Geoenergy Science and Engineering最新文献

{"title":"A study of high-intensity high voltage electric pulse fracturing - A perspective on the energy distribution of shock waves","authors":"Zhehao Zhang ,&nbsp;Baisheng Nie ,&nbsp;Chao Ma ,&nbsp;Xianfeng Liu ,&nbsp;Yaoqian Li ,&nbsp;Changxing Li","doi":"10.1016/j.geoen.2025.213791","DOIUrl":"10.1016/j.geoen.2025.213791","url":null,"abstract":"<div><div>High voltage electrical pulse is regarded as a new fracturing technology. High voltage electrical pulse under electro-hydraulic conditions produces shock waves to destroy an object. However, the energy generation mechanism of shock waves is still unclear. In this study, image evolution and vibration time-frequency analysis are used to analyze the fracture mode and shock energy action mode of concrete. The high voltage electrical pulse fracturing process produces an intense flash of light. The rise in voltage leads to an increase in peak particle velocity and maximum amplitude. The discharge conditions for concrete fracture were 12 kV and 500 μF. The peak shock waves vibrational energy occurs in the time domain near 0 s, and at a frequency of 1.07 Hz. The energy of shock waves is concentrated in the frequency domain from 0 to 100 Hz. When concrete fractures, the energy of shock waves is shifted in the frequency domain from 0 to 10 Hz. The difference of amplitude integral is 276.14 when the voltage rises from 8 kV to 12 kV.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213791"},"PeriodicalIF":0.0,"publicationDate":"2025-02-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143478684","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental study on the formation and storage characteristics of CO2 hydrate under condition of grain gradating: Influence of different particle sizes and ratios","authors":"Xuemin Zhang ,&nbsp;Pengyu Li ,&nbsp;Hongbin Song ,&nbsp;Huan Sun ,&nbsp;Wenqiang Cui ,&nbsp;Jinping Li ,&nbsp;Qingbai Wu ,&nbsp;Peng Zhang","doi":"10.1016/j.geoen.2025.213794","DOIUrl":"10.1016/j.geoen.2025.213794","url":null,"abstract":"<div><div>CO₂ sequestration in seabed sediments is considered to be a promising way to reduce CO₂ emissions in atmosphere. The formation characteristics and gas storage capacity of hydrate are the critical indicators for measuring the effectiveness of geological sequestration of CO₂ by hydrate method. In this work, the formation processes and storage characteristics of CO₂ hydrate were studied in porous media composed of two single grain sizes (10 and 63 μm), porous media with grain gradatings (10–90 μm and 63–90 μm) of different mass ratios (30%, 50% and 70%) were further investigated. The influence of different gradation ratios on gas consumption rate and gas storage capacities of hydrate was discussed. The results showed that whether the difference in grain gradating between two mixtures was large or small, the larger the ratios of large grains in porous was, the more favorable for the formation of hydrate. The gas storage capacity is far from the gas storage theoretical upper limit of hydrate in the experiment. And geological transformation is necessary in order to increase the gas storage capacity. The gas storage capacity of hydrate decreased in porous media with grain gradating of 63–90 μm as the ratios of large grains increased. The variation of gas storage capacity was non-linear in porous media with grain gradating of 10–90 μm to a certain degree. Compared to the porous media composed of a single grain size (10 μm and 63 μm), the porous media system with 63–90 μm has an inhibitory effect on hydrate formation. However, the porous media system with 10–90 μm can promote the formation process of hydrate. The relevant results will provide essential theoretical support and guidance for CO₂ geological storage in seabed sediments by hydrate method.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213794"},"PeriodicalIF":0.0,"publicationDate":"2025-02-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143508778","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Enhanced prediction and uncertainty analysis for hydrogen production rate in depleted oil and gas reservoirs using advanced machine learning techniques","authors":"Zhengyang Du ,&nbsp;Lulu Xu ,&nbsp;Shangxian Yin ,&nbsp;Shuning Dong ,&nbsp;Zhenxue Dai ,&nbsp;Yue Ma ,&nbsp;Hung Vo Thanh ,&nbsp;Mohamad Reza Soltanian","doi":"10.1016/j.geoen.2025.213795","DOIUrl":"10.1016/j.geoen.2025.213795","url":null,"abstract":"<div><div>Climate change has driven a global shift from fossil fuels to renewable energy sources. However, the inherent variability of renewable energy, influenced by temporal and climatic factors, presents significant challenges. Underground hydrogen storage offers a promising solution for retaining surplus energy. The complexity and heterogeneity of geological formations are difficult to accurately quantify, leading to large uncertainties in storage assessment results, and computation of forward modeling for large-scale sites is often time-consuming. This study introduced a numerical modeling framework incorporating the complex geological structures into the uncertainty analysis of formation porosity and permeability. We developed surrogate models to predict the hydrogen storage process using three machine learning (ML) algorithms: Extreme Gradient Boosting (XGBoost), Random Forest (RF), and Support Vector Regression (SVR). The study utilized the Sobol algorithm to examine the impact of variations in porosity and permeability on model output. This study applied and analyzed the numerical modeling framework at Wangjiawan in China. The findings indicated that the average final stability of hydrogen injection mass approximates 1800 tons, with the average production mass of hydrogen reaching approximately 950 tons. The XGBoost model demonstrated excellent predictive performance (R² = 0.9679 and RMSE = 0.0318). Hydrogen production mass and rate are primarily influenced by the permeability of the formations, including injection and production wells during stable periods, while the impact of formation porosity is relatively minor. This study quickly and accurately predicts hydrogen storage processes under different geological parameters by employing ML algorithms. It also evaluates the importance of various geological parameters, providing crucial insights for effectively designing underground hydrogen storage facilities.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213795"},"PeriodicalIF":0.0,"publicationDate":"2025-02-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143508776","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Quantitative macro and micro analysis on enhanced oil recovery (EOR) mechanisms of multi-component composite steam flooding (MCCSF) based on image recognition algorithm","authors":"Qingjing Hong ,&nbsp;Zhanxi Pang ,&nbsp;Xiaohong Liu ,&nbsp;Bo Wang ,&nbsp;Dong Liu ,&nbsp;Hui Liao ,&nbsp;Luting Wang","doi":"10.1016/j.geoen.2025.213766","DOIUrl":"10.1016/j.geoen.2025.213766","url":null,"abstract":"<div><div>Multi-component composite steam flooding (MCCSF) has emerged as a promising method for enhancing oil recovery (EOR) in heavy oil reservoirs. However, its complex EOR mechanisms remain unclear, and a quantitative evaluation method for production performance in the process has not been established. In this paper, one dimensional (1D) displacement experiments were conducted to measure the oil displacement efficiency (ODE), and the optimal composite mode of multi-components was selected. This was coupled with two dimensional (2D) visualization experiments to investigate the macroscopic and microscopic EOR mechanisms during the process of MCCSF. Image recognition algorithms and image segmentation techniques were introduced to quantitatively analyze the volume of remaining oil (VORO) and the sweep efficiency at different locations during the different displacement stages. The results indicated that the integration of foams and viscosity reducer (VR) significantly improved both sweep efficiency and ODE. Finally, the effective oil production period was obviously extended. The ODE in the 1D experiments reached 76.3%, and the overall sweep efficiency in the 2D visualization experiments reached 97.97%. During pure steam flooding (PSF), the swept area was mainly targeted the near-well zone and the main flow channel. However, after adding foams and a VR for along with steam flooding, the remaining oil in the side channels and corner zones was effectively mobilized, and the ODE in the central swept areas and the displacement front were significantly enhanced, resulting in a final oil recovery factor (ORF) of 74.72%, which was 46.71% higher than that of PSF. This study primarily investigated the EOR mechanisms of MCCSF from two perspectives: improving ODE and sweep efficiency. These findings provided valuable insights and offer a quantitative method for the development effect evaluation.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213766"},"PeriodicalIF":0.0,"publicationDate":"2025-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143488422","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"ReaxFF molecular dynamics study on hydrogen generation from heavy oil in-situ combustion gasification","authors":"Qingyuan Chen ,&nbsp;Xiaodong Tang ,&nbsp;Wanfen Pu ,&nbsp;Dongdong Wang ,&nbsp;Renbao Liu","doi":"10.1016/j.geoen.2025.213786","DOIUrl":"10.1016/j.geoen.2025.213786","url":null,"abstract":"<div><div>Hydrogen is considered a key fuel in energy transition. In-situ combustion gasification (ISCG) of heavy oil is viewed as a promising new technology for blue hydrogen production, making the study of its mechanisms of crucial importance. The hydrogen production process through ISCG of heavy oil was investigated using reactive force field (ReaxFF) molecular dynamics simulation. The results indicate that hydrogen yield increases with temperature but decreases with higher oil saturation and oxygen-to-oil ratios. The detailed pathways of hydrogen production and consumption were revealed. The study reveals that hydrogen is primarily generated through the reaction of hydrogen radicals with water, contributing to 87.71% of the total hydrogen production reactions. The consumption of hydrogen is primarily due to its reaction with O radicals and OH radicals, accounting for 92.50% of the total consumption. Additionally, sulfur transfer in ISCG was analyzed and concluded; sulfur in heavy oil initially forms carbonyl sulfide (COS), which then converts into hydroxyl thiohydroxy (HOS) and hydrosulfide ion (HS) under the influence of water and oxygen, and subsequently transforms into H₂S and SO₂.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213786"},"PeriodicalIF":0.0,"publicationDate":"2025-02-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143465305","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Thermal-hydro-mechanical coupled dual-medium model of inclined wellbore in fractured anisotropic formations","authors":"Yi Qiu ,&nbsp;Tianshou Ma ,&nbsp;Jinhua Liu ,&nbsp;Ali.M. Fadhel ,&nbsp;Nian Peng ,&nbsp;Honglin Xu ,&nbsp;P.G. Ranjith","doi":"10.1016/j.geoen.2025.213782","DOIUrl":"10.1016/j.geoen.2025.213782","url":null,"abstract":"<div><div>The deep shale formation exhibits anisotropic and fractured properties. Previous models of shale wellbore stability have primarily focused on fractured or mechanical anisotropies of shale. Furthermore, thermal effects are inevitably considered when drilling deep shale formations. Nevertheless, the instability mechanism of a wellbore under the combined effects of anisotropy, fractures, and thermal-hydro-mechanical coupling is unclear. Thus, based on the assumption of generalized plane strain, anisotropic porothermoelastic theory, and dual-porosity medium theory, this study established a thermal-hydro-mechanical coupled dual-porosity medium model for inclined wellbore considering complete material anisotropy. The finite element formulation was employed to solve this model. Parametric analysis was performed to investigate the effect of dual-porosity medium properties and material anisotropy parameters on effective stress, fracture pore pressure(<em>p</em>^II), and matrix pore pressure(<em>p</em>^I). Through model comparison, the effective stress, pore pressure, and failure zone were observed to be completely different from those of the traditional elastic isotropic dual-porosity medium model and elastic anisotropic single-porosity medium model when subjected to the combined action of influence dual-porosity medium and anisotropy. With the elastic anisotropy index increases, the elastic anisotropic <em>p</em>^I is smaller than the elastic isotropic <em>p</em>^I. The effective stiffness of the rock increases with the elastic anisotropy index, which leads to the generation of ‘negative’ thermal stress, reduces the effective radial stress and hoop stress. When the well inclination exceeds 60°, the evolution of the induced <em>p</em>^I in elastic anisotropy is significantly different from that in elastic isotropy in the X direction, but <em>p</em>^II in is not sensitive to the change of well inclination. When a horizontal well is drilled parallel to the bedding direction, the risk of wellbore shear failure will be reduced for a higher ratio of anisotropy in elasticity, solid thermal expansion, and permeability.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213782"},"PeriodicalIF":0.0,"publicationDate":"2025-02-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143488679","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Using an objective function to guide the parameterization of a stratigraphic forward model","authors":"João Vitor Lottin Boing ,&nbsp;Ana Paula Soares ,&nbsp;Paulo César Soares ,&nbsp;Lindaura Maria Steffens ,&nbsp;Luiz Adolfo Hegele Júnior ,&nbsp;Jessica de Souza Brugognolle ,&nbsp;Bruno Mateus Bazzo ,&nbsp;Mathieu Ducros ,&nbsp;Daniel Fabian Bettú","doi":"10.1016/j.geoen.2025.213783","DOIUrl":"10.1016/j.geoen.2025.213783","url":null,"abstract":"<div><div>Building representative geological models of reservoirs is a complex task, especially while using traditional geostatistical modeling methods due to data limitations. Stratigraphic Forward Modeling (SFM) enhances the accuracy of models by incorporating geologic and depositional concepts, resulting in greater applicability. However, the method struggles with well data integration and definition of simulation input parameters which are not easily drawn from usual available data or conceptual modeling. Hence, there are uncertainties related to SFM input parameters and the reliability of results. In this work, SFM multi-realizations performed by DionisosFlow™ were analyzed through an objective function that measures similarity between facies successions (stratigraphic correlation objective function – SCOOF) to compose an empirical methodology that performs the adjustment of SFM models to well data. A set of scenarios was assembled by varying a group of selected uncertain parameters. These scenarios were submitted to SCOOF calculation and parameter values were taken from those that gave lower SCOOF values. By re-parameterizing the initial model with chosen values, thickness and lithology deposition improvements in wells were obtained and validated by the decline of objective function values from the initial to the final model.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213783"},"PeriodicalIF":0.0,"publicationDate":"2025-02-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143471746","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental and numerical study of the effect of polymer flooding on sand production in poorly consolidated porous media","authors":"Daniyar Kazidenov ,&nbsp;Sagyn Omirbekov ,&nbsp;Meruyet Zhanabayeva ,&nbsp;Yerlan Amanbek","doi":"10.1016/j.geoen.2025.213746","DOIUrl":"10.1016/j.geoen.2025.213746","url":null,"abstract":"&lt;div&gt;&lt;div&gt;Polymer flooding is crucial in hydrocarbon production, increasing oil recovery by improving the water–oil mobility ratio. However, the high viscosity of displacing fluid may cause problems with sand production on poorly consolidated reservoirs. This work investigates the effect of polymer injection on the sand production phenomenon using the experimental study and numerical model at a laboratory scale.&lt;/div&gt;&lt;div&gt;The experiment uses an artificially made sandstone based on the characteristics of the oil field in Kazakhstan. Polymer solution based on Xanthan gum is injected into the core to study the impact of polymer flooding on sand production. The rheology of the polymer solution is also examined using a rotational rheometer, and the power-law model fits outcomes. The fitting parameters are used for the numerical model as an input. We observe no sand production during the brine injection at various flow rate ranges. However, the sanding is noticed when the polymer solution is injected. More than 50% of cumulatively produced sand is obtained after one pore volume of polymer sand is injected.&lt;/div&gt;&lt;div&gt;In the numerical part of the study, we present a coupling model of the discrete element method (DEM) with computational fluid dynamics (CFD) to describe the polymer flow in a granular porous medium. The numerical model is performed considering the particle size distribution, porosity, and cementation behavior of the sample associated with the sandstone of the Kazakhstan reservoir. In the solid phase, the modified cohesive contact model characterizes the bonding mechanism between sand particles. The fluid phase is modeled as a non-Newtonian fluid using a power-law model. The drag force acting on a particle by the fluid is calculated considering the rheology of non-Newtonian fluid. We verify the numerical model with the laboratory experiment by comparing the dimensionless cumulative mass of produced particles. The numerical model observes non-uniform bond breakage when only a confining stress is applied. On the other hand, the injection of the polymer into the sample leads to a relatively gradual decrease in bonds. A greater fluid velocity enhances the influence of rheological parameters on the particle drag force, which causes intensive sand production at the onset of the injection. As fluid and particle velocities decrease, sand production enters a transient phase associated with a gradual decrease in the mass of sand produced over time. The polymer viscosity is lower at the region near the outlet hole, where the unbonded particles significantly predominate. In contrast, higher fluid viscosity is established in areas with tightly bonded particles, where the polymer flows at a lower velocity. Therefore, even at lower velocity values, the shear-thinning characteristics of polymer solution maintain the drag force at a higher and more constant level compared to water injection, in which the drag force decreases dramatically. The ratio of medium","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213746"},"PeriodicalIF":0.0,"publicationDate":"2025-02-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143452802","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effect of pore-throat structure on irreducible water saturation and gas seepage capacity in a multilayer tight sandstone gas reservoir","authors":"Lianhe Wang ,&nbsp;Xiaofeng Li ,&nbsp;Jingjian Wang ,&nbsp;Haibo Zhang ,&nbsp;Hongguang Shi ,&nbsp;Guangfeng Liu ,&nbsp;Daoyong Yang","doi":"10.1016/j.geoen.2025.213787","DOIUrl":"10.1016/j.geoen.2025.213787","url":null,"abstract":"&lt;div&gt;&lt;div&gt;In this study, effects of pore-throat structure on gas seepage capacity in a multilayer tight sandstone gas reservoir and the interlayer interference characteristics during commingled multilayer production have been experimentally investigated. More specifically, representative core samples were selected from a multilayer tight sandstone gas reservoir in the eastern Ordos Basin according to a statistical analysis of various cores with respect to their petrophysical properties. Then, high-pressure mercury intrusion (HPMI) experiments were conducted to obtain capillary pressure curves of core samples collected from each layer, while their corresponding pore-throat structure characteristics were evaluated based on median throat radius, cutoff throat volume ratio, pore-throat skewness, and fractal dimension. Subsequently, combined with the nuclear magnetic resonance (NMR) technique, gas-water seepage experiments with the collected core samples of each layer were performed to obtain the relative permeability curves and &lt;em&gt;T&lt;/em&gt;&lt;sub&gt;2&lt;/sub&gt; spectrum distribution curves. Considering the effect of pore-throat structure heterogeneity and water saturation on gas slippage, gas relative permeabilities of core samples were corrected. According to irreducible water saturation distribution, gas relative permeability together with water locking damage coefficient, irreducible water saturation and gas seepage capacity of each layer were quantitatively assessed. In addition, depletion experiments from single- and two-layer cores were conducted to examine the impact of pressure differences and pore-throat structure variations on interlayer interference. The heterogeneity of throats is found to be the main factor dominating irreducible water saturation. With the aggravating heterogeneity in the pore-throat structure, there exists an increase in irreducible water saturation and water locking saturation. Irreducible water is principally distributed in small pores/throats controlled by capillary force, leading to a more serious water locking phenomenon. With a decrease in proportion of small throats and a reduction in structure heterogeneity of large throats, irreducible water mainly occupies as a form of membrane in large pores/throats whose proportion and heterogeneity are the key to gas seepage capacity. With an increase in proportion of large throats and a reduction in their structure heterogeneity, the damage coefficient due to water locking becomes smaller, gas relative permeability at the irreducible water saturation increases, and the gas seepage capacity is enhanced. With a deterioration of pore-throat structures, irreducible water saturation increases, water locking phenomenon intensifies, and gas seepage capacity is weakened. The increase in disparity of interlayer pore-throat structure leads to heightened levels of interlayer interference. The interlayer pressure differentials play a crucial role in determining the extent of interlayer interfere","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213787"},"PeriodicalIF":0.0,"publicationDate":"2025-02-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143552935","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Cement additives to mitigate wellbore cement degradation in CO2 corrosive environment: A review","authors":"Theogene Hakuzweyezu ,&nbsp;Liwei Zhang ,&nbsp;Manguang Gan ,&nbsp;Yan Wang ,&nbsp;Ishrat Hameed Alvi ,&nbsp;Chikezie Chimere Onyekwena","doi":"10.1016/j.geoen.2025.213785","DOIUrl":"10.1016/j.geoen.2025.213785","url":null,"abstract":"<div><div>To mitigate climate change concerns and fulfil the net-zero emission targets, CO₂ geological utilization and storage (CGUS) is currently the most promising strategy for reducing anthropogenic CO₂ emission levels. CGUS involves injecting captured CO₂ into deep geological formations. Wellbore cement, as an integral part of the CGUS system, is chemically unstable in CO₂-rich conditions because exposure of its hydrated products to CO₂ causes physicochemical changes that are harmful to the cement matrix. Exposure to CO₂ results in cement degradation and integrity loss, which is a major cause of CO₂ leakage via wellbores. Therefore, to minimize cement integrity loss, cement slurry must be properly prepared. Researchers have made notable advancements in formulating cement by incorporating diverse additives into cement to boost its resistance to CO₂ corrosion. This review intends to summarize the findings from recent advances of CO₂ corrosion remediation using various cement additives, as well as to highlight their potential to be incorporated into wellbore cement to mitigate CO₂ corrosion. Furthermore, the key mechanisms by which different additives enhance the effectiveness of CO₂ corrosion mitigation have been demonstrated. In light of current research advances and existing problems, gaps in the research have been identified and considerations for future development of formulations of CO₂-resisting wellbore cement slurry have been provided.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213785"},"PeriodicalIF":0.0,"publicationDate":"2025-02-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143520720","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}