Search

Coal is a typical dual-porosity structural material. The injection of CO2 into coal seams has been shown to be an effective method for storing greenhouse gasses and extracting coal bed methane. In light of the theory of dual-porosity media, we investigate the impact of non-homogeneity on seepage anisotropy and examine the influence of CO2 gas injection on the anisotropy of coal and the permeability of fractures. The results demonstrate that under constant pressure conditions, coal rock has the greatest permeability variation in the direction of face cleats and the smallest changes in the direction of vertical bedding. The more pronounced the heterogeneity, the more evident the change in permeability and the less pronounced the decreasing stage of permeability. Additionally, the larger the diffusion coefficient is, the less pronounced the permeability change. The change in permeability is inversely proportional to the size of the adsorption constant and directly proportional to the size of the fracture. As the matrix block size increases, the permeability also increases, whereas the decrease in permeability becomes less pronounced. The findings of this study offer a theoretical basis for further research into methods for enhancing the CO2 sequestration rate. [ABSTRACT FROM AUTHOR]

In the process of deep coal seam mining, the problem of coal–gas compound disasters is increasingly prominent, with the safe and efficient extraction of gas serving as the key to disaster reduction. A deep coal seam gas extraction project is a complex coupled system involving multiple physical fields, such as stress fields, gas flow fields, and energy. Constructing a systematic theoretical framework of multiphysics field coupling is crucial for improving the safety and efficiency of gas extraction. This paper examines all existing multiphysics field coupling theories. It then suggests a theoretical modeling framework that is based on three important scientific issues: the coal deformation law, the gas flow law, and the coal porosity and permeability spatiotemporal distribution law. We further analyze the application and development of the model in typical coal seam gas extraction engineering on this basis. Finally, this paper points out the shortcomings of the current research and looks forward to the future research directions for the coupled coal and gas multiphysics field model, aiming to provide a theoretical basis and guidance for the model's construction and application in gas extraction engineering. [ABSTRACT FROM AUTHOR]

The expansion of hydraulic fractures in coalbed methane (CBM) reservoirs is key to effective stimulation, making it essential to understand fracture propagation and its influencing factors for efficient resource development. Using petrological characteristics, logging data, microseismic monitoring, and fracturing reports from the Baode Block on the eastern Ordos Basin, this study systematically investigates the geological and engineering factors influencing hydraulic fracture propagation. The real-time monitoring of fracture propagation in 12 fractured wells was conducted using microseismic monitoring techniques. The results indicated that the fracture orientations in the study area ranged from NE30° to NE60°, with fracture lengths varying between 136 and 226 m and fracture heights ranging from 8.5 to 25.3 m. Additionally, the fracturing curves in the study area can be classified into four types: stable, descending, fluctuating, and falling. Among these, the stable and descending types exhibit the most effective fracture propagation and are more likely to generate longer fractures. In undeformed–cataclastic coals and bright and semi-bright coals, long fractures are likely to form. When the Geological Strength Index (GSI) of the coal rock ranges between 60 and 70, fracture lengths generally exceed 200 m. When the coal macrolithotype index (Sm) is below 2, fracture lengths typically exceed 200 m. When the difference between the maximum and minimum horizontal principal stresses exceeds 5 MPa, fractures with length >180 m are formed, while fracture heights generally remain below 15 m. From an engineering perspective, for the study area, hydraulic fracturing measures with a preflush ratio of 20–30%, an average sand ratio of 13–15%, and a construction pressure between 15 MPa and 25 MPa are most favorable for coalbed methane production. [ABSTRACT FROM AUTHOR]

The development of deep coalbed methane has become an important way to obtain natural gas in China. The development of deep CBM mainly depends on horizontal well technology. The different orientations of horizontal wells will have an important impact on the productivity of coalbed methane wells. The angle grid geological model of coalbed methane reservoirs with different inclination angles is established, and the deployment orientation of horizontal wells is changed to study the optimal deployment orientation of deep-saturated coalbed methane reservoirs. When CBM horizontal wells in deep saturated CBM reservoirs are deployed upward along the dip, well-controlled reserves, peak daily gas production, and cumulative gas production increase as the dip decreases. When deploying down the dip, with the increase in dip angle, the well-controlled reserves increase, and the peak daily gas production and cumulative gas production first increase and then decrease. In the low-dip reservoir, the development effect of horizontal wells deployed in different directions is better than that in the up-dip direction. In the high-dip reservoir, the development effect of horizontal wells deployed along the strike is better than that in the up-dip and down-dip directions. The development effect of horizontal wells is controlled by both well-controlled reserves and reservoir pressure drop. Because this method is targeted at different geological conditions, it can be used to guide the horizontal well optimization of other coalbed methane blocks and has very important significance for the development and optimization of coalbed methane reservoirs. [ABSTRACT FROM AUTHOR]

Injecting CO2 into coal seams to enhance coal bed methane (ECBM) recovery has been identified as a viable method for increasing methane extraction. This process also has significant potential for sequestering large volumes of CO2, thereby reducing the concentration of greenhouse gases in the atmosphere. However, for deep coal seams where formation pressure is relatively high, there is limited research on CO2 injection into systems with higher methane adsorption equilibrium pressure. Existing studies, mostly confined to the low-pressure stage, fail to effectively reveal the impact of factors such as temperature, high-pressure CO2 injection, and coal types on enhancing the recovery and sequestration of CO2-displaced methane. Thus, this study aims to investigate the influence of temperature, pressure, and coal types on ECBM recovery and CO2 sequestration in deep coal seams. A series of CO2 core flooding tests were conducted on various coal cores, with CO2 injection pressures ranging from 8 to 18 MPa. The CO2 and methane adsorption rates, as well as methane displacement efficiency, were calculated and recorded to facilitate result interpretation. Based on the results of these physical experiments, numerical simulation was conducted to study multi-component competitive adsorption, desorption, and seepage flow under high temperature and high pressure in a deep coal seam's horizontal well. Finally, the optimization of the total injection amount (0.7 PV) and injection pressure (approximately 15.0 MPa) was carried out for the plan of CO2 displacement of methane in a single well in the later stage. [ABSTRACT FROM AUTHOR]

The assessment of highly mature source rocks linked to hydrocarbon generation remains a challenge in oil and gas exploration. However, substantial terrigenous influences and thermal variations have complicated the formation and evolution of source rocks. This study presents an integrated assessment of highly mature source rocks in the Fuxin Basin, based on sedimentological, geochemical, and organic petrological analyses. Two types of oil- and coal-bearing source rocks were deposited in the semi-deep lake and shore–shallow lake facies during the Jiufotang and Shahai periods. The development of source rocks migrated eastward alongside the lacustrine depocenter, influenced by basin evolution related to extensional detachment tectonism. Furthermore, a gradual increase in thermal records was detected from the western to eastern basins. Consequently, thermal decomposition of source rocks in the Jiufotang formation reduced the organic matter (OM) abundance in the central and eastern basins. Meanwhile, OM types of source rocks range from kerogen type-II1/-I to type-II2/-III, with intense hydrogen generation observed from the western to eastern basins. Consequently, the quality and hydrocarbon accumulation of source rocks are influenced by sedimentation and thermal maturity variation. The spatiotemporal variation in mature source rocks enhances the potential for exploring conventional petroleum, coalbed methane, and shale gas across different strata and locations. Our findings illustrate the significance of the sedimentary and thermal effects in characterizing the evolution of highly mature source rocks, which is relevant to determine oil and gas exploration in similar geological settings. [ABSTRACT FROM AUTHOR]

This study investigates the reservoir physical properties, present-day stress, hydraulic fracturing, and production capacity of No. 3 coal in the Shizhuang south block, Qinshui Basin. It analyzes the control of in situ stress on permeability and hydraulic fracturing, as well as the influence of geo-engineering parameters on coalbed methane (CBM) production capacity. Presently, the direction of maximum horizontal stress is northeast–southwest, with local variations. The stress magnitude increases with burial depth, while the stress gradient decreases. The stress field of strike-slip faults is dominant and vertically continuous. The stress field of normal faults is mostly found at depths greater than 800 m, whereas the stress field of reverse faults is typically found at depths shallower than 700 m. Permeability, ranging from 0.003 to 1.08 mD, is controlled by in situ stress and coal texture, both of which vary significantly with tectonics. Hydraulic fracturing design should consider variations in stress conditions, pre-existing fractures, depth, structural trends, and coal texture, rather than employing generic schemes. At greater depths, higher pumping rates and treatment pressures are required to reduce fracture complexity and enhance proppant filling efficiency. The Shizhuang south block is divided into five zones based on in situ stress characteristics. Zones III and IV exhibit favorable geological conditions, including high porosity, permeability, and gas content. These zones also benefit from shorter gas breakthrough times, relatively higher gas breakthrough pressures, lower daily water production, and a higher ratio of critical desorption pressure to initial reservoir pressure. Tailored fracturing fluid and proppant programs are proposed for different zones to optimize subsequent CBM development. [ABSTRACT FROM AUTHOR]

Coalbed methane (CBM), recognized as a sustainable and environmentally friendly energy source, plays a crucial role in mitigating global climate change and advancing low-carbon energy solutions. However, the prevalence of low-permeability coal seams poses a significant challenge to effective CBM extraction. Improving coal permeability has emerged as a viable strategy to address the issue of low-permeability coal. Conventional CBM stimulation methods fall short in overcoming this obstacle. In contrast, the enhanced technique of CBM extraction by water-based ultrasonic cavitation holds great promise due to its use of high energy intensity, safety, and efficiency. Nevertheless, the inadequate theoretical framework for managing this technology impedes its widespread adoption for large-scale applications. This study investigated the impact of water-based ultrasonic cavitation treatment on coal's properties and permeability through mechanical testing and permeability measurements conducted before and after treatment. This study also explored the process by which this technology, known as WUC-ECBM, improves coal's mechanical properties and permeability. The findings suggest a potential stimulation technique (WUC-ECBM) for use in CBM extraction, and its physical mechanism. [ABSTRACT FROM AUTHOR]

CO2 is being considered as an effective alternative working fluid for geothermal applications due to its superior fluid dynamics and heat transfer properties compared to water. Utilizing sedimentary rocks for geothermal energy recovery through a CO2-plume geothermal system, especially in carbonate reservoirs, has been shown to be a practical approach that eliminates the need for hydraulic fracturing. However, uncertainties remain regarding the thermal and hydraulic behavior, particularly the chemical interactions between CO2 and carbonate rocks. This study develops a comprehensive wellbore–reservoir coupling reactive transport model based on specific information obtained from the Ordovician limestone geothermal reservoir in Shandong, China. The model aims to assess the feasibility of heat extraction in carbonate reservoirs by evaluating the heat extraction performance and fluid–rock interaction. The results indicate a rapid temperature drop after CO2 breakthrough due to the Joule–Thomson effect. Simultaneously, the fluid transitions into and maintains a two-phase state throughout the operation. Chemical reactions within the reservoir are not aggressive since complete mixing between unsaturated water and CO2 only occurs in the vicinity of the production well, highlighting the potential of utilizing carbonate reservoirs for efficient heat extraction in geothermal systems. Further research is needed to optimize the performance of CO2-based geothermal systems in carbonate reservoirs. [ABSTRACT FROM AUTHOR]

Carbon Dioxide-Enhanced Coalbed Methane (CO2-ECBM), a progressive technique for extracting coalbed methane, substantially boosts gas recovery and simultaneously reduces greenhouse gas emissions. In this process, the dynamics of coalbed fractures, crucial for CO2 and methane migration, significantly affect carbon storage and methane retrieval. However, the extent to which fracture roughness, under the coupled thermal-hydro-mechanic effects, impacts engineering efficiency remains ambiguous. Addressing this, our study introduces a pioneering, cross-disciplinary mathematical model. This model innovatively quantifies fracture roughness, incorporating it with gas flow dynamics under multifaceted field conditions in coalbeds. This comprehensive approach examines the synergistic impact of CO2 and methane adsorption/desorption, their pressure changes, adsorption-induced coalbed stress, ambient stress, temperature variations, deformation, and fracture roughness. Finite element analysis of the model demonstrates its alignment with real-world data, precisely depicting fracture roughness in coalbed networks. The application of finite element analysis to the proposed mathematical model reveals that (1) fracture roughness ξ markedly influences residual coalbed methane and injected CO2 pressures; (2) coalbed permeability and porosity are inversely proportional to ξ; and (3) adsorption/desorption reactions are highly sensitive to ξ. This research offers novel insights into fracture behavior quantification in coalbed methane extraction engineering. [ABSTRACT FROM AUTHOR]

Coalbed methane (CBM) is the only unconventional gas in Poland with estimated recoverable resources. The prospects for developing deep CBM have been explored in recent years by drilling deep exploration wells within the depocenter of the Upper Silesian Coal Basin. The purpose of this study is to analyze the occurrence and potential for CBM extraction in this area of the basin, which can be considered prospective due to the confirmed presence of significant amounts of gas and thick coal seams at depths > 1500 m. The study examined the vertical and horizontal variability of the gas content in the studied area, the coal rank in the seams, thermal conditions, and coal reservoir parameters. The gas content in the seams, reaching more than 18 m3/t coaldaf at a depth of 2840 m, and indicative estimated gas resources of 9 billion m3 were found. The high gas content is accompanied by positive thermal and coal rank anomalies. The permeability and methane saturation of the coal seams are low, and therefore, potential methane production may prove problematic. However, the development of CBM extraction technologies involving directional drilling with artificial fracturing may encourage gas production testing in the study area. [ABSTRACT FROM AUTHOR]

This study evaluated two distinct cryo-fracturing techniques using liquid nitrogen (LN2). The evaluation included tests for peak compression strength, acoustic emission, and energy absorption. The experiments compared single-exposure freezing time (FT) and multiple-exposure freezing–thawing cycle (FTC) processes on dried specimens. The outcomes indicated that FTC experiments demonstrated lower uniaxial compression stress (UCS) values compared to FT experiments because, during the thawing phase, the ice inside the pores reverts to liquid as the temperature rises. The difference between average baseline experiments versus FT180 and FTC6 indicated a reduction in stress of 14.5% and 38.5%, respectively. The standard error of our experiments ranged from 0.58% for FT60 to 5.35% for FTC6. The damage factor follows a downward trend in both FT and FTC experiments as the time of LN2 treatment augments. The amount of energy that can be absorbed in elastic or plastic deformation before failure is less for FTC specimens with the same total LN2 exposure time. Samples undergoing the freezing time process demonstrate a greater and denser quantity of acoustic emissions in comparison to freezing–thawing cycle processes, suggesting a positive correlation with uniaxial compressive strength outcomes. The large network of fractures formed by the FTC and PFTC techniques indicated that they have the greatest potential as stimulation approaches. The engineering results were improved by adding the geological context, which is essential to apply these findings to coals that have comparable origins. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is an essential technology in the development of coalbed methane reservoirs. Hydraulic fracturing can create a highly conductive fracture in the reservoir and increase its permeability. At present, the focus of coalbed methane reservoir fracturing optimization is gradually shifting to the fracturing scale. In the current development process, more and more coalbed methane blocks try to increase the fracturing scale to increase the gas production of coalbed methane wells. Field tests show that gas production of coalbed methane wells will increase to a certain extent with the increase of fracturing scale. However, the increase in the scale of fracturing also increases its cost. Therefore, the most economical fracturing scale is not necessarily the optimal fracturing scale for gas production. The field test usually pays more attention to the gas production effect, but the development of a coalbed methane field should pay more attention to the economic benefit, and the optimization of fracturing should take the economic benefit as the goal. Taking economic benefits as the starting point, this paper uses fracturing simulation to calculate the fracture extension under different geological conditions and different fracturing scales. It also uses numerical simulation to calculate the gas well productivity under different fracture extension conditions. The economic evaluation model was established to calculate the economic benefits under different fracturing scales, and the optimal fracturing scale was obtained. Finally, the typical maps of fracturing optimization under different geological conditions are formed. The optimization method of fracturing scale integrating economy, fracturing, and gas reservoir is realized. The research results have been successfully applied to the optimization scheme of Liulin block development, and very good results have been achieved. Because this method is targeted at different geological conditions, it can be used to guide the fracturing optimization of other coalbed methane blocks and has very important significance for the development and optimization of coalbed methane reservoirs. [ABSTRACT FROM AUTHOR]

In the process of coalbed methane development, drilling fluid and fracturing fluid cannot achieve absolute compatibility with formation. The incompatibility between the working fluid and reservoir will lead to the intrusion of working fluid into the reservoir and cause reservoir pollution. This is a very common phenomenon. There is a large amount of pulverized coal in the coal seam, and the intrusion of working liquid will be combined with the pulverized coal to form cement to block the seepage space in the reservoir. Since pressure relief and fracturing fluid backflow will be performed at the first time after fracturing, the intrusion range of the working fluid is small, generally reaching 10 m to 50 m. Compared with a conventional gas reservoir or shale gas reservoir, the working fluid loss during CBM development will seriously affect the subsequent production project and even make the gas well lose production capacity. On the other hand, in order to avoid this phenomenon, measures such as acidification or volumetric fracturing are sometimes used to improve the seepage environment near the well and near the fracture. The purpose of this study is to quantitatively evaluate the impacts of working fluid filtration and reservoir reconstruction on production. In this study, a single well productivity evaluation model and sensitivity analysis method considering drilling fluid filtration loss, fracturing fluid filtration loss, reservoir reconstruction and other processes is proposed. The formation mechanism of fluid loss during drilling and fracturing is described, and the productivity evaluation model considering fluid loss is combined with the Langmuir isothermal adsorption equation, steady-state diffusion law, Darcy's seepage law and Duhamel convolution formation. Combined with the distribution of actual gas reservoir flow characteristics, the sensitivity of single well productivity to gas reservoir porosity, gas reservoir permeability, coal seam adsorption coefficient, working fluid filtration loss and reservoir reconstruction measures are analyzed. Through the analysis and fitting of the actual production data on site, the relationship curve can better fit the field production data, and the evaluation results are in line with the drilling and fracturing conditions at that time and the subsequent production conditions, with small errors. The obtained method is suitable for predicting the productivity of fractured vertical wells in different working conditions and provides a basis for the development and productivity prediction of CBM reservoirs in China and in international cooperation. [ABSTRACT FROM AUTHOR]

To facilitate the efficient exploration and development of coalbed methane of the Longtan Formation in the Guxu coal mining area, Sichuan, it is essential to evaluate the reservoir characteristics of the main production layers. In this study, scanning electron microscopy, low-temperature liquid nitrogen adsorption experiments, high-pressure mercury pressure experiments, and isothermal adsorption experiments were conducted to investigate the reservoir characteristics of favorable coalbed methane reservoirs. The results indicate that the main coal seams in the Longtan Formation are medium-to-high ash content anthracite with a well-developed pore–fracture system. The pore size distribution exhibits both unimodal and bimodal types, while the pore morphology includes impermeable pores closed at one end, open permeable pores, and ink bottle-shaped pores. It shows that the middle part of Longtan Formation acts as an enrichment zone for coalbed methane, which is characterized by a stronger adsorption capacity, high Langmuir volume, high gas content, and high gas saturation distribution. The pH value, mineralization degree, and hydrogen–oxygen isotope of the produced water in the main coal seams indicate that the enrichment zone is typically located in a stagnant flow zone with a reducing environment and favorable storage conditions. [ABSTRACT FROM AUTHOR]

The coupling relationship between the deformation field, the diffusion field, and the seepage field is an important factor in fluid transport mechanisms in the long-term coalbed methane (CBM) exploitation process. A mathematical model of gas–water two-phase fluid–structure coupling in a double-porosity medium in coal reservoirs is established in this paper. Taking Hancheng Block, a typical production block in Qinshui Basin, as the geological background critical desorption pressure, reservoir permeability anisotropy is considered in the model. COMSOL Multiphysics (COMSOL_6.0) was used to create the model. The accuracy and rationality of the model were verified by comparing field production data with the results of the simulation. Using the simulation, the influence law of various reservoir geological characteristics parameters (Langmuir strain constant, ratio of critical desorption pressure to reservoir pressure of coal seam (CDPRP), elastic modulus, initial water saturation, Langmuir pressure, etc.) on CBM productivity, reservoir pressure, and permeability ratio was discussed, and a thorough analysis of the factors affecting productivity was obtained using the orthogonal test method. The findings of this study indicate that the change in permeability is the result of the superposition effect of many factors. Different stages of drainage have different primary regulating factors. Rock skeleton stress has a consequence on coal matrix permeability in the early drainage stage, and coal matrix shrinkage is primarily impacted in the later drainage stage. Besides the initial water saturation, other reservoir geological parameters (e.g., CDPRP, Langmuir volume, Langmuir strain constant, elastic modulus) have a strong relationship with productivity. When the value of coal geological parameters increases, the degree of productivity release is higher (as the initial water saturation increases, the production decreases correspondingly). Different coal and rock parameters have varying levels of impact on the drainage stage of CBM wells. The influences of the CDPRP, Langmuir volume, Langmuir strain constant, and elastic modulus on gas production are mainly concentrated in the initial and intermediate drainage stages and begin to fall off during the last drainage stage. Per the multi-factor analysis, the main coal–rock parameters affecting the productivity release are the Langmuir strain constant, followed by the CDPRP and other parameters. The analysis findings can offer theoretical guidance for CBM well selection and layer selection and enhance the block's overall CBM development level. The improved productivity prediction model for CBM, which is based on fluid–structure coupling theory, can offer a new technical benchmark for CBM well productivity prediction. [ABSTRACT FROM AUTHOR]

Core analysis is an accurate and direct method for finding the physical properties of oil and natural gas reservoirs. However, in some cases coring is time consuming and difficult, and only cuttings with the drilling fluid can be obtained. It is important to determine whether cuttings can adequately represent formation properties such as porosity, permeability, and pore size distribution (PSD). In this study, seven limestone samples with different sizes were selected (Cubes: 4 × 4 × 4 cm, 4 × 4 × 2 cm, 4 × 2 × 2 cm and 2 × 2 × 2 cm, Core: diameter of 2.5 cm and a length of 5 cm, Cuttings: 1–1.7 mm and 4.7–6.75 mm in diameter), and low-field nuclear magnetic resonance (NMR) measurements were performed on these samples to obtain porosity, PSD, and permeability. The results showed that the porosity of cubes and cuttings with different sizes are consistent with cores, which is about 1%. Whereas the PSDs and permeabilities of the two cutting samples (less than in size 6.75 mm) differ significantly within cores. It is suggested that interparticle voids and mechanical pulverization during sample preparation have a negligible effect on porosity and a larger effect on PSD and permeability. Combined with factors such as wellbore collapse and mud contamination suffered in the field, it is not recommended to use cuttings with a particle size of less than 6.75 mm to characterize actual extra-low porosity and extra-low permeability formation properties. [ABSTRACT FROM AUTHOR]

The Permian Longtan Formation in the Songzao coalfield, Southwest China, has abundant coalbed methane (CBM) stored in high-rank coals. However, few studies have been performed on the mechanism underlying the differences in CBM gas content in high-rank coal. This study focuses on the characterization of coal geochemical, reservoir physical, and gas-bearing properties in the coal seams M6, M7, M8, and M12 based on the CBM wells and coal exploration boreholes, discusses the effects of depositional environment, tectono-thermal evolution, and regional geological structure associated with CBM, and identifies major geological constraints on the gas-bearing properties in high-rank coal. The results show that high-rank coals are characterized by high TOC contents (31.49~51.32 wt%), high Tmax and R0 values (averaging 539 °C and 2.17%), low HI values (averaging 15.21 mg of HC/g TOC), high porosity and low permeability, and high gas-bearing contents, indicating a post-thermal maturity and a good CBM production potential. Changes in the shallow bay–tidal flat–lagoon environment triggered coal formation and provided the material basis for CBM generation. Multistage tectono-thermal evolution caused by the Emeishan mantle plume activity guaranteed the temperature and time for overmaturation and thermal metamorphism and added massive pyrolytic CBM, which improved the gas production potential. Good geological structural conditions, like enclosed fold regions, were shown to directly control CBM accumulation. [ABSTRACT FROM AUTHOR]

Studying the heterogeneity of coal reservoirs is significant to coal bed methane (CBM) exploitation. To investigate the development of the pore–fracture and acoustic emission response characteristics of the coal rock in the Yunnan Laochang block, four cores were extracted from the same coal rock in different directions. Through a comprehensive analysis using CT scanning and three-axis compression tests combined with synchronous acoustic emission experiments, a three-dimensional visualization of the pore–fracture structure and an analysis of the acoustic emission process during the elastic phase were conducted. Additionally, the impact of the heterogeneous development of pore–fractures on the acoustic emission characteristics was discussed. The results show that: there is strong heterogeneity in pore and fracture development within the coal rock, with the most significant development occurring along the direction of vertical stratification; the acoustic emission process in the elastic phase can be divided into three stages: strong–weak–strong; the development of pores and fractures affects the acoustic emission characteristics, with both counts and signal strength increasing as the percentage of voids rises; and the inferred in situ stress aligns with strike-slip faulting stress using acoustic emission. These results can provide a reference for the actual project. [ABSTRACT FROM AUTHOR]

Alternative fuels such as hydrogen, compressed natural gas, and liquefied natural gas are considered as feasible energy carriers. Selected positive factors from the EU climate and energy policy on achieving climate neutrality by 2050 highlighted the need for the gradual expansion of the infrastructure for alternative fuel. In this research, continuity equations and the first and second laws of thermodynamics were used to develop a theoretical model to explore the impact of hydrogen and natural gas on both the filling process and the ultimate in-cylinder conditions of a type IV composite cylinder (20 MPa for CNG, 35 MPa and 70 MPa for hydrogen). A composite tank was considered an adiabatic system. Within this study, based on the GERG-2008 equation of state, a thermodynamic model was developed to compare and determine the influence of (i) hydrogen and (ii) natural gas on the selected thermodynamic parameters during the fast-filling process. The obtained results show that the cylinder-filling time, depending on the cylinder capacity, is approximately 36–37% shorter for pure hydrogen compared to pure methane, and the maximum energy stored in the storage tank for pure hydrogen is approximately 28% lower compared to methane, whereas the total entropy generation for pure hydrogen is approximately 52% higher compared to pure methane. [ABSTRACT FROM AUTHOR]

Coal rock pores are the space in which coalbed gas is stored and flows. Accurately characterizing the pore structure of coalbed gas is the foundation of coalbed gas reserve assessment and production forecasting. Traditional experimental methods are unable to characterize the multi-scale pore structure characteristics of coal rock. In this paper, a multi-scale pore structure characterization method is proposed by coupling various experimental methods, including low-pressure nitrogen gas adsorption experiments, X-ray computed tomography (XCT) imaging technology, and scanning electron microscopy (SEM). Using Zhengzhuang coalbed gas as an example, the micro-pore structure of coalbed gas reservoirs is characterized and depicted from a multi-scale perspective. The results indicate that a single experimental approach can only partially reveal the microstructure of coal rock pores. The combined use of multiple methods can accurately reveal the full-scale microstructure of coal rock pores. The pore structure of the experimental coal rock samples exhibits multi-scale characteristics, with a complex variety of pore types, including inorganic pores, organic pores, and fractures. Organic pores are predominant, with a small number of inorganic pores, and their sizes range from 2 nm to 50 μm. Mineral particles and fractures are observed at both the nanoscale and microscale, exhibiting typical multi-scale characteristics, with quartz being the predominant mineral. [ABSTRACT FROM AUTHOR]

The increasing demand for natural gas energy will promote unconventional natural gas, such as coal seam gas and shale gas, to play a key role in future energy development. The mechanical properties of coal seams are weaker compared with conventional natural gas reservoirs. The fluid–solid coupling phenomenon exists widely at the pore scale and macro scale of coal seams, and runs through the whole process of coalbed gas exploitation. The objective of this study is to establish a microscale gas–water flow model for coalbed methane considering fluid structure coupling. Frist, this study used scanning electron microscopy (SEM) to obtain microscopic pore images of coal rocks. Then, we constructed a numerical model to simulate the movement of coalbed methane and water within the scale of coal cleats based on the Navier–Stokes equation, phase field method, and solid mechanics theory. Finally, we analyzed the effects of injection pressure and wettability on the microscopic two-phase seepage characteristics and displacement efficiency of coal. Our research shows that when the injection pressure is increased from 60 kPa to 120 kPa, the displacement completion time is shortened from 1.3 × 10−4 s to 7 × 10−5 s, and the time is doubled, resulting in a final gas saturation of 98%. The contact angle increases from 45° to 120°, and the final gas saturation increases from 0.871 to 0.992, an increase of 12.2%. [ABSTRACT FROM AUTHOR]

Different from conventional gas reservoirs, the permeability of coalbeds is affected by stress sensitivity and matrix shrinkage during production. These two conditions lead to lower permeability in the reservoir and affect the production efficiency of the gas well. In addition, coalbed methane wells have single-phase water flow in the initial stage of production. When the reservoir pressure is reduced to its critical desorption pressure, the adsorbed gas in the reservoir desorbs into the pore space and participates in the flow. The flow state in the reservoir changes from single-phase to two phase, and the permeability of the reservoir decreases. The occurrence of these three damage mechanisms is related to the flow rate of fluid in the reservoir. At present, there is a lack of research on the optimization of drainage and production systems considering the damage mechanism of coal reservoirs. This study comprehensively considers how to optimize the production rate of coal reservoirs under the influence of stress sensitivity, matrix shrinkage and two phase flow in the production process to achieve the purpose of production with the least damage to the reservoir. [ABSTRACT FROM AUTHOR]

Against the backdrop of the national strategic goals of carbon peaking and carbon neutrality, the imperative for China's low-carbon new energy transformation is evident. Emerging as an efficient and clean new energy source, the coal-based "three gases" (coalbed methane, tight sandstone gas, and shale gas) have gained prominence. Nevertheless, the current exploration of the coal-based "three gases" is limited to individual reservoirs, posing challenges to achieving overall extraction efficiency. The primary obstacle lies in the conspicuous disparities in gas content among different reservoirs, with the causes of such disparities remaining elusive. To address this issue, this study focused on the Permian Longtan Formation (coal, shale, and tight sandstone) in the southeastern Sichuan Basin. Through a comparative analysis of the mineral composition, organic geochemical features, and pore structure characteristics, this study aimed to delineate reservoir variations and establish a foundation for the simultaneous exploration and exploitation of the coal-based "three gases". The research findings revealed that the differences in reservoir characteristics account for the variations in gas content among coal, shale, and tight sandstone. The mineral composition of the rock formations in the study area primarily consists of quartz, feldspar, clay minerals, pyrite, calcite, and dolomite. By comparison, the coal samples from the four major coal seams in the study area exhibited relatively large pore sizes, which are favorable for gas accumulation. [ABSTRACT FROM AUTHOR]

The sandstone layer connectivity in coal measure strata is one of the key factors in CBM escape in underlying coal seams, which lacks systematic research currently. This study aimed to explore sandstone layer connectivity and its control on CBM accumulation, taking the Lower Shihezi Formation in Qinan Coal Mine, Xuzhou–Suzhou Region, China, as a case study; to do so, we studied the No. 7 coal CBM unit, the pore-rich sandstone layers, and their connectivity modes by performing sequence stratigraphic analysis on the borehole cores, the logging data, and the theory of sequence stratigraphy and sedimentology, combined with the accumulation characteristics of the No. 7 coal seam CBM. This study shows the following: (1) The sequence stratigraphic framework of the Lower Shihezi Formation in the research region consists of two third-class sequences and six system tracts. (2) The No. 7 coal seam CBM unit includes the CBM formation layer, the connectivity layer, and the stable capping layer. (3) There are 10 types of parasequences in the No. 7 coal connectivity layer, and the pore-rich sandstone layers are all located in the connectivity layer and connected in three modes (vertical connectivity, lateral connectivity, and non-connectivity). (4) The connectivity modes and the thickness of pore-rich sandstone layers control the CBM accumulation in the region. Where the pore-rich sandstone layers are thickest and display vertical connectivity, the strong CBM desorption and escape lead to low CBM; where the pore-rich sandstone layers are thinnest and unconnected, the weak to no CBM desorption and escape result in high CBM. (5) Three models for sandstone layer connectivity and its control on CBM accumulation include the CBM weak accumulation model with a strong source supply, large basin subsidence, and undercompensation deposition; the CBM moderate accumulation model with a moderate source supply, moderate basin subsidence, and overcompensation to isostatic compensation deposition; and the CBM strong accumulation model with a weak source supply, small basin subsidence, and undercompensation deposition. [ABSTRACT FROM AUTHOR]

Using the self-developed "TCHFSM-I" large-size true triaxial fracturing seepage simulation device and fluid injection flow dynamic monitoring device, we studied the crack initiation and expansion law of multi-fractures under different perforation spacing conditions and revealed the mechanism of multi-fractures expanding from non-equilibrium to equilibrium on the basis of the evolution law of the injection pressure and characteristics of the distribution of the injection flow. The results show that when the perforation spacing is small (<60 mm), the central injection fracturing cracks are affected by the extension of the upper and lower injection cracks, and their extension lengths are shorter; on the contrary, the extension lengths of the upper, central and lower injection cracks are basically the same, and the three hydraulically fractured cracks shift from non-equilibrium to equilibrium extension. When the perforation spacing is small, the fracture initiation pressure of the middle perforation is much larger than that of the upper and lower perforations. However, as the perforation spacing increases, the fracture initiation pressure of the middle perforation gradually decreases. Its fracture initiation pressure is basically the same as that of the upper and lower perforations. The expansion of the three hydraulically fractured cracks is independent of each other. In addition, the evolution law of the injection flow rate can better reflect the multi-fracture fracture initiation and expansion pattern, and the evolution pattern of the injection flow rate can better reflect the synchronous fracture initiation and expansion mechanism of multi-fracture fracture. The results of the study can provide technical guidance for efficient coalbed methane extraction. [ABSTRACT FROM AUTHOR]

The macroscopic structural fractures (joints) and geostress distribution characteristics of coal reservoirs are important factors affecting the exploitation of coalbed methane (CBM). In this study, the joints in the sedimentary strata of the Dahebian block in Liupanshui area, Guizhou Province were investigated. Directional coal samples were collected for observation and statistical analysis of coal microfractures, the paleotectonic stress fields of the study area were reconstructed, and the tectonic evolution was elucidated. The geostress distribution characteristics of the target coal seam (coal seam No. 11, P3l) in the study area were analyzed using the finite element numerical simulation method. The results indicate that the structural evolution of the Dahebian syncline in the study area can be divided into two stages. The Late Jurassic–Early Cretaceous stage (Early Yanshanian) is the first stage. Affected by the sinistral strike slip of the Weining–Ziyun–Luodian (WZL) fault zone, the derived stress field in the study area exhibits maximum principal stress (σ1) in the NEE–SWW direction. The Late Cretaceous stage (Late Yanshanian) is the second stage. Affected by the dextral strike slip of the WZL fault zone, the derived stress field exhibits σ1 in the NNW–SSE direction. The folds and faults formed in the first stage were modified by the structural deformation in the second stage. The dominant strikes of joints in the sedimentary strata are found to be in the NW–NNW (300°–360°) and NE (30°–60°) directions, with dip angles mostly ranging from 60° to 90°. The dominant strikes of coal microfractures are in the NW (285°–304°) and NE (43°–53°) directions. The distribution of geostress in the study area is characterized by high levels of geostress in the syncline center, decreasing towards the surrounding periphery. The overall trend of the geostress contour line is similar to the shape of the syncline and is influenced by folds and faults. The σ1 of coal seam No. 11 is vertical stress. The prediction results show that the joint density of coal seam No. 11 in the block is 36–50 joints/m, and the shape of the joint density contour line is also affected by the axial direction of the Dahebian syncline and the surrounding faults. The variation in coal seam joint density and the control effect of geostress on joints opening or closing affects the permeability of coal reservoirs. The study results provide significant guidance for the exploitation of CBM. [ABSTRACT FROM AUTHOR]

The southern Junggar Basin, Xinjiang, has abundant coalbed methane (CBM) resources. Currently, the Baiyang River development pilot test area (BYR block for short) in the Fukang east block has achieved large-scale CBM development, but the productivity characteristics and its controlling factor are still unclear. Based on the field production data of the BYR block and experimental tests, this paper summarizes the gas and water production characteristics and presents the analysis results of the geological and geochemical responses to the productivity of CBM wells. The productivity of CBM wells in the BYR block was generally characterized as medium-to-low yield. The productivity was jointly controlled by the burial depth, structure condition, thickness and number of co-production coal seams, and hydrogeological conditions. The gas production first increased and then decreased with the increase in the burial depth of the coal seam, and a burial depth between 750 and 1000 m was the most beneficial to increasing the gas production due to the good gas preservation conditions and suitable permeability and stress conditions. The total thickness of the co-production coal seams had a positive effect on the productivity of gas wells, but the productivity was also affected by the number of co-production coal seams and interlayer interference. In the BYR block, the co-production of the nos. 41 and 42 coal seams was the most favorable combination form for CBM drainage. The productivity of CBM wells had a good response to the Na+, K+ and HCO3− concentrations but a poor response to δD-H2O and δ18O-H2O. Based on the concentrations of the main ions and TDSs of the coal seam water, a productivity response index δ* was established, and there was a good positive correlation between the productivity and δ*. [ABSTRACT FROM AUTHOR]

Coalbed methane (CBM) reservoirs' permeability is the result of dynamic variations influenced by tectonics, hydrology and the CBM production process. Taking samples from the southeastern Ordos Basin, China, the permeability evolution of bituminous coal and its control were analyzed in three steps: (1) the coal fracture permeability evolution was acquired via X-ray CT scanning and permeability evolution experiments; (2) the permeability variation was determined while considering the coupling characteristics effective stress, gas slippage, and matrix shrinkage effect and its influencing factors; and (3) a dynamic permeability model was built while considering those effects. For samples in which neither fractures nor bedding developed, the permeability decreased first and then increased as the gas pressure increased. For samples with fractures that developed parallel to the axial direction, with a gradual increase in gas pressure, the permeability also increased. As the gas pressure decreased, the matrix shrinkage effect became positive, resulting in a permeability increase. The gas slippage effect was positive in the low-pressure stage, which also resulted in a permeability increase. [ABSTRACT FROM AUTHOR]

In coal seam gas (CSG) coproduction wells, due to the different production pressures of CSG production layer at different depths, the interlayer interference in wellbore seriously affects the gas production of a coproduction well. To effectively suppress the interlayer interference of the wellbore, a wellbore pressure distribution method for a two-layer coproduction well is proposed. Based on the analysis of the factors influencing the flow pressure distribution in the wellbore of two-layer coproduction wells, a method of coproduction flow pressure adjustment by regulating the wellhead pressure and the depth of the dynamic fluid level was established in this paper. The results show that wellhead pressure can directly affect the production pressure of two layers. The variation in layer 1 output mainly affects the pressure difference between the wellhead pressure and the pressure at the depth of layer 1, which has little effect on the pressure difference between layer 1 and 2. An increase in gas production from layer 2 would not only cause a pressure increase in layer 1, but also result in a reduction of the production pressure at layer 2. The maximum pressure gradient of the gas section is 0.14 MPa/100 m, and the pressure gradient of the gas–liquid section is 0.53–1.0 MPa/100 m. [ABSTRACT FROM AUTHOR]

During the mining of highly gassy and low-permeability coalbed groups, massive pressure-relieved desorbed coal bed methane (CBM) is stored in the fracture zone and in the gob under the impact of mining activities. Surface wells can cross the fracture zone and the gob to drain a large amount of highly concentrated pressure-relieved CBM. CBM drainage by surface wells is an effective technology for disaster control. However, it is difficult to drill or maintain surface wells in the mining disturbance zone and overlying strata in the gob. The keyisto prevent the surface wells in the mining disturbance zone from being broken and to keep the whole surface wells unblocked. This study adopted a variety of research methods, including similar-material simulation in laboratory, numerical simulation, onsite monitoring and industrial tests. Specifically, the strata structure of surface wells for pressure-relieved CBM drainage was explored, and the characteristics of roof strata movement and stress redistribution under coalbed group mining were analyzed. Besides, positions where the surface wells are prone to breakage were found. Furthermore, based on the mechanical analysis and breakage characteristics of surface wells, the anti-breakage principle of "resistance and dodge" and the surface well completion and protection method of "upper stop and lower leak" were proposed. The proposed theory and method were then applied to pressure-relieved CBM drainage surface wells in a coalbed group covered by the super-thick pedosphere in the Huainan Coal Field. The application results indicate that the proposed theory and method succeeded in solving the breakage of surface wells and realizing the smooth transport of CBM product. The surface wells can completely resist the mining disturbance, achieving an average single-well pure CBM production of 2.71 million m3, an average service period of 482 d, and a maximum pure CBM production of 4.32 million m3. [ABSTRACT FROM AUTHOR]

In the process of working face mining, the permeability of the coal seam and the crack evolution characteristics of overlying strata are very important for efficient gas drainage. In this study, the distribution characteristics of the stress field and crack field in the working face and their relations are analyzed mainly by 3DEC numerical simulation. Furthermore, combined with the on-site measurement of coal seam stress, gas pressure, and gas seepage in front of the working face and the gas seepage in overlying strata before and after mining, the coupling effect of stress field and gas field and the law of gas migration and distribution in the working face are deeply explored. The results show that the changing trend of gas seepage and gas pressure is controlled by the stress change of the working face, and with the increase of stress, gas pressure and gas seepage also increase. The peak position of gas pressure is the farthest from the coal wall, about 22.5~25 m, followed by the peak of stress and gas seepage. When the permeability of coal and rock mass increases, the gas seepage increases and the gas pressure decreases. The coal seam stress and gas seepage in the working face and gas seepage in the overlying strata fracture zone along the tailgate side are generally greater than those on the headgate side, but the gas pressure is the opposite. Mining cracks and strata separation provide a good channel and space for gas migration and accumulation. Along the strike and tendency of the working face, gas is mainly concentrated in the overlying strata crack space above the separation zone and the roof and overlying strata crack space on the side of the tailgate, respectively. Based on this, the directional borehole gas drainage technology and borehole layout scheme in the fractured zone are put forward, which effectively reduce the gas concentration in the working face by 30~36%. [ABSTRACT FROM AUTHOR]

For highly heterogeneous complex carbonate reef reservoirs, rock typing with respect to depositional conditions, secondary processes, and permeability and porosity relationships is a useful tool to improve reservoir characterization, modeling, prediction of reservoir volume properties, and estimation of reserves. A review of various rock typing methods has been carried out. The basic methods of rock typing were applied to a carbonate reservoir as an example. The advantages and disadvantages of the presented methods are described. A rock typing method based on a combination of hydraulic flow units and the R35 method is proposed. Clustering methods for rock typing are used. The optimum clustering method is identified, and for each rock type, the permeability–porosity relationships are built and proposed for use in the geomodelling stage. [ABSTRACT FROM AUTHOR]

The aim of this paper is to analyze the deformation-failure degree and microstructure variations in coal under the cryogenic-freezing effect of liquid CO2. In this paper, X-ray CT scanning technology is adopted to measure the microscopic-morphological parameters of coal. Drawing support from the image processing and three-dimensional (3D) visualization functions of Avizo software, 3D spatial structure variation rules, as well as the deformation and permeability parameters, are quantitatively calculated. Under the effect of LCO2 cryogenic freezing, the macroscopic mechanical properties and deformation-failure degree of coal are thoroughly analyzed. The results show that fracture-scale parameters of treated coal are significantly increased, resulting in spatial structure parameters including the coal plug total volume (Vt), fracture network volume (V0), and proportion of fracture network (μ0) to increase by 17.11%, 56.57%, and 55.59%, respectively. A comparison analysis indicates that the coverage area of a single value function from the percolation theoretical model for treated coal plugs becomes larger, and its percolation curves are more intensive; the quantitative coal permeability coefficients are increased to more than 40% on average, which further proves that the permeability of coal by using LCO2 cryogenic freezing is significantly improved. Under the same uniaxial stress loading rate, the peak stress threshold value required by treated coal in the compaction and elastoplastic deformation stage is decreased. The corresponding output acoustic emission energy is apparently increased, owing to the increased brittleness of coal, and deformation failure of coal occurs more easily. Simultaneously, the fracture network and matrix surface of treated coal are more complex, and the corresponding fractal characteristic is obvious. It could be thus concluded that the coal plugs have deformation-failure changes under cryogenic freezing by using LCO2, increasing the proportion of coal microstructure and enhancing coal permeability. Therefore, the capability of gas migration through the coal microstructure becomes easier, which is favorable for coalbed methane recovery. [ABSTRACT FROM AUTHOR]

Deep coalbed methane (CBM, commonly accepted as >1500 m) has enormous exploration and development potential, whereas the commercial development of deep CBM exploration areas wordwide has been quite limited. The Linxing area, with coals buried approximately 2000 m deep, shows great development potential. Based on a basic geological analysis of structural and hydrodynamic conditions, combining field tests of reservoir temperature and pressure and indoor measurements of maceral composition, proximate analysis, thermal maturity, porosity and permeability, the factors controlling deep CBM accumulations were discussed. The results show that the present burial depth of the No. 8 + 9 coal seam, mainly between 1698 and 2158 m, exhibits a high reservoir temperature (45.0–64.0 °C) and pressure (15.6–18.8 MPa), except for the uplift area caused by the Zijinshan magma event (with coal depth approximately 1000 m). The maximum vitrinite reflectance (Ro,max) of the coal varies from 1.06% to 1.47%, while the magma-influenced areas reach 3.58% with a relatively high ash content of 31.3% (air-dry basis). The gas content calculated by field desorption tests shows a wide range from 7.18 to 21.64 m3/t. The key factors controlling methane accumulation are concluded from regional geological condition variations. The north area is mainly controlled by structural conditions and the high gas content area located in the syncline zones. The center area is dominated by the Zijinshan magma, with relatively high thermal maturity and a high gas content of as much as 14.5 m3/t. The south area is developed with gentle structural variations, and the gas content is mainly influenced by the regional faults. Furthermore, the groundwater activity in the eastern section is stronger than that in the west, and the hydrodynamic stagnant areas in the western are more beneficial for gas accumulation. The coals vary from 3.35% to 6.50% in porosity and 0.08 to 5.70 mD in permeability; thus, hydrofracturing considering high temperature and pressure should be applied carefully in future reservoir engineering, and the co-production of gas from adjacent tight sandstones also should be evaluated. [ABSTRACT FROM AUTHOR]

Nano-clean fracturing fluids have broad application potential in coalbed methane reservoir fracturing owing to their high stability, good temperature resistance, low filtration loss, and strong frictional resistance reduction. However, the sand-carrying regularity of nano-clean fracturing fluids in coalbed methane reservoirs is unclear, especially for complex fractures with variable directions. This study established a sand transport model that considers proppant collision, wall friction blocking, fracture fluid filtration loss, and the fracture branching angle to study the sand-carrying law of nano-clean fracturing fluids and its influencing factors in complex fractures. The degrees of influence on equilibrium height and placement rate from high to low were the proppant particle size, proppant density, fracturing fluid properties, sand ratio, and pumping discharge volume, and the correlation degrees obtained by grey correlation analysis are 0.862, 0.861, 0.855, 0.854, and 0.832, respectively. As the complexity of the fractures deepens and the resistance increases, the flow rate of the fracturing fluid is reduced, making it difficult for the proppant to enter the branching joints. The sand-carrying performance of a nano-clean fracturing fluid is better than that of a common clear-water fracturing fluid. The fluid-structure coupling model of a nano-clean fracturing fluid can accurately characterize the sand-carrying law of nano-clean fracturing fluids, providing a research basis for optimizing high efficiency sand-carrying fracturing fluid parameters in coalbed methane reservoir fracturing construction. [ABSTRACT FROM AUTHOR]

The carbonate reservoir in the northern Yishan slope of the Ordos Basin presents significant challenges to gas field exploration and development. With its low pressure, limited porosity, low permeability, and abundance of micro-fractures, the reservoir is resistant to acid dissolution. Once solid particles block these fractures during drilling and completion, serious reservoir damage ensues. To address these obstacles, we engineered an acid-soluble, solid-free drilling fluid system in the lab. This involved incorporating sodium carboxymethyl cellulose, heat-resistant starch, fungicides, and lubricants. Contrasted with the commonly used potassium ammonium based drilling fluid system, our innovative solution showed notable improvements. Specifically, the density decreased by 0.04 to 0.06 g/cm3, and the solid content decreased by 4.0% to 6.50%, while the acid-soluble rate surged from 8.50% to 95.45%. In addition, the reservoir permeability recovery value saw an increase from 51.50% to 95.88%. In practical field application, we employed this novel drilling fluid system in ten horizontal wells. Following acid fracturing and reconstruction, these wells registered a 75.94% increase in gas production compared to nearby wells. Our findings demonstrate that the proposed system effectively mitigates the incursion of solid-phase particles into the reservoir while enhancing acidification during acid fracturing. This results in the swift removal of plugging, restoration of formation permeability, and improved well production. Our research thus introduces a drilling and completion fluid system of high efficiency with superior reservoir protection performance, potentially offering substantial benefits to the development of carbonate rock salt gas reservoirs. [ABSTRACT FROM AUTHOR]

The surface wettability is important in the change in the relative permeability of gas and water. Due to the heterogeneous property of coal, it has a mixed wetting state, which makes it difficult to predict the change in permeability. To investigate the influence of different wettabilities on two-phase flow, a total of three different rank coal samples were collected and were treated with different chemicals. The alteration of the coal's wettability, characteristics of gas–water flow, and relative permeability of the coal after the chemical treatments were analyzed. The research conclusions suggest that (1) the coal samples treated with SiO2 and H2O2 increased the hydrophilicity of the coal surface, while the coal samples treated with DTAB increased the hydrophobicity of the coal surface. Compared to SiO2, both H2O2 and DTAB can form a uniform wetting surface. (2) The wettability alteration mechanism among the three different chemical reagents is different. (3) All the chemicals can change the gas–water interface. The water migrates more easily through the cleats after H2O2 treatment, while it is more difficult for the water to migrate through cleats after the DTAB treatment. (4) There are two types of flow states of gas and water on different wetting surfaces. A slug flow is formed on a hydrophilic surface, while an annular flow is formed on a hydrophobic surface. (5) The crossover point and the residual water saturation of the relative permeability curves were influenced by the surface wettability. [ABSTRACT FROM AUTHOR]

In the L Area, big data techniques are employed to manage the principal controlling factors of coalbed methane (CBM) production, thereby regulating single-well output. Nonetheless, conventional data cleansing and the use of arbitrary thresholds may result in an overemphasis on certain controlling factors, compromising the design and feasibility of optimization schemes. This study introduces a novel approach that leverages raw data without data cleaning and eschews artificial threshold setting for controlling factor identification. The methodology supplements previously overlooked controlling factors, proposing a more pragmatic CBM production adjustment scheme. In addition to the initial five controlling factors, this approach incorporates three additional ones, namely, dynamic fluid level state, drainage velocity, and fracturing displacement. This study presents a practical application case study of the proposed approach, demonstrating its ability to reduce reservoir damage during the coal fracturing process and enhance output through seal adjustments. Utilizing the full spectrum of original data and minimizing human intervention thresholds enriches the information available for model training, thereby facilitating the development of a more efficacious model. [ABSTRACT FROM AUTHOR]

The largest marine carbonate oilfield and gas condensate field in China have been found in the Ordovician limestones in the central Tarim Basin. They are defined as large "layered" reef-shoal and karstic reservoirs. However, low and/or unstable oil/gas production has been a big challenge for effective exploitation in ultra-deep (>6000 m) reservoirs for more than 20 years. Together with the static and dynamic reservoir data, we have a review of the unconventional characteristics of the oil/gas fields in that: (1) the large area tight matrix reservoir (porosity less than 5%, permeability less than 0.2 mD) superimposed with localized fracture-cave reservoir (porosity > 5%, permeability > 2 mD); (2) complicated fluid distribution and unstable production without uniform oil/gas/water interface in an oil/gas field; (3) about 30% wells in fractured reservoirs support more than 80% production; (4) high production decline rate is over 20% per year with low recovery ratio. These data suggest that the "sweet spot" of the fractured reservoir rather than the matrix reservoir is the major drilling target for ultra-deep reservoir development. In the ultra-deep pre-Mesozoic reservoirs, further advances in horizontal drilling and large multiple fracturing techniques are needed for the economic exploitation of the matrix reservoirs, and seismic quantitative descriptions and horizontal drilling techniques across the fault zones are needed for oil/gas efficient development from the deeply fractured reservoirs. [ABSTRACT FROM AUTHOR]

Numerical well testing is used mostly in oil/gas, geothermal, and coalbed methane injection/falloff well-testing interpretations while few published studies have been presented on how to adjust the models and numerical experiments parameters. Meanwhile, there is no simple and highly applicable evaluation standard on the approximation degree between the simulated and field-measured pressure response. In this paper, seven groups of numerical experiments were conducted to obtain the simulated pressure response. The Pearson correlation coefficients and the grey correlation between the simulated and field-measured pressure response were calculated to evaluate the approximation degree. In homogeneous, stress-independent, multi-layered, heterogeneous and integrated models, the simulated pressure response curves all fit to the field data well at the early and late time of the falloff period. However, the highest approximation degree was only found in the integrated model. Finally, the permeability, initial pressure, skin factor and investigation radius of the tested CBM reservoir were determined. The results show that, to obtain a reliable interpretation result, it is best to give an approximation degree evaluation standard on the approximation degree between the simulated and field-measured pressure response, build an integrated numerical model, and input the correct parameters, such as the effective thickness and the testing fluid viscosity. Otherwise, it will also drop into a pitfall of multi-results. The method we used is very relevant to CBM exploration and safe mining in Hedong coalfield. [ABSTRACT FROM AUTHOR]

The phenomenon of coalbed-methane synclinal accumulation in the Qinshui Basin has been widely reported, but it has mainly been observed in the core block of the Qinshui Syncline. The questions arise: does this phenomenon exist in the wing of the Qinshui Syncline and, if so, what is the mechanism behind it? Further study is required to answer these questions. This paper focuses on the South Anze No. 3 coal seam in the Qinshui Basin as an example. It conducts a systematic sorting of coalbed-methane geological characteristics and an analysis of the effects of structural assemblage characteristics, genetic mechanisms, and structural control on coalbed-methane accumulation. Additionally, it examines the basin structure and evolution during the critical period of the Qinshui Basin, as well as the gas geological characteristics of adjacent areas, in order to discuss the gas-rich mechanism of the syncline in the Qinshui Basin. Key insights obtained from the study include the following: (i) The whole South Anze is a nosing structure that plunges from west to east and superposes secondary folds and faults in different directions. Four deformation zones can be identified based on the characteristics of structural assemblage, including NEN-oriented compressive structures, ENE-trend shear fractures, EW-trend compressive fractures, and EW-trend compressive folds. The formation of structural assemblage in the study area is attributed to the compression in the Indosinian and Yanshanian, and the fault inversion in the Himalayan period. (ii) The ENE-trend shear fracture deformation area located in the nosing uplift is a low CBM (coalbed methane) content area due to gas diffusion during the Himalayan extension. The syncline in the combination of NEN-trend and EW-trend "ejective folds" in the west and south of the study area is a high-value area of coalbed-methane content. It is further verified that the law of syncline gas accumulation in the Qinshui Basin is also applicable to the wing of the Qinshui Syncline. (iii) Since the formation of the Qinshui Syncline, the main coal seam has been in an extensional environment below the neutral plane, resulting in the main dissipation of coalbed methane. During its geological history, surface water penetrated the aquifer above the main coal seam through two channels: the extensional area above the neutral plane of the adjacent anticline and the shear fracture. A hydrostatic pressure seal is formed in the Qinshui Syncline and the secondary syncline is superimposed upon it, which is the cause of gas enrichment in the syncline of the Qinshui Basin. (iv) Weak deformation in the syncline basin is the focus of global coalbed-methane exploration and development. The mechanism proposed in this paper can provide ideas and references for further understanding of coalbed-methane enrichment in this type of basin. [ABSTRACT FROM AUTHOR]

Decarbonization of the mining industry on the basis of closing the energy generation, on the basis of cogeneration of coal mine methane, and on the internal consumption of the mine is a promising direction in ensuring sustainable development. Known problems of deep underground mining do not allow for realizing the potential of man-made gas reservoirs due to the deterioration of the conditions of development of reserves of georesources. The aim of the work was to improve recommendations for the substantiation of drilling parameters for undermined drainage boreholes for increasing methane production from unconventional coal-gas collectors. The authors' approach innovation lies in the possibility of using the established patterns of better natural stability of undermined boreholes to optimize them as spatial orientation parameters in an existing drilling passport for the improvement of methane extraction productivity. For this purpose, smoothing (LOESS) of the experimental data of two similar types of wells was used; then deterministic interpolation methods in combination with a three-dimensional representation of the response function in "gnuplot" were used. As a result, it was found that the increase in the inclination angle from 40° to 60° leads to a significant transformation of the model of the studied process, accompanied by a decline in the dynamics of methane emission and a decrease in the distance of the productive work zone of this type of well from 13 to 5 m before the roof landing, which then is replaced by a sharp increase in the productive work zone up to 35 m ahead of the longwall face. This allows under specific conditions for recommending increasing the productivity of methane capex from technogenic disturbed coal-gas reservoir replacement of wells with a smaller angle of rise to the transition to a more frequent grid of clusters from wells #4. [ABSTRACT FROM AUTHOR]

The purpose of this review paper is to show the possibilities of carbonate reservoir characterization using well logging and laboratory measurements. Attention was focused on standard and new methods of well logging acquisition and interpretation including laboratory experiments to show a part of the history of carbonate rock investigations as hydrocarbon or water reservoirs. Brief information on the geology, mineralogy and petrography of carbonate rocks was delivered. Reservoir properties, i.e., porosity (including fracturing), permeability, and saturation, were defined to emphasize the specific features of carbonates, such as fractures, and vugs. Examples of methodologies were selected from the commonly used laboratory techniques (thin sections examination, mercury and helium porosimetry, X-ray diffraction—XRD) combined with the standard well logs (bulk density—RHOB, neutron porosity—NPHI, sonic slowness—DT, and deep resistivity—Rd) to show the methods that have been used since the very beginning of the scientific and engineering studies of carbonates. Novelty in well logging, i.e., resistivity and acoustic imaging, nuclear magnetic resonance–NMR, dipole shear sonic imaging–DSI, and a spectral neutron-gamma log-geochemical device–GLT combined with modern laboratory investigations (NMR laboratory experiments, scanning electron microscopy SEM), showed how continuous information on mineral composition, porosity and saturation could be obtained and juxtaposed with very detailed laboratory data. Computed X-ray tomography (CT) enabling the 2D and 3D analyses of pores and fractures was presented as a quantitative methodology, effective in pore space characterization, revealing rock filtration abilities. Deep learning and artificial intelligence were used for joining various types of data. It was shown that thanks to new computational technologies original data from very small samples (micro scale), extensively describing the flow ability of the reservoir, could be extended to mezzo scale (core samples) and macro scale (well log images). Selected examples from the published papers illustrated the review. References cited in the text, together with the issues included in them, were the rich source of the practical knowledge processed These were checked by the authors and could be used in other projects. [ABSTRACT FROM AUTHOR]

The largest Precambrian gas field in China has been found in the central Sichuan Basin. It is assumed as a mound-shoal microfacies-controlled dolomite reservoir. Recently, a large strike-slip fault system has been identified in the gas field that needs further study of its effect on the Ediacaran reservoirs for highly efficient exploitation of the gas field. For this contribution, we study the matrix reservoir and fractured reservoir along the strike-slip fault damage zones by the cores, FMI (Formation MicroScanner Image) and logging interpretation data, seismic description and production data. It has shown that the matrix reservoir is tight (porosity less than 3%, permeability less than 0.5 mD) that cannot support economical production by conventional exploitation technology in the deep subsurface. On the other hand, the porosity and permeability of the Ediacaran fractured reservoirs could be increased more than one time and 1–3 orders of magnitude. Except for a few localized fracture zones, the fracture elements and fractured reservoirs show a paw-law distribution with the distance to the fault core. Furthermore, the fault effect is more favorable for the increase in the porosity and permeability of the matrix reservoir in the intraplatform than in the platform margin. The overlapping of mound-shoal microfacies, fracturing and karstification could result in large-scale "sweet spots" of the fractured reservoirs in the fault damage zone. The "sweet spot" of fractured reservoir in the fault damage zone is a new favorable exploitation target in the deep central Sichuan Basin. [ABSTRACT FROM AUTHOR]

Analyzing and mastering the fractal features of coal-measure sedimentary rocks is crucial for accurately describing the pore structure of coalbed methane resources. In this work, mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) are performed on coal-measure sedimentary rocks (i.e., shale, mudstone, and sandstone) to analyze their pore structure. Pore size distributions (PSDs) and the multifractal dimensions of the investigated samples are discussed. Moreover, multivariable linear regression models of multifractal dimensions are established through a comprehensive analysis of multifractal characteristics. The results show that sandstone (SS-1) and clay rocks are dominated by nanopores of 0.01 to 1 μm, while sandstone (SS-2) is mostly mesopores and macropores in the range of 1 to 10 μm. The fractal characteristics of the investigated rock samples show a prominent multifractal characteristic, in which DA reflects the surface structure of micropores, while DS represents the pore structure of macropores. Multifractal dimension is affected by many factors, in which the DA is greatly influenced by the pore surface features and mineral components and the DS by average pore diameters. Moreover, multivariate linear regression models of adsorption pore and seepage pore are established, which have a better correlation effect on the multifractal dimension. [ABSTRACT FROM AUTHOR]

Expansion energy is the main factor of coal and gas outbursts, and the gas desorption around the outburst hole is developed in variable pressure conditions. While studying the impact of moisture on gas desorption characteristics, atmospheric pressure desorption is usually used, but its characteristics under variable pressure conditions have not been thoroughly investigated. In this study, typical outburst coal samples with different water contents from the Jincheng mining area of China were selected as research objects, and the effects of water on gas displacement, desorption, desorption rate, and gas desorption index (K1) of drilling cuttings under step-by-step depressurization were analyzed by means of stepwise depressurization and atmospheric desorption experiments. The research conclusions suggest that (1) the amount of gas replacement, which augments rapidly during the inception, increases with the growth of water content under the experimental conditions, and then the rate decreases; (2) the gas desorption falls gradually at different depressurization stages when the humidity is constant, while the total desorption and the drop amplitude taper with the increasing water content; (3) the additional water enhances the desorption rate significantly only at the initial stage, but scarcely has an impact later on; and (4) the value of the drilling cuttings' gas desorption index (K1) shows a downward trend with the developing humidity in each stage of stepwise depressurization desorption. We take humidity as a variable to simulate the desorption process of coal gas around the hole when coal and gas outbursts occur in the laboratory and study the influence of water on the desorption characteristics under desorption conditions of stepwise depressurization. This provides a reference for the purpose of studying the mechanism of coal and gas outbursts from the perspective of energy. [ABSTRACT FROM AUTHOR]

Most coal and gas outbursts occur in the coal thickness variation zone. However, it is difficult to illustrate the mechanism of outbursts in coal thickening areas by physical simulation experiments. In this study, a coupled multi-field model, established by considering the stress–strain field, gas transport field and damage field, was used to investigate the evolution of stress, gas pressure and plastic failure zones under different variation gradients and amplitudes of coal thickness. The simulation results show that the stress peak at the coal thickening transition zone caused by mining is higher than that at the constant thickness coal seam. The stress peak at the coal thickening transition zone decreases from 18.8 MPa to 16.9 MPa with the increase in the transition zone from 0 m to 10 m under the constant coal thickness variation from 3 m to 7 m; while it increases from 16.2 MPa to 19.3 MPa with the increase in the transition zone from 2 m to 10 m under the constant coal thickness variation gradient of 45°. Similarly, the plastic deformation volume of the coal seam between the driving face and the coal thickening interface increases with the increase in the coal thickness variation gradient and amplitude. In addition, the gas pressure in the fracture declines slower in the coal thickness variation zone affected by the higher coal thickness variation gradients or amplitudes. The mechanism for outbursts occurring in the increasing coal thickness area was further discussed, and combined with the simulation results for the energy principle of outbursts. Compared with the constant thickness coal seam, the elastic energy increases from 1.85 MJ to 1.94 MJ, and the free gas expansion energy increases from 24.19 MJ to 50.57 MJ when the coal thickness varies from 3 m to 13 m within a 10 m transition zone. The variation of coal thickness causes higher stress, higher gas pressure and low coal strength, which triggers outbursts more easily. The research could provide the theoretical support to prevent and control outbursts in coal seam thickening areas during mining. [ABSTRACT FROM AUTHOR]

The area studied covers unmined Pennsylvanian Ćwiklice and Dankowice coal deposits located in the southern part of the Upper Silesian Coal Basin, Poland. The geological structure of the area clearly affects the current distribution of methane. The content of methane is lower in coal seams lying within porous and permeable sandstones (Łaziska sandstones), whereas it is higher in seams that occur in sequences (Mudstone Series) where impermeable shales and mudstones occur. Due to the previous attempts to extract methane from boreholes, this area, characterized by a dense network of exploratory and prospecting drillings, is worth analyzing with regard to the conditions of methane occurrence in terms of extraction possibilities. Using contour maps, cross-sections and profiles, the variability of methane content and resources, as well as the moisture and ash content of coal seams, were analyzed. Methane content isolines are parallel to the boundary between the Cracow Sandstone Series and the Mudstone Series and to main faults. Coal moisture contents clearly reduce methane contents. A high methane content >8 m3/t coaldaf is typical for coal seams in which moisture contents do not exceed 5%. High- and medium-volatile bituminous coal in the area is characterized by low methane saturation, though saturation increases with depth. Coal permeability is variable (from 0.2 to more than 100 mD), but, below a depth of 1200 m, a clear trend of decreasing permeability with depth is evident. From the point of view of coalbed methane (CBM) recovery, relatively low coal permeabilities and methane saturation levels could make CBM output problematic in the studied area. Methane production will be more probable as a result of demethanation of the Dankowice 1 deposit, where coal mining is planned. This will result in the emission of methane into the atmosphere from ventilation shafts and methane drainage stations. Therefore, effective use of the gas captured by the methane drainage station is highly desirable for environmental and economic reasons. [ABSTRACT FROM AUTHOR]

This paper develops a model of the multi-wing finite-conductivity fractures considering stress sensitivity for low-permeability bi-zone composite gas reservoirs. A new semi-analytical solution in the Laplace domain is presented. The main solution includes the theory of source function, Laplace integral transformation, perturbation technique, and Stehfest numerical inversion. Wellbore pressure is obtained by coupling solutions of reservoirs and fractures. The results showed that the pressure and derivative curves generated by this model include a bi-linear flow stage. The model was validated by comparing its results with Wang's results and the commercial well-test simulator; the results showed excellent agreement. This model illustrated the seepage characteristic of acid fracturing stimulated wells during refracturing treatment and how they are influenced by reservoir and hydraulic fractures parameters (asymmetrical factor and fractures distribution, etc.). The model is suitable to solve the solution of arbitrary-angle hydraulic fracture in refracturing and helpful to understand the transient production rate characteristic of the multi-wing fracturing well. [ABSTRACT FROM AUTHOR]