Given the severe climate crisis and the urgent need to limit the adverse effects of global warming, drastic changes are required across various industries. Among them, the iron and steel sector is a major contributor to greenhouse gas emissions, accounting for approximately 7 % of global CO2 emissions. This study proposes the integration of innovative carbon capture technologies, such as DISPLACE and CASOH, into a conventional BF-BOF (Blast Furnace-Basic Oxygen Furnace) steelmaking process. A comprehensive techno-economic analysis was conducted, supported by simulations performed in Aspen Plus, to optimize the integration of these technologies. The study suggests a redesigned gas distribution system within the BF-BOF steel plant, incorporating oxy-fired units to facilitate post-combustion carbon capture and minimize the plant emissions. The analysis reveals that, employing CASOH for pre-combustion CO2 capture to decarbonize a mixture of BFG (Blast Furnace Gas) and BOFG (Basic Oxygen Furnace Gas), combined with DISPLACE for decarbonizing flue gases from hot stoves, sinter plant, and reheating ovens, 72 % reduction in CO2 emissions and a SPECCA around 0 GJ/tCO2 can be achieved. This is attainable within a renewable electricity scenario, at a cost of 138 € per ton of CO2 avoided. Lower CO2 avoidance values can also be achieved by treating less exhaust gases with reduction in both SPECCA and costs.
{"title":"Integration of CASOH and DISPLACE technologies in a steel plant for the mitigation of CO2 emissions – A techno-economic analysis","authors":"Nicola Zecca , Santiago Zapata Boada , Vincenzo Spallina , Giampaolo Manzolini","doi":"10.1016/j.ijggc.2025.104478","DOIUrl":"10.1016/j.ijggc.2025.104478","url":null,"abstract":"<div><div>Given the severe climate crisis and the urgent need to limit the adverse effects of global warming, drastic changes are required across various industries. Among them, the iron and steel sector is a major contributor to greenhouse gas emissions, accounting for approximately 7 % of global CO<sub>2</sub> emissions. This study proposes the integration of innovative carbon capture technologies, such as DISPLACE and CASOH, into a conventional BF-BOF (Blast Furnace-Basic Oxygen Furnace) steelmaking process. A comprehensive techno-economic analysis was conducted, supported by simulations performed in Aspen Plus, to optimize the integration of these technologies. The study suggests a redesigned gas distribution system within the BF-BOF steel plant, incorporating oxy-fired units to facilitate post-combustion carbon capture and minimize the plant emissions. The analysis reveals that, employing CASOH for pre-combustion CO<sub>2</sub> capture to decarbonize a mixture of BFG (Blast Furnace Gas) and BOFG (Basic Oxygen Furnace Gas), combined with DISPLACE for decarbonizing flue gases from hot stoves, sinter plant, and reheating ovens, 72 % reduction in CO<sub>2</sub> emissions and a SPECCA around 0 GJ/t<sub>CO2</sub> can be achieved. This is attainable within a renewable electricity scenario, at a cost of 138 € per ton of CO<sub>2</sub> avoided. Lower CO<sub>2</sub> avoidance values can also be achieved by treating less exhaust gases with reduction in both SPECCA and costs.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"147 ","pages":"Article 104478"},"PeriodicalIF":5.2,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145217709","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 : 2025-10-01DOI: 10.1016/j.ijggc.2025.104487
Seunghwan Baek , Leon Hibbard , Nate Mitchell , Delphine Appriou , Robert Dilmore , Md․Lal Mamud
For geologic systems where carbon dioxide (CO2) is injected underground, existing wells represent potential pathways for fluid migration. This study introduces a novel deep learning model to quantify the likelihood and potential magnitude of fluid migration through wellbores at sites with intermediate aquifers or thief zones between the injection units and underground drinking water sources. Synthetic datasets, generated using reservoir simulations, captured a wide range of subsurface conditions, well attributes, operational parameters, and fluid migration scenarios. Among the regression models developed to predict brine and CO2 leakage rates and CO2 saturations along leaky wellbores, convolutional neural network (CNN) outperformed both Light Gradient Boosting Machine and deep neural network. Additionally, a CNN-based classification model was created to predict whether brine and CO₂ would leak along a wellbore, further improving performance over regression alone. The best models were integrated into the National Risk Assessment Partnership Open-source Integrated Assessment Model for rapid, stochastic assessment of storage system containment and leakage risks. A case study demonstrated the model’s ability to simulate fluid migration through existing wells with multiple intermediate aquifers. This computationally efficient wellbore model offers value in support of site performance evaluation and risk-informed decision making by stakeholders.
{"title":"Deep-learning-enhanced assessment of wellbore barrier effectiveness in geologic storage systems with intermediate aquifers","authors":"Seunghwan Baek , Leon Hibbard , Nate Mitchell , Delphine Appriou , Robert Dilmore , Md․Lal Mamud","doi":"10.1016/j.ijggc.2025.104487","DOIUrl":"10.1016/j.ijggc.2025.104487","url":null,"abstract":"<div><div>For geologic systems where carbon dioxide (CO<sub>2</sub>) is injected underground, existing wells represent potential pathways for fluid migration. This study introduces a novel deep learning model to quantify the likelihood and potential magnitude of fluid migration through wellbores at sites with intermediate aquifers or thief zones between the injection units and underground drinking water sources. Synthetic datasets, generated using reservoir simulations, captured a wide range of subsurface conditions, well attributes, operational parameters, and fluid migration scenarios. Among the regression models developed to predict brine and CO<sub>2</sub> leakage rates and CO<sub>2</sub> saturations along leaky wellbores, convolutional neural network (CNN) outperformed both Light Gradient Boosting Machine and deep neural network. Additionally, a CNN-based classification model was created to predict whether brine and CO₂ would leak along a wellbore, further improving performance over regression alone. The best models were integrated into the National Risk Assessment Partnership Open-source Integrated Assessment Model for rapid, stochastic assessment of storage system containment and leakage risks. A case study demonstrated the model’s ability to simulate fluid migration through existing wells with multiple intermediate aquifers. This computationally efficient wellbore model offers value in support of site performance evaluation and risk-informed decision making by stakeholders.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"147 ","pages":"Article 104487"},"PeriodicalIF":5.2,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145262990","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 : 2025-10-01DOI: 10.1016/j.ijggc.2025.104483
Sahar Bakhshian , Hassan Dashtian , Arya Chavoshi , Mahdi Haddad , Susan D. Hovorka , Michael H. Young , Katherine D. Romanak , Mohsen Ahmadian
The risk of CO and brine leakage to environmental receptors is one of the main concerns in geologic CO storage. Legacy wells from past oil and gas activities may be located within the area of review, necessitating continuous monitoring to ensure they are properly sealed to prevent fluid migration. Deployment of an efficient monitoring system for early detection of leakage from failed wells is imperative to mitigate environmental and financial risks. This study proposes a cost-effective near-surface monitoring package capable of real-time surveillance of plugged and abandoned (P&A) wells. Controlled pilot-scale CO and water release experiments were conducted to identify soil properties that are most sensitive to leakage in the near-surface vadose zone above P&A well stubs. Multiple release scenarios with different rates and durations were implemented, and machine learning techniques were applied to identify anomalous data patterns caused by leakage. Among measured parameters, soil electrical conductivity (EC) was the most sensitive indicator of leakage. Several machine learning models, including Logistic Regression, K-Nearest Neighbors, Support Vector Machine, Random Forest, XGBoost, and LightGBM, were evaluated for anomaly detection in EC data. Tree-based models outperformed traditional classifiers, with Random Forest achieving the lowest false alarm rate and XGBoost yielding the highest detection rate. Uncertainty quantification using Conformal Prediction showed that LightGBM had the highest confidence in anomaly prediction. Although the experiments were performed under controlled conditions, the approach demonstrates a relatively promising, low-cost monitoring technique for leakage detection for near-surface monitoring of legacy wells.
{"title":"Near-Surface Monitoring of Plugged and Abandoned Wells for Real-Time Leakage Detection in Geologic Carbon Storage","authors":"Sahar Bakhshian , Hassan Dashtian , Arya Chavoshi , Mahdi Haddad , Susan D. Hovorka , Michael H. Young , Katherine D. Romanak , Mohsen Ahmadian","doi":"10.1016/j.ijggc.2025.104483","DOIUrl":"10.1016/j.ijggc.2025.104483","url":null,"abstract":"<div><div>The risk of CO<span><math><msub><mrow></mrow><mrow><mn>2</mn></mrow></msub></math></span> and brine leakage to environmental receptors is one of the main concerns in geologic CO<span><math><msub><mrow></mrow><mrow><mn>2</mn></mrow></msub></math></span> storage. Legacy wells from past oil and gas activities may be located within the area of review, necessitating continuous monitoring to ensure they are properly sealed to prevent fluid migration. Deployment of an efficient monitoring system for early detection of leakage from failed wells is imperative to mitigate environmental and financial risks. This study proposes a cost-effective near-surface monitoring package capable of real-time surveillance of plugged and abandoned (P&A) wells. Controlled pilot-scale CO<span><math><msub><mrow></mrow><mrow><mn>2</mn></mrow></msub></math></span> and water release experiments were conducted to identify soil properties that are most sensitive to leakage in the near-surface vadose zone above P&A well stubs. Multiple release scenarios with different rates and durations were implemented, and machine learning techniques were applied to identify anomalous data patterns caused by leakage. Among measured parameters, soil electrical conductivity (EC) was the most sensitive indicator of leakage. Several machine learning models, including Logistic Regression, K-Nearest Neighbors, Support Vector Machine, Random Forest, XGBoost, and LightGBM, were evaluated for anomaly detection in EC data. Tree-based models outperformed traditional classifiers, with Random Forest achieving the lowest false alarm rate and XGBoost yielding the highest detection rate. Uncertainty quantification using Conformal Prediction showed that LightGBM had the highest confidence in anomaly prediction. Although the experiments were performed under controlled conditions, the approach demonstrates a relatively promising, low-cost monitoring technique for leakage detection for near-surface monitoring of legacy wells.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"147 ","pages":"Article 104483"},"PeriodicalIF":5.2,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145262992","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 : 2025-10-01DOI: 10.1016/j.ijggc.2025.104493
Kevin L. McCormack , Tom Bratton , Adewale Amosu , Lianjie Huang , David Li , Jeffrey Burghardt , William Ampomah
A key consideration when planning the injection of fluids into the subsurface is the potential for induced seismicity. While avoiding major faults during injection is ideal, a detailed understanding of the fault slip potential of faults at the site enables operators to prevent large seismic events. Induced seismicity forecasting relies on combining fault surface geometries—here, we utilize ant-tracking of three-dimensional seismic images to map faults in the San Juan Basin, New Mexico—and the state of stress, which we evaluate using three distinct models. The fault slip potential is quantified using the Coulomb failure function, which measures proximity to frictional failure, based on the states of stress and fault geometries for both individual faults and a complete fault suite (n = 51). The differences observed across the three stress states are subtle, but the statistical distributions of the Coulomb failure function suggest that uncertainties vary between the models. Notably, our findings reveal that both the linear-elastic approximation and the failure criterion yield similar fault slip potentials. Consequently, the choice of method for determining the state of stress most relevant to a project depends on the specific requirements and context of the project.
{"title":"A comparative analysis of states of stress for analyzing fault slip potential","authors":"Kevin L. McCormack , Tom Bratton , Adewale Amosu , Lianjie Huang , David Li , Jeffrey Burghardt , William Ampomah","doi":"10.1016/j.ijggc.2025.104493","DOIUrl":"10.1016/j.ijggc.2025.104493","url":null,"abstract":"<div><div>A key consideration when planning the injection of fluids into the subsurface is the potential for induced seismicity. While avoiding major faults during injection is ideal, a detailed understanding of the fault slip potential of faults at the site enables operators to prevent large seismic events. Induced seismicity forecasting relies on combining fault surface geometries—here, we utilize ant-tracking of three-dimensional seismic images to map faults in the San Juan Basin, New Mexico—and the state of stress, which we evaluate using three distinct models. The fault slip potential is quantified using the Coulomb failure function, which measures proximity to frictional failure, based on the states of stress and fault geometries for both individual faults and a complete fault suite (<em>n</em> = 51). The differences observed across the three stress states are subtle, but the statistical distributions of the Coulomb failure function suggest that uncertainties vary between the models. Notably, our findings reveal that both the linear-elastic approximation and the failure criterion yield similar fault slip potentials. Consequently, the choice of method for determining the state of stress most relevant to a project depends on the specific requirements and context of the project.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"147 ","pages":"Article 104493"},"PeriodicalIF":5.2,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145325752","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 : 2025-10-01DOI: 10.1016/j.ijggc.2025.104489
Ali Barati Harooni, Mehran Sohrabi Sedeh, Seyed Amir Farzaneh, Jalal Fahimpour
The injection of CO₂ into underground formations is critical for enhancing hydrocarbon recovery and mitigating climate change through Carbon Capture and Storage (CCS) projects. In these operations, maintaining the integrity of wellbore cement—the primary barrier preventing CO₂ leakage—is essential for the success and safety of both active and abandoned wells. Any compromise in cement integrity could lead to CO₂ leakage, undermining injection efforts and posing serious environmental risks. Therefore, understanding CO₂ flow through wellbore cement is crucial.
This study evaluates the structural characteristics and gas permeability of short-term cured Neat and lightweight cement under simulated bottomhole conditions, representing early-stage exposure to CO₂ after cementing operations. Samples were prepared following optimized API-standard procedures. XRD analysis quantified hydration levels, while CT scans and MICP tests provided insights into cement microstructure and pore size distribution, informing gas flow behavior during permeability testing.
Experimental results showed significant differences between the two cements. Neat cement displayed a uniform, fracture-free matrix with ∼38 % porosity and a mean pore throat radius of 0.041 µm, resulting in low gas permeability (18–21 µD) and particularly low CO₂ permeability due to its higher density and adsorption properties. Lightweight cement, however, exhibited a fractured structure, higher porosity (46 %), and a smaller mean pore throat radius (0.011 µm), leading to much higher gas permeabilities (1.1–1.4 mD).
These findings underscore the importance of cement type and microstructure in controlling CO₂ migration, emphasizing the need for optimized cement designs to ensure long-term well integrity in CCS applications.
{"title":"Experimental investigation of gas permeability and flow behaviour in wellbore cements","authors":"Ali Barati Harooni, Mehran Sohrabi Sedeh, Seyed Amir Farzaneh, Jalal Fahimpour","doi":"10.1016/j.ijggc.2025.104489","DOIUrl":"10.1016/j.ijggc.2025.104489","url":null,"abstract":"<div><div>The injection of CO₂ into underground formations is critical for enhancing hydrocarbon recovery and mitigating climate change through Carbon Capture and Storage (CCS) projects. In these operations, maintaining the integrity of wellbore cement—the primary barrier preventing CO₂ leakage—is essential for the success and safety of both active and abandoned wells. Any compromise in cement integrity could lead to CO₂ leakage, undermining injection efforts and posing serious environmental risks. Therefore, understanding CO₂ flow through wellbore cement is crucial.</div><div>This study evaluates the structural characteristics and gas permeability of short-term cured Neat and lightweight cement under simulated bottomhole conditions, representing early-stage exposure to CO₂ after cementing operations. Samples were prepared following optimized API-standard procedures. XRD analysis quantified hydration levels, while CT scans and MICP tests provided insights into cement microstructure and pore size distribution, informing gas flow behavior during permeability testing.</div><div>Experimental results showed significant differences between the two cements. Neat cement displayed a uniform, fracture-free matrix with ∼38 % porosity and a mean pore throat radius of 0.041 µm, resulting in low gas permeability (18–21 µD) and particularly low CO₂ permeability due to its higher density and adsorption properties. Lightweight cement, however, exhibited a fractured structure, higher porosity (46 %), and a smaller mean pore throat radius (0.011 µm), leading to much higher gas permeabilities (1.1–1.4 mD).</div><div>These findings underscore the importance of cement type and microstructure in controlling CO₂ migration, emphasizing the need for optimized cement designs to ensure long-term well integrity in CCS applications.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"147 ","pages":"Article 104489"},"PeriodicalIF":5.2,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145325753","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 : 2025-10-01DOI: 10.1016/j.ijggc.2025.104492
Dunyu Liu , Wei Li , Qian Cheng , Jing Jin , Jun Chen
{"title":"Retraction notice to “Measurement and modeling of nitrogen oxides absorption in a pressurized reactor relevant to CO2 compression and purification process” [International Journal of Greenhouse Gas Control 100 (2020) 103107]","authors":"Dunyu Liu , Wei Li , Qian Cheng , Jing Jin , Jun Chen","doi":"10.1016/j.ijggc.2025.104492","DOIUrl":"10.1016/j.ijggc.2025.104492","url":null,"abstract":"","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"147 ","pages":"Article 104492"},"PeriodicalIF":5.2,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145412488","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 : 2025-10-01DOI: 10.1016/j.ijggc.2025.104485
Chinemerem C. Okezie , Alexander P. Bump
Over 50 geologic carbon storage (GCS) projects are now advancing on the US Gulf Coast. Comparing their stated goals with the number of currently permitted wells suggests some planned injection rates over 5Mtpa/well. Modelling supports these numbers, but Gulf Coast reservoirs are structurally and stratigraphically complicated, with potential for compartmentalization that may lead to unanticipated pressure buildup and premature loss of injectivity. We seek to calibrate that risk by looking at historical saltwater disposal (SWD) on the Texas Gulf Coast. From 1990 to 2020, over 20 billion barrels of brine (∼2 Gt CO2-equivalent) were injected into non-productive reservoirs, largely without adverse effect. Analysis of injectivity index for these wells shows that most are poor performers in lifetime average terms, with few wells clearly capable of 1Mtpa CO2-equivalent. However, intermittent injection, not captured by the data, may explain apparently poor performance. Analysis of monthly injectivity index shows that over half the wells had at least one month indicative of >1Mtpa CO2-equivalent capability. Anecdotal evidence, and even our analysis, suggests that all wells eventually lose injectivity, but we can see no evidence of pressure buildup or declining performance at the formation level. More commonly, the cause seems to be formation damage, apparently mostly resulting from impurities in the injected brines—microbes, incompatible chemistry and/or entrained solids. We believe that GCS wells are likely to perform better than SWD wells, owing to better location, superior planning, and a cleaner injection stream. These results suggest cautious optimism for large-scale GCS on the Gulf Coast.
{"title":"Calibrating large-scale injection: Using saltwater disposal experience to predict CCS performance on the Texas Gulf Coast","authors":"Chinemerem C. Okezie , Alexander P. Bump","doi":"10.1016/j.ijggc.2025.104485","DOIUrl":"10.1016/j.ijggc.2025.104485","url":null,"abstract":"<div><div>Over 50 geologic carbon storage (GCS) projects are now advancing on the US Gulf Coast. Comparing their stated goals with the number of currently permitted wells suggests some planned injection rates over 5Mtpa/well. Modelling supports these numbers, but Gulf Coast reservoirs are structurally and stratigraphically complicated, with potential for compartmentalization that may lead to unanticipated pressure buildup and premature loss of injectivity. We seek to calibrate that risk by looking at historical saltwater disposal (SWD) on the Texas Gulf Coast. From 1990 to 2020, over 20 billion barrels of brine (∼2 Gt CO<sub>2</sub>-equivalent) were injected into non-productive reservoirs, largely without adverse effect. Analysis of injectivity index for these wells shows that most are poor performers in lifetime average terms, with few wells clearly capable of 1Mtpa CO<sub>2</sub>-equivalent. However, intermittent injection, not captured by the data, may explain apparently poor performance. Analysis of monthly injectivity index shows that over half the wells had at least one month indicative of >1Mtpa CO<sub>2</sub>-equivalent capability. Anecdotal evidence, and even our analysis, suggests that all wells eventually lose injectivity, but we can see no evidence of pressure buildup or declining performance at the formation level. More commonly, the cause seems to be formation damage, apparently mostly resulting from impurities in the injected brines—microbes, incompatible chemistry and/or entrained solids. We believe that GCS wells are likely to perform better than SWD wells, owing to better location, superior planning, and a cleaner injection stream. These results suggest cautious optimism for large-scale GCS on the Gulf Coast.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"147 ","pages":"Article 104485"},"PeriodicalIF":5.2,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145217710","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 : 2025-10-01DOI: 10.1016/j.ijggc.2025.104479
Wassim Dbouk , Damon Teagle , Lindsay-Marie Armstrong , Johanna Hjalmarsson , Stephen Turnock , Alexandros Ntovas
Carbon Capture and Storage (CCS) is an essential component of the UK Government’s net-zero strategy. Policies emphasize the need for flexible and accessible CO₂ transport and storage networks, with shipping emerging as a key non-pipeline transport modality to connect industrial clusters to offshore storage. In this article, we assess whether current health and safety and major accident prevention regulations adequately govern the risks posed by expanding CO₂ handling and storage in UK ports to support CCS deployment.
Our analysis identifies three regulatory gaps. First, while the Port Marine Safety Code addresses regulatory complexity in UK ports through establishing uniform national standards for marine safety, it cannot regulate the emerging risks of anticipated large-scale CO₂ shipping activities without clear performance standards in specific legislation. Second, duly appointed harbor masters must be well-informed to effectively exercise the powers granted under the Dangerous Goods in Harbour Areas Regulations (DGHAR) to reduce serious accident risks associated with increased CO₂ shipping. Third, the Control of Major Accident Hazards Regulations (COMAH) currently exclude temporary CO₂ storage and do not include CO₂ within their scope, limiting their effectiveness for major accident prevention in port storage scenarios.
To address these gaps, we recommend issuing tailored guidance under DGHAR to clarify risk management responsibilities for CO₂ shipping and amending COMAH to include CO₂ storage and recognize CO₂ as a dangerous substance. These reforms are essential to protect port communities, ensure robust risk management, and support the safe, sustainable expansion of CO₂ shipping as a critical enabler of CCS.
{"title":"Critical review and recommendations for strengthening health and safety and major accident prevention regulations for carbon capture and storage in UK ports","authors":"Wassim Dbouk , Damon Teagle , Lindsay-Marie Armstrong , Johanna Hjalmarsson , Stephen Turnock , Alexandros Ntovas","doi":"10.1016/j.ijggc.2025.104479","DOIUrl":"10.1016/j.ijggc.2025.104479","url":null,"abstract":"<div><div>Carbon Capture and Storage (CCS) is an essential component of the UK Government’s net-zero strategy. Policies emphasize the need for flexible and accessible CO₂ transport and storage networks, with shipping emerging as a key non-pipeline transport modality to connect industrial clusters to offshore storage. In this article, we assess whether current health and safety and major accident prevention regulations adequately govern the risks posed by expanding CO₂ handling and storage in UK ports to support CCS deployment.</div><div>Our analysis identifies three regulatory gaps. First, while the Port Marine Safety Code addresses regulatory complexity in UK ports through establishing uniform national standards for marine safety, it cannot regulate the emerging risks of anticipated large-scale CO₂ shipping activities without clear performance standards in specific legislation. Second, duly appointed harbor masters must be well-informed to effectively exercise the powers granted under the Dangerous Goods in Harbour Areas Regulations (DGHAR) to reduce serious accident risks associated with increased CO₂ shipping. Third, the Control of Major Accident Hazards Regulations (COMAH) currently exclude temporary CO₂ storage and do not include CO₂ within their scope, limiting their effectiveness for major accident prevention in port storage scenarios.</div><div>To address these gaps, we recommend issuing tailored guidance under DGHAR to clarify risk management responsibilities for CO₂ shipping and amending COMAH to include CO₂ storage and recognize CO₂ as a dangerous substance. These reforms are essential to protect port communities, ensure robust risk management, and support the safe, sustainable expansion of CO₂ shipping as a critical enabler of CCS.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"147 ","pages":"Article 104479"},"PeriodicalIF":5.2,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145217781","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 : 2025-10-01DOI: 10.1016/j.ijggc.2025.104490
Benjamin J. Drewry, Gary T. Rochelle
Water washing is an important component of amine scrubbing that is used to remove vaporized amine and degradation products from absorber outlet flue gas. After 3700 hours of pilot testing of CO2 capture from a natural gas combined cycle flue gas using 30 wt % piperazine (PZ) in 2023, single- and two-stage water washes were tested for 800 operating hours, including an acid wash. The washed flue gas and aqueous wash liquid were analyzed by a Proton-Transfer-Reaction Time-of-Flight Mass Spectrometer (PTR-ToF-MS) and ion chromatography for amines and amine degradation products. These data were used to validate Aspen Plus® and offline models of water wash performance. The models using the Song correlations to estimate gas film mass transfer coefficients predicted PZ transfer units (ln (yin/yout) in the single-stage wash with an accuracy of ± 20%; two-stage simulations were less accurate. Thermodynamic equilibrium and mass-transfer limitations were identified for amine absorption. A simplified thermodynamic and mass transfer model previously developed to validate PZ Aspen Plus® results and adapted for other solvents was expanded to include degradation products. The offline model successfully simulated removal of 1-methylpiperazine (MPZ), 1-ethylpiperazine (EPZ), mononitrosopiperazine (MNPZ), methylamine, and ethylamine. Uncertainty in modeled emissions resulted from unsteady-state measurements and inaccuracies of volatility correlations at dilute conditions.
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Pub Date : 2025-10-01DOI: 10.1016/j.ijggc.2025.104486
Eric. R. Upchurch , Yaxin Liu , Lei Zhou , Bjoern-Tore Anfinsen
This study focusses on understanding the physics of halting subsea CO2 blowouts using dynamic-kill methods. A computational fluid dynamics (CFD) model that replicates the thermophysical properties of CO2 is used. We also analyze analogous CH4 scenarios, juxtaposing the impacts of both fluids.
We simulate sixteen blowout/dynamic-kill scenarios, representing all combinations of water depth (305 or 762 m), blowout rate (2.83 or 11.34 MMm3/d), relief well intercept depth (1220 or 1830 m TVD BML), and reservoir fluid (CO2 or CH4). This defines a sufficiently broad simulation space for gaining insight into the heretofore undefined aspects of dynamically killing subsea CO2 blowouts – and how they differ from CH4 blowouts.
CO2‘s thermophysical properties generally reduce dynamic kill pumping rates to one-third of that required for CH4 blowouts when using 1801-kg/m3 kill fluid. CO2 phase change at elevated pressures drives most of the difference. During a dynamic kill, increases in well pressure can cause CO2 density to jump from 68 to 904 kg/m3, while CH4 exhibits a modest 22 to 192 kg/m3 range. This radical difference in density-vs-pressure behavior results in CO2 blowouts being generally easier to kill than CH4 blowouts. Other differences in the dynamic killing of CO2 and CH4 blowouts, like multiphase flow behavior, are detailed in the paper to explain their impacts.
We also find that CO2 blowouts in shallower water can generate sub-freezing temperatures at the wellhead, resulting in ice and/or hydrate formation – a result that can introduce unintended complexity into the overall response to a subsea blowout.
这项研究的重点是了解使用动态压井方法阻止海底二氧化碳井喷的物理原理。计算流体动力学（CFD）模型复制了CO2的热物理性质。我们还分析了类似的CH4情景，并列分析了两种流体的影响。我们模拟了16种井喷/动态压井情景，代表了水深（305或762 m）、井喷速率（2.83或11.34 MMm3/d）、减压井拦截深度（1220或1830 m TVD BML）和储层流体（CO2或CH4）的所有组合。这定义了一个足够广泛的模拟空间，可以深入了解海底CO2井喷动态灭井的未定义方面，以及它们与CH4井喷的区别。当使用1801-kg/m3压井液时，CO2的热物理性质通常会将动态压井泵送速率降低到CH4井喷所需泵送速率的三分之一。压力升高时二氧化碳的相变是造成这种差异的主要原因。在动态压井过程中，井压的增加会导致CO2密度从68 kg/m3跃升至904 kg/m3，而CH4的密度则在22 kg/m3至192 kg/m3之间。这种密度-压力行为的根本差异导致CO2井喷通常比CH4井喷更容易被杀死。本文还详细介绍了CO2和CH4井喷动态杀伤的其他差异，如多相流行为，以解释它们的影响。我们还发现，较浅水域的二氧化碳井喷会在井口产生低于冰点的温度，导致冰和/或水合物的形成，这一结果可能会给海底井喷的整体响应带来意想不到的复杂性。
{"title":"Dynamic kill modeling of subsea CO2 and CH4 blowouts: Differentiating factors and their implications for offshore carbon sequestration","authors":"Eric. R. Upchurch , Yaxin Liu , Lei Zhou , Bjoern-Tore Anfinsen","doi":"10.1016/j.ijggc.2025.104486","DOIUrl":"10.1016/j.ijggc.2025.104486","url":null,"abstract":"<div><div>This study focusses on understanding the physics of halting subsea CO<sub>2</sub> blowouts using dynamic-kill methods. A computational fluid dynamics (CFD) model that replicates the thermophysical properties of CO<sub>2</sub> is used. We also analyze analogous CH<sub>4</sub> scenarios, juxtaposing the impacts of both fluids.</div><div>We simulate sixteen blowout/dynamic-kill scenarios, representing all combinations of water depth (305 or 762 m), blowout rate (2.83 or 11.34 MMm<sup>3</sup>/d), relief well intercept depth (1220 or 1830 m TVD BML), and reservoir fluid (CO<sub>2</sub> or CH<sub>4</sub>). This defines a sufficiently broad simulation space for gaining insight into the heretofore undefined aspects of dynamically killing subsea CO<sub>2</sub> blowouts – and how they differ from CH<sub>4</sub> blowouts.</div><div>CO<sub>2</sub>‘s thermophysical properties generally reduce dynamic kill pumping rates to one-third of that required for CH<sub>4</sub> blowouts when using 1801-kg/m<sup>3</sup> kill fluid. CO<sub>2</sub> phase change at elevated pressures drives most of the difference. During a dynamic kill, increases in well pressure can cause CO<sub>2</sub> density to jump from 68 to 904 kg/m<sup>3</sup>, while CH<sub>4</sub> exhibits a modest 22 to 192 kg/m<sup>3</sup> range. This radical difference in density-vs-pressure behavior results in CO<sub>2</sub> blowouts being generally easier to kill than CH<sub>4</sub> blowouts. Other differences in the dynamic killing of CO<sub>2</sub> and CH<sub>4</sub> blowouts, like multiphase flow behavior, are detailed in the paper to explain their impacts.</div><div>We also find that CO<sub>2</sub> blowouts in shallower water can generate sub-freezing temperatures at the wellhead, resulting in ice and/or hydrate formation – a result that can introduce unintended complexity into the overall response to a subsea blowout.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"147 ","pages":"Article 104486"},"PeriodicalIF":5.2,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145217780","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}
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