International Journal of Greenhouse Gas Control最新文献

{"title":"A smart injection optimization for CO₂ sequestration: ensuring storage integrity through adaptive control and real-time monitoring","authors":"Ahmed Ali Shanshool Alsubaih,&nbsp;Kamy Sepehrnoori,&nbsp;Mojdeh Delshad","doi":"10.1016/j.ijggc.2025.104542","DOIUrl":"10.1016/j.ijggc.2025.104542","url":null,"abstract":"<div><div>The oil and gas industry is undergoing a transformative shift towards digital and smart fields, driven by the integration of artificial intelligence (AI), machine learning (ML), and real-time data analytics. Within this context, the novelty of this study lies in the development of an adaptive smart injection system for CO₂ sequestration that integrates real-time monitoring with advanced control strategies. Unlike conventional injection schemes that rely on pre-defined injection plans, the proposed framework dynamically adjusts injection parameters to optimize storage efficiency while mitigating leakage risks. A fully three-dimensional reservoir model with three injection wells and one legacy well is simulated over 5 years of injection followed by 50 years of storage, using a commercial reservoir simulator coupled to Python-based supervisory control. Three control strategies Proportional Integral Derivative (PID) control, Reinforcement Learning (RL), and Genetic Algorithm (GA) based optimization are compared under a conservative bottom-hole pressure limit tied to the fracture gradient. In an uncontrolled case, 10.2 % of the injected CO₂ leaks through the legacy well. The smart injection framework reduces this leakage to 2.8 % with PID, 2.0 % with GA, and 1.6 % with RL, corresponding to an 84 % reduction for RL relative to the baseline. RL provides the greatest average leakage reduction and most adaptive response to changing reservoir conditions, whereas GA offers slightly higher leakage but the most consistent performance across realizations; PID serves as a simple benchmark with limited adaptability. These results demonstrate that AI- and optimization-driven control can substantially enhance CO₂ storage security and operational efficiency, with direct transferability to waterflooding, enhanced oil recovery, and underground gas storage operations.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"149 ","pages":"Article 104542"},"PeriodicalIF":5.2,"publicationDate":"2026-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145748579","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}

{"title":"Integrated CO2-EOR and post-EOR dedicated CO2 storage: Demonstrating the value of coupled system and optimal incentive structures","authors":"Abouzar Mirzaei-Paiaman ,&nbsp;Larry W. Lake ,&nbsp;Lorena G. Moscardelli","doi":"10.1016/j.ijggc.2025.104543","DOIUrl":"10.1016/j.ijggc.2025.104543","url":null,"abstract":"&lt;div&gt;&lt;div&gt;Injecting anthropogenic CO&lt;sub&gt;2&lt;/sub&gt; into oil reservoirs provides the dual benefits of enhanced oil recovery (EOR) and reduced atmospheric CO&lt;sub&gt;2&lt;/sub&gt; levels. After a CO&lt;sub&gt;2&lt;/sub&gt;-EOR project ends, operations can transition into dedicated CO&lt;sub&gt;2&lt;/sub&gt; storage, wherein CO&lt;sub&gt;2&lt;/sub&gt; injection continues without further oil production. However, most prior studies have treated CO&lt;sub&gt;2&lt;/sub&gt;-EOR and dedicated storage as separate processes, potentially overlooking important interdependencies. This separation may limit the optimization of both economic and environmental outcomes. In this study, we adopt an integrated approach that jointly considers the EOR and post-EOR phases, with the objective of maximizing benefits across the entire project timeline. We demonstrate the value of the integrated system using a case study from a San Andres reservoir in the Permian Basin, West Texas, and also use it to provide first-order estimates of optimal carbon storage incentives for both phases. Optimality is defined as the level of incentive that aligns economic returns with environmental gains. Using a compositional simulation model, we compared two integrated strategies under identical conditions: (1) continuous CO&lt;sub&gt;2&lt;/sub&gt; injection and (2) CO&lt;sub&gt;2&lt;/sub&gt;-WAG (Water-Alternating-Gas), each followed by a post-EOR CO&lt;sub&gt;2&lt;/sub&gt; storage phase. The CO&lt;sub&gt;2&lt;/sub&gt;-WAG approach yielded higher oil production but resulted in lower CO&lt;sub&gt;2&lt;/sub&gt; storage compared to continuous injection, with the reduction in CO&lt;sub&gt;2&lt;/sub&gt; storage observed during both the EOR and post-EOR phases. A similar trend was observed in terms of net CO&lt;sub&gt;2&lt;/sub&gt; emissions, further reinforcing that CO&lt;sub&gt;2&lt;/sub&gt;-WAG is less favorable from climate perspective. Economically, the relative attractiveness of each strategy was highly dependent on the level of incentives. At lower incentive levels, the CO&lt;sub&gt;2&lt;/sub&gt;-WAG strategy was more profitable, both during the EOR phase and over the entire integrated system. However, as incentives increased, certain scenarios emerged where CO&lt;sub&gt;2&lt;/sub&gt;-WAG remained more profitable only during the EOR phase, while the strategy involving continuous CO&lt;sub&gt;2&lt;/sub&gt; injection became economically superior over the full integrated system. In some cases, continuous injection was consistently more profitable in both the EOR phase and the integrated context. These findings underscore the importance of evaluating CO&lt;sub&gt;2&lt;/sub&gt;-EOR and post-EOR storage as a single, integrated system. Economic superiority during the EOR phase alone does not guarantee optimal outcomes across the full project period. Moreover, compromising CO&lt;sub&gt;2&lt;/sub&gt; storage during the EOR phase can make it implausible to achieve maximum storage potential in the integrated system. These results also highlight the critical role of well-designed incentive structures in aligning economic and environmental goals, ensuring that the most economically beneficial strategy also delivers ","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"149 ","pages":"Article 104543"},"PeriodicalIF":5.2,"publicationDate":"2026-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145692543","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}

{"title":"Feasibility of subsurface storage of hydrochar in the Netherlands as carbon dioxide removal technique","authors":"Timothy F. Baars ,&nbsp;Hemmo A. Abels ,&nbsp;Anne-Catherine A.M. Dieudonné ,&nbsp;Joachim B. Hanssler ,&nbsp;Sebastian Geiger","doi":"10.1016/j.ijggc.2025.104539","DOIUrl":"10.1016/j.ijggc.2025.104539","url":null,"abstract":"<div><div>Hydrothermal carbonisation enables the conversion of wet biomass into hydrochar, a carbon-rich solid with potential for durable carbon dioxide removal (CDR). While hydrochar has been studied extensively for topics as soil application or wastewater treatment, its role in subsurface storage remains underexplored. This study examines the feasibility of hydrochar-based biomass carbon removal and storage (BiCRS) in the Netherlands, where abundant wet biomass and well-developed subsurface infrastructure offer a promising deployment context. We characterise the chemical and mechanical properties of manure-derived hydrochar and evaluate seven potential storage configurations, from abandoned coal mines to quarry lakes and lightweight fill applications, based on technical feasibility, environmental risk, and long-term containment. Our findings identify two priority pathways: storage in salt caverns and use as lightweight filling material for land elevation. A third pathway, storage in sand quarry lakes, also holds potential, though additional safeguards and site-specific assessments are needed to ensure environmental integrity and carbon retention. Hydrochar’s compatibility with wet, low-value feedstocks and potential for decentralised implementation position it as a flexible addition to the CDR portfolio. However, realising this potential will depend on further field validation, material optimisation, and regulatory alignment. Key uncertainties remain regarding long-term degradation, leachate behaviour, and performance under representative subsurface conditions. This study highlights hydrochar as a scalable, technically viable CDR approach. If supported by robust containment, monitoring, and governance frameworks, it could play a meaningful role in national and regional climate mitigation strategies.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"149 ","pages":"Article 104539"},"PeriodicalIF":5.2,"publicationDate":"2026-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145692596","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}

{"title":"Effect of anionic surfactant on interfacial tension and wettability of rock/water/CO2 system under geological carbon storage conditions","authors":"Marcopolo Alcantara Fuentes ,&nbsp;Taehyung Park ,&nbsp;Min-Kyung Jeon ,&nbsp;Joo Yong Lee ,&nbsp;Tae-Hyuk Kwon","doi":"10.1016/j.ijggc.2025.104562","DOIUrl":"10.1016/j.ijggc.2025.104562","url":null,"abstract":"<div><div>This study tests the hypothesis that sodium dodecyl sulfate, a commercially available anionic surfactant, can enhance CO₂ injection efficiency in geological carbon storage systems by simultaneously reducing interfacial tension and altering rock wettability. High-pressure and high-temperature experiments covered a wide range of pressure and temperature (1–12 MPa, 25–80 °C), covering from gaseous, sub-critical, to supercritical CO2 phases, and measured interfacial tensions and contact angles on quartz, Berea sandstone, and Mancos shale substrates in the absence and presence of sodium dodecyl sulfate. Results show that sodium dodecyl sulfate reduces the interfacial tension between CO₂ and brine by up to 61% at 40 °C, with reduced effectiveness at 80 °C due to increased critical micelle concentration and thermal effects on surfactant packing. Static and dynamic contact angle measurements reveal that sodium dodecyl sulfate consistently shifts wettability toward more water-wet conditions, with quartz exhibiting the greatest sensitivity and shale showing moderate change. The pore network modelling analysis demonstrates that reductions in capillary factor caused by this anionic surfactant increase CO₂ sweep efficiency. These findings highlight that sodium dodecyl sulfate can improve injectivity via interfacial tension reduction and can also enhance structural trapping by shalely caprock through wettability alteration. This study provides the first systematic experimental evidence of such effects on reservoir-relevant lithologies, sandstone as porous media and shale as caprock.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"149 ","pages":"Article 104562"},"PeriodicalIF":5.2,"publicationDate":"2026-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145837179","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}

{"title":"Interoperability and energy optimization in low pressure ship to medium pressure terminal interfacing","authors":"Panos Deligiannis ,&nbsp;Vangelis Karageorgos ,&nbsp;Paraskevi Bardavillia ,&nbsp;Chara Georgopoulou","doi":"10.1016/j.ijggc.2025.104544","DOIUrl":"10.1016/j.ijggc.2025.104544","url":null,"abstract":"<div><div>Large-scale deployment of Carbon Capture and Storage (CCS) is essential to meet global climate change mitigation goals, with CO₂ shipping playing an important role in enabling cost-effective transport from dispersed sources to storage sites. However, transporting CO₂ is facing interoperability challenges due to the absence of standardized specifications for transport conditions, including state (gas, liquid, or dense phase), pressure and temperature levels.</div><div>To address this, the authors propose a compatibility framework between Low Pressure (LP, 7–10 bara) ships and Medium Pressure (MP, 12–20 bara) terminals, serving liquefied CO₂ (LCO₂) shipping. The aim is to identify machinery systems and operating strategies that ensure cost-effective LCO₂ transfer. A thermodynamic model is used to simulate and optimize performance during loading and discharging operations, by quantifying energy and equipment needs and proposing ship-terminal interface solutions. The model is applied in a case study featuring a ship with three 7300 m³ tanks (simulated range: 5840–8760 m³) and evaluated across varying pressures, temperatures, and flow rates. The study concludes that:<ul><li><span>•</span><span><div>During LP discharging, the LCO₂ is pressurized and heated to MP saturation conditions. To reduce vapor displacement from the terminal tank, subcooled inlet conditions are applied. Vapor returned to the ship is cooled via heat integration before being depressurized to LP.</div></span></li><li><span>•</span><span><div>During MP loading, the fluid stream is depressurized to LP, requiring subcooling to avoid two-phase flow and excessive vapor return. A sub-cooler reduces vapor displacement but demands more energy than a high-capacity vapor return compressor.</div></span></li></ul></div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"149 ","pages":"Article 104544"},"PeriodicalIF":5.2,"publicationDate":"2026-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145748492","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}

{"title":"A workflow for estimating injection pressure limits for CO2 storage: A reservoir-geomechanical analysis of a candidate site in the German North Sea sector","authors":"Firdovsi Gasanzade ,&nbsp;Hendrawan Diandaru Bayu Aji ,&nbsp;Frank Wuttke ,&nbsp;Sebastian Bauer","doi":"10.1016/j.ijggc.2025.104534","DOIUrl":"10.1016/j.ijggc.2025.104534","url":null,"abstract":"<div><div>Geological carbon capture and storage (CCS) in saline formations is seen as a plausible short-term solution to reduce atmospheric carbon dioxide (CO₂) concentrations and mitigate climate change. Besides storage capacity, largely determined by pore space within a geological trap, the maximum allowable pressure in the storage formation represents a major limitation for geological CO₂ storage. This study, therefore, addresses the hydromechanical aspects of geological CO₂ storage by developing an integrated workflow to determine site-specific injection pressure limits and applying it to a potential storage site in the German North Sea sector. The workflow ensures consistency between reservoir flow and geomechanical models by automatically extracting near-wellbore geomechanical domains from the large-scale model. For a vertical well, the site-specific injection pressure limit is estimated at 17.9 MPa/km, governed by tensile failure in the storage formation. Within the cap rock, the limit increases to 28.6 MPa/km, providing a large margin of safety and enabling higher injection rates. A horizontal well configuration yields a slightly higher limit of 19.7 MPa/km, due to the larger well-reservoir contact area and improved pressure dissipation. The derived pressure limits are subsequently implemented in a large-scale dynamic simulation to verify workflow performance and assess formation integrity. Results indicate that injection rates of approximately 1.7 Mt CO₂ per year per vertical well can be sustained over 30 years, with reservoir overpressure and the corresponding stress states strongly dependent on the hydraulic setting of the reservoir. Importantly, injection-induced stresses and thus the probability of fracture formation decreases rapidly after CO₂ injection ends.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"149 ","pages":"Article 104534"},"PeriodicalIF":5.2,"publicationDate":"2026-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145748578","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}

{"title":"When is a central CO2 conditioning system beneficial for CCS from biogas?: A techno-economic analysis of capacities and distances","authors":"Rikke C. Pedersen ,&nbsp;Simon Roussanaly ,&nbsp;Lars O. Nord ,&nbsp;Jonas K. Jensen","doi":"10.1016/j.ijggc.2025.104563","DOIUrl":"10.1016/j.ijggc.2025.104563","url":null,"abstract":"<div><div>Biogas plants are expected to play an important role in the future global energy system and hold a large potential for achieving negative CO₂ emissions. In Denmark, CO₂ separation is implemented in the majority of biogas plants. Therefore, their CO₂ is readily available, only requiring the subsequent process steps conditioning, transportation, and storage to exploit the biogenic CO₂ for net-negative emissions. However, biogas plants are relatively small point sources, which may result in high CCS deployment costs. Therefore, this study investigates how two biogas plants could economically benefit from sharing a common conditioning system. The technical performance of the processes are evaluated through process modelling and simulation, and a detailed economic analysis is used to evaluate the costs of the system. Four different options with different degrees of centralisation were considered. It was investigated for which emission levels and transport distances a centralised system shared between at least two biogas plants could be relevant. A shared conditioning system was found to yield economic benefits when two plants were located within 5<!--> <!-->km to 10<!--> <!-->km and when only the liquefaction and purification subprocesses were centralised. The results show that permanent storage of CO₂ from biogas plants can be cost-competitive with other negative emission technologies. Furthermore, an average cost saving of 13<!--> <!-->% can be achieved by relevant existing Danish plants when the CO₂ conditioning process is shared between at least two biogas plants.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"149 ","pages":"Article 104563"},"PeriodicalIF":5.2,"publicationDate":"2026-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145837174","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}

{"title":"Reassessing historical gas occurrences considering CO2 geological storage, a case study of the Cuiabá Paulista occurrence, Brazil","authors":"Vitória Cruz Paluri Piedade ,&nbsp;Saulo B. de Oliveira ,&nbsp;Carlos Henrique Tozzi de Oliveira","doi":"10.1016/j.ijggc.2025.104557","DOIUrl":"10.1016/j.ijggc.2025.104557","url":null,"abstract":"<div><div>The Carbon Capture and Storage (CCS) technology encompasses integrated processes to prevent carbon dioxide (CO₂) emissions from reaching the atmosphere, including storage in deep geological formations. This technology supports international carbon reduction objectives, such as those established by the Paris Agreement. This study focuses on the Cuiabá Paulista natural gas occurrence, chosen for its proximity to one of Brazil's largest concentrations of CO₂ stationary emitters and its favorable geological attributes, which present future opportunities combining gas exploitation with CO₂ storage, besides tight gas potential, reassessing the historical gas occurrence that was previously considered subeconomic. This research aims to evaluate key geological parameters for CO₂ storage and to develop a 3D stratigraphic model based on lithological and petrophysical data from drilling wells, emphasizing the subdivision of formations into electrofacies to identify reservoirs with the potential for CO₂ storage. The analysis reveals that saline aquifer storage is a potential geological option, with a theoretical capacity of approximately 930 Mt of CO₂. The key findings demonstrate that integrating geological, petrophysical, and reservoir data enables a robust reassessment of the Cuiabá Paulista gas occurrence as a potential CO₂ storage site, which implicates the broader applicability of an electrofacies-based capacity evaluation within a methodological workflow that can be replicated for other historical gas occurrences with limited data availability. The identified reservoir could function as a CO₂ sink not only for the local emitters but also as a regional hub, contributing to emission reduction efforts in the Southeast region of Brazil.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"149 ","pages":"Article 104557"},"PeriodicalIF":5.2,"publicationDate":"2026-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145920741","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}

{"title":"CO2 storage evaluation combined with oil recovery in depleted gulf of America reservoirs","authors":"Manohar Gaddipati,&nbsp;Elif Agartan,&nbsp;Can Yetkin,&nbsp;Bill Savage,&nbsp;Chet Ozgen","doi":"10.1016/j.ijggc.2025.104553","DOIUrl":"10.1016/j.ijggc.2025.104553","url":null,"abstract":"<div><div>Enhanced Oil Recovery techniques using carbon dioxide (CO₂-EOR) focus primarily on oil production with CO₂ storage being an incidental benefit. In contrast, EOR with Carbon Capture and Storage (CCS-EOR) combines oil recovery with the explicit objective of capturing and storing anthropogenic CO₂ to reduce emissions. As part of a DOE-funded project, 461 depleted oil and gas reservoirs in the Gulf of America were analyzed and CO₂ storage correlations were developed and published in 2018. This study extends that foundational work in two phases: quantifying and comparing the storage benefits of CCS-EOR operations with those achieved through conventional CO₂ injection in selected fields, and refining storage capacity estimates by incorporating practical operational constraints through staging analysis, which involves strategic completion of injection wells while eliminating unsuitable sands based on operational considerations.</div><div>Ten reservoir sands across nine depleted federal offshore fields were selected for detailed evaluation based on storage capacity, oil recovery potential, available data, and reservoir properties. Simulation models were developed using data from the Bureau of Ocean Energy Management (BOEM). CCS-EOR operations consistently achieve higher storage volumes than conventional CO₂ storage, with total storage capacities ranging from 10.4 Bscf (0.54 MM tons) to 137.9 Bscf (7.19 MM tons). The incremental storage benefit ranges from 5.24 Bscf (0.27 MM tons) to 71.56 Bscf (3.73 MM tons). This enhanced performance results from two primary mechanisms: maintaining lower reservoir pressures through continuous production and improving CO₂ sweep efficiency compared to conventional storage. Primary oil recovery ranges from 0.2 % to 30.2 %, while incremental recovery factors from CCS-EOR operations vary from 46.3 % to 87.8 %. The wide range in recovery performance reflects low primary recovery creating greater recovery potential, homogeneous reservoir modeling assumptions that may overestimate sweep efficiency, and uncertainties in critical parameters such as minimum miscibility pressure.</div><div>Sensitivity analysis of well configurations, residual oil saturation at CO₂ miscibility, CO₂ availability, and reservoir heterogeneity shows that CCS-EOR provides greater storage capacity but introduces higher operational uncertainty. Stochastic analysis demonstrates that geological heterogeneity reduces oil recovery by 28–50 % compared to homogeneous models. Staging analysis applied to 3514 depleted formations reduces prospective storage resources from 79,811 Bscf (4162 MM tons) to 46,362 Bscf (2418 MM tons), representing a 58 % reduction, with gas sands experiencing the highest losses particularly in low permeability-thickness formations.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"149 ","pages":"Article 104553"},"PeriodicalIF":5.2,"publicationDate":"2026-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145748577","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}

{"title":"Modelling temporal variations of direct-wave DAS traveltimes and amplitudes caused by CO2 injection","authors":"Wanting Hou ,&nbsp;Olivia Collet ,&nbsp;Li-Yun Fu ,&nbsp;Roman Isaenkov ,&nbsp;Roman Pevzner ,&nbsp;Pavel Shashkin ,&nbsp;Boris Gurevich","doi":"10.1016/j.ijggc.2025.104555","DOIUrl":"10.1016/j.ijggc.2025.104555","url":null,"abstract":"<div><div>Permanent downhole seismic receivers such as Distributed Acoustic Sensors (DAS) offer a useful means for long-term seismic monitoring. Indeed, amplitudes of seismic waves recorded using downhole DAS are sensitive to changes of formation properties and can be used to monitor these changes. A recent analysis of downhole DAS data acquired during a CO₂ injection into a 1500 m deep shows that DAS amplitudes and traveltimes of direct waves emitted by permanent seismic sources are controlled by temporal variations of formation properties caused by injected CO₂. Comparison of the observed traveltimes and amplitudes against 1.5D simulations over the entire length of the well shows a reasonably good agreement for source offsets of up to 600 m. The time-lapse effects in the vicinity of the reservoir interval are also reproduced by the 1.5 modelling reasonably well, but this modelling cannot explain strong depth variations of traveltime shifts and amplitudes below the injection interval. The decrease in time shifts below the plume is reproduced in 2D finite-difference simulations, which shows that this decrease is caused by a finite lateral size of the plume. Matching the modelled traveltimes and amplitudes for a range of plume thicknesses to field observations gives an estimate of the plume thickness. Modelling the effect of injected supercritical CO₂ close to the well for uniform and patchy saturation models confirms that the CO₂ saturation is likely closer to uniform, and is above 10 %. Above this value, the sensitivity of both traveltimes and amplitudes is insufficient to obtain a more definitive estimate.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"149 ","pages":"Article 104555"},"PeriodicalIF":5.2,"publicationDate":"2026-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145797861","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}