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The successful commercial development of high-quality middle-shallow and middle-deep shale gas in the Sichuan Basin marks a significant achievement. With the escalating energy demand, attention has shifted toward exploring and exploiting deep-buried, low-quality middle-shallow, and middle-deep shale gas reservoirs in China. This shift necessitates advancements in geological evaluation and engineering design. Here, the key issues related to sweet spot identification in shale gas reservoirs are introduced, and three correlated parameters (gas-in-place, microstructure, and permeability) are concisely overviewed. Numerous efforts and advances have been dedicated to characterizing these parameters in recent years, attempting to reveal the underlying mechanisms and identify the appropriate evaluation methods. However, challenges persist, and potential improvement opportunities are outlined here to provide insights for researchers.

In the calculation of shale gas resources/reserves, isothermal adsorption parameters are mainly determined by dry sample data at the laboratory temperature, and the regression effect of total organic carbon content (TOC) isothermal adsorption parameters is poor. Based on the physical significance of key parameters in Langmuir and Henry adsorption models, the problems in determining the isothermal adsorption parameters in the calculation of shale gas reserves/reserves are analyzed by taking the marine shale in the Upper Ordovician Wufeng Forming–Lower Silurian Longmaxi Formation in the Sichuan Basin as an example. Based on a large number of measured isothermal adsorption data, the effects of TOC, temperature and water saturation on the shale gas adsorption parameters are analyzed. The influence model of TOC, temperature and water saturation on isothermal adsorption parameters of shale gas is established, and a novel method for calculating the adsorption parameters of shale gas from under experimental conditions to original reservoir conditions is proposed. The results are obtained as follows. First, there are problems in the calculation of shale gas resources/reserves, such as poor and contradictory fitting relation between isothermal adsorption parameters and TOC, difficulty in the conversion of Van't Hoff equation, and difficulty in direct application of water saturation (Sw) in resource/reserves calculation. Second, the problem of poor direct fitting relation between Langmuir pressure (pL) and TOC is solved by integrating the Langmuir adsorption model with the Henry adsorption model and by establishing a new parameter – Henry constant a for methane adsorption capacity of shale. Third, when Sw30 MPa), the effect of Sw on the methane adsorption capacity of shale shows a similar trend, and the effect of water molecules on the adsorption capacity on shale pore surface is constant. It is concluded that the proposed novel method for determining the isothermal adsorption parameters of shale with different TOC, temperature and water saturation conditions provides a technical support for the accurate calculation of shale gas resources/reserves and contributes to the scientific development of shale gas industry.

In 2012, China's first national shale gas demonstrations areas were set up in the Sichuan Basin. After 10 years' construction and practice, the giant marine shale gas area of 10 × 1012 m3 level is built up in the Sichuan Basin, and shale gas steps into a new stage of large-scale benefit exploration and development. In order to systematically summarize the achievements in shale gas exploration and development and provide guidance and reference for the exploration and development of deep shale gas and shale oil & gas in other areas, this paper systematically summarizes the main characteristics, development models and key identification and evaluation technologies for quality reservoirs of Wufeng Formation–Longmaxi Formation shale gas by analyzing the electric property, lithofacies, reservoir parameters and microscopic porosity of key wells in the basin. And the following research results are obtained. First, biogenetic siliceous shale, calcareous shale and mixed shale are main lithofacies types in quality shale gas reservoirs, and they are formed in the environment of semi-deep and deep water continental shelf. Their lateral distribution is controlled by the paleogeomorphology and their vertical development is influenced by provenance, redox condition and paleo productivity. They are 25–90 m thick. Second, in the quality shale gas reservoirs develop organic pores, inorganic pore and microfractures (including lamina/bedding fractures), among which, organic pore is one of the main reservoir spaces and microfracture is not only indispensable reservoir space, but also production pathway. The reservoir space of shale gas is overall micro-nano pore, and macropores play an important role in shale gas enrichment. Third, three development models of quality reservoir are established, including sedimentary type, diagenesis type and reworking type. The sedimentary type is the foundation. Multiple quality reservoirs are developed in the high U/Th interval of graptolite belt at the bottom of Longmaxi Formation, and their thickness is mainly controlled by paleogeomorphology and especially greater in the depression area. The diagenesis type is divided into three forms, i.e., syngenetic-early diagenetic rigid support, middle-late diagenetic mineral-organic matter transformation, and overpressure relief compaction. The reworking type is dominated by quality reservoirs with microfractures. Fourth, the core technologies for identifying and evaluating quality shale gas reservoir include large-size core and rock slice observation, high-accuracy rock mineral identification, experimental gas content test and simulation, SEM microscopic characterization, 3D microscopic pore reconstruction, comprehensive geophysical interpretation and prediction and big data analysis. In conclusion, nearly 10 years' research and practice achievements in demonstration area construction can deepen the understanding on domestic quality shale gas reservoirs, promote the effective development of the theories and technologies related to shale gas reservoirs, improve the prediction accuracy of shale gas sweet spot zones/intervals, and expand the shale gas exploration and development achievements of demonstration areas.

To efficiently develop deep shale gas in southern Sichuan Basin, under the guidance of “extreme utilization” theory, a basic idea and solutions for deep shale gas development are put forward and applied in practice. In view of multiple influencing factors of shale gas development, low single-well production and marginal profit of wells in this region, the basic idea is to establish “transparent geological body” of the block in concern, evaluate the factors affecting shale gas development through integrated geological-engineering research and optimize the shale gas development of wells in their whole life cycle to balance the relationship between production objectives and development costs. The solutions are as follows: (1) calculate the gold target index and pinpoint the location of horizontal well drilling target, and shale reservoirs are depicted accurately by geophysical and other means to build underground transparent geological body; (2) optimize the drilling and completion process, improve the adaptability of key tools by cooling, reducing density and optimizing the performance of drilling fluid, the “man-made gas reservoir” is built by comprehensively considering the characteristics of in-situ stress and fractures after the development well is drilled; (3) through efficient management, establishment of learning curve and optimization of drainage and production regime, the development quality and efficiency of the well are improved across its whole life cycle, to fulfil “extreme utilization” development of shale gas. The practice shows that the estimated ultimate recovery of single wells in southern Sichuan Basin increase by 10%-20% than last year.

Deep shale gas (3500–4500 m) is the important replacement field of shale gas production growth in the future China. The research on key parameters of deep shale-gas reservoir is critical to determine its basic geological characteristics and establish a suitable development mode. In order to clarify the adsorption characteristics and controlling factors of deep shale gas in Longmaxi Formation, the main tests such as high-pressure methane adsorption, low-temperature nitrogen and carbon dioxide adsorption coupled with the adsorption fitting model and comparative analysis were conducted. The results show that the adsorption isotherms of deep shale gas also have a downward trend in spite of the higher pressure, and there is no obvious difference in adsorption characteristics, which is mainly due to the similar characteristics of microscopic pore-structure between deep shale and shallower shale. It is found that different adsorption models can well fit the experimental adsorption curve of deep shale gas, but the absolute adsorption capacity converted from excess adsorption capacity shows the same fitting result, i.e., DA-LF model > DR model > Langmuir model. Furthermore, DR model based on micropore filling theory is more suitable for characterizing the adsorption law of deep shale gas combined with the correlation analysis between pore structure and adsorbed-gas capacity. In addition, TOC is the key material factor controlling the adsorption capacity, and specific surface area of micropore is the key spatial factor. Compared to shallower shale, the deep shale shows higher siliceous content, lower calcite content, lower TOC content and lower adsorbed-gas content (the proportion of adsorbed-gas is about 30%).

Marine deep shale gas represents the main target of future shale gas development in China. In order to identify the key parametric characteristics of deep shales, a comprehensive test method and application study was carried out based on LF-NMR technology. The results show that the NMR T2 spectrum of shales varied considerably in different states. A new NMR porosity and water saturation test method based on three-time measurements was established. The relative error between corrected NMR and water immersion porosity is reduced from 49.97% to 6.66%, while that between corrected NMR and weighing water saturation is reduced from 32.15% to 6.85%. By testing key parameters such as free water quantity, adsorbed water quantity, and average adsorption thickness, the NMR surface relaxivity of shale is determined and used to transform NMR T2 spectrum into pore size distribution. The NMR T2 spectra of individual sublayers also differ significantly. In order to quantitatively describe the distribution of spectral peaks, a new reservoir evaluation parameter, T2 geometric mean value (T2g), is proposed. Larger T2g values signify larger pores, broader average pore size distribution, and higher fluid mobility. With this parameter, qualitative description of pore size distribution can be transformed into quantitative characterization. When evaluating shale gas reservoirs, it is important to use multiple key parameters, among which NMR test results are an important indicator. LF-NMR testing is uniquely superior over other test methods as one or more NMR tests can provide abundant parametric information. The presented comprehensive NMR test method offers useful theoretical references for furthering the development and application of this technology in shale gas research.

Deep shale gas reservoir (3,500 ∼ 4,500 m) of Wufeng–Longmaxi Formation in southern Sichuan Basin in China has great potential for exploration and development, with resource of 16.31 × 1012 m3, counting 84% of the total resources in this area. And the deep shale gas wells in Luzhou and west Chongqing have achieved good development results in the past two years. We systematically summarized the geological characteristics of deep shale gas reservoir of Wufeng–Longmaxi Formation, and discussed the facing challenges and proposed some corresponding strategies. The deep shale gas reservoir in southern Sichuan Basin has six major characteristics. The reservoir is concentrated in depositional center and deep-water shelf environment. The reservoir is rich in silica and organic carbon while low in calcium and clay. Organic pores, inorganic pores, and microfractures are developed and well interconnected to form networks. Surface porosity is generally > 5% and increasing with depth. The gas content is 4.7 ∼ 7.5 m3/t, higher than that in Changning, Weiyuan, and Zhaotong area. The deep shale gas pressure coefficient is greater than 2.0 and is the highest in the southern Sichuan Basin, indicating its best preservation condition. Up to now, deep shale gas exploration is still encountered with many problems and challenges, including great difficulty in accurately obtaining reservoir parameters, unclear of high production mechanism, urgent need for optimal and quick drilling technology, great difficulty in reservoir fracturing, and unclear of hydro-fracture expansion rules. We proposed two strategies corresponding to the challenges, including deepen the delicate reservoir evaluation and clarify the rules of high production and enrichment of shale gas wells, and strengthen field experiments and explore effective and applicable technologies for drilling and fracturing of deep shale gas in China.

Porosity is a key parameter in shale gas reservoir evaluation and reserve calculation and its accurate test is the basis for calculating geological reserves of shale gas and determining development plans. In order to clarify the differences between different porosity test methods and their influences on the calculation results of shale gas reserves, we collected 65 shale samples of Lower Silurian Longmaxi Formation from six shale gas wells in the Zhaotong National Shale Gas Demonstration Area of the southern Sichuan Basin for comparative experiments using three porosity test method, including gas injection porosimetry (GIP) method, water immersion porosimetry (WIP) method and nuclear magnetic resonance (NMR) method. Then, these three methods were comparatively analyzed based on the test results. Finally, it was proposed to optimize the key parameters of these three shale porosity test methods. And the following research results were obtained. First, in terms of the GIP method, the particle size of shale sample shall be in the range of 20–60 mesh and the helium saturation equilibrium time shall be over 1800 s. Second, in terms of the WIP method, the sample shall be dried for at least 48 h under 110 °C and saturated for 24 h under the confining pressure of 15 MPa. Third, in terms of the NMR method, NMR porosity calculation shall not be conducted until the NMR signal of the dried sample is deducted, on the basis of echo time and waiting time optimization. Fourth, porosity average and median value obtained by these three shale porosity test methods follow the relationship of WIP porosity > NMR porosity > particle GIP porosity > plunger GIP porosity. Fifth, different shale porosity test methods have greater influences on the calculation results of shale gas geological reserves, whose difference can reach 20%. In conclusion, during the application of NMR method and WIP method, fluid is introduced for saturation, which may damage the shale pores. However, the particle GIP porosity can reflect the entire space of shale more comprehensively and is not influenced by the properties of the applied fluid. Therefore, it is suggested to adopt the particle GIP method to calculate shale gas geological reserves.

This study focuses on the organic-rich mud shale in the Upper Palaeozoic transitional facies in the southeastern margin of the Ordos Basin. It systematically analyzes the shale gas accumulation conditions of the organic-rich mud shale in the Lower Permian Shanxi-Taiyuan Formation, including the thickness, distribution, organic matter type and content, thermal maturity, reservoir space, gas-bearing property, and rock brittleness. The results show that the thick dark mud shale contains a high organic matter content, is a suitable kerogen type for gas generation, and exhibits moderate thermal evolution, providing excellent conditions for hydrocarbon accumulation. Residual primary pores formed by shale compaction, secondary pores formed by organic matter hydrocarbon generation, clay mineral transformation and dissolution, and fractures provide suitable reservoir spaces for shale gas. The shale in the study area has a higher gas content than the shale strata in the marine basins of the United States. In addition, the content of brittle minerals such as quartz is higher, and Poisson’s ratio is lower, facilitating the subsequent transformation. The accumulation conditions indicate the high potential of the study area for shale gas exploration and development. The geological analogy method is used to compare the study area with five major shale gas basins in the United States. The results indicate that the shale gas resources of the Shanxi-Taiyuan Formation in the study area are in the range of 2800–3200×108 m3. The primary controlling factors affecting shale gas reservoirs in this area are the abundance of organic matter, thermal maturity, shale thickness, and quartz content. Favorable areas are predicted based on these factors.

Abstract Both of the coalbed methane (CBM) and shale gas reservoirs are dominated by nanometer‐scale pores with their nanopore structures controlling the occurrence, enrichment, and accumulation of natural gas. Low‐pressure nitrogen gas adsorption (LP‐N2GA), low‐pressure carbon dioxide gas adsorption (LP‐CO2GA), high‐pressure methane adsorption (HPMA), and field emission scanning electron microscope (FE‐SEM) experiments were conducted on 14 different‐rank coal samples and nine Longmaxi shale samples collected from various basins in China to compare their nanopore characteristics. The FE‐SEM results indicate that the pore structures of both the coal and shale samples consist of nanometer‐sized pores that primarily developed in the organic matter. The types of their isothermal adsorption curves are similar. However, the coal and shale samples possess various hysteresis loops, which suggest that the nanopores in shale are open‐plated, whereas those in coal are semi‐open. Furthermore, the specific surface area (SSA) and pore volume (PV) of the micropores in coal are much larger than those of the mesopores, with the micropore SSAs accounting for 99% of the total SSA in the coal samples. However, the micropore SSAs in the shale samples only account 42.24% of the total SSA. These different nanopore structures reflect their different methane adsorption mechanisms. The methane adsorption of coal is primarily controlled by the micropore SSA, whereas that of shale is primarily controlled by the mesopore SSA. If we use mesopore SSA to analyze its impact on methane adsorption capacity of coal and shale, it will be mismatched. However, no mismatching relationship exists between the total SSAs and adsorption capacities of coal and shale. This study highlights the controlling effect of total SSA on methane adsorption capacity.

To compare the micropore structure of marine-continental transitional shale with marine shale, organic geochemical, field emission scanning electron microscopy, and low-temperature nitrogen adsorption experiments were conducted on shale samples from the Shanxi Formation in the eastern Ordos Basin and the Longmaxi Formation in the southern Sichuan Basin. The results show that Shanxi Formation shale has a smaller specific surface area and pore volume than Longmaxi Formation shale; therefore, the transitional shales fail to provide sufficient pore spaces for the effective storage and preservation of natural gas. Both the transitional and marine shales are in an overmature stage with high total organic carbon content, but they differ considerably in pore types and development degrees. Inorganic pores and fractures are dominantly developed in transitional shales, such as intragranular pores and clay mineral interlayer fractures, while organic nanopores are rarely developed. In contrast, organic pores are the dominant pore type in the marine shales and inorganic pores are rarely observed. The fractal analysis also shows that pore structure complexity and heterogeneity are quite different. These differences were related to different organic types, i.e., type I of marine shale and type III of transitional shale. Marine Longmaxi shale has experienced liquid hydrocarbon cracking, gas generation, and pore-forming processes, providing good conditions for natural gas to be preserved. However, during the evolution of transitional Shanxi shale, gas cannot be effectively preserved due to the lack of the above evolution processes, leading to the poor gas-bearing property. The detailed comparison of the micropore structure between the transitional and marine shales is of great importance for the future exploitation of marine-continental transitional shale gas in China.

During the development of shale gas reservoirs, the mechanical parameters of shale rocks are greatly significant to guide reservoir drilling design, reservoir stimulation, scheme design, and wellbore stability evaluation. Compared with conventional gas reservoirs, the mechanical properties of shale gas reservoir are more complex and lack of the comprehensive understanding. In this study, the uniaxial and triaxial compression experiments of the Longmaxi shale in South China were conducted to understand the mechanical characteristics and damage mechanism of shale rocks. Combined with the characteristics of shale microstructure, the effects of the mechanical properties such as mineral composition, deformation, stress–strain, and fracture damage characteristics were analyzed and discussed. The results show that the stress–strain curves of shale are two main types of elastic deformation and elastic–plastic deformation. There is a significant difference in effective pressure of yield platform in different shale post-peak deformation. The effective pressure of rigid shale is 60 MPa while that of other shales is 30 MPa. With the increase of effective pressure, the increase of peak compressive strength decreases gradually, and the effect of effective pressure on compressive strength decreases gradually with the transition from the brittleness to the ductility. The higher the effective pressure of the brittleness to the ductility is, the greater the change of compressive strength with effective pressure is, and the smaller the compressive strength under low effective pressure is, the smaller the variation with pressure is. Shale rocks with relatively high brittleness under different effective pressures are mainly characterized by brittle split fracture dominated by tensile fracture, while other shales with low brittleness are dominated by single shear fracture plane.

The microstructures of shale samples before and after hydration were characterized by field emission scanning electron microscopy (FESEM), and the differences in microstructure and physical parameters of original shale samples, water saturated samples and samples with water centrifugated were examined by micro CT, porosity and permeability tests. The FESEM test shows that the hydration has no effect on the main morphology, position and pores of organic matter (OM). Hydration can increase the number and width of fractures in shale, including generation of new fractures and extension of existent fractures between inorganic minerals and width increase of fractures between banded organic matter and inorganic minerals. Micro CT results of samples with different water saturations show that the intensity of hydration is dominated by primary fracture development, in other words, the more developed the primary fractures of the shale, the stronger the hydration will be. The width of fractures increased two to five times by intense hydration. The porosity of shale is mainly controlled by organic matter content and secondly influenced by the fracture development. The permeability of shale is mainly affected by fracture development and secondly by the porosity. The fracture development influenced both porosity and permeability, but more strongly on permeability than porosity. Key words: shale, hydration, microstructure, physical parameters, fracture, pore

Studies on the origin of shale brittleness are of great significance to understanding shale gas accumulation laws. The current studies, however, mostly focus on the improvement of shale brittleness by biological quartz enrichment, but rarely on the recrystallization of quartz in the process of diagenetic evolution. In this paper, a series of researches were carried out on the Lower Silurian Longmaxi Fm marine shale in the Changning block of the Sichuan Basin. Firstly, shale pore, mineral component and bedding characteristics were observed by means of cathodoluminescence (CL), scanning electron microscope (SEM) and so on. Then, the control effects of quartz origin, overpressure environment and diagenetic evolution on shale brittleness were investigated by analyzing the mineral composition and siliceous composition of shale microscopically. Finally, the authigenic embrittlement model of marine shale was put forward and the geological significance of authigenic microcrystalline quartz to the improvement of shale brittleness in the process of diagenesis was illustrated. The following results were obtained. First, during the sedimentation, burial and diagenetic evolution, shale experiences diagenetic changes which help increase quartz content and form concealed fracture networks, thus benefiting the formation of complex flow pathways in later stimulation. Second, organic matters play a positive role in improving shale brittleness in the process of geological evolution. It promotes the formation of authigenic microcrystalline quartz and improves the brittleness of shale. In conclusion, due to the authigenic embrittlement of shale in the process of diagenesis, rock structure is changed, rock strength is enhanced and shale porosity is preserved. Consequently, reservoir space in shale is improved and the enrichment state of shale gas is modified. Therefore, the preservation condition under the control of tectonic movement factors is vital to geological evaluation on shale gas. In addition, marine shale is certainly well brittle after authigenic embrittlement in the process of diagenesis as long as its organic matter content is abundant. Keywords: Marine shale, Quartz, Recrystallization, Authigenic embrittlement, Concealed fracture network, Brittleness improvement, Sichuan Basin, Changning block, Early Silurian, Longmaxi Fm

The graptolitic shale of the Wufeng–Longmaxi Formations is widely deposited across the Ordovician and Silurian transition in South China, which is the target of shale gas exploration and development within China. The contribution of graptolites to organic enrichment and reservoir of gas shale is discussed below based on the statistics of nearly 1000 shale samples from the Wufeng Formation and the bottom part of the Longmaxi Formation in the southern and northern margins of the Yangtze plate. The assessment involves graptolites abundance, the total organic carbon (TOC) content analyses, and the different scales of scanning electron microscopy analyses of related samples. The TOC content of the Wufeng–Longmaxi graptolitic shales (including graptolites and non-graptolites, i.e., the host shale) is mainly controlled by that of its host shale, while less affected by the graptolites abundance, indicating that the graptolites barely influence the organic enrichment. Graptolites consist of a large number of organic matter with reticular biological tissue structure; they account for 20%–50% of the graptolitic area. The aforementioned also developed honeycomb-shaped pores with pore sizes ranging 110 nm-1.7 μm (an average of about 500 nm), which are higher than those of the organic pores in the host shale (108–770 nm, average 330 nm), proving that graptolites have an important contribution to shale gas storage space. Since there are a large number of graptolites within the shales from the Wufeng Formation and the bottom part of the Longmaxi Formation, the laminated and stacked local pattern of their distribution provides abundant storage space for shale gas. Moreover, the feature also serves as the predominant channel for shale gas flow. Therefore, the widely developed graptolites should be considered as one of the essential factors controlling enrichment and high productivity of shale gas in the Wufeng–Longmaxi Formations. Keywords: Shale gas, Graptolites, Longmaxi formation, Organic pore, Organic enrichment, Reservoir, Sichuan basin

In the Carboniferous–Permian period, several organic-rich black shales were deposited in a marine–continental transitional environment in the Linfen area on the eastern margin of the Ordos Basin. Integrated sedimentological and organic geochemical analyses are performed on an outcrop in order to clarify the relationship between paleoenvironment and organic matter accumulation. The results of this study show that the marine–continental transitional strata of the Upper Carboniferous Benxi Formation to Lower Permian Taiyuan and Shanxi Formation exposed in the Linfen area are composed of sandstone, shale, coal, and limestone. Total organic carbon (TOC) contents of the studied samples were mainly distributed in the range of 0.59%–35.4%, with an average of 7.32%. From Benxi Formation to Shanxi formation, the humidity gradually increased, and the climate gradually changed from hot and humid to warm and humid during Carboniferous to Permian. The deposition of the Shanxi Formation ended with the climate returning to hot and humid, having an oxic-suboxic conditions and a high paleoproductivity. Paleoredox conditions and paleoproductivity are the two vital factors controlling the formation of organic matter in black shales. The transitional environment characterized by oxic-suboxic, relatively high deposition rate, and various source of organic matter, although different from the marine environment, provides a good material basis for the deposition of organic-rich shales.

The effect of clay minerals on the methane adsorption capacity of shales is a basic issue that needs to be clarified and is of great significance for understanding the adsorption characteristics and mechanisms of shale gas. In this study, a variety of experimental methods, including XRD, LTNA, HPMA experiments, were conducted on 82 marine shale samples from the Wufeng–Longmaxi Formation of 10 evaluation wells in the southern Sichuan Basin of China. The controlling factors of adsorption capacities were determined through a correlation analysis with pore characteristics and mineral composition. In terms of mineral composition, organic matter (OM) is the most key methane adsorbent in marine shale, and clay minerals have little effect on methane adsorption. The ultra-low adsorption capacity of illite and chlorite and the hydrophilicity and water absorption ability of clay minerals are the main reasons for their limited effect on gas adsorption in marine shales. From the perspective of the pore structure, the micropore and mesopore specific surface areas (SSAs) control the methane adsorption capacity of marine shales, which are mainly provided by OM. Clay minerals have no relationship with SSAs, regardless of mesopores or micropores. In the competitive adsorption process of OM and clay minerals, OM has an absolute advantage. Clay minerals become carriers for water absorption, due to their interlayer polarity and water wettability. Based on the analysis of a large number of experimental datasets, this study clarified the key problem of whether clay minerals in marine shales control methane adsorption.

The isosteric heat of adsorption (IHA) is one of the key thermodynamic variables for evaluating the interaction between shale and methane, which is rarely studied especially under high pressure. In this work, we conducted methane adsorption experiments at pressures up to 30 MPa and different temperatures on shale samples collected from Longmaxi formation in Sichuan Basin, China. Based on the definition of IHA and Langmuir adsorption model, we proposed a new method to analyze the IHA of methane on shale under four conditions. The calculated results show that the commonly used Clausius–Clapeyron equation overestimates the true isosteric heat of shale, especially under high pressure. IHA under four conditions yield a fixed order as q st,i-va > q st,r-va > q st,i+va > q st,r+va , indicating both the real gas behavior and the adsorbed-phase volume have a negative influence on it, and the effect of adsorbed-phase volume is dominant. Moreover, IHA at zero coverage ( q st 0 ) in Henry region determined by linear fitting can be regarded as a maximum value in the above four cases, which is independent of pressure and temperature. Therefore, q st 0 can be used as a unique descriptor to evaluate the adsorption affinity of the shale. This work modified the method to obtain the true IHA of supercritical methane on shale more accurately, which lays the foundation for future investigations of the thermodynamics and heat transfer characteristics of the interaction between high pressure methane and shale.

Shales in the Well district of Yu 106 of the Shanxi Formation in the Eastern Ordos Basin is deposited in the swamp between delta plains, distributary river channels, natural levee, the far end of crevasse splay, and depression environments. According to organic geochemistry, reservoir physical property, gas bearing capacity, lithology experimental analysis, combined with the data of drilling, logging, testing and sedimentary facies, the reservoir conditions of shale gas and the distribution of an advantageous area in Shanxi Formation have been conducted. The results show that the total organic carbon content of the Shanxi Formation is relatively high, with an average content value of 5.28% in the segment 2 and 3.02% in segment 1, and the organic matter is mainly kerogen type II2 and III. The maturity of organic matter is high with 1.89% as the average value of R o which indicates the superior condition for gas generation of this reservoir. The porosity of shales is 1.7% on average, and the average permeability is 0.0415 × 10 −3 µm 2 . The cumulative thickness is relatively large, with an average of 75 m. Brittle mineral and clay content in shales are 49.9% and 50.1%, respectively, but the burial depth of shale is less than 3000 m. The testing gas content is relatively high (0.64 × 10 4 m 3 /d), which shows a great potential in commercial development. The total organic carbon of the segment 2 is higher than that of the segment 1, and it is also better than segment 1 in terms of gas content. Based on the thickness of shale and the distribution of sedimentary facies, it is predicted that the advantageous area of shale gas in the segment 2 is distributed in a striped zone along the northeast and the northsouth direction, which is controlled by the swamp microfacies between distributary river channels.