Energy Geoscience最新文献

{"title":"ToC","authors":"","doi":"10.1016/S2666-7592(24)00089-1","DOIUrl":"10.1016/S2666-7592(24)00089-1","url":null,"abstract":"","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 1","pages":"Article 100374"},"PeriodicalIF":0.0,"publicationDate":"2025-01-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143101167","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":"Hydrothermal activity and its influence on hydrocarbon accumulation in deep dolomite reservoirs of the Ediacaran Dengying Formation, Sichuan Basin","authors":"Zhanlei Wang ,&nbsp;Chan Jiang ,&nbsp;Changcheng Yang ,&nbsp;Yuqiang Jiang ,&nbsp;Yifan Gu","doi":"10.1016/j.engeos.2024.100370","DOIUrl":"10.1016/j.engeos.2024.100370","url":null,"abstract":"<div><div>There are abundant hydrothermal events within the Dengying Formation dolomite of the Precambrian system in southwest China. Methods including petrography identification, fluid-inclusion observation, in-situ U-Pb dating, and in-situ measurement of rare earth element (REE), etc. are integrated to characterize hydrothermal activity process within the Dengying Formation dolomite. The hydrothermal activity therein can be divided into four stages on the basis of in-situ U-Pb dating results of saddle dolomite cements. The 1st-stage (415.0–400.0 Ma) and 2nd-stage (259.4–248.0 Ma) hydrothermal events are characterized by saddle dolomite filling along the margin of fractures, or filling within dilational breccia and zebra textures. Compared with matrix dolomite and seawater-derived fibrous dolomite, saddle dolomite exhibits obvious negative anomalies of Ce elements. The 3rd-stage (225.6–199.0 Ma) hydrothermal event is represented by galena, sphalerite and other Mississipppi Valley-type (MVT) mineral cements in residual space. The formation of lead-zinc ore is due to the precipitation of metal sulfide caused by the thermo-chemical sulfate reduction (TSR) reaction between hydrothermal fluids and hydrocarbons during the large-scale hydrocarbon charging period. The 4th-stage (130.0–41.0 Ma) hydrothermal event is characterized by quartz and a small amount of fluorite filling the residual pores with dolomites. Quartz and fluorite record the migration of deep high-temperature hydrothermal fluid along early fractures and residual pores. During this period, the hydrothermal fluids result in the heterogeneous structure of bitumen, which is a clear response to high-temperature hydrothermal activity.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 2","pages":"Article 100370"},"PeriodicalIF":0.0,"publicationDate":"2024-12-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143133478","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":"Thermo-hydro-mechanical-chemical coupling effects on the integrated optimization of CO2-EOR and geological storage in a high water-cut reservoir in Xinjiang, China","authors":"Yifan Ma ,&nbsp;Zongfa Li ,&nbsp;Hui Zhao ,&nbsp;Botao Liu ,&nbsp;Fankun Meng ,&nbsp;Chuixian Kong ,&nbsp;Yiyang Yin ,&nbsp;Haotian Zheng ,&nbsp;Yi Wu ,&nbsp;Chenjie Luo","doi":"10.1016/j.engeos.2024.100371","DOIUrl":"10.1016/j.engeos.2024.100371","url":null,"abstract":"<div><div>Carbon dioxide-enhanced oil recovery (CO₂-EOR) and storage is recognized as an economically feasible technique if used in suitable reservoirs. The type or form and capacity of this CO₂ sequestration technique is synergistically affected by heat, flow, stress, and chemical reactions. Aimed at addressing the technological issues in applying CO₂-EOR and storage in a high water-cut reservoir in Xinjiang, China, this paper proposes a thermo-hydro-mechanical-chemical coupling method during CO₂ flooding. The potential of CO₂ sequestration and EOR in the target reservoir is discussed in combination with the surrogate optimization method. This method works better as it considers the evolution of structural trapping, capillary trapping, solubility trapping, and mineral trapping during CO₂ injection as well as the influence the physical field has on the sequestration capacity for different forms of CO₂ sequestration. The main mechanisms of CO₂ sequestration in the high water-cut reservoir is structural trapping, followed by capillary trapping. Solubility trapping and mineral trapping have less contribution to the total sequestration capacity of CO₂. After optimization, the cumulative oil production was 2.36 × 10⁶ m³, an increase of 0.25 × 10⁶ m³ or 11.9 % compared to the pre-optimization value. The CO₂ sequestration capacity after optimization was 1.39 <span><math><mrow><mo>×</mo></mrow></math></span> 10⁶ t, which is an increase of 0.23 <span><math><mrow><mo>×</mo></mrow></math></span> 10⁶ t compared to values obtained before optimization; this effectively increases the area affected by CO₂ by 24.4 %. Of the four trapping mechanisms, capillary trapping and structural trapping showed a high increase of 32.5 % and 17.28 %, respectively, while solubility trapping and mineral trapping only led to an increase of 5.1 % and 0.43 %, respectively. This research could provide theoretical support for fully utilizing the potential of CO₂-EOR and sequestration technology.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 2","pages":"Article 100371"},"PeriodicalIF":0.0,"publicationDate":"2024-12-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143133323","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":"CO2 geological storage in sedimentary basins: An update on the potential and suitability evaluation and a field test","authors":"Yujie Diao,&nbsp;Xin Ma,&nbsp;Chenglong Zhang,&nbsp;Xiaolin Jin,&nbsp;Xufeng Li,&nbsp;Chao Zhang","doi":"10.1016/j.engeos.2024.100369","DOIUrl":"10.1016/j.engeos.2024.100369","url":null,"abstract":"<div><div>China has pledged to peak carbon dioxide (CO₂) emissions by 2030 and achieve carbon neutrality by 2060. Carbon capture and storage (CCS) will play a key role in these efforts. Over the past several years, the China Geological Survey (CGS) has completed the <em>Suitability Evaluation Map of CO</em>_<em>2</em> <em>Geological Storage in Main Sedimentary Basins in China and Adjacent Sea Regions</em> in 2017. This map reflects the suitability of the first- and secondary-order tectonic units within sedimentary basins for CO₂ geological storage for CCS planning. The Junggar Basin is recognized as an important region for future CCS projects. Results from a mesoscale evaluation using the volume method indicate that deep saline aquifers represent the most significant resources for CO₂ storage, with potential ranging from 48 × 10⁹ to 164 × 10⁹ t (with a P50 value of 96 × 10⁹ t). The highest storage potential is identified in the central and northern parts of the basin, reaching up to 9.5 × 10⁶ t/km² at the P50 probability level. In contrast, the hinterland, eastern, and western parts of the basin generally exhibit storage potential of below 1.0 × 10⁶ t/km² at the same probability level. The CGS has also characterized historical CO₂ plume migration in reservoirs at the storage site of the Shenhua CCS demonstration project and conducted numerical simulations of CO₂ plume migration for periods of 10 and 20 years following the shutdown of the injection well. The CGS implemented a kiloton-scale pilot test on CO₂-enhanced water recovery (CO₂-EWR) in eastern Junggar, revealing that CO₂ flooding can improve the pressure for fluid production, with the highest ratio of CO₂ to produced fluids estimated at approximately 1.2. Besides, an observation field for natural CO₂ leakage, covering about 930 m², was built in Qinghai Province. In natural CO₂ fields or at artificial CO₂ injection research sites, CO₂ leakage points are primarily related to the distribution of faults (especially fault crossing), which can serve as pathways for CO₂ leakage. The observation field provides a natural analog to wellbore failure and offers an opportunity to further monitor CO₂ geological storage sites. However, it has been inferred that borehole ZK10 at the observation field has become a leakage pathway due to the drilling activities, inadequate well-plugging, and abandonment procedures without considering CO₂ corrosion.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 1","pages":"Article 100369"},"PeriodicalIF":0.0,"publicationDate":"2024-12-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143101164","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":"Segmented evolution and exploration targets of the Cambrian platform margin in the Manxi area, Tarim Basin","authors":"Zongquan Hu ,&nbsp;Fan Feng ,&nbsp;Chengming Fang ,&nbsp;Zicheng Cao ,&nbsp;Tieyi Wang ,&nbsp;Kangkang Guo ,&nbsp;Yang Li ,&nbsp;Shi Wang","doi":"10.1016/j.engeos.2024.100367","DOIUrl":"10.1016/j.engeos.2024.100367","url":null,"abstract":"<div><div>The Cambrian platform margin in the Tarim Basin boasts favorable source-reservoir-cap assemblages, making it a significant target for hydrocarbon exploration in ultra- to extra-deep facies-controlled formations. Of the three major basins in western China, Tarim is the only basin with large-scale platform margin where no exploration breakthrough has been achieved yet. This study determines the vertical and lateral differential evolution of the platform margin (in the Manxi area hereafter referred to as the Cambrian Manxi platform margin) through fine-scale sequence stratigraphic division and a segmented analysis. The platform margin can be divided into the Yuqi, Tahe, Shunbei, and Gucheng segments, from north to south, based on the development of different ancient landforms and the evolutionary process of the platform. The Yuqi and Shunbei segments exhibit relatively low-elevation ancient landforms. Both segments were in a submarine buildup stage during the Early Cambrian, resulting in overall limited scales of their reservoirs. The Gucheng segment features the highest-elevation ancient landforms and accordingly limited accommodation spaces. As a result, the rapid lateral migration of high-energy facies zones leads to the development of large-scale reservoirs with only limited thicknesses. In contrast, the Tahe segment, exhibiting comparatively high-elevation ancient landforms, is identified as the most favorable segment for the formation of large-scale reservoirs. The cap rocks of the platform margin are dominated by back-reef dolomitic flats and tight carbonate rocks formed in transgressive periods. A comprehensive evaluation of source rocks, reservoirs, and cap rocks indicates that the Tahe segment boasts the optimal hydrocarbon accumulation conditions along the platform margin. In this segment, the Shayilike Formation transgressive deposits and the high-energy mound-shoal complexes along the platform margin of the Wusonggeer Formation constitute the optimal reservoir - cap rock assemblage, establishing this segment as the most promising target for hydrocarbon exploration in the platform margin.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 1","pages":"Article 100367"},"PeriodicalIF":0.0,"publicationDate":"2024-12-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143157535","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":"Traffic light system regulation of induced seismicity under multi-well fluid injection","authors":"Miao He ,&nbsp;Qi Li ,&nbsp;Xiaying Li ,&nbsp;Yao Zhang","doi":"10.1016/j.engeos.2024.100368","DOIUrl":"10.1016/j.engeos.2024.100368","url":null,"abstract":"<div><div>The occurrence time and magnitude of injection-induced seismicity are influenced by engineering factors, such as wellhead pressure, injection location, injection volume, and injection rate. Understanding the relationship between injection operations and seismic magnitude is of great significance for optimizing industrial production and reducing earthquake disasters. Numerical simulation of hydro-mechanical coupling is a crucial method for studying injection-induced seismicity. However, few studies have explored the risk management measures for injection-induced seismicity from the perspective of engineering. How seismic magnitudes can be reduced through reasonable adjustments to injection operations in engineering remains unclear. Therefore, in this study, a 3D hydro-mechanical coupling model involving multiple faults and injection wells was established based on the geological background and well location of Fox Creek, Canada. Different injection schemes under multi-well and multi-fault conditions were studied, and a traffic light system was used to simulate and control the magnitudes under a multi-well injection scheme. Specifically, we simulated injection scenarios involving up to three wells and analyzed the response of five faults. We compared the maximum moment magnitude of different scenarios by controlling the same injection volume. The results revealed the effect and advantage of the multi-well scheme in reducing seismic magnitude. To reduce the risk of induced seismicity, utilizing far-fault operational wells to compensate for the effects of near-fault operational wells proves to be an efficient and cost-effective method, with potential for wide practical applications.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 2","pages":"Article 100368"},"PeriodicalIF":0.0,"publicationDate":"2024-12-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143379251","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":"Source rock characterization of the Dingo Claystone, Barrow Sub-basin, Australia – Influence of contamination on geochemical analyses","authors":"Ummi Fayyadhah Binti Haji Talipudin ,&nbsp;Mohamed Ragab Shalaby","doi":"10.1016/j.engeos.2024.100366","DOIUrl":"10.1016/j.engeos.2024.100366","url":null,"abstract":"<div><div>An integrated study on source rock characterization and hydrocarbon generation potential modeling was conducted for the selected Dingo Claystone, Barrow Sub-basin, Australia. In this study, data were collected solely from two wells represented by the Bambra-1 and Bambra-2 wells. The collected data include those from bulk geochemical analyses of cuttings and sidewall cores sampled from the Late Jurassic Dingo Claystone. Geochemical data obtained from Rock-Eval pyrolysis and gas chromatography (GC) of extracted organic matter were integrated for source rock characterization and the construction of burial history and hydrocarbon generation in the Dingo Claystone. To improve the accuracy of thermal maturity estimations, only samples with <em>S</em>₂ greater than 1 were considered due to potential issues with peak integration and uncertainties of <em>T</em>_max determination in samples with lower <em>S</em>₂ values. Furthermore, Rock-Eval data from the Bambra wells may be unreliable due to the contamination of cuttings and side-wall core (SWC) samples by drilling mud additives and natural hydrocarbons, which could impact the reliability of the data for determining thermal maturity. This study reveals that the Dingo Claystone Formation has total organic carbon (<em>TOC</em>) contents ranging from 0.66 % to 8.31 %. A poor to good hydrocarbon generation potential is indicated, with a production yield (<em>PY</em>=<em>S</em>₁ + <em>S</em>₂) ranging from 1.37 to 10.44 mg HC/g rock. Hydrogen index values vary between 42 and 226 mg HC/g <em>TOC</em>, confirming that the Dingo Claystone is dominantly kerogen Type III, with minor contributions from types II/III and IV. Thermal maturity ranges from immature to late mature and is mostly in the oil window. This is indicated by <em>T</em>_max values of 398–462 °C and vitrinite reflectance (<em>R</em>_o, %) of 0.47–1.99. Some samples show suppressed <em>T</em>_max and a higher production index, which is typical for samples affected by drilling fluids during drilling operations. Additionally, gas chromatography (GC) analyses are used to interpret the paleodepositional environment showing mixed input between marine and terrestrial origins of the source rocks. One-dimensional basin modeling for the Bambra-1 and Bambra-2 wells was carried out to evaluate the burial and thermal history of the formation. The transformation ratio suggests that hydrocarbon generation has not reached its peak and is still in an ongoing phase. An indication of hydrocarbon migration can be observed in this formation based on the transformation ratio. The effects of contamination warrant further investigation, as it could significantly impact maturity estimates and data reliability.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 1","pages":"Article 100366"},"PeriodicalIF":0.0,"publicationDate":"2024-12-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143156897","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":"Deformation of the void space of pores and fractures of carbonates: Comprehensive analysis of core and field data","authors":"Dmitriy A. Martyushev ,&nbsp;Inna N. Ponomareva ,&nbsp;Shadfar Davoodi ,&nbsp;Yousef Kazemzadeh ,&nbsp;Ali Kadkhodaie ,&nbsp;Zhang Tao","doi":"10.1016/j.engeos.2024.100364","DOIUrl":"10.1016/j.engeos.2024.100364","url":null,"abstract":"<div><div>Many new and developed oilfields are confined to carbonate reservoirs with a complex void space structure. In this study, the behavior of carbonates as a function of decreased reservoir pressure was examined. The study was based on actual production data from wells rather than just on model data or results from computational experiments. Well-test data (170 well tests) and laboratory core samples (45 samples) results were used in the analysis. The problem of reservoir deformation has been comprehensively addressed at the micro and macro levels. The effect of reservoir permeability throughout the entire reservoir volume on reservoir pressure was determined. With a decline in reservoir pressure, the permeability of fractures and pores in carbonates decreases. The deformation coefficients, which characterize the actual rate of decrease in permeability with decreasing reservoir pressure, were also calculated. The deformation coefficients and data from core studies using μ-CT and SEM were compared. Based on micro-CT data, the effective diameters of the voids were calculated to be 93 μm, 109 μm, and 140 μm for the Vinnikovskoe, Sofinskoe, and Sukharev fields, respectively. Based on μ-CT and SEM data, the predominant geometric shapes of the voids were assessed. The deformation coefficient of voids was found to depend on their size and geometric shape. The study's findings revealed deformation coefficients of 0.172, 0.205, and 0.748 for the Vinnikovskoe, Sofinskoe, and Sukharev fields, respectively. Maximum deformation coefficients are typical for large voids with a predominant slot-like shape. However, even with the predominance of primary spherical voids in carbonates, the permeability of voids decreases with decreasing reservoir pressure.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 1","pages":"Article 100364"},"PeriodicalIF":0.0,"publicationDate":"2024-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143156901","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":"Integrated AutoML-based framework for optimizing shale gas production: A case study of the Fuling shale gas field","authors":"Tianrui Ye ,&nbsp;Jin Meng ,&nbsp;Yitian Xiao ,&nbsp;Yaqiu Lu ,&nbsp;Aiwei Zheng ,&nbsp;Bang Liang","doi":"10.1016/j.engeos.2024.100365","DOIUrl":"10.1016/j.engeos.2024.100365","url":null,"abstract":"<div><div>This study introduces a comprehensive and automated framework that leverages data-driven methodologies to address various challenges in shale gas development and production. Specifically, it harnesses the power of Automated Machine Learning (AutoML) to construct an ensemble model to predict the estimated ultimate recovery (<em>EUR</em>) of shale gas wells. To demystify the “black-box” nature of the ensemble model, KernelSHAP, a kernel-based approach to compute Shapley values, is utilized for elucidating the influential factors that affect shale gas production at both global and local scales. Furthermore, a bi-objective optimization algorithm named NSGA-II is seamlessly incorporated to optimize hydraulic fracturing designs for production boost and cost control. This innovative framework addresses critical limitations often encountered in applying machine learning (ML) to shale gas production: the challenge of achieving sufficient model accuracy with limited samples, the multidisciplinary expertise required for developing robust ML models, and the need for interpretability in “black-box” models. Validation with field data from the Fuling shale gas field in the Sichuan Basin substantiates the framework's efficacy in enhancing the precision and applicability of data-driven techniques. The test accuracy of the ensemble ML model reached 83 % compared to a maximum of 72 % of single ML models. The contribution of each geological and engineering factor to the overall production was quantitatively evaluated. Fracturing design optimization raised <em>EUR</em> by 7 %–34 % under different production and cost tradeoff scenarios. The results empower domain experts to conduct more precise and objective data-driven analyses and optimizations for shale gas production with minimal expertise in data science.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 1","pages":"Article 100365"},"PeriodicalIF":0.0,"publicationDate":"2024-12-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143156902","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":"Quantifying the crossover from capillary fingering to viscous fingering in heterogeneous porous media","authors":"Xin Yang ,&nbsp;Xingfu Li ,&nbsp;Bo Kang ,&nbsp;Bin Xu ,&nbsp;Hehua Wang ,&nbsp;Xin Zhao ,&nbsp;Bo Zhang ,&nbsp;Kai Jiang ,&nbsp;Shitao Liu ,&nbsp;Yanbing Tang","doi":"10.1016/j.engeos.2024.100362","DOIUrl":"10.1016/j.engeos.2024.100362","url":null,"abstract":"<div><div>Studying immiscible fluid displacement patterns can provide a better understanding of displacement processes within heterogeneous porous media, thereby helping improving oil recovery and optimizing geological CO₂ sequestration. As the injection rate of water displacing oil increases and the displacement pattern transits from capillary fingering to viscous fingering, there is a broad crossover zone between the two that can adversely affect the oil displacement efficiency. While previous studies have utilized phase diagrams to investigate the influence of the viscosity ratio and wettability of the crossover zone, fewer have studied the impact of rock heterogeneity. In this study, we created pore network models with varying degrees of heterogeneity to simulate water flooding at different injection rates. Our model quantifies capillary and viscous fingering characteristics while investigating porous media heterogeneity's role in the crossover zone. Analysis of simulation results reveals that a higher characteristic front flow rate within the crossover zone leads to earlier breakthrough and reduced displacement efficiency. Increased heterogeneity in the porous media raises injection-site pressure, lowers water saturation, and elevates the characteristic front flow rate, thereby expanding the extent of crossover zone.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 1","pages":"Article 100362"},"PeriodicalIF":0.0,"publicationDate":"2024-11-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143156899","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}