Coal Reservoir Permeability Research Articles

A Practical Approach for Determining Postfracturing Permeability in Unsaturated Coal Reservoirs

A Practical Approach for Determining Postfracturing Permeability in Unsaturated Coal Reservoirs

Present-day stress regime, permeability, and fracture stimulations of coal reservoirs in the Qinshui Basin, northern China

Present-day stress regime, permeability, and fracture stimulations of coal reservoirs in the Qinshui Basin, northern China

Study on the Mechanical Parameters and Permeability of Coal Reservoirs at Different Temperatures.

Deep coal reservoirs, as opposed to their shallower counterparts, exhibit characteristics of higher temperatures and pressures. These conditions affect the fracture structure and mechanical properties of coal, which in turn controls permeability. Substantial studies have been conducted to determine the effects of overburden pressure on permeability, but the correlation between the temperature and mechanical parameters/permeability of coal remains unclear. This study focused on low-rank bituminous coal from the southern edge of the Junggar Basin in Xinjiang. Using experiments conducted on seepage and mechanics at different depths (considering effective stress and temperature), the study investigated how temperature affects the mechanical parameters and permeability of coal column samples. A permeability prediction model was established incorporating temperature, mechanical parameters, and effective stress. The results show that from 20 to 80 °C, the elastic modulus of coal column samples decreases by 31.0%, and the Poisson ratio increases by 72.0%. Permeability decreases between 48.37 and 90.12% under different depths. The stress sensitivity coefficient under various temperature conditions decreased exponentially as the effective stress increased, and the temperature sensitivity coefficient under various effective stress conditions decreased with increasing temperature. The permeability was more sensitive to a temperature below 40 °C. In the permeability prediction model, the fracture compressibility coefficient is bifurcated into two coefficients, each controlled by temperature and effective stress. The permeability prediction error of the model was 12.7% under constant effective stress and 17.2% under varying effective stress and temperature conditions. The study could provide guidance for fracturing and coalbed methane production in deep coal reservoirs.

Analysis of methane diffusion on permeability rebound and recovery in coal reservoirs: Implications for deep coalbed methane-enhanced extraction

A proper understanding of the effect of methane diffusion on coal reservoir permeability rebound and recovery is essential, as coal reservoir permeability is the key parameter influencing the efficiency of coalbed methane migration and computational research on it is lacking. In this paper, the multifield coupling model for methane migration was established. Then, two parameters, the influence coefficient of diffusion on permeability rebound (DPRB) and the influence coefficient of diffusion on permeability recovery (DPRC), were proposed to quantify the effect of methane diffusion on rebound and recovery of coal reservoir permeability. Subsequently, we used COMSOL software to study the variation rules of the coal reservoir permeability rebound time, permeability recovery time, and permeability rebound value, DPRB, and DPRC for different geologic parameters. The results shown that the permeability rebound time and recovery time are proportional to the coal seam initial pressure, but inversely proportional to the initial permeability and initial diffusion coefficient. The rebound value decreases with increasing coal seam initial pressure and initial permeability, but ascends with rising initial diffusion coefficient. DPRB declines with increasing coal seam initial pressure, initial permeability, and initial diffusion coefficient, but they are all greater than 0.7, indicating that methane diffusion has a significant effect on permeability rebound. The DPRC values for different coal seam initial pressures, initial permeabilities, and initial diffusion coefficients are above 0.98, which implies that methane diffusion dominates the permeability recovery process. Finally, a conceptual model was presented to research the mechanism of diffusion influence on rebound and recovery of coal reservoir permeability, and the implications for enhanced drainage of deep coalbed methane were discussed. Therefore, the results of this paper can provide a theoretical foundation for deep coalbed methane-enhanced extraction.

Study on the Thermal Expansion Characteristics of Coal during CO2 Adsorption

The adsorption of CO2 fracturing fluid into coal reservoirs causes the expansion of the coal matrix volume, resulting in changes in the fracture opening, which alters the permeability of the coal reservoir. However, it is not yet clear whether thermal expansion during CO2 adsorption on coal is the main cause of coal adsorption expansion. Therefore, by testing the thermal properties, expansion coefficient, and adsorption heat of the three coal samples, the adsorption thermal expansion characteristics of coal and their impact on the permeability of coal reservoirs are clarified. The results reveal the following: (1) Under the same conditions, the adsorption heat increases with increasing pressure, while it decreases with increasing temperature. The relationship between adsorption heat and pressure conforms to the Langmuir equation before 40 °C, and it follows a second-order equation beyond 40 °C. At 100 °C, the adsorption heat of coal samples to CO2 is primarily determined by temperature. (2) The maximum temperature variation in coal samples from Xinjiang, Liulin, and Zhaozhuang during CO2 adsorption is 95.767 °C, 87.463 °C, and 97.8 °C, respectively. The maximum thermal expansion rates are 12.66%, 5.74%, and 14.37%, and the maximum permeability loss rates are 16.16%, 7.51%, and 18.24%, respectively, indicating that thermal expansion is the main reason for coal adsorption expansion. (3) This research can elucidate the impact of CO2 fracturing fluid on coal reservoirs and its potential application value, thus providing theoretical support for coalbed methane development and CO2 geological storage.

Assessing the impact of pore‐fracture structures on permeability sensitivity in tectonic coal using computerized tomography scanning

AbstractThe heterogeneity in permeability of coal reservoirs is primarily attributed to the considerable variation in the morphologies and structures of microscopic pore‐fractures, shaped by complex geological processes. This study emphasizes the necessity of understanding the impact and governance of these morphological and structural variations in pore‐fractures across different types of coal bodies on their permeability. Utilizing computerized tomography scanning and three‐dimensional imaging, we examined coal samples from the Datong coalfield in the southeastern Qinshui Basin, Shanxi Province, to characterize the pore‐fracture morphologies and structures distinct to various coal‐body types based on tomographic data. This introduces a methodology for assessing the influence of microscopic pore‐fracture parameters, such as porosity, specific surface area, tortuosity and fractal dimension, on permeability sensitivity. This is achieved through the application of the modified Kozeny–Carman equation and a fractal permeability model. Findings indicate a predominance of slab fractures in raw coal, whereas fragmented coal under weak brittle deformation exhibits small, isolated pore‐fractures with minimal diameter and volume and poor connectivity. In contrast, granular coal subjected to strong brittle deformation features extensive clusters of large pore‐fractures with significant diameter and volume, enhancing connectivity. Moreover, permeability predictions are refined by integrating the modified Kozeny–Carman equation with tomographic data, offering a more precise understanding of the permeability across different coal bodies.

Comprehensive Analysis of Connectivity and Permeability of a Pore-Fracture Structure in Low Permeability Seam of Huainan-Huaibei Coalfield.

The connectivity and permeability of the coal seam pore structures control the occurrence and migration of coalbed methane. Coal samples were used from Huainan-Huaibei to reconstruct three-dimensional models of the pores and an equivalent pore network model, Statistical pore structure characteristic parameters. The pore structure of the coal reservoir was analyzed from the direction of multidimensional and multiangle. It shows that based on quantitative analysis, the representative Elementary volume of 500 × 500 × 500 was the most suitable experimental volume. The Y-axis direction of the Renlou sample had poor pore connectivity compared to that of other samples. Large volume connected pores dominated their pore systems. In terms of coal sample pore connectivity, the coal samples from the Liuzhuang and Qidong regions had pore connectivity better than those from the other regions. The pore connectivity of the Liuzhuang coal samples was the best. In terms of coal permeability, the Liuzhuang sample had better permeability than the other three samples, and the permeability was the best in the Y-axis direction. For all the combinations of the different types of throats, the shorter the throat, the greater the equivalent radius and the better the permeability. Conversely, the worse the permeability. During gas injection production, the closer the gas injection area was to the gas injection well, the poorer the connectivity and the lower the permeability over time. Near the production area, where the CO2 did not reach the production area, the fracture porosity and effective connected porosity of the coal reservoir increased over time. When CO2 reached the production area, the change in its connected pore structure was consistent with the change in the connected pores in the gas injection area. With this study, the coal seam pore structure on a microscale was characterized. A comprehensive analysis of the coal reservoir pore connectivity and permeability was completed. The study results are significant for the exploration and development of coalbed methane in the Huainan-Huaibei coalfield.

Paleotectonic Stress and Present Geostress Fields and Their Implications for Coalbed Methane Exploitation: A Case Study from Dahebian Block, Liupanshui Coalfield, Guizhou, China

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.

The geological factors affecting gas content and permeability of coal seam and reservoir characteristics in Wenjiaba block, Guizhou province

The gas content and permeability of coal reservoirs are the main factors affecting the productivity of coalbed methane. To explore the law of gas content and permeability of coal reservoirs in the Zhijin area of Guizhou, taking No.16, No.27 and No.30 coal seams in Wenjiaba mining area of Guizhou as the engineering background, based on the relevant data of coalbed methane exploration in Wenjiaba block, the geological structure, coal seam thickness, coal quality characteristics,coal seam gas content and permeability of the area were studied utilizing geological exploration, analysis of coal components and methane adsorption test. The results show that the average thickness of coal seams in this area is between 1.32 and 1.85 m; the average buried depth of the coal seam is in the range of 301.3–384.2 m; the gas content of No.16 and No.27 coal seams is higher in the syncline core. The gas content of the No.30 coal seam forms a gas-rich center in the south of the mining area. The buried depth and gas content of coal seams in the study area show a strong positive correlation. Under the same pressure conditions, the adsorption capacity of dry ash-free basis is significantly higher than that of air-dried coal. The permeability decreases exponentially with the horizontal maximum principal stress and the horizontal minimum principal stress. The horizontal maximum primary stress and the flat minimum prominent stress increase with the increase of the buried depth of the coal seam. The permeability and coal seam burial depth decrease exponentially. This work can provide engineering reference and theoretical support for selecting high-yield target areas for CBM enrichment in the block.

Experimental investigation of the effects of long-period cyclic pulse loading of pulsating hydraulic fracturing on coal damage

Coalbed methane recovery can largely ease the crisis of annually increasing energy consumption of China. Low permeability and porosity of deep coal reservoirs mainly cause the low gas production rate. Pulsating hydraulic fracturing (PHF) is an alternative tool to improve the reservoir permeability and stimulate the gas productivity. However, little has been done to directly observe the fatigue damage in coal created by the pulsating loading. Because the fatigue damage is primarily governed by the time-length of PHF period. Therefore, the effect of long period pulsating loading of PHF on coal damage has been investigated in this work. Results show that long-period pulsating loading of PHF can cause significant damage in coal. The low-field NMR data indicates coal porosity increases with the increase of maximum pulsating pressure. Pulsating pressure also plays an important role in the cracking pressure. A larger pulsating pressure leads to a lower cracking pressure. Comparison of PHF and HF damaged coal investigated by the X-ray CT indicates the PHF creates more fractures and higher porosity than conventional hydraulic fracturing. The increase ratios of the coal porosity by HF and PHF are 40 %–60 % and 80 %–100 %, respectively. This paper provides a better understanding the mechanism of the coal damage by the PHF under long-period pulsating loading which is of great importance for optimizing PHF technique and generating connected fracture networks.

Fluid seepage mechanism and permeability prediction model of multi-seam interbed coal measures

The successful development of coal measure gas (CMG) in the Surat Basin in Australia shows that the geological conditions of thin-interbed CMG development may be more favorable, but the above understanding is still in the geological law summary level. This study combines numerical simulation and physical simulation experiments to study the core geological problems of CMG in the geological control of the permeability of a multi-thin coal seam composite reservoir (MTCCR). The results show that in the initial stage of stress loading, the permeability advantage of the coal-mudstone/sandstone composite reservoir is reflected in the bedding permeability. Based on this phenomenon, the concept of “cross-layer seepage effect of fluid in MTCCR” is proposed for the first time, which is analyzed as the result of the permeation effect of adjacent rock fluids in the composite reservoir under the action of pressure difference. The numerical simulation shows that the permeability increase of the MTCCR depends on the increase in the fracture, and the coupling effect of the fracture and pore changes the fluid pressure field and seepage mode around the fracture. From the experimental perspective, the above understanding confirms the results of previous conclusions on the geological law of high permeability of MTCCR, and explains the geological phenomenon of high permeability of MTCCR from the seepage mechanism. Based on numerical and physical simulation experiment, a sedimentation-tectonics controlled permeability prediction model was constructed. The seepage mechanism and the permeability prediction model established of MTCCR in this study can provide theoretical support and quantitative basis for the selection of high permeability zones and evaluation of high permeability sections in the exploration and development process of thin interbed CMG.

Experimental Investigation on the Impact of Coal Fines Migration on Pores and Permeability of Cataclastic Coal.

During the production process of coalbed methane, the generation and migration of coal fines can obstruct fractures in coal reservoirs and reduce their permeability. In order to investigate the effects of coal fines migration on the porosity and permeability of coal reservoirs, we conducted core water flooding experiments, low-field nuclear magnetic resonance (NMR), and low-temperature N2 adsorption experiments to study the variations in porosity and permeability of cataclastic coal during coal fines migration and the impact of coal fines migration on porosity and permeability. The experimental results reveal that the initial porosity ratio of cataclastic coal exhibits the characteristics of micropore > macropore > transitional pore > mesopore, with the pore types being predominantly fissured. The porosity of pores larger than 1000 nm and those larger than 10,000 nm exhibit consistent trends before and after water flooding, indicating that the blockage or unblocking of pores with radius larger than 10,000 nm by coal fines can also cause blockage or unblocking of some interconnected macropore. The early stage of flooding is the main period for coal fines migration and production in cataclastic coal, during which the mass concentration of coal fines production is higher and some macropores and fractures become blocked, resulting in a larger decrease in porosity. The higher the initial permeability of cataclastic coal samples with a larger end-face fracture density, the more similar the variations in porosity and permeability of pores larger than 10,000 nm during the flooding experiment, indicating that coal fines mainly block interconnected pores and fractures with radius larger than 10,000 nm through migration, thereby reducing permeability. This study provides a theoretical basis for the efficient production of coalbed methane.

Changing Law of Permeability of Coal Reservoirs under Variable Pressure Conditions and Its Influence on Extraction Efficiency of Coalbed Methane

Coal permeability data are critical in the prevention and control of coal and gas outbursts in mines and are an important reservoir parameter for the development of coalbed methane. The mechanism by which permeability is affected by gas pressure is complex. We used a self-developed true triaxial seepage experimental device that collects lignite and anthracite coal samples, sets fixed axial pressure and confining pressure, and changes gas pressure by changing the orientation of the coal seam to study the influence of the gas pressure on the permeability of the coal seam under the conditions of different coal types and different bedding orientations. Coal permeability decreased rapidly and then decreased slowly and tended to be stable with the increase in gas pressure. This conformed to the power exponential fitting relationship, and the fitting degree reached more than 99%. The comparison of the two anthracite coal samples showed that the sample’s permeability with a bedding plane vertical to the seepage direction was significantly lower than that of the bedding plane parallel to the seepage direction, indicating that gas seeped more easily along the bedding. The sensitivity coefficient of permeability with the change in gas pressure was calculated. The analysis showed that coal permeability was sensitive to changes in gas pressure during the low-pressure stage. When the gas pressure was greater than 0.8 MPa, the sensitivity coefficient was significantly reduced, which may have been related to the slow increase in the amount of gas absorbed by the coal seam in the high-pressure stage. A theoretical calculation model of coal seam permeability considering adsorption/desorption and seepage effects was proposed and then verified with experimental results showing that the theoretical model better reflected the permeability characteristics of coal and predicted its permeability. Using the finite element simulation software COMSOL, the extraction efficiency of the coal seam gas under different gas pressure conditions was simulated. The results showed that coal permeability and extraction efficiency decreased with an increase in gas pressure. In the low-pressure stage, the reduction in the extraction efficiency was more evident than that in the high-pressure stage.

Characteristics and Geological Impact Factors of Coalbed Methane Production in the Taiyuan Formation of the Gujiao Block

The coalbed methane resources of the Gujiao Block are abundant, and the exploration degree is high. The gas production and water production of different CBM (coalbed methane) wells vary greatly. The average gas production of CBM wells in the study area is mostly less than 1000 m3/d, while the average water production is mostly less than 5 m3/d. The gas production of CBM wells near the core of the Malan syncline is relatively high. A series of large faults exist in the central and eastern parts of the study area, and CBM wells nearby produce more water but less gas. The salinity of water discharged from CBM wells ranges from 810.34 to 3115.48 mg/L, which is consistent with the trend of a gradual increase from north to south. The gas content distribution follows this same gradually increasing north to south trend. Coal thickness and buried depth have little effect on gas production, but have some effects on water production. The endogenous fracture system in the coal reservoir is extremely developed and the porosity and permeability of the reservoirs are low, which is not conducive to the migration and recovery of coalbed methane. The adsorption capacity of the coal sample is strong. However, the continuous uplift and denudation of the stratum from the middle Yanshanian to the Himalayan region are not conducive to the preservation and enrichment of coalbed methane. In addition, a series of large faults exist in this area, and the coal structures are broken. A large amount of coalbed methane is continually being released. Generally, structural and hydrological conditions affect the porosity, permeability, and gas content of coal reservoirs, thereby affecting the productivity of coalbed methane wells. The comprehensive analysis shows that the Xingjiashe well field in the southern part of the study area is a favorable area for CBM exploration and development.

Elucidation of evolutionary characteristics of pore structure in anthracite through microwave-LN2 freeze–thaw cycling

Coalbed methane (CBM) extraction has been restricted by low permeability. Liquid nitrogen fracturing has been proven to be a valid method for ameliorating the condition of coal reservoirs. Microwave-liquid nitrogen (LN2) cyclic processing (MLCP) may be a potentially viable technology to increase the coal reservoir permeability. Therefore, this study conducted an analysis of the pore structure and surface morphology of single-mode processing coal (SPC) and MLCPC based on LT-N2GA and SEM. The results indicate that maximum N2 adsorption capacity and the frequency of cycles for both meso- and macropores volume of the cycles coal samples are positively correlated, and the effects are more significant than that of the SPC. Moreover, the fractal dimension D2 tended to increase and then decrease as the cycles deepened. This means that MLCP destroys the pore structure at the beginning of the cycle. When the frequency is exceeded the cycle threshold (n > 20), it will promote the development and fusion of micro- and mesopores to simplify the pore structure. After 30 freeze–thaw cycles, the TPV increased by 242.2%, and isolated pores were penetrated. The study provides essential theoretical support and a scientific basis for the engineering application of MLCP.

Coalbed methane accumulation, in-situ stress, and permeability of coal reservoirs in a complex structural region (Fukang area) of the southern Junggar Basin, China

The enrichment of coalbed methane (CBM), in-situ stress field, and permeability are three key factors that are decisive to effective CBM exploration. The southern Junggar Basin is the third large CBM basin in China but is also known for the occurrence of complex geological structures. In this study, we take the Fukang area of the southern Junggar Basin as an example, coalbed methane accumulation and permeability, and their geological controls were analyzed based on the determination of geological structures, in-situ stress, gas content, permeability, hydrology and coal properties. The results indicate that gas contents of the Fukang coal reservoirs are controlled by structural framework and burial depth, and high-to-ultra-high thickness of coals has a slightly positive effect on gas contents. Perennial water flow (e.g., the Baiyanghe River) favors gas accumulation by forming a hydraulic stagnant zone in deep reservoirs, but can also draw down gas contents by persistent transportation of dissolved gases to ground surfaces. Widely developed burnt rocks and sufficient groundwater recharge make microbial gases an important gas source in addition to thermogenic gases. The in-situ stress field of the Fukang area (700–1,500 m) is dominated by a normal stress regime, characterized by vertical stress > maximum horizontal stress > minor horizontal stress. Stress ratios, including lateral stress coefficient, natural stress ratios, and horizontal principal stress ratio are all included in the stress envelopes of China. Permeability in the Fukang area is prominently partitioned into two distinct groups, one group of low permeability (0.001–0.350 mD) and the other group of high permeability (0.988–16.640 mD). The low group of permeability is significantly formulated by depth-dependent stress variations, and the high group of permeability is controlled by the relatively high structural curvatures in the core parts of synclines and the distance to the syncline core. Meanwhile, coal deformation and varying dip angles intensify the heterogeneity and anisotropy of permeability in the Fukang area. These findings will promote the CBM recovery process in China and improve our understanding of the interaction between geological conditions and reservoir parameters and in complex structural regions.

Investigation of cleat and micro-fracture and its aperture distribution in the coals of different ranks in North China: Relative to reservoir permeability

The apertures of cleats and micro-fractures in coal play an important role in the permeability of the coal bed. In this study, optical microscopy and scanning electron microscopy were used to investigate the morphology of cleats and micro-fractures and their apertures, distribution of minerals, and matrix/fracture interactions. The neighboring mineralized and unmineralized cleats suggest the possibility of multi-stage evolutionary processes of cleat formation during the coalification process. The micro-fracture distribution of coals is closely related to their components, including organic macerals and inorganic minerals. Micro-fractures are prone to developing at the junction surface of organic macerals or the surface of organic and inorganic minerals. A mineral-genetic micro-fracture can be classified as an intra-crystal micro-fracture, an extra-crystal micro-scale fracture, or a grain-edge micro-scale fracture. Compared with the low- and middle-ranking coals, cleat and micro-scale fractures in high-ranking coal are usually filled with carbonate minerals and clay minerals. Statistical analysis reveals that the aperture distribution of cleat and micro-fracture in coal shows a log-normal distribution. The aperture of cleat and micro-fracture shows a decreasing trend with increase in coal rank. For low-ranking coal, cleats contribute more to the permeability than micro-fractures. However, for the middle- and high-ranking coals, the contribution of cleats and micro-fractures to the coal reservoir permeability will be close. As the rank of coal increases, the degree of cleat contribution to reservoir permeability decreases, while the degree of micro-fracture contributing to the reservoir permeability increases. Possible reasons for the extremely low reservoir permeability in China may be the following: 1) subsurface cleats and micro-fractures close their apertures significantly due to the in situ geo-stress or 2) cleats and micro-fractures have better permeability in the geological history, which makes the precipitation of minerals decrease the coal reservoir permeability. Therefore, the acid solvent (e.g., HAc, HCl, and HF) added to the drilling or hydraulic fracturing fluid or the geo-stress relief technologies may be an effective way of enlarging the cleat or micro-fracture aperture and enhance the reservoir permeability for coalbed methane production.

Characteristics of in situ stress field of coalbed methane reservoir and its influence on permeability in western Guizhou coalfield, China

In-situ stress is an important indicator for the preferential selection of coalbed methane (CBM) exploration dessert zones, and is a key factor affecting the production capacity of coalbed methane wells. Coal reservoir permeability is one of the key parameters to evaluate the recoverability and modifiability of coalbed methane and reflects the seepage capacity of coal reservoirs. In this study, in situ stress data were collected from multiple injection/fall-off tests of multiple parameter wells in western Guizhou province, China The relationships among parameters such as pore pressure (Pp), closure pressure (Pc), breakdown pressure (Pb), in situ stress, coal permeability, and depth were explore. Using Anderson’s classification method, the distribution of three different in situ stress states was counted. A new simplified model diagram of triaxial principal stress and depth in the study area is proposed by linearly fitting the triaxial principal stress and burial depth. The envelope equation and median equation of the lateral pressure coefficient k-value stress ratio with depth of burial obtained by Brown and Hoek method were calculated using hyperbolic regression algorithm. The k-values were found to be discrete at shallower depths and converge at deeper depths, gradually converging to .65. The control of in situ stress on the permeability of coal reservoirs was explored, and a strong positive correlation was found between the permeability and the Z-shaped variation of the lateral pressure coefficient k-values at shallow depths of 1,000 m. Also, the distribution pattern of vertical permeability basically corresponds to the stress transition zone from the strike-slip fault mode to the normal fault mode. The coal seam permeability has a strong sensitivity to effective in situ stress (EIS). In this study, the least squares method with multiple fitting of power exponents is applied to analyze the control mechanism of EIS on permeability in depth and reveal a new relationship between permeability and EIS that is different from that considered by previous authors. Summarizing the above research results, the vertical CBM in western Guizhou is divided into three development potential zones, and 400–1,000 m burial depth is the most favorable vertical development zone.

In situ stress variation and coal reservoir permeability response of the Jurassic Yan'an formation in the southwestern Ordos basin, China: Its impact on coalbed methane development

The in situ stress (ISS) and permeability determine the coalbed methane (CBM) development method and extraction efficiency to a certain extent. Based on the data of the CBM well test and microseismic monitoring in the Jurassic Yan'an Formation, a prediction model of the ISS is established, and its influence on permeability and CBM development in the southwestern Ordos Basin, China, is discussed. The results show that the orientations of maximum principal stresses (Shmax) in the study area's eastern, central, and western parts are NE–SW, SEE–NWW, and NNW–SSE, respectively. With the increased burial depth, the main ISS parameters show an S-shaped variation. The study area's ISS state can be divided into Shmax > vertical stress (Sv) > horizontal minimum principal stress (Shmin) (<420 m), Sv > Shmax > Shmin (420 m–800 m), and Shmax ≈ Sv > Shmin (>800 m), and the transformation depth of the ISS field is 550 m and 1000 m. The lateral pressure coefficients (λ) ranged from 0.30 to 1.19, with an average of 0.69. The λ, Shmax/Shmin and Shmin/Sυ of the stress field are small, which indicates that the horizontal tectonic stress is weak. The coal reservoir's permeability is distributed between 0.0084 and 6.84 mD (av. 1.13 mD). Affected by the variation of the ISS state in the vertical direction, the coal reservoir permeability shows obvious zoning. The tensile stress field is beneficial to high-permeability coal reservoir formation, but it is constrained by the coupling constraints of a coal reservoir's confining pressure and effective stress. The coal reservoirs are in a normal fault stress state, which is beneficial for improving their hydraulic fracturing effect. Since the Shmin in the study area is always smaller than the Sυ, the height of the fracturing fracture should be controlled in the fracturing of the coal reservoir to avoid the overlying aquifer being connected by fracturing fractures. The above new insights have important guiding significance for the hyperpermeability CBM reservoir prediction, well-bore structure and hydraulic fracturing design in the Ordos Basin.

Experimental study on water saturation effect on coal sample permeability under different effective stresses

During the drainage and production of coalbed methane (CBM) wells, the constant changes in stress and water saturation of reservoir restrict the dynamic change of the reservoir permeability. By carrying out stress sensitivity experiments with different water saturations in coal, the correlation between permeability and the coupling of effective stress and water saturation was analyzed. The water saturation sensitivity and stress sensitivity of reservoir were evaluated by the stress sensitivity index (S), permeability damage rate (PDR), and stress sensitivity coefficient (αk), and the change law of coal permeability under different stresses with different water saturations was revealed. The results showed that the coal reservoir permeability decreased with increasing stress following a negative exponential function and decreased nearly linearly with increasing water saturation. In addition, the coal water saturation sensitivity was positively correlated with effective stress, and the coal stress sensitivity was positively correlated with water saturation. Finally, a mathematical model for predicting coal permeability that considered the impacts of water saturation and effective stress was established, revealing the controlled mechanism affecting the permeability change.