Natural Gas Industry B最新文献

{"title":"CO2 solubility and mineral trapping behavior in high-salinity reservoirs","authors":"Shugang Yang ,&nbsp;Linlin Zhang ,&nbsp;Shuangxing Liu ,&nbsp;Mingyu Cai ,&nbsp;Ming Xue ,&nbsp;Xingchun Li ,&nbsp;Kunfeng Zhang","doi":"10.1016/j.ngib.2026.03.006","DOIUrl":"10.1016/j.ngib.2026.03.006","url":null,"abstract":"<div><div>CO₂ solubility and mineral trapping behavior are critical to the stability and effectiveness of integrating CO₂ geological storage synergistically with gas field produced water (GPW) reinjection, a promising strategy for achieving co-benefits in pollution mitigation and carbon emission reduction. To investigate CO₂ solubility-mineral trapping during co-injection with GPW–characterized by high salinity and complex ion composition–a series of CO₂-GPW-rock interaction experiments and geochemical simulations were conducted using sandstone and limestone samples, together with simulated GPW of salinities ranging from 47.6 to 225.5 g/L. The results indicate that: (1) CO₂ solubility-mineral trapping behavior is governed primarily by CO₂ pressure, injection method, and GPW salinity, and is further influenced by calcium concentration and rock mineralogy. Under the experimental conditions, the CO₂ solubility-mineral trapping capacity ranged from 9.03 to 11.01 g/L, with corresponding trapping proportions between 74.56% and 87.38%; (2) within a closed CO₂-GPW-rock reactive system, the time-dependent CO₂ solubility-mineral trapping proportion can be described by the cumulative Weibull model. The CO₂ solubility-mineral trapping capacity increases with increasing CO₂ pressure but decreases with increasing GPW salinity. A slight elevation in calcium concentration enhances CO₂ solubility-mineral trapping at low CO₂ pressures, despite concurrent increases in ionic strength and brine salinity. When the GPW salinity remains constant, the variation in calcium concentration exerts only a limited influence on CO₂ solubility-mineral trapping; (3) a higher reactive mineral content in the reservoir enhances CO₂ solubility-mineral trapping, and intermittent injection significantly improves this process; (4) the cumulative solubility-mineral trapping capacity can reach 22.13–38.01 g/L, representing 2.28–3.04 times the capacity achieved under single-injection conditions. These findings underscore the importance of carefully selecting storage sites and designing injection schemes in CO₂ geological storage operations.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 2","pages":"Pages 147-163"},"PeriodicalIF":6.5,"publicationDate":"2026-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147828171","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Inhibition performance and mechanisms of methane hydrate inhibitors in oil and gas pipelines","authors":"Jie Wang ,&nbsp;Yong Cheng ,&nbsp;Yuan Li ,&nbsp;Pan Ma ,&nbsp;Hualei Xu ,&nbsp;Houshun Jiang","doi":"10.1016/j.ngib.2026.03.003","DOIUrl":"10.1016/j.ngib.2026.03.003","url":null,"abstract":"<div><div>During winter natural gas transportation, hydrate formation under low-temperature and high-pressure conditions frequently results in pipeline blockage and severe low assurance challenges. Although conventional thermodynamic hydrate inhibitors (THIs) are effective in shifting hydrate phase equilibrium, the application is constrained by high volumetric injection requirements and the associated operational costs, thereby driving research interest toward low-dosage hydrate inhibitors (LDHIs). This study integrates high-pressure pipeline flow simulations with molecular dynamics simulations to systematically evaluate the inhibition performance and elucidate the molecular-scale mechanisms of representative inhibitor classes in methane hydrates. Pipeline simulation results indicate that, at low additive concentrations: (1) the inhibition effectiveness of cations follows the order Al³⁺ &gt; Fe²⁺ &gt; Ca²⁺ &gt; Na⁺, suggesting a strong dependence on ionic charge density; (2) at identical mass fraction, methanol exhibits greater thermodynamic inhibition performance than ethylene glycol. Notably, 5.0 wt% ethylene glycol accelerates hydrate formation kinetics, exhibiting an anomalous promotion effect. For kinetic inhibitors and their blends, the following observations were obtained: (3) PVP K30 exhibited optimal inhibition performance at 1.0 wt%, significantly extending the hydrate induction time; moreover, the combination of 1.0 wt% PVP K30 with 5.0 wt% methanol completely suppressed hydrate formation under the tested conditions while substantially reducing the required alcohol dosage; (4) molecular-scale analysis indicates that methanol and ethylene glycol primarily act by shifting the hydrate phase equilibrium and perturbing the hydrogen-bond network of water. In contrast, PVP K30 inhibits hydrate formation by disrupting hydrogen-bond structures and decreasing methane–water association through steric hindrance and interfacial adsorption. The blended system exhibits a clear synergistic effect between thermodynamic and kinetic inhibition, combining a phase equilibrium shift with delayed hydrate formation kinetics. This THI-focused investigation systematically clarifies the inhibition of mechanisms of representative additives and provides a scientific basis for selecting cost-effective LDHIs strategies for hydrate control in oil and gas pipelines, with direct relevance to mitigating hydrate blockage in field operations.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 2","pages":"Pages 239-255"},"PeriodicalIF":6.5,"publicationDate":"2026-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147828187","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Sand-carrying thresholds of viscous slickwater: Weissenberg number–based prediction and field application","authors":"Junlin Wu,&nbsp;TianBo Liang,&nbsp;Bin Wang,&nbsp;Leyi Zheng,&nbsp;Hao Bai,&nbsp;Fangzhou Xu,&nbsp;FuJian Zhou","doi":"10.1016/j.ngib.2026.03.004","DOIUrl":"10.1016/j.ngib.2026.03.004","url":null,"abstract":"<div><div>The complex viscoelastic and shear-thinning behavior of slickwater fracturing fluids imposes competing effects on proppant transport, complicating the prediction of sand-carrying capacity and increasing the sand plugging risk. This study quantifies slickwater elasticity over a range of shear rates using the Weissenberg number (Wi) and establishes a fracture-scale shear-rate calculation method to estimate elastic energy at different flow velocities. The results show that: (1) the Wi strongly correlates with sand-carrying capacity, demonstrating its effectiveness in characterizing elastic-dominated transport behavior; (2) fracture experiment identify distinct settling-rate thresholds for slickwater systems with different polymer concentrations; (3) at these thresholds, fluids transporting equivalent proppant volumes exhibit identical elastic energies, indicating a the existence of a critical elastic-energy requirement for stable proppant suspension; (4) elastic-energy thresholds are established for three sand concentrations, allowing rapid prediction of sand-carrying capacity across slickwater systems with different viscosities; and (5) a field construction strategy derived from the predicted operating window is validated through field trials conducted both within and outside this window, with close agreement observed between the predicted and actual proppant-transport performance. This study provides a quantitative and practical framework for optimizing slickwater fracturing operations.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 2","pages":"Pages 192-205"},"PeriodicalIF":6.5,"publicationDate":"2026-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147828173","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Machine-learning models for classification of mudcake thickness in oil-based drilling fluids","authors":"Shadfar Davoodi ,&nbsp;Grachik Eremyan ,&nbsp;Amir H. Mohammedi ,&nbsp;Mohammed Al-Shargabi ,&nbsp;Evgeny Burnaev","doi":"10.1016/j.ngib.2026.03.007","DOIUrl":"10.1016/j.ngib.2026.03.007","url":null,"abstract":"<div><div>The performance of oil-based drilling fluids (OBDFs) is critical for maintaining drilling efficiency under conditions in which water-based fluids fail to perform effectively. Mudcake or filtercake thickness (MCT) is a key property of OBDFs because it directly influences wellbore stability and the extent of formation damage. Conventional methods for determining MCT rely on manual laboratory measurements that are time-consuming and cannot represent real-time downhole conditions, thereby limiting their value for operational decision-making and motivating the development of reliable predictive methods. This study proposes a novel framework for the near-real-time classification of MCT in OBDF systems. A comprehensive field dataset was compiled from five routinely measured, rapidly acquired laboratory parameters: mud weight, temperature, alkalinity, emulsion stability, and Marsh funnel viscosity. Four machine-learning classifiers—extreme gradient boosting (XGB), support vector machine, extreme learning machine, and multi-layer perceptron—were developed to classify MCT into three operationally meaningful categories: Excellent (≤1.0 mm), Good (1.0–2.2 mm), and Poor (&gt;2.2 mm). The developed models achieved high classification accuracy, with the XGB algorithm demonstrating the most stable and reproducible performance (test accuracy: 0.98, F1-score: 0.98). Comprehensive evaluation—including receiver operating characteristic analysis, model confidence assessment, learning curves, group K-fold cross-validation, and external validation—confirmed the strong generalization capability of the XGB model, which achieved 94.81% accuracy when applied to completely unseen wells. Interpretability analysis using SHapley Additive exPlanations (SHAP) identified emulsion stability as the dominant predictive feature and revealed that parameter interactions (e.g., alkalinity–emulsion stability) vary dynamically across different MCT classes. The primary innovation of this study lies in reframing MCT prediction as a multi-class classification problem rather than a traditional regression task, enabling rapid and actionable interpretation of drilling fluid performance. The proposed framework provides a semi-automated, data-driven tool for near-real-time monitoring of MCT in OBDF systems, reducing reliance on slow laboratory measurements and supporting timely operational decisions that improve drilling efficiency and preserve wellbore integrity in complex drilling environments.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 2","pages":"Pages 206-227"},"PeriodicalIF":6.5,"publicationDate":"2026-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147828185","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The synthesis and evaluation of two new gas hydrate kinetic inhibitors","authors":"Huang Liu ,&nbsp;Minghao Liu ,&nbsp;Jianfen Du ,&nbsp;Qingping Li ,&nbsp;Ping Guo ,&nbsp;Yanghui Liu","doi":"10.1016/j.ngib.2026.03.002","DOIUrl":"10.1016/j.ngib.2026.03.002","url":null,"abstract":"<div><div>Gas hydrate plugging is a common yet hazardous problem during oil and gas reservoir exploitation, compelling the petroleum industry to invest substantial resources annually in mitigation strategies. Two novel hydrate kinetic inhibitors (HKIs), a PVP derivative (PVP-DP) and a PVCap derivative (PVCap-DP), were synthesized and systematically evaluated. Structural characterization by FT-IR, NMR, and TG analyses confirmed increased molecular weights and the introduction of additional polar functional groups relative to the present polymers. In pure water at a subcooling temperature of 6.2 K and a concentration (C_p) of 1 wt%, the methane hydrate induction times (<em>I</em>_<em>h</em>) for PVP-DP and PVCap-DP were 358 min and 395 min, respectively. These values significantly exceed those observed in distilled water (23 min) and in systems containing commercial HKIs, such as PVP (138 min) and VC-713 (272 min). Increasing C_p to 3 wt% further prolonged <em>I</em>_<em>h</em> to 911 min and 964 min, respectively. Even at a higher subcooling of 8.4 K, <em>I</em>_<em>h</em> remained considerable at 126 min and 158 min, demonstrating sustained inhibition under more severe thermodynamic driving forces. Synergistic effects were observed when HKIs (3 wt%) were combined with glycol (1 wt%), resulting in <em>I</em>_<em>h</em> values of 230 min and 268 min. Increasing the glycol concentration to 3 wt% maintained a strong inhibition performance, with <em>I</em>_<em>h</em> values of 211 min and 238 min even at a subcooling of 9 K. In addition, both derivatives exhibited effective inhibition in water/diesel emulsion systems. At 6.2 K subcooling, the PVP-DP (3 wt%)–water/diesel emulsion system achieved an <em>I</em>_<em>h</em> of 404 min, which was markedly longer than that of the uninhibited water/diesel emulsion (51 min), although the emulsion phase moderately reduced the inhibitor efficiency. Overall, PVP-DP and PVCap-DP demonstrate strong kinetic inhibition performance against the formation of natural gas hydrate in both aqueous and emulsion systems, indicating promising application potential in complex production environments.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 2","pages":"Pages 228-238"},"PeriodicalIF":6.5,"publicationDate":"2026-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147828186","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Modeling overpressure vertical transfer via faults in clastic sequences at the basin scale: Implications for overpressure generation and fluid flow","authors":"Chao Li ,&nbsp;Jun Li ,&nbsp;Huanwei Shi ,&nbsp;Xiaorong Luo ,&nbsp;Yukai Qi ,&nbsp;Zhongpei Zhang ,&nbsp;Changrong Bian ,&nbsp;Yida Zhao","doi":"10.1016/j.ngib.2026.03.001","DOIUrl":"10.1016/j.ngib.2026.03.001","url":null,"abstract":"<div><div>The vertical transfer of overpressure significantly influences the subsurface fluid dynamics, fault zone stability, and geomechanical drilling safety. However, the mechanisms governing vertical overpressure transfer through faults remain poorly understood, and few quantitative assessments have clarified how key geological parameters control the magnitude and evolution of vertically transferred overpressure. In this study, a conceptual model for overpressure vertical transfer was developed, and a sensitivity analysis of geological factors controlling this process was conducted using the DMflow simulator. The results indicate that fault-zone permeability, fault activity duration, sand body permeability, the number of sand bodies connected by a fault, and the initial overpressure difference exert a strong control on both the transfer process and the magnitude of the vertically transferred overpressure. In contrast, the fault dip and sand body spacing have a relatively minor influence on the vertical transfer overpressure. In permeable formations, vertically transferred overpressure dissipates rapidly; therefore, overpressure generated by multiple fault activation events cannot be effectively accumulated. The overpressure is uniform within permeable formations connected by a fault; however, the pressure coefficient is highest in the shallow formation. Overpressure transfer alters local fluid migration pathways. During overpressure re-equilibration, the development of a strong fluid potential gradient promotes the rapid upward migration of deep fluids into shallower layers along the fault. This understanding not only provides new insights into the mechanisms of overpressure generation in sedimentary basins but also has significant implications for predicting pre-drilling formation pressure and improving the understanding of fluid flow behavior within fault zones.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 2","pages":"Pages 129-146"},"PeriodicalIF":6.5,"publicationDate":"2026-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147828188","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Rock-breaking experiments and simulations of shaped cutters in hard rock formations","authors":"Yang Guan,&nbsp;Qingyou Liu,&nbsp;Tao Huang,&nbsp;Zhengtong Mou","doi":"10.1016/j.ngib.2026.01.005","DOIUrl":"10.1016/j.ngib.2026.01.005","url":null,"abstract":"<div><div>To address the challenges of rapid bit failure and high drilling costs associated with hard limestone in Sichuan Basin of China, we conducted rock-breaking experiments and simulations of shaped (cylindrical, ridge, and chopper) cutters. Rock mechanics, drillability, and acoustic emission indentation tests revealed the drilling resistance characteristics of the limestone: average uniaxial compressive strength of 202.472 MPa, tensile strength of 7.092 MPa, and drillability of 7.866. We evaluated the performance differences between the shaped cutters before introducing an efficient and innovative finite-discrete-infinite element method (FDIEM) to establish an interaction model between the shaped cutters and limestone. The simulation results indicated the following: (1) The shaped cutters demonstrated superior rock-breaking performance compared to the traditional cylindrical cutter. (2) Compared with the cylindrical cutter, the ridge cutter yielded the lowest peak indentation force and mechanical specific energy, with reductions of 8.71 % and 33.83 %, respectively. This confirmed that the ridge cutter had the optimal tooth profile for the target formation. Its rock-breaking mechanism relied on the convex edges to induce localized high stress in the rock, which enabled efficient rock fragmentation via a plowing mode while mitigating frictional resistance from cuttings. (3) The novel chopper cutter with its secondary step surface exerted a buffering effect on the cuttings, thereby achieving high cutting stability. This study provides theoretical and technical support for the design of personalized drill bits and the acceleration of the rate of penetration (ROP) in deep hard rock formations.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 1","pages":"Pages 93-110"},"PeriodicalIF":6.5,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147387908","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Molecular simulation of CH4/CO2/N2 ternary mixture competitive adsorption and diffusion dynamics in tight sandstone","authors":"Shihao Xu ,&nbsp;Cheng Cao ,&nbsp;Yulong Zhao ,&nbsp;Liehui Zhang ,&nbsp;Qingping Li ,&nbsp;Shouwei Zhou ,&nbsp;Shaomu Wen ,&nbsp;Yong Hu ,&nbsp;Jinbu Li ,&nbsp;Yunsheng Wei ,&nbsp;Wei Xiong ,&nbsp;Bowen Guan","doi":"10.1016/j.ngib.2026.01.003","DOIUrl":"10.1016/j.ngib.2026.01.003","url":null,"abstract":"<div><div>Injecting impure CO₂ for enhanced gas recovery (CO₂-EGR) offers a dual benefit by improving natural gas extraction while enabling CO₂ sequestration. However, the interactions between CO₂, N₂, and CH₄ under reservoir conditions require further investigation. This study employs Grand Canonical Monte Carlo (GCMC) and Molecular Dynamics (MD) simulations to quantify the adsorption and diffusion behaviors of CO₂, N₂, and CH₄ in quartz nanopores over a pressure range of 1–24 MPa under varying water saturations and gas compositions. The results indicate that: (1) CO₂ exhibits the broadest energy distribution and the strongest adsorption stability, occupying about 20 %–30 % more adsorption sites than CH₄ or N₂ and showing the least sensitivity to water saturation, with only a 30 % reduction at 50 % saturation, compared to 60 % for CH₄, giving CO₂ a clear competitive advantage. (2) The adsorption and desorption behaviors are strongly pressure dependent, as increasing pressure reduces the adsorption layer area and shifts gas distribution from adsorption dominated to free phase. Competitive adsorption analysis reveals that while CO₂ dominates displacement at low pressures, mixtures that contain N₂ achieve higher CH₄ desorption efficiency above 13 MPa by mitigating diffusion resistance. (3) A higher N₂ fraction improves CH₄ diffusion coefficients, thereby facilitating gas mobility and ensuring superior recovery performance under high-pressure conditions. This study advances the fundamental knowledge of microscale gas behavior in tight sandstones and supports the feasibility of impure CO₂ injection as a practical strategy for sustainable gas production.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 1","pages":"Pages 77-92"},"PeriodicalIF":6.5,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147387906","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Quantitative evaluation of coal fracability based on 3D CT reconstruction and fractal characteristics","authors":"Fanhui Zeng ,&nbsp;Weixin Yang ,&nbsp;Jianchun Guo ,&nbsp;Ran Zhang ,&nbsp;Yu Zhang ,&nbsp;Zhangxing Chen","doi":"10.1016/j.ngib.2026.01.006","DOIUrl":"10.1016/j.ngib.2026.01.006","url":null,"abstract":"<div><div>Fracability is a critical indicator for evaluating the exploration and development potential of coalbed methane reservoirs and assessing the effectiveness of hydraulic fracturing stimulation operations. Its core function is to characterize the complexity of the induced fracture network and the resulting effective stimulated volume. In this study, we quantified fracture area and geometric complexity using true triaxial fracturing experiments and computed tomography three-dimensional (3D) reconstruction technology, combined with the box-counting method to calculate the 3D fractal dimension of the fracture surfaces. The results revealed that the total fracture surface area per unit volume of the stimulated reservoir effectively characterized reservoir fracability; specifically, both a larger total fracture surface area and a higher fractal dimension corresponded to better reservoir fracability. Fracture complexity was enhanced by a decrease in the horizontal principal stress difference or an increase in the injection rate. Under optimal conditions of a 3 MPa stress difference and an injection rate of 60 mL/min, fracability improved by 27.6 %. Furthermore, liquid carbon dioxide (CO₂) improved fracability by 50.7 % compared to using water as the fracturing fluid, a result attributed to its low viscosity and strong diffusion capacity, which activated a greater number of natural fractures. A fracability evaluation model integrating brittleness, fracture toughness, and dimensionless net pressure was developed using regression analysis, which demonstrated high reliability with a strong determination coefficient (<em>R</em>²) of 0.9019. This study clarifies the logical relationships among fracture area, complexity, and fractal dimension, providing a novel method for evaluating the fracability of coal reservoirs.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 1","pages":"Pages 60-76"},"PeriodicalIF":6.5,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147387905","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Control of ash yield on vertical pore structure development and its impact on coalbed methane adsorption in the deep coal seams of the Ordos Basin","authors":"Runye Han ,&nbsp;Hua Wang ,&nbsp;Yan Liu ,&nbsp;Cheng Li ,&nbsp;Xiangchun Chang ,&nbsp;Lingyu Zhao ,&nbsp;Shangbin Wang ,&nbsp;Junjian Zhang","doi":"10.1016/j.ngib.2026.01.001","DOIUrl":"10.1016/j.ngib.2026.01.001","url":null,"abstract":"<div><div>The vertical heterogeneity of the pore structure in deep coal seams with varying ash yields is a key control for coalbed methane storage and producibility; however, its specific impact on gas adsorption is not clearly defined. The focus of this study is the No.8 coal seam of the Carboniferous Benxi Formation in the Central-Eastern Ordos Basin. By integrating microscopic identification, proximate analysis, gas adsorption (CO₂, N₂, and CH₄), and the multifractal theory, we quantitatively characterized the nanopore structure (micropores &lt;2 nm and mesopores 2 nm–100 nm) of coal reservoirs with varying ash yields. The results indicate that (1) ash yield is the primary factor that controls the vertical evolution of pore structures in coal seams. In low-ash yield coal seams, the extent of thermal evolution and ash yield jointly constrain the heterogeneity of pore size distribution. In medium- to high-ash yield coal seams, the heterogeneity of pore structure and pore size distribution are predominantly constrained by ash yield. (2) As the ash yield vertically increases, the mesoporous pore volume and specific surface area initially decrease and subsequently increase, while the contribution of micropores to both pore volume and specific surface area continuously diminishes. Consequently, the total pore volume and specific surface area of the coal samples exhibit a two-stage reduction close to an ash yield threshold of approximately 20 %. (3) Further, the Langmuir volume for CH₄ adsorption sharply declines below the 20 % threshold, followed by a gradual decrease; in contrast, the Langmuir pressure initially decreases and subsequently increases. Hence, the vertical increase in ash yield constrains the development of pore systems and diminishes pore connectivity, thereby reducing methane adsorption capacity and adversely affecting coalbed methane productivity. (4) Low-ash yield coal reservoirs are characterized by a rapid gas breakthrough and high productivity, whereas medium-ash yield coal reservoirs generally require prolonged depressurization to achieve peak gas production. These findings reveal that in medium-high rank coal, ash yield—and not thermal evolution—is the main factor that controls vertical pore evolution and methane adsorption efficiency. The quantitative ash yield threshold (20 %) established in this study provides a practical criterion for evaluating reservoir quality and predicting vertical variations in gas storage potential in the Ordos Basin.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 1","pages":"Pages 9-29"},"PeriodicalIF":6.5,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147387929","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}