc.2025.104326","DOIUrl":"10.1016/j.ijggc.2025.104326","url":null,"abstract":"<div><div>To meet the goals of the Paris Agreement, decarbonization across all sectors, including industrial facilities with multiple CO<sub>2</sub> emission sources, is essential. Post-combustion capture, despite its high energy demands, is a promising technology for reducing carbon emissions. This study explores the feasibility of CO<sub>2</sub> capture using a multi-absorber/combined-stripper system at an industrial refinery. CO<sub>2</sub> capture was modeled using 30 wt.% MEA for four stacks, optimizing each to minimize energy use while achieving 95 % capture. The study also examines CO<sub>2</sub> capture costs, operational expenses, and unit size requirements.</div><div>Results indicate that the multi-absorber/combined-stripper configuration required less solvent and had lower reboiler duties compared to individual absorber setups, though it required higher initial investment for larger equipment. Compared to flue gas mixing, the multi-absorber/combined-stripper system had higher equipment costs but lower operating expenses. While flue gas mixing had lower equipment costs, it incurred significantly higher transportation costs depending on the distance between sources and the capture site.</div><div>A sensitivity analysis on packing and steam costs showed that a 50 % reduction in packing costs could lower capital expenses by 10–30 %, while reduced steam costs could cut operating expenses by 25 %. This analysis highlights areas where cost reductions could make CO<sub>2</sub> capture more economically viable.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"142 ","pages":"Article 104326"},"PeriodicalIF":4.6,"publicationDate":"2025-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143455039","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-20DOI: 10.1016/j.ijggc.2025.104335
James P. Verdon , Ryan Schultz , Benjamin Edwards
Induced seismicity is a risk that must be managed during the development of Carbon Capture and Storage (CCS) projects. A key step in effective management of induced seismicity is the definition of a tolerable magnitude threshold, MTOL, which defines the level at which the nuisance or damage caused by induced seismicity is likely to no longer be tolerated by affected populations. Having established MTOL, induced seismicity mitigation strategies can be implemented with the objective to avoid induced events that exceed MTOL. In this study our objective is to estimate MTOL for CCS developments in the waters around the UK. Siting CCS operations offshore reduces, but does not eliminate, the risks posed by induced seismicity by increasing the distance from exposed populations. For a given induced earthquake location and magnitude, we use ground motion models, nuisance and fragility functions, and population densities, to estimate the numbers of households that would experience different levels of disturbance and damage. We use past cases of induced seismicity that were, or were not, accepted by the public to define risk tolerances based on the numbers of households that experience different levels of disturbance or damage. We sense-check our results through comparison with observed macroseismic impacts from past, natural earthquakes located in the seas around the UK. As expected, we find that the strongest control on MTOL is the distance to the shore from the proposed project. Our results can be used by CCS operators and regulators in designing induced seismicity mitigation strategies for their sites.
{"title":"Tolerable magnitudes for induced seismicity at offshore carbon capture and storage projects","authors":"James P. Verdon , Ryan Schultz , Benjamin Edwards","doi":"10.1016/j.ijggc.2025.104335","DOIUrl":"10.1016/j.ijggc.2025.104335","url":null,"abstract":"<div><div>Induced seismicity is a risk that must be managed during the development of Carbon Capture and Storage (CCS) projects. A key step in effective management of induced seismicity is the definition of a tolerable magnitude threshold, M<sub>TOL</sub>, which defines the level at which the nuisance or damage caused by induced seismicity is likely to no longer be tolerated by affected populations. Having established M<sub>TOL</sub>, induced seismicity mitigation strategies can be implemented with the objective to avoid induced events that exceed M<sub>TOL</sub>. In this study our objective is to estimate M<sub>TOL</sub> for CCS developments in the waters around the UK. Siting CCS operations offshore reduces, but does not eliminate, the risks posed by induced seismicity by increasing the distance from exposed populations. For a given induced earthquake location and magnitude, we use ground motion models, nuisance and fragility functions, and population densities, to estimate the numbers of households that would experience different levels of disturbance and damage. We use past cases of induced seismicity that were, or were not, accepted by the public to define risk tolerances based on the numbers of households that experience different levels of disturbance or damage. We sense-check our results through comparison with observed macroseismic impacts from past, natural earthquakes located in the seas around the UK. As expected, we find that the strongest control on M<sub>TOL</sub> is the distance to the shore from the proposed project. Our results can be used by CCS operators and regulators in designing induced seismicity mitigation strategies for their sites.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"142 ","pages":"Article 104335"},"PeriodicalIF":4.6,"publicationDate":"2025-02-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143455038","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-15DOI: 10.1016/j.ijggc.2025.104336
Benjamin Pullen , Aaron Cahill , Daniel Arnold
Carbon Capture and Storage (CCS) is a critical technology for mitigating climate change by securely storing CO₂ emissions underground. Former oil and gas fields are prime candidates for CCS due to their proven storage capacity, existing infrastructure, and favourable geology. However, legacy wells in these fields pose significant containment risks. Assessing these risks typically requires site-specific evaluations, which are time-intensive and impractical at scale, hindering systematic regional assessments, particularly in areas where CCS is expected to expand.
We developed a weight sum model (WSM) multi-criteria decision analysis (MCDA) approach to evaluate the containment risks of 12,264 legacy oil and gas wells in the North Sea. The model was informed by expert elicitation involving 54 global subject matter experts, 70 % of whom are industry professionals with over a decade of CCS experience. Wellbores were assigned consideration scores reflecting their containment risks based on geospatial, temporal, and engineering factors, weighted by expert consensus. The mean consideration score was 0.55 (range: 0–1), with outlier thresholds at 0.74 and 0.36, identifying 506 wells with significantly higher or lower risks to containment.
Among Scotland's nine most promising CO₂ storage sites, the Miller Oil Field and Captain Sandstone Fairway represent the highest and lowest cases of consideration score, respectively. By integrating expert knowledge into an MCDA framework, this approach provides a systematic method to prioritise wellbores for further evaluation based on risk profiles, supplementing traditional case-by-case assessments. It offers a scalable solution for managing containment risks across domains with multiple planned CCS projects.
{"title":"Differentiating legacy wellbores in the scottish north sea using multi-criteria decision analysis with a view to minimising containment risk for carbon capture and storage","authors":"Benjamin Pullen , Aaron Cahill , Daniel Arnold","doi":"10.1016/j.ijggc.2025.104336","DOIUrl":"10.1016/j.ijggc.2025.104336","url":null,"abstract":"<div><div>Carbon Capture and Storage (CCS) is a critical technology for mitigating climate change by securely storing CO₂ emissions underground. Former oil and gas fields are prime candidates for CCS due to their proven storage capacity, existing infrastructure, and favourable geology. However, legacy wells in these fields pose significant containment risks. Assessing these risks typically requires site-specific evaluations, which are time-intensive and impractical at scale, hindering systematic regional assessments, particularly in areas where CCS is expected to expand.</div><div>We developed a weight sum model (WSM) multi-criteria decision analysis (MCDA) approach to evaluate the containment risks of 12,264 legacy oil and gas wells in the North Sea. The model was informed by expert elicitation involving 54 global subject matter experts, 70 % of whom are industry professionals with over a decade of CCS experience. Wellbores were assigned consideration scores reflecting their containment risks based on geospatial, temporal, and engineering factors, weighted by expert consensus. The mean consideration score was 0.55 (range: 0–1), with outlier thresholds at 0.74 and 0.36, identifying 506 wells with significantly higher or lower risks to containment.</div><div>Among Scotland's nine most promising CO₂ storage sites, the Miller Oil Field and Captain Sandstone Fairway represent the highest and lowest cases of consideration score, respectively. By integrating expert knowledge into an MCDA framework, this approach provides a systematic method to prioritise wellbores for further evaluation based on risk profiles, supplementing traditional case-by-case assessments. It offers a scalable solution for managing containment risks across domains with multiple planned CCS projects.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"142 ","pages":"Article 104336"},"PeriodicalIF":4.6,"publicationDate":"2025-02-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143420837","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-08DOI: 10.1016/j.ijggc.2025.104334
Khizar Abid , Felipe Baena , Catalin Teodoriu , Junghun Leem , Latief Riyanto , Yon Azwa Sazali , Muhammad Syafeeq
For the repurposing of plug and abandoned (P&A) wells for the Carbon Capture and Sequestration (CCS) project, it is essential to know the condition of the well plugs. These plugs serve as a barrier that restricts the movement of unwanted fluids to the surface. Therefore, the integrity of the cement plug becomes essential. Thus, this study focuses on the interfacial debonding strength of the cement, which is a crucial parameter that must be quantified to find the integrity of the plug. The methodology used for this testing consisted of the novel apparatus established at the University of Oklahoma to find the debonding strength of the cement. The cement used for these experiments consisted of neat Class G mixed according to the API standard. The samples were cured for seven days in the pipe, which had a diameter of 2″ and a height of 6″. Different test variations were conducted, including thermal cyclic loading, transient, elevated, and room temperature tests. The samples were heated with the help of a thermal jacket, whereas the water for the hydraulic debonding test consisted of room and elevated temperature (95 °C). The experiments found that before the complete debonding of the cement plug, the leakage of water (wetting phase) on the sample surface was observed, which happened at a lower pressure than the interfacial debonding pressure. This wetting phase starts at a low pressure, i.e., around 500 psi, compared to debonding pressure, which mainly was above 1,000 psi. It was also noted that samples exposed to temperature testing (elevated temperature, transient, and cyclic loading) had lower interfacial debonding strength than those tested at room temperature. The final failure mode of these samples was due to the shear debonding, which was facilitated by the development of the microannuli in the testing samples, especially when the cement was exposed to temperature testing. Therefore, care should be taken, and proper calculations should be performed when using the P&A wells that are exposed to high-temperature conditions for the CCS project.
{"title":"Experimental investigation of the interfacial debonding strength of class G cement and the implications to well integrity","authors":"Khizar Abid , Felipe Baena , Catalin Teodoriu , Junghun Leem , Latief Riyanto , Yon Azwa Sazali , Muhammad Syafeeq","doi":"10.1016/j.ijggc.2025.104334","DOIUrl":"10.1016/j.ijggc.2025.104334","url":null,"abstract":"<div><div>For the repurposing of plug and abandoned (P&A) wells for the Carbon Capture and Sequestration (CCS) project, it is essential to know the condition of the well plugs. These plugs serve as a barrier that restricts the movement of unwanted fluids to the surface. Therefore, the integrity of the cement plug becomes essential. Thus, this study focuses on the interfacial debonding strength of the cement, which is a crucial parameter that must be quantified to find the integrity of the plug. The methodology used for this testing consisted of the novel apparatus established at the University of Oklahoma to find the debonding strength of the cement. The cement used for these experiments consisted of neat Class G mixed according to the API standard. The samples were cured for seven days in the pipe, which had a diameter of 2″ and a height of 6″. Different test variations were conducted, including thermal cyclic loading, transient, elevated, and room temperature tests. The samples were heated with the help of a thermal jacket, whereas the water for the hydraulic debonding test consisted of room and elevated temperature (95 °C). The experiments found that before the complete debonding of the cement plug, the leakage of water (wetting phase) on the sample surface was observed, which happened at a lower pressure than the interfacial debonding pressure. This wetting phase starts at a low pressure, i.e., around 500 psi, compared to debonding pressure, which mainly was above 1,000 psi. It was also noted that samples exposed to temperature testing (elevated temperature, transient, and cyclic loading) had lower interfacial debonding strength than those tested at room temperature. The final failure mode of these samples was due to the shear debonding, which was facilitated by the development of the microannuli in the testing samples, especially when the cement was exposed to temperature testing. Therefore, care should be taken, and proper calculations should be performed when using the P&A wells that are exposed to high-temperature conditions for the CCS project.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"142 ","pages":"Article 104334"},"PeriodicalIF":4.6,"publicationDate":"2025-02-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143369781","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-01DOI: 10.1016/j.ijggc.2025.104320
Jonas Simon Junker , Anne Obermann , Martin Voigt , Hansruedi Maurer , Ovie Emmanuel Eruteya , Andrea Moscariello , Stefan Wiemer , Alba Zappone
In-situ CO2 mineral storage is moving into focus as a technology for storing substantial amounts of CO2 that would otherwise be released into the atmosphere. However, one of the main drawbacks of this technology is that it requires large amounts of freshwater for injection. To overcome this obstacle, a pilot project in Helguvik, Iceland is testing the effectiveness of carbon mineralization using saline water, similar to seawater. Here, we describe the project and the geophysical characterization of the pilot site using crosshole seismic- and single-hole electrical resistivity measurements. The data show that the subsurface strata are dominated by decameter-thick horizontal layers of basaltic strata, with varying seismic velocities and electrical resistivities. Variations in both seismic velocity and electrical resistivity are in excellent agreement and delineate high and low porosity zones in the subsurface. The results are compared to well logging results and the mineralogical composition of drill cuttings to build a comprehensive subsurface model of the future CO2 mineral storage reservoir, highlighting potential pathways for the injected CO2-charged waters.
{"title":"Geophysical characterization of the in-situ CO2 mineral storage pilot site in Helguvik, Iceland","authors":"Jonas Simon Junker , Anne Obermann , Martin Voigt , Hansruedi Maurer , Ovie Emmanuel Eruteya , Andrea Moscariello , Stefan Wiemer , Alba Zappone","doi":"10.1016/j.ijggc.2025.104320","DOIUrl":"10.1016/j.ijggc.2025.104320","url":null,"abstract":"<div><div>In-situ CO<sub>2</sub> mineral storage is moving into focus as a technology for storing substantial amounts of CO<sub>2</sub> that would otherwise be released into the atmosphere. However, one of the main drawbacks of this technology is that it requires large amounts of freshwater for injection. To overcome this obstacle, a pilot project in Helguvik, Iceland is testing the effectiveness of carbon mineralization using saline water, similar to seawater. Here, we describe the project and the geophysical characterization of the pilot site using crosshole seismic- and single-hole electrical resistivity measurements. The data show that the subsurface strata are dominated by decameter-thick horizontal layers of basaltic strata, with varying seismic velocities and electrical resistivities. Variations in both seismic velocity and electrical resistivity are in excellent agreement and delineate high and low porosity zones in the subsurface. The results are compared to well logging results and the mineralogical composition of drill cuttings to build a comprehensive subsurface model of the future CO<sub>2</sub> mineral storage reservoir, highlighting potential pathways for the injected CO<sub>2</sub>-charged waters.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"141 ","pages":"Article 104320"},"PeriodicalIF":4.6,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143095746","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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