Geoenergy Science and Engineering最新文献

{"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":"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":"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":"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}

{"title":"Real-time model-based condition monitoring of geothermal systems under uncertainties – Case study on electrical submersible pumps","authors":"Pejman Shoeibi Omrani ,&nbsp;Yifan Yang ,&nbsp;Huub H.M. Rijnaarts ,&nbsp;Shahab Shariat Torbaghan","doi":"10.1016/j.geoen.2025.213775","DOIUrl":"10.1016/j.geoen.2025.213775","url":null,"abstract":"<div><div>Monitoring the condition of geothermal facilities and equipment (GFE) is crucial for ensuring reliable and cost-effective operations. This work emphasizes the importance of real-time data-driven condition monitoring for proactive operation and maintenance (O&amp;M) planning in geothermal assets. Recognizing that operational planning can be significantly impacted by uncertainties, a novel framework is proposed to monitor the performance of geothermal assets under these conditions. The approach combines machine learning (ML), statistical methods, and expert knowledge to account for uncertainty in evaluating the degradation or onset of failure in GFE. This method was applied to field data from a geothermal plant to monitor Electrical Submersible Pumps (ESPs) and tested for the accuracy and robustness of the framework. Additionally, the framework provides explainability, aiding in understanding the factors influencing equipment condition and degradation. The framework was capable of systematically detecting the onset of the ESP degradation up to six months prior to its failure, with an accuracy of more than 95% in estimating the performance of ESP during normal operation. The explainability layer provided insights on the cause of the failure which was not attributed to ESP malfunction but to a restriction in production inflow into the well. The framework's ability to accurately assess equipment condition under uncertainty supports more informed maintenance decisions, ultimately improving GFE operational reliability and efficiency.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213775"},"PeriodicalIF":0.0,"publicationDate":"2025-02-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143456003","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":"Reviewing CO2 dynamics in acidizing carbonate reservoirs: Mechanisms, impacts, and models","authors":"Mohammad Khojastehmehr,&nbsp;Mohammad Bazargan,&nbsp;Mohsen Masihi","doi":"10.1016/j.geoen.2025.213767","DOIUrl":"10.1016/j.geoen.2025.213767","url":null,"abstract":"<div><div>Acidizing is a stimulation technique used in underground reservoirs to enhance well productivity by increasing the permeability of the rock matrix. During the reaction between acid and carbonates, carbon dioxide (CO₂) is produced, and factors such as its quantity and physical state significantly influence the efficiency of the acidizing process. This review explores the impact of CO₂ on acidizing through four primary mechanisms: relative permeability reduction, surface area reduction, diffusivity modification, and oil viscosity reduction. Each mechanism can either positively or negatively influence the efficiency of wormhole propagation, which is crucial for the success of acidizing treatments. Experimental studies reveal that the production of non-aqueous CO₂ leads to a reduction in relative permeability. The reduction in available surface area caused by CO₂ leads to enhanced acid propagation. The effect of CO₂ on diffusion is complex, as it can either decrease or increase the diffusion coefficient depending on its phase—aqueous, gaseous, liquid, or supercritical—and whether it promotes enhanced mixing. Additionally, oil viscosity reduction in the presence of an additional phase can improve acid propagation under certain conditions. This review also highlights key research gaps. The threshold backpressure required to maintain CO₂ in the aqueous phase remains poorly defined, with studies indicating that even pressures exceeding 6.90 MPa (1000 psi) may not suffice in certain cases. The combined and individual effects of aqueous and non-aqueous CO₂ under diverse reservoir conditions remain poorly understood. Additionally, while multiphase pore-scale numerical models have shown promise in simulating CO₂ behavior during acidizing, core-scale models often fail to capture the intricate interplay of mechanisms, particularly when multiple phases coexist. Addressing these gaps requires future experimental and numerical studies to focus on the porous media implications of CO₂ interactions. Specifically, research should aim to identify the critical parameters and develop robust methodologies to quantify the effects of CO₂-related mechanisms. By doing so, this work can guide future research toward improving the predictability and effectiveness of acidizing treatments while ensuring practical applicability across diverse reservoir conditions.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213767"},"PeriodicalIF":0.0,"publicationDate":"2025-02-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143488840","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 analyses of rock damage behavior and fragmentation mechanism under enlarged hole impact conditions","authors":"Congshan Zhang ,&nbsp;Yan Zhao ,&nbsp;Ke Gao ,&nbsp;Bo Tian ,&nbsp;Huilan He ,&nbsp;Jiuquan Wang ,&nbsp;Junsheng Qin ,&nbsp;Qilei Yin","doi":"10.1016/j.geoen.2025.213778","DOIUrl":"10.1016/j.geoen.2025.213778","url":null,"abstract":"<div><div>The cluster down-the-hole hammer reverse-circulation drilling technology is an attractive approach for achieving a high rate of penetration (ROP) through the \"small hole drilling, large hole enlarged\" construction method. However, limited research has been conducted on the mechanism of button rock-breaking mechanism under enlarged impact conditions. In this paper, the rock crater morphology, debris size, and debris removal volume of sandstone, limestone, and granite with different ratio (<em>k</em>) of enlarged-hole to pilot-hole diameter were investigated by means of drop hammer impact test under the impact of a nine-button drill bit. Subsequently, a three-dimensional dynamic damage numerical model of button bit-enlarged hole rock based on the plastic damage model was established to investigate the impact stress distribution, damage evolution characteristics, impact depth and other parameters under enlarged hole impact loading. The laboratory tests showed that the limestone has the largest crater projection area, with a maximum impact depth of 1.396 mm at <em>k</em> = 2 and a maximum volume of rock debris removed of 3.925 cm³; the granite has the largest volume of debris removal at <em>k</em> = 3; the sandstone has a significantly higher depth of fragmentation than the other two types of rock, and has the largest crater size and volume of rock debris removed at <em>k</em> = 2. Numerical simulation indicated that the enlargement condition is more favorable to concentrate the stress around the borehole wall, resulting in rapid rock fragmentation. Under the enlargement condition, the peak impact force gradually increases with increasing <em>k</em>-value, and the impact depth declines with the increase of <em>k</em>-value. The peak impact force at <em>k</em> = 5 is similar to that of the non-enlargement condition, and the peak impact force will be smaller than that of the non-enlargement condition when it is lower than this enlargement ratio. Well wall damage in granite, limestone and sandstone under enlargement conditions (<em>k</em> = 2–3) is significantly less than in non-enlargement conditions and favors fragmentation of the rock while maintaining the stability of the borehole wall. Although larger reaming ratios <em>k</em> are conducive to rock fragmentation, the fracture effect and time consumption of <em>k</em>-values need to be comprehensively accounted for in practical engineering.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213778"},"PeriodicalIF":0.0,"publicationDate":"2025-02-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143471747","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}