Natural Gas Industry B最新文献

{"title":"Integrated study of hydraulic/CO2 fracturing and production coupled with a THM-D process in ultra-shallow shale reservoirs","authors":"","doi":"10.1016/j.ngib.2024.09.001","DOIUrl":"10.1016/j.ngib.2024.09.001","url":null,"abstract":"<div><div>To explore fracturing technology for vertical wells in ultra-shallow shale gas reservoirs, a coupled thermo-hydro-mechanical-damage (THM-D) fracturing and production integration model is established in this study. In addition, a new coupled hydro-mechanical damage model is established to calculate fracture evolution. These two models are validated through theoretical models and field data, respectively. Based on these models, the quality of fracturing under different geological parameters, fracturing parameters, and fracturing technology is compared and analyzed. The results show that the distribution of natural fractures significantly influences fracturing and production. In addition, due to the high leak-off in the ultra-shallow shale reservoir, the total fracture length and cumulative production after 720 days of carbon dioxide fracturing are only 70.35% and 77.26% of the values achieved by hydraulic fracturing, respectively. Therefore, it is necessary to consider reducing carbon dioxide leak-off in the design of carbon dioxide fracturing in ultra-shallow shale reservoirs. Fracturing efficiency also should be considered when designing fracturing time. When the injection rate is 5 m³/min, the efficiency drops sharply if the fracturing time exceeds 67.45 min. The production of hydraulic fracturing and carbon dioxide fractured wells has also been studied when fracturing methods without proppant are used. This study found that a satisfactory production rate can also be achieved in ultra-shallow shale gas reservoirs when fracturing without proppant.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":null,"pages":null},"PeriodicalIF":4.2,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142538257","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Optimization of Jiyang depression block X shale condensate reservoir well spacing based on geology–engineering integration","authors":"","doi":"10.1016/j.ngib.2024.08.005","DOIUrl":"10.1016/j.ngib.2024.08.005","url":null,"abstract":"<div><p>Appropriate well spacing is crucial for the efficient development of shale reservoirs, as it is closely related to the degree of resource utilization. Well spacing design is influenced by both fracturing processes and geological characteristics. While increasing well density can enhance reservoir recovery, it may lead to higher investment costs and significant well interference issues. In this study, we adopted an integrated geological–engineering approach, combining fracture propagation simulation, EDFM (Embedded Discrete Fracture Modeling), and numerical simulation methods to comprehensively analyze well interference under different well spacings in shale condensate reservoirs. Development well spacing was optimized using the degree of resource utilization and well interference rate as key indicators. There are three main research findings: (1) The geological engineering integration approach allows for differentiated well spacing according to specific research areas. Combining this integrated approach with EDFM and leveraging quantitative evaluation, we have developed an efficient and precise methodology for well spacing optimization. (2) When well spacing is less than the length of hydraulic fractures, inter-well fractures exhibit an entangled pattern, reducing the effectiveness of fracturing treatments and causing severe well interference. As well spacing increases, interference between fractures from different wells diminishes, but unstimulated volumes gradually emerge, leading to a decrease in reservoir recovery. (3) Considering both well interference and resource utilization, a well spacing of 400 m is recommended in the study area. At this spacing, interference between hydraulic fractures from different wells is minimal. After 10 years of production, the estimated reservoir recovery is 39.16%, with a production rate of 25.58% and a well interference rate of 13.58%. These research outcomes provide valuable insights for optimizing the well spacing of hydraulic fractured horizontal wells in shale condensate reservoirs.</p></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":null,"pages":null},"PeriodicalIF":4.2,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2352854024000561/pdfft?md5=8bec66d94f665f9e38648801ba39748e&pid=1-s2.0-S2352854024000561-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142098558","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental study and thermodynamic modeling of CO2+CH4 gas mixture hydrate phase equilibria for gas separation efficiency","authors":"","doi":"10.1016/j.ngib.2024.08.001","DOIUrl":"10.1016/j.ngib.2024.08.001","url":null,"abstract":"<div><p>Gas separation is a critical application of gas hydrates, and accurately predicting separation performance is crucial. In this study, we used thermodynamic calculations to predict the equilibrium phase of gas hydrates for various mole fractions of CO₂ + CH₄ gas mixtures. We also determined the mole fraction of each gas component trapped within the hydrate clathrate. To predict the equilibrium points, we used the Soave–Redlich–Kwong（(SRK) equation of state for the gas phase, the nonrandom two-liquid (NRTL)model for the liquid phase, and the Chen–Guo model for the hydrate phase. We modified the hydrate fugacity formula and introduced a new function to improve the accuracy of the Chen–Guo model. By incorporating experimental equilibrium results from our study and another study, we developed a correlation based on gas mixture composition and temperature, resulting in highly accurate predictions. The use of this new correlation for hydrate fugacity calculation significantly improved precision, as evidenced by an average absolute deviation percent of calculated pressures (AADP) of 1.34% for pure CO₂ and 1.25% for CH₄. When considering the 27 data points of different CO₂ + CH₄ mixtures, the AADP% was 1.98%.To implement the model to predict equilibrium phases, we used the Chen–Guo framework to determine the mole fraction of each gas component in the hydrate mixture. Interestingly, we discovered a linear correlation between the CO₂ mole fraction in the hydrate and equilibrium pressure, with a slope of approximately 0.001 and a y-intercept of less than one, for all gas compositions. Therefore, we can conclude that low thermodynamic conditions (temperature and pressure) result in a high CO₂ mole fraction in the hydrate phase and great separation efficiency.</p></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":null,"pages":null},"PeriodicalIF":4.2,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2352854024000524/pdfft?md5=1cc0531eb8cb949df3e5b186706e0aa7&pid=1-s2.0-S2352854024000524-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142098620","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigation of the effect of bedding and confining pressure on the energy evolution of shale during the unloading process","authors":"","doi":"10.1016/j.ngib.2024.08.003","DOIUrl":"10.1016/j.ngib.2024.08.003","url":null,"abstract":"<div><p>To explore the effect of bedding and initial confining pressure on the energy evolution characteristics of shale during the unloading process, samples were drilled with different bedding angles, unloading tests were conducted under different initial confining pressures, and the mechanical and energy evolution characteristics of shale during the unloading process were analyzed. The results show that the stress–strain curve of the unloading test can be divided into the linear elasticity stage, the stable crack growth stage, the accelerated crack growth stage, and the post-failure stage. Critical confining pressure can show the relative strength of the rock samples. The elastic modulus and Poisson's ratio increase with an increase in axial preset load. The elastic modulus increases with the bedding angle, and the effect of the bedding angle on the Poisson's ratio is insignificant. The energy evolution of the unloading test can be divided into three stages: energy accumulation, energy dissipation, and energy release. The larger the axial preset load, the higher the critical confining pressure, the higher the elastic modulus, and the higher the Poisson's ratio. The total energy, elastic energy, and dissipation energy all increase with the increase in the initial confining pressure, and the correlation is high. Confining pressure enhances the ability of the shale sample to store elastic energy and improves the ability of the shale sample to resist internal crack propagation. The total energy, elastic energy, and dissipated energy of the samples in the failure point decrease first and then increase with the increase in the bedding angle. The maximum value can be obtained when the bedding angle is 0°. The elastic energy and dissipated energy of shale are highly heterogeneous due to bedding, and the effects of bedding should be taken into account when exploring the law of rock deformation and failure from an energy perspective.</p></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":null,"pages":null},"PeriodicalIF":4.2,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2352854024000548/pdfft?md5=08e14f5d11469602920a67ac04eff4b8&pid=1-s2.0-S2352854024000548-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142098557","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Exploring the prospects of deep natural gas resources from the geochemical parameters of the Shahejie Formation source rocks in the Banqiao depression","authors":"","doi":"10.1016/j.ngib.2024.08.004","DOIUrl":"10.1016/j.ngib.2024.08.004","url":null,"abstract":"<div><p>Deep natural gas is an important field and direction for oil and gas exploration and development in the Banqiao depression. The geochemical characteristics of the Paleogene Shahejie Formation source rocks in the Banqiao Sag were investigated based on pyrolysis, Total Organic Carbon (TOC), chloroform bitumen A, vitrinite reflectance, saturated hydrocarbon gas chromatography–mass spectrometry, and maceral determination. The results showed that the Es₃ source rocks of the Paleogene Shahejie Formation were generally of better quality than the Es₁ source rocks. Regarding the Es₁ source rocks, the abundance of organic matter was variable, with mixed types and low maturity. The source rocks were formed in a saline-water reductive environment. Regarding the Es₃ source rocks, the abundance of organic matter was relatively high, meaning that they were of medium–high quality, with mixed types of, yet highly mature, organic matter. The hydrocarbon generation environment was oxidative, and the source rocks were mainly deposited in fresh water with localized salinization. The main hydrocarbon-generating components of organic matter in the Shahejie Formation were amorphous humic components formed by intensive microbial modification of lower planktonic algae and terrestrial higher plants. Aquatic organisms were the main sources of organic matter, with localized mixing of higher-plant organic matter. The organic matter derived from these higher plant debris sources provided beneficial conditions for the generation of natural gas. At present, the Shasan source rock is at the peak of hydrocarbon generation. Under deep conditions, the maturity of organic matter increases, and organic matter rich in terrestrial higher plants can make a significant contribution to the generation of natural gas, especially shale gas.</p></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":null,"pages":null},"PeriodicalIF":4.2,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S235285402400055X/pdfft?md5=20c2950d51ca87f981e307ffe5f7de8b&pid=1-s2.0-S235285402400055X-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142098554","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Analyses of the characteristics and main controlling factors of shale pores in the Niutitang Formation in the Guizhou region","authors":"","doi":"10.1016/j.ngib.2024.08.006","DOIUrl":"10.1016/j.ngib.2024.08.006","url":null,"abstract":"<div><p>The shale of the Lower Cambrian Niutitang Formation in the Guizhou region has undergone complex diagenesis and has developed different types of pore textures, which affect the occurrence status of shale. In the present study, we applied scanning electron microscopy (SEM) and an isotherm analysis of low-temperature nitrogen gas adsorption to shale core samples drawn from the Niutitang Formation in the Guizhou region to quantify the shale pore development characteristics. In addition, we conducted a shale geochemical analysis in light of the main controlling factors for pore development. The results indicate that the shale pores and fractures of the Niutitang Formation can be divided into three types: organic pores, inorganic pores, and micro fractures. The organic pores are mainly distributed in the organic matter between inorganic mineral particles, with small pore diameters, which are characterized by inkpot, elliptic, and beaded shapes. The inorganic pores are mainly composed of narrow slit intragranular pores and intergranular pores. The micro fractures develop parallel plates with four-side openings and splint plates. The pores of the shale are mainly mesopores (53%), followed by micropores and macropores, with pore diameter distributions ranging mainly from 1 to 50 nm. The specific surface area is mainly provided by nanoscale pores with average diameters of less than 4 nm. Therefore, the smaller pore makes a greater contribution to the specific surface area, while the specific surface area increases with an increase in the total pore volume. The study further indicates that organic carbon content is the most important internal factor for shale pore development, especially in terms of the control of volume and the specific surface area of micropores. Moreover, quartz content has a certain effect on shale pores; the pore volume and specific surface area increase with increasing quartz content, but the control effect is not obvious. The effect of clay minerals on shale pores is negligible. The type of organic matter is also an important factor in controlling the developmental difference of shale pores, and a high degree of thermal evolution is not conducive to organic pore development. It was therefore concluded that intergranular pores and microfractures, mainly mesopores, are the main reservoir space and migration channels of Niutitang shale in the study area. The organic carbon content, mineral components, organic matter type, and degree of thermal evolution jointly control the development of shale pores, among which the organic carbon content is the most important influencing factor.</p></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":null,"pages":null},"PeriodicalIF":4.2,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2352854024000573/pdfft?md5=f324252ed79301dde9aefefafd70c041&pid=1-s2.0-S2352854024000573-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142098556","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Simulation analysis of gas–liquid flow and mass transfer in a shaking triethylene glycol dewatering absorber","authors":"","doi":"10.1016/j.ngib.2024.07.003","DOIUrl":"10.1016/j.ngib.2024.07.003","url":null,"abstract":"<div><p>Tall towers with large diameters on floating liquefied natural gas devices are highly sensitive to sway. If tower equipment is relatively high, swaying can easily cause uneven gas–liquid contact in the tower, inhibiting its absorption capacity. In this paper, gas–liquid counterflow triethylene glycol dehydration absorption towers are taken as the research object. A porous medium model was used to simplify the packing environment, and the Euler–Euler method was used to simulate the flow field in the tower. The flow field encompasses the effects of the gas–liquid phase dispersion force, gas–liquid phase diffusion coefficient, and interphase mass transfer. By introducing a dynamic grid model to establish sway boundary conditions, we quantitatively examine the influence of sway duration and angle on gas–liquid flow and mass transfer performance in absorption towers. The results show that, when the sloshing angle of the absorption tower is 9° and the sloshing period is 20 s, the influence of the disturbance of the absorption tower's internal flow field is increased by 85% and 78% respectively compared with normal working conditions. When the sloshing angle of the absorption tower is 9° and the sloshing period exceeds 21 s, the gas–liquid mass transfer inside the absorption tower diminishes. When the sloshing period of the regeneration tower is 6 s and the sloshing angle reaches 20°, the mass fraction of poor ethylene glycol in the regeneration tower fluctuates significantly in the first sloshing cycle, and unqualified products appear.</p></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":null,"pages":null},"PeriodicalIF":4.2,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2352854024000512/pdfft?md5=c64d0f0e6d80b9f8ff8c1cc3421152d6&pid=1-s2.0-S2352854024000512-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142098618","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Hydrocarbon accumulation process and reservoir-forming models of structure A in the central inversion tectonic belt of the Xihu Depression, East China Sea Basin","authors":"","doi":"10.1016/j.ngib.2024.07.001","DOIUrl":"10.1016/j.ngib.2024.07.001","url":null,"abstract":"<div><p>The Huagang Formation of the central inverted structural tectonic belt structure A in the Xihu Depression has abundant hydrocarbon resources. This is an important area for exploration and development in the East China Sea Basin (ECSB). Due to the high drilling costs in offshore basins and limited drilling in Structure A, the mechanism of hydrocarbon accumulation is complex, and the laws and processes of hydrocarbon accumulation in structure A are still unclear. To clarify the hydrocarbon accumulation process in the Huagang Formation of structure A, this study used thin section observation, scanning electron microscopy, natural gas carbon isotopes, fluid inclusions, and micro thermometry. Combined with structural evolution and burial history, the origin and source of natural gas, hydrocarbon accumulation periods, and processes were systematically analyzed. The research shows that the sandstone reservoir in the Huagang Formation has satisfactory reservoir, trapping, and preservation conditions; the primary hydrocarbon accumulation period was the Longjing Movement. Therefore, early natural gas filling existed before the Longjing Movement. Based on the evolutionary and fluid potential characteristics of the top tectonic peak of the Pinghu Formation, the natural gas generated in the early stage of structure A is stored in the paleo-structural high point of the Pinghu Formation (paleo convergence area). In the early stage of the Longjing Movement, natural gas migrated from the paleo convergence area of the Pinghu Formation to the current tectonic high point and accumulated in the trap. Therefore, three different “convergence ahead of accumulation” reservoir formation models were developed. These reservoir formation models are critical for guiding the exploration of a series of large traps, including structure A and its surrounding structures, and they have important reference significance for natural gas exploration in other basins.</p></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":null,"pages":null},"PeriodicalIF":4.2,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2352854024000494/pdfft?md5=9808b7f6c828f16d0b3e17d1e262d0d0&pid=1-s2.0-S2352854024000494-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142098559","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Creep behavior of marine Wufeng–Longmaxi Formation shales in the Sichuan Basin, Southwest China characterized at micro scale: A case study of exploration well SQ-1 in Sanquan Town, Nanchuan District, Chongqing","authors":"","doi":"10.1016/j.ngib.2024.07.002","DOIUrl":"10.1016/j.ngib.2024.07.002","url":null,"abstract":"<div><p>Creep behavior is a very important attribute of shale and is crucial in the design of hydraulic fracturing schemes to ensure the long-term stable development of shale gas. However, how different shale minerals, organic matter, bedding planes, and pores affect the micro-creep behavior of Upper Ordovician Wufeng and Lower Silurian Longmaxi (WF–LMX) Formation shales is poorly understood. In this study, we employed a nanoindentation mechanical testing technique alongside rock mineralogical, major elemental, and pore analyses to investigate the creep behavior and influencing factors of WF–LMX shales at the microscale. The results show that (1) the creep displacement (Δ<em>h</em>) and indentation creep parameter (C_IT) are each positively correlated with clay, total pore volume, and clay + total organic carbon (TOC) contents but negatively correlated with the content of quartz, excess SiO₂, and TOC. We found weak or no correlation between the occurrence of minor rock constituents, such as feldspar, carbonates, and pyrite, and the shale creep properties; (2) the creep parameters (Δ<em>h</em>, C_IT, and stress exponent (<em>n</em>)) exhibit anisotropy due to the layering of shale, with values 7.3%–24.2% higher in the plane perpendicular to bedding (X1) than those in the plane parallel to bedding (X3). The creep displacement exhibits negative correlations with Young's modulus, hardness, and stress exponent (<em>n</em>), especially for the X1 direction; (3) compared with those of China's Yanchang shale, the stress exponents of WF–LMX shale are relatively high (8.5–30), indicating that the average creep capacity of WF–LMX shale is relatively weak. Overall, nanoindentation technology has shown great potential in studying shale creep and provides quantitative data support for macroscopic shale creep research.</p></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":null,"pages":null},"PeriodicalIF":4.2,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2352854024000500/pdfft?md5=0290643d9b8854a3d4814fd3eea184eb&pid=1-s2.0-S2352854024000500-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142098560","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Numerical modeling of deep coalbed methane accumulation in the central-eastern Ordos Basin, China","authors":"","doi":"10.1016/j.ngib.2024.08.002","DOIUrl":"10.1016/j.ngib.2024.08.002","url":null,"abstract":"<div><p>Deep coalbed methane (CBM) has become one of the most significant potential sources of natural gas in China. However, the exploration and development of deep CBM in China is still in an initial stage, and its accumulation-forming characteristics require further study. Therefore, taking the No. 8 deep coal seam in the central-eastern region of Ordos Basin as an example, this study investigated the geologic characteristics of CBM accumulations to establish a numerical model. The evolution of the burial and accumulation of CBM in the area was reconstructed. The modeling results suggest that the No. 8 coal seam experienced continuous subsidence from the Late Cretaceous to the Triassic, alternating subsidence and uplift during the Jurassic, rapid burial throughout the Early Cretaceous, and continuous uplift since the Late Cretaceous. The coal reached its maximum maturity at the end of the Early Cretaceous. Furthermore, CBM generation in the region was divided into four stages of thermal events—biogenic and early thermogenic gas, cracking of light oil into gas, cracking of the remaining kerogen into gas, and hydrocarbon generation ceasing—which accelerated coal maturity and generation. The adsorption capacity presented an overall declining trend prior to the end of the Cretaceous, followed by a rapid increase since the Late Cretaceous. As for adsorption mass evolution, the CBM successively underwent unsaturated minor adsorption, unsaturated rapid-rising adsorption, saturated decreasing adsorption, and saturated rising adsorption. The in-situ gas mass was found to be controlled by a combination of generation, adsorption, and expulsion of hydrocarbons, with its present-day value being 9–29 × 10⁴ t/km² and the corresponding gas volume per ton of coal being 12–28 m³/t. Moreover, free gas evolution initially showed an increasing trend, followed by a decline, ultimately accounting for 11%–28% of the total gas content.</p></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":null,"pages":null},"PeriodicalIF":4.2,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2352854024000536/pdfft?md5=598f26228298890a70653e8104a53b51&pid=1-s2.0-S2352854024000536-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142098555","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}