Search Results (18)

Against the backdrop of the global pursuit of carbon neutrality, research on coal pore structure has shifted from a single focus on coal mine safety to a dual orientation of hazard prevention and carbon sequestration, forming two distinct research directions worldwide. To clarify the evolutionary trajectory, research heterogeneity and integration paths of this field, this study systematically analyzes 722 core publications on coal pore structure from the CNKI and Web of Science core databases during 2015–2025, combining knowledge visualization analysis and systematic literature sorting (using CiteSpace as an auxiliary analysis tool). The results show that global research on coal pore structure has experienced three developmental stages (embryonic, developmental, and explosive growth) and entered an exponential growth phase after 2020, driven by the dual carbon goals. A clear research divergence has formed between regional engineering practices and international theoretical models: Chinese research is highly oriented to on-site coal mine engineering needs, focusing on the characterization of coal pore structure and its engineering application in gas extraction and outburst prevention of structural coal; international research prioritizes the theoretical exploration of carbon sequestration and CO₂-ECBM, with core research on gas adsorption kinetics, multiphysics coupling mechanisms of coal pore structure, and numerical simulation of reservoir modification. This research disconnect between engineering practice and theoretical modeling has become a key bottleneck restricting the safe application of coal pore structure theory in carbon capture, utilization, and storage (CCUS) projects. To address this issue, a Safety–Sustainability Nexus framework is proposed, which integrates field-based mine safety protocols with theoretical carbon storage models, and realizes cross-scale validation from micro-scale pore characterization to field-scale engineering application. Further, this study points out that the cross-scale data fusion of artificial intelligence and machine learning is the core direction to bridge the gap between engineering practice and theoretical models. In future CO₂-ECBM pilot projects, traditional gas outburst prevention indicators must be taken as mandatory safety thresholds to realize the dynamic matching of carbon injection parameters and coal reservoir stress sensitivity. This study sorts out the global research context and hotspots of coal pore structure, and provides a theoretical and practical reference for the synergy and integration of coal mine gas control engineering and carbon sequestration theoretical research under the dual carbon goals. CBM, coalbed methane; CNKI, China National Knowledge Infrastructure; WOS, Web of Science; CCUS, carbon capture, utilization, and storage; ECBM, Enhanced Coalbed Methane; CO₂-ECBM, CO₂-Enhanced Coalbed Methane. Full article

This study develops a field-based techno-economic model and decision framework for a CO₂-enhanced oil recovery and storage project under joint market uncertainty. Historical drilling and completion expenditures calibrate investment cost functions, and three years of production data are fitted with segmented hyperbolic Arps curves to forecast 20-year oil output. Markov-chain models jointly generate internally consistent pathways for crude oil, ETA, and purchased CO₂ prices, which are embedded in a Monte Carlo valuation. The framework outputs probability distributions of NPV and deferral option value; under the mid scenario, their mean values are USD 18.1M and USD 2.0M, respectively. PRCC-based global sensitivity analysis identifies the dominant value drivers as oil price, CO₂ price, utilization factor, oil density, pipeline length, and injection volume. Techno-economic boundary maps in the joint oil and CO₂ price space then delineate feasible regions and break-even thresholds for key design parameters. Results indicate that CCUS-EOR viability cannot be inferred from oil price or any single cost factor alone, but requires coordinated consideration of subsurface constraints, engineering configuration, and multi-market dynamics, including the value of waiting in unfavorable regimes, contributing to low-carbon development and sustainable energy transition objectives. Full article

Supercritical CO₂ pipeline transportation is a crucial link in Carbon Capture, Utilization, and Storage (CCUS). Compared with traditional oil and gas pipelines, if a supercritical CO₂ pipeline is shut down for an excessively long time, the phase state of CO₂ may transform into a gas–liquid two-phase state. It is urgently necessary to conduct research on the phase change mechanism and safety control during the restart process of gas–liquid two-phase CO₂ pipelines. Based on a certain planned supercritical carbon dioxide pipeline demonstration project, this paper proposes a new pipeline safety restart scheme that actively seeks the liquefaction of gaseous CO₂ inside the pipeline by injecting liquid-phase CO₂ at the initial station. Through numerical simulation and experimental methods, the co-variation laws of parameters such as temperature, pressure, density, and phase state during the pipeline restart process were revealed. It was found that the pipeline shutdown and restart process could be subdivided into four stages: shutdown stage, liquefaction stage, pressurization stage, and displacement stage. The phase transition line would form a closed curve that is approximately trapezoidal. It is suggested to optimize the restart scheme from aspects such as reducing the restart time, controlling the pressure rise rate, and saving CO₂ consumption. It is proposed that the liquid holdup of CO₂ fluid in the pipe at the initial moment of restart and the mass flow rate of CO₂ injected at the initial station during the restart process are the main controlling factors affecting the evolution of the phase path of pipeline restart. For the demonstration project, the specific critical threshold values are given. The research results can provide a certain theoretical guidance and reference basis for the safe restart method of supercritical CO₂ pipelines. Full article

Cement bond evaluation helps check wellbore integrity and zonal isolation in carbon capture, utilisation, and storage (CCUS) projects. This overview describes various cement bond evaluation methods, focusing on acoustic logging and ultrasonic imaging tools supplemented by emerging data-driven interpretation techniques. Their advantages, limitations, and recent advancements are described with illustrative example on ultrasonic-image-based machine learning classifier that detect microannulus. Key research gaps remain in field-scale validation of long-term cement behaviour and in establishing comprehensive 3-D bond-strength benchmarks. To address these gaps, this review recommends (i) creating an open, standardised ML dataset for CCUS well logs, (ii) adopting best-practice pressure-monitoring protocols during and after injection, and (iii) integrating ML analytics with advanced modelling while exploring alternative binder systems. The next step is to test these ML models on real CO₂-storage well data, paving the way toward more reliable cement-bond integrity assessments in future CCUS projects. Full article

To reduce CO₂ emissions, CO₂ geological storage is recognized as an effective approach to decrease atmospheric carbon concentration. Sequestration in deep saline aquifers has become a research focus. However, the physicochemical property changes in saline formations induced by CO₂ injection remain unclear, making it difficult to assess their CO₂ storage potential. This study focuses on saline aquifers within the Jurassic Badaowan formation (J₁b), Sangonghe formation (J₁s), and Cretaceous Tugulu Group (K₁tg) of the Baijiahai Uplift in the Junggar Basin. An integrated methodology combining laboratory experiments—including CO₂ static immersion tests, dynamic displacement tests, X-ray diffraction (XRD), mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR) measurements, and mechanical testing—with CMG-based numerical modeling was employed to analyze CO₂ storage mechanisms and evaluate storage potential. The results show that after CO₂ immersion, extensive dissolution of calcite in J₁s, clay swelling/cementation in J₁b, and extensive dissolution of calcite in K₁tg all lead to increased porosity and permeability, with the J₁b formation exhibiting superior CO₂ storage capacity, the highest MICP-derived porosity, and the greatest NMR-measured porosity among the three formations. Numerical simulations further confirmed J₁b’s leading sequestration volume. Based on integrated experimental and simulation results, the J₁b formation is identified as the optimal reservoir for CO₂ storage. However, to manage potential mechanical instability during real-world injection scenarios, injection pressures and rates should be carefully controlled and continuously monitored to avoid formation fracturing and ensure long-term storage security. This study provides a reference for implementing saline aquifer CCUS projects. Full article

Capturing CO₂ emitted by coal chemical enterprises and injecting it into oil reservoirs not only effectively improves the recovery rate and development efficiency of tight oil reservoirs in the Ordos Basin but also addresses the carbon emission problem constraining the development of the region. Since initiating field experiments in 2012, the Ordos Basin has become a significant base for CCUS (Carbon capture, Utilization, and Storage) technology application and demonstration in China. However, over the years, projects have primarily focused on enhancing the recovery rate of CO₂ flooding, while issues such as potential reservoir damage and its extent have received insufficient attention. This oversight hinder the long-term development and promotion of CO₂ flooding technology in the region. Experimental results were comprehensively analyzed using techniques including nuclear magnetic resonance (NMR), X-ray diffraction (XRD), scanning electron microscopy (SEM), inductively coupled plasma (ICP), and ion chromography (IG). The findings indicate that under current reservoir temperature and pressure conditions, significant asphaltene deposition and calcium carbonate precipitation do not occur during CO₂ flooding. The reservoir’s characteristics-high feldspar content, low carbon mineral content, and low clay mineral content determine that the primary mechanism affecting physical properties under CO₂ flooding in the Chang 4 + 5 tight sandstone reservoir is not, as traditional understand, carbon mineral dissolution or primary clay mineral expansion and migration. Instead, feldspar corrosion and secondary particles migration are the fundamental reasons for the changes in reservoir properties. As permeability increases, micro pore blockage decreases, and the damaging effect of CO₂ flooding on reservoir permeability diminishes. Permeability and micro pore structure are therefore significant factors determining the damage degree of CO₂ flooding inflicts on tight reservoirs. In addition, temperature and pressure have a significant impact on the extent of reservoir damage caused by CO₂ flooding in the study region. At a given reservoir temperature, increasing CO₂ injection pressure can mitigate reservoir damage. It is recommended to avoid conducting CO₂ flooding projects in reservoirs with severe pressure attenuation, low permeability, and narrow pore throats as much as possible to prevent serious damage to the reservoir. At the same time, the production pressure difference should be reasonably controlled during the production process to reduce the risk and degree of calcium carbonate precipitation near oil production wells. Full article

Geological storage of CO₂ in offshore deep saline aquifers is widely recognized as an effective strategy for large-scale carbon emission reduction. This study aims to assess the mechanical integrity and storage efficiency of reservoirs using a multi-layer CO₂ injection method in the Enping 15-1 Oilfield CO₂ storage project which is the China’s first offshore carbon capture, utilization, and storage (CCUS) demonstration. A coupled Hydro–Mechanical (H–M) model is constructed using the TOUGH-FLAC simulator to simulate a 10-year CO₂ injection scenario, incorporating six vertically distributed reservoir layers. A sensitivity analysis of 14 key geological and geomechanical parameters is performed to identify the dominant factors influencing injection safety and storage capacity. The results show that a total injection rate of 30 kg/s can be sustained over a 10-year period without exceeding mechanical failure thresholds. Reservoirs 3 and 4 exhibit the greatest lateral CO₂ migration distances over the 10-year injection period, indicating that they are the most suitable target layers for CO₂ storage. The sensitivity analysis further reveals that the permeability of the reservoirs and the friction angle of the reservoirs and caprocks are the most critical parameters governing injection performance and mechanical stability. Full article

Abandoned production and monitoring wells in depleted oil and gas fields can readily serve as primary leakage pathways for stored CO₂. The temperature, pressure conditions around the wellbore bottom, and CO₂ concentration influence the phase behavior of CO₂ during leakage. This study establishes a 3D wellbore–reservoir coupled model using CO₂ injection data from 1 December 2009, in the DAS area, eastern Cranfield oilfield, Mississippi, USA, to analyze the dynamic evolution of CO₂ leakage along wellbores. Simulations are conducted using the collaboration of ECO2M and ECO2N v2.0 modules. The study examines leakage regimes under varying distances from the injection well and different reservoir temperatures. The results indicate that CO₂ phase changes occur primarily in wells near the injection point or under high-pressure and high CO₂ saturation conditions, usually with a short leakage period due to ice formation at the wellhead. In areas with low CO₂ saturation, prolonged leakage periods lead to significant pressure drops at the bottom, as well as the temperature as a result of the Joule–Thomson effect. Lower reservoir temperatures facilitate smoother and more gradual leakage. These findings provide a theoretical foundation for ensuring the safe implementation of CCUS projects and offer insights into the mechanical explanation of CO₂ geyser phenomena. Full article

This study investigates the impact of injection depth on CO₂ plume migration dynamics in saline aquifers, a critical aspect of secure and efficient carbon capture, utilization, and storage (CCUS). While CCUS offers a vital pathway for mitigating greenhouse gas emissions, challenges such as buoyancy-driven flow, salinity effects, and potential leakage threaten long-term CO₂ containment. Using compositional reservoir simulation (CMG GEM 2021.10, Calgary, Canada) and Illinois Basin Decatur Project (IBDP) data, we modeled CO₂ injection into a 10,000 ppm salinity aquifer, evaluating the effects of single- and multi-depth injection (5370 to 5385 ft). The results demonstrate that multi-depth injection significantly enhances CO₂–brine contact area, promoting dissolution trapping and mitigating buoyancy-driven migration. This enhanced dissolution and residual trapping improves horizontal containment and overall storage security in the modeled salinity environment. The work provides valuable insights for optimizing injection strategies to maximize CO₂ storage efficiency and minimize leakage risks. 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

With the continuous growth of global energy demand, greenhouse gas emissions are also rising, leading to serious challenges posed by climate change. Carbon Capture, Utilization, and Storage (CCUS) technology is considered one of the key pathways to mitigate climate change. Among the CCUS technologies, CO₂ storage in offshore saline aquifers has gained significant attention in recent years. This paper conducts an in-depth analysis of the Sleipner and Snøhvit projects in Norway and the Tomakomai project in Japan, exploring key issues related to the application, geological characteristics, injection strategies, monitoring systems, and simulation methods of CO₂ storage in offshore saline aquifers. This study finds that CO₂ storage in offshore saline aquifers has high safety and storage potential but faces several challenges in practical applications, such as geological reservoir characteristics, technological innovation, operational costs, and social acceptance. Therefore, it is necessary to further strengthen technological innovation and policy support to promote the development and application of CO₂ storage in offshore saline aquifers. This study provides valuable experiences and insights for similar projects worldwide, contributing to the sustainable development of CO₂ storage in offshore saline aquifers and making a greater contribution to achieving global net-zero emission targets. Full article

The application of carbon dioxide (CO₂) in enhanced oil recovery (EOR) projects is becoming increasingly more interesting in the petroleum industry because it can boost oil production rates while potentially reducing greenhouse gas emissions. The injected CO₂ causes oil swelling and viscosity reduction, making it easier to flow through the reservoir fractures. This article studies the performance of the first EOR CO₂ project in Croatia, which started operations in 2014 with a capacity of 0.41 million tons per year (Mtpa). The CO₂ source is a natural gas processing plant, which released the CO₂ into the atmosphere prior to the EOR project. Now, this CO₂ is continuously captured, compressed, transported, liquefied, and injected into the EOR fields of Ivanić and Žutica. Tertiary (EOR) oil recovery at these two oil fields is expected to raise the oil recovery factors up to 55% from the previously achieved 9% in the primary stage and 36% in the secondary stage. Besides the EOR project, this article reviews other carbon capture, utilization, and storage (CCUS) projects in Croatia, for the cement industry, power generation, and biofuel production. All these projects combined could bring the total CCUS capacity up to 1.843 Mtpa by 2030. Full article

As oil and gas companies are one of the major greenhouse gas emitters, they face increasing responsibility to address climate challenges. This highlights the necessity of integrating decarbonization options into their operations to meet global climate objectives. While progress in technologies for capturing, utilizing, and storing CO₂ (CCUS technologies) is often attributed to oil and gas companies, CCUS projects in the sector predominantly focus on carbon storage, namely CO₂ injection for enhanced oil recovery, which presents limited possibilities. Meanwhile, carbon capture and utilization (CCU) technologies offer a promising avenue for producing valuable products from CO₂, a potential that has been underexplored in theory and practice within the oil and gas sector. This study analyzes the development of the full CCU cycle by oil and gas companies, assessing the economic viability of such projects. It includes a content analysis of research materials on CCU deployment and a case study modeling the economic viability of producing methanol from CO₂ in Russia. The findings indicate that the estimated minimum price for CO₂-based methanol to achieve project payback is USD 1128 per ton, compared to approximately USD 400 per ton for traditional methanol. This price gap underscores the need to foster the development of low-carbon technologies, markets, and measures to support these projects. In the domain of CCU projects, cost-reduction measures could be more applicable, while regulatory measures, such as carbon taxes, currently have a limited impact on the economic viability of these projects. Full article

Geothermal power production may result in significant CO₂ emissions as part of the produced steam. CO₂ capture, utilisation, subsurface storage (CCUS) and developments to exploit geothermal resources are focal points for future clean and renewable energy strategies. The Synergetic Utilisation of CO₂ Storage Coupled with Geothermal Energy Deployment (SUCCEED) project aims to demonstrate the feasibility of using produced CO₂ for re-injection in the geothermal field to improve geothermal performance, while also storing the CO₂ as an action for climate change mitigation. Our study has the aim to develop innovative reservoir-monitoring technologies via active-source seismic data acquisition using a novel electric seismic vibrator source and permanently installed helically wound cable (HWC) fibre-optic distributed acoustic sensing (DAS) system. Implemented together with auxiliary multi-component (3C and 2C) geophone receiver arrays, this approach gave us the opportunity to compare and cross-validate the results using wavefields from different acquisition systems. We present the results of the baseline survey of a time-lapse monitoring project at the Hellisheiði geothermal field in Iceland. We perform tomographic inversion and multichannel seismic processing to investigate both the shallower and the deeper basaltic rocks targets. The wavefield analysis is supported by seismic modelling. The HWC DAS and the geophone-stacked sections show good consistency, highlighting the same reflection zones. The comparison of the new DAS technology with the well-known standard geophone acquisition proves the effectiveness and reliability of using broadside sensitivity HWC DAS in surface monitoring applications. Full article

To mitigate dangerous climate change effects, the 195 countries that signed the 2015 Paris Agreement agreed to “keep the increase in average global surface temperature below 2 °C and limit the increase to 1.5 °C” by reducing carbon emissions. One promising option for reducing carbon emissions is the deployment of carbon capture, utilization, and storage technologies (CCUS) to achieve climate goals. However, for large-scale deployment of underground carbon storage, it is essential to develop technically sound, safe, and cost-effective CO₂ injection and well control strategies. This involves sophisticated balancing of various factors such as subsurface engineering policies, technical constraints, and economic trade-offs. Optimization techniques are the best tools to manage this complexity and ensure that CCUS projects are economically viable while maintaining safety and environmental standards. This work reviews thoroughly and critically carbon storage studies, along with the optimization of CO₂ injection and well control strategies in saline aquifers. The result of this review provides the foundation for carbon storage by outlining the key subsurface policies and the application of these policies in carbon storage development plans. It also focusses on examining applied optimization techniques to develop CO₂ injection and well control strategies in saline aquifers, providing insights for future work and commercial CCUS applications. Full article