Search Results (111)

Geological storage is an integral element of the green energy transition. Geological formations, such as aquifers, depleted reservoirs, and hard rock caverns, are used mainly for the storage of hydrocarbons, carbon dioxide and increasingly hydrogen. However, potential adverse effects such as ground movements, leakage, seismic activity, and environmental pollution are observed. Existing research focuses on monitoring subsurface elements of the storage, while on the surface it is limited to ground movement observations. The review was carried out based on 191 research contributions related to geological storage. It emphasizes the importance of monitoring underground gas storage (UGS) sites and their surroundings to ensure sustainable and safe operation. It details surface monitoring methods, distinguishing geodetic surveys and remote sensing techniques. Remote sensing, including active methods such as InSAR and LiDAR, and passive methods of multispectral and hyperspectral imaging, provide valuable spatiotemporal information on UGS sites on a large scale. The review covers modelling and prediction methods used to analyze the environmental impacts of UGS, with data-driven models employing geostatistical tools and machine learning algorithms. The limited number of contributions treating geological storage sites holistically opens perspectives for the development of complex approaches capable of monitoring and modelling its environmental impacts. Full article

This paper presents a numerical simulation study evaluating carbon dioxide capture and storage (CCS) feasibility for the Turceni Power Plant in Oltenia, Romania, using the nearby depleted Bibești-Bulbuceni gas reservoir. A comprehensive reservoir model was developed using Petrel software, integrating geological and reservoir engineering data for the formations of the Bibești-Bulbuceni structure, which is part of the western Moesian Platform. The static model incorporated realistic petrophysical inputs for the Meotian reservoirs. Dynamic simulations were performed using Eclipse compositional simulator with Peng–Robinson equation of state for a CH4-CO₂ system. The model was initialized with natural gas initially in place at 149 bar reservoir pressure, then produced through depletion to 20.85 bar final pressure, achieving 80% recovery factor. CO₂ injection simulations modeled a phased 19-well injection program over 25 years, with individual well constraints of 100 bar bottom-hole pressure and 200,000 Sm³/day injection rates. Results demonstrate successful injection of a 60 Mt CO₂, with final reservoir pressure reaching 101 bar. The modeling framework validates the technical feasibility of transforming Turceni’s power generation into a net-zero process through CCS implementation. Key limitations include simplified geochemical interactions and relying on historical data with associated uncertainties. This study provides quantitative evidence for CCS viability in depleted hydrocarbon reservoirs, supporting industrial decarbonization strategies. The strategy not only aligns with the EU’s climate-neutral policy but also enhances local energy security by repurposing existing geological resources. The findings highlight the potential of CCS to bridge the gap between current energy systems and a sustainable, climate-neutral future. Full article

Based on a detailed investigation of the geological setting of coalbed methane by previous work in the Xiangzhong Depression, Hunan Province, numerical simulation methods were used to simulate the geological storage of carbon dioxide and displacement gas production in this area. In this simulation, a 400 m × 400 m square well group was constructed for coalbed methane production, and a carbon dioxide injection well was arranged in the center of the well group. Injection storage and displacement gas production simulations were carried out under the conditions of original permeability and 1 mD permeability. At the initial permeability (0.01 mD), carbon dioxide is difficult to inject, and the production of displaced and non-displaced coalbed methane is low. During the 25-year injection process, the reservoir pressure only increased by 7 MPa, and it is difficult to reach the formation fracture pressure. When the permeability reaches 1 mD, the carbon dioxide injection displacement rate can reach 4000 m³/d; the cumulative production of displaced and non-displaced coalbed methane is 7.83 × 10⁶ m³ and 9.56 × 10⁵ m³, respectively, and the average daily production is 1430 m³/d and 175 m³/d. The displacement effect is significantly improved compared to the original permeability. In the later storage stage, the carbon dioxide injection rate can reach 8000 m³/d, reaching the formation rupture pressure after 3 years, and the cumulative carbon dioxide injection volume is 1.17 × 10⁷ m³. This research indicates that permeability has a great impact on carbon dioxide geological storage. During the carbon dioxide injection process, selecting areas with high permeability and choosing appropriate reservoir transformation measures to enhance permeability are key factors in increasing the amount of carbon dioxide injected into the area. Full article

Acid gas injection (AGI), which primarily involves injecting hydrogen sulfide (H₂S) and carbon dioxide (CO₂), is recognized as a cost-efficient and environmentally sustainable method for controlling sour gas emissions in oil and gas operations. This review examines case studies of twelve AGI projects conducted in Canada, Oman, and Kazakhstan, focusing on reservoir selection, leakage potential assessment, and geological suitability evaluation. Globally, several million tonnes of acid gases have already been sequestered, with Canada being a key contributor. The study provides a critical analysis of geochemical modeling data, monitoring activities, and injection performance to assess long-term gas containment potential. It also explores AGI’s role in Enhanced Oil Recovery (EOR), noting that oil production can increase by up to 20% in carbonate rock formations. By integrating technical and regulatory insights, this review offers valuable guidance for implementing AGI in geologically similar regions worldwide. The findings presented here support global efforts to reduce CO₂ emissions, and provide practical direction for scaling-up acid gas storage in deep subsurface environments. Full article

Basalt is prevalent in the Earth’s crust and makes up about 90% of all volcanic rocks. The earth is warming at an alarming rate, and there is a search for a long-term solution to this problem. Geologic carbon storage in basalt offers an effective and durable solution for carbon dioxide sequestration. Basaltic rocks are widely used for road and building construction and insulation, soil amendment, and in carbon storage. There is a need to understand the parameters that affect this process in order to achieve efficient carbon mineralization. This review systematically analyzes peer-reviewed studies and project reports published over the past two decades to assess the mechanisms, effectiveness, and challenges of carbon mineralization in basaltic formations. Key factors such as mineral composition, pH, temperature and pressure are evaluated for their impact on mineral dissolution and carbonate precipitation kinetics. The presence of olivine and basaltic glass also accelerates cation release and carbonation rates. The review includes case studies from major field projects (e.g., CarbFix and Wallula) and laboratory experiments to illustrate how mineralization performs in different geological environments. It is essential to maximize mineralization kinetics while ensuring the formation of stable carbonate phases in order to achieve efficient and permanent carbon dioxide storage in basaltic rock. Full article

Under the dual-carbon policy framework, geological CO₂ storage, particularly in saline aquifers, is pivotal to achieving national emission reduction targets. However, selecting geologically favorable storage sites demands quantitative assessment of complex geological factors—a task hindered by subjective traditional methods. To address this, the study employs an integrated approach combining multi-criteria decision analysis (Analytic Hierarchy Process and Fuzzy Comprehensive Evaluation) with multiphase flow simulations to investigate the Dezhou Subdepression in Shandong Province. The results indicate that the Dezhou Subdepression is moderately favorable for CO₂ geological storage, characterized by geologically optimal burial depth and favorable reservoir conditions. When the injection pressure increases from 1.1 times the original Group pressure (1.1P) to 1.5 times the original Group pressure (1.5P), the lateral migration distance of CO₂ expands by 240%, and the total storage capacity increases by approximately 275%. However, under 1.5P conditions, the CO₂ plume reaches the model boundary within 6.3 years, underscoring the increased risk of CO₂ leakage under high-pressure injection scenarios. This study provides strategic insights for policymakers and supports strategic planning for a CO₂ storage pilot project in the Dezhou Subdepression. It also serves as a reference framework for future assessments of CO₂ geological storage potential. Full article

This study systematically investigates the pore–fracture architecture of deep coal seams in the JiaTan (JT) block of the Ordos Basin using an integrated suite of advanced techniques, including nuclear magnetic resonance (NMR), high-pressure mercury intrusion, low-temperature nitrogen adsorption, low-pressure carbon dioxide adsorption, and micro-computed tomography (micro-CT). These complementary methods enable a quantitative assessment of pore structures spanning nano- to microscale dimensions. The results reveal a pore system overwhelmingly dominated by micropores—accounting for more than 98% of the total pore volume—which play a central role in coalbed methane (CBM) storage. Microfractures, although limited in volumetric proportion, markedly enhance permeability by forming critical flow pathways. Together, these features establish a dual-porosity system that governs methane transport and recovery in deep coal reservoirs. The multiscale characterization employed here proves essential for resolving reservoir heterogeneity and designing effective stimulation strategies. Notably, enhancing methane desorption in micropore-rich matrices and improving fracture connectivity are identified as key levers for optimizing deep CBM extraction. These insights offer a valuable foundation for the development of deep coalbed methane (DCBM) resources in the Ordos Basin and similar geological settings. Full article

Carbon dioxide (CO₂) injection into geologic formations has gained global traction, including in South Africa, to mitigate anthropogenic emissions through carbon capture, utilisation, and storage technology. These technological and technical developments require a comprehensive and reliable study of CO₂ sorption equilibria under in situ unmineable coal reservoir conditions. This paper presents novel findings on the study of the equilibrium adsorption of CO₂ on two South African coals measured at four temperatures between 30 and 60 °C and pressures up to 9.0 MPa using the volumetric technique. Additionally, the sorption mechanism and thermodynamic nature of the process were studied by fitting the experimental data into Langmuir–Freundlich (Sips), Tóth, and Dubinin–Astakhov (DA) isotherm models, and the Clausius–Clapeyron equation. The findings indicate that the sorption process is highly exothermic, as presented by a negative temperature effect, with the maximum working capacity estimated to range between 3.46 and 4.16 mmol/g, which is also rank- and maceral composition-dependent, with high-rank vitrinite-rich coal yielding more sorption capacity than low-rank inertinite-rich coal. The experimental data fit well in Sips and Tóth models, confirming their applicability in describing the CO₂ sorption behaviour of the coals under the considered conditions. The isosteric heat of adsorption varied from 7.518 to 37.408 kJ/mol for adsorbate loading ranging from 0.4 to 3.6 mmol/g. Overall, the coals studied demonstrate well-developed sorption properties that characteristically make them viable candidates for CO₂ sequestration applications for environmental sustainability. Full article

Salt caverns serve as underground storage for crude oil, natural gas, compressed air, carbon dioxide, and hydrogen. Key stages of cavern development for storage purposes include design, construction, storage, and abandonment. The design phase addresses optimal cavern shape, size, pillar dimensions, number of caverns, the impact of interbeds, and cyclic loading while considering the creep behavior of salt and the mechanical behavior of surrounding layers. During this phase, geological factors such as depth, thickness, and the quality of salt are considered. For construction, two main methods—direct leaching and reverse leaching—are chosen based on design specifications. The storage stage includes the injection and withdrawal of gases in a cyclic manner with specific injection rates and pressures. After 30 to 50 years, the caverns are plugged and abandoned. The geological limitation of salt domes makes it essential to look for more bedded evaporites. This study provides a comprehensive review of bedded evaporites, including their origin and depositional environment. The stability of caverns in all these stages heavily relies on geomechanical analysis. Factors affecting the geomechanics of bedded salts such as mineralogy, physical properties, and mechanical properties are reviewed. A list of bedded evaporites in the U.S. and Canada, including their depth, thickness, and existing caverns, is provided. Additionally, this study discusses the main geomechanical considerations influencing design, solution mining, cyclic loading, and abandonment of caverns in bedded salt caverns. Full article

Kerogen micropores in shale are crucial for gas sorption; nevertheless, their formation and evolution have been insufficiently studied. To qualitatively and quantitatively analyze changes in the molecular structure and associated micropores of kerogen throughout natural maturation, a series of experiments were performed on collected kerogen samples with varying maturity levels. The results demonstrated that the evolution of the chemical structure and associated micropores of kerogen can be divided into three stages during thermal evolution. When Ro < 1.43%, micropores are primarily controlled by the aliphatic composition of kerogen, resulting in a reduction in the micropore volume with decreasing numbers of aliphatic functional groups. When 1.43% < Ro < 1.93%, the micropore structure is primarily governed by the aromatic composition of kerogen and the micropore volume exhibits a gradual increment with increasing aromatic ring size. When Ro > 1.93%, the micropore volume rapidly increases with increasing aromatic composition of kerogen, and the aromatic rings become more orderly. Moreover, molecular simulations also show that the adsorption curves of CO₂ and CH₄ are type I isotherms, and that the adsorption capacity of CO₂ is greater than that of CH₄ under the same conditions, which indicates that the microscopic adsorption mechanism of CH₄ and CO₂ is gas competitive adsorption. This research offers new perspectives on the formation and evolution of kerogen micropores, and the carbon sequestration process. Full article

The pursuit of effective climate change mitigation strategies is driving research into geological carbon dioxide (CO₂) storage. The present work explores the interaction of CO₂ with carbonate rocks from the El Abra formation in the Tampico-Misantla basin, focusing on the comparative influence of organic matter (OM) content on mineralization processes, hypothesizing that variations in OM content significantly modulate the mineralization process affecting both the rate and type of carbonate formation. Expanding on a previous study, CO₂ is studied and injected under high-pressure (1350-2350 PSI) and high-temperature (60–110 °C) conditions into two contrasting samples: one with high OM content and another with low OM content. Structural, morphological, and physical adsorption changes were evaluated through Fourier transform infrared (FT-IR) spectroscopy, X-ray diffraction (XRD), scanning electron microscopy (SEM), and Brunauer–Emmett–Teller (BET) analyses. The findings indicate that the mineralogy of El Abra promotes secondary carbonate precipitation, with rock–fluid interactions significantly enhanced by brine presence. Samples with high OM exhibited a dramatic reduction in average particle size from 13 μm to 2 μm, along with the formation of metastable phases, such as vaterite—evidenced by XRD peak shifting and modifications in the FT-IR spectrum of carbonate bands. Meanwhile, low-OM samples showed an increase in particle size from 1.6 μm to between 3.26 and 4.12 μm, indicating predominant recrystallization. BET analysis confirmed a significant porosity enhancement in high-OM samples (up to 2.918 m²/g). Therefore, OM content plays a critical role in modulating both the rate and type of mineralization, potentially enhancing physical storage capacity in low-OM samples. These integrated findings demonstrate that OM critically governs calcite dissolution, secondary carbonate formation, and microstructural evolution, providing key insights for optimizing CO₂ storage in complex carbonate reservoirs. Full article

This article provides detailed geological and reservoir data on the existing underground gas storage (UGS) facilities in Ukraine and their prospects for hydrogen (H₂) and carbon dioxide (CO₂) storage. The H₂ and CO₂ storage issue is an integral part of the decarbonisation of Ukraine and Europe as a whole. A detailed assessment of UGS in Ukraine was carried out in the framework of the EU Horizon 2020 project Hystories, which is about the possibility of the geological storage of H₂. A database of the available geological data on reservoir and caprock properties was compiled and standardised (reservoir geometry, petrophysics, tectonics, and reservoir fluids). General environmental criteria were defined in terms of geology and surface context. The total estimated H₂ energy storage capacity in 13 studied UGS facilities is about 89.8 TWh, with 459.6 and 228.2 Mt of H₂ using the total (cushion and working gas) and working gas volumes, respectively. The estimated optimistic and conservative CO₂ storage capacities in the 13 studied UGS facilities are about 37.6/18.8 Gt, respectively. The largest and deepest UGS facilities are favourable for H₂ and CO₂ storage, while shallower UGS facilities are suitable only for H₂ storage. Studies could be conducted to determine if CO₂ and H₂ storage could be applied in synergy with CO₂ being used as a cushion gas for H₂ storage. The underground storage of H₂ and CO₂ plays key roles in reducing greenhouse gas emissions and supporting clean energy while enhancing energy security. Increasing the share of renewable energy and integrating sustainable development across various sectors of the economy is crucial for achieving climate goals. Full article

Deep well injection and storage is an emerging technology for realizing the low-cost treatment of extremely large quantities of three types of waste in coal mines in China, while simultaneously supporting coordinated development that considers its impact on the ecological environment. There has been significant progress in research on the geological storage of carbon dioxide in China. However, the geological storage of fluids such as mine water and high-salinity water needs to be studied further. Based on a comprehensive analysis of the lithology, mineral composition, physical and mechanical characteristics, and spatial structure of the Liujiagou and Shiqianfeng formations in a mining area in the Ordos Basin, we determined the geological storage space for fluids, predicted the storage potential, and evaluated the feasibility of deep geological storage of high-salinity water in coal mines. In the study area, the Liujiagou Formation is dominated by fine sandstone and siltstone, while the Shiqianfeng Formation is dominated by medium sandstone and conglomerate. The main storage space comprises micro-cracks, as well as intergranular, dissolution, and intergranular pores. Among these, the intergranular pores are the most conducive to reservoir development. The burial depth intervals of 1820–1835 m, 1905–1920 m, and 2082–2098 m are favorable for storage and are characterized by high porosities, permeabilities, and storage capacities. The effective storage capacity within a 100 m radius of the storage well was estimated to be 33.15 × 10⁴ m³. The effective storage capacity in the favorable area is 27.69 × 10⁴ m³, accounting for 83.50% of the total storage capacity. The Liujiagou and Shiqianfeng formations thus can serve as favorable reservoirs for deep well injection and storage of high-salinity water in the Ordos Basin. This research provides new ideas for the treatment of high-salinity water in coal mines in the Ordos Basin and technical support for deep well injection and the storage of high-salinity water. Full article

Climate change has become one of the most pressing global challenges, with greenhouse gas emissions, particularly carbon dioxide (CO₂), being the primary drivers of global warming. To effectively address climate change, reducing carbon emissions has become an urgent task for countries worldwide. Carbon capture, utilization, and storage (CCUS) technologies are regarded as crucial measures to combat climate change, among which ocean CO₂ sequestration has emerged as a promising approach. Recent reports from the International Energy Agency (IEA) indicate that by 2060, CCUS technologies could contribute up to 14% of global cumulative carbon reductions, highlighting their significant potential in mitigating climate change. This review discusses the main technological pathways for ocean CO₂ sequestration, including oceanic water column sequestration, CO₂ oil and gas/coal seam geological sequestration, saline aquifer sequestration, and seabed methane hydrate sequestration. The current research status and challenges of these technologies are reviewed, with a particular focus on the potential of seabed methane hydrate sequestration, which offers a storage density of approximately 0.5 to 1.0 Gt per cubic kilometer of hydrate. This article delves into the formation mechanisms, stability conditions, and storage advantages of CO₂ hydrates. CO₂ sequestration via hydrates not only offers high storage density but also ensures long-term stability in the low-temperature, high-pressure conditions of the seabed, minimizing leakage risks. This makes it one of the most promising ocean CO₂ sequestration technologies. This paper also analyzes the difficulties faced by ocean CO₂ sequestration technologies, such as the kinetic limitations of hydrate formation and leakage monitoring during the sequestration process. Finally, this paper looks ahead to the future development of ocean CO₂ sequestration technologies, providing theoretical support and practical guidance for optimizing their application and promoting a low-carbon economy. Full article

In carbon dioxide capture, utilization and storage (CCUS) technology, CO₂ flooding and storage is currently the most effective geological storage method and the flow law of the gas injection wellbore is the key to achieving safe and efficient CO₂ injection. The existing wellbore flow model lacks research on the corrosion law. To this end, this paper established a gas injection wellbore flow-heat transfer-corrosion coupling model based on the actual situation of Huang 3 District of the CCUS Demonstration Base of Changqing Oilfield. The field measured data verification showed that the relative average error of the model in predicting pressure and temperature was less than 7.5% and the R² of the predicted value and the measured value was greater than 0.99. The model was used for sensitivity analysis to evaluate the effects of different gas injection temperatures (15–55 °C), pressures (15–55 MPa), displacements (10–500 t/d) and CO₂ contents (50–100%) on wellbore temperature, pressure and corrosion rate, and the wellbore flow law under different gas injection conditions was clarified. The results show that the wellbore temperature, pressure and corrosion rate are significantly affected by gas injection parameters. The wellbore temperature increases with the increase of gas injection temperature and decreases with the increase of gas injection displacement. The wellbore pressure is positively correlated with the gas injection pressure and CO₂ content and the gas injection temperature and displacement have little effect on the pressure. The corrosion rate increases with the increase of gas injection temperature and displacement and decreases with the increase of gas injection pressure. In the wellbore, it shows a trend of first increasing and then decreasing with depth. The wellbore corrosion rate is affected by many factors. Reasonable adjustment of gas injection parameters (lowering temperature, increasing pressure, controlling displacement and CO₂ content) can effectively slow down the wellbore corrosion loss. The research results can provide a theoretical basis for the optimization of gas injection system. Full article