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The pore structures and mechanical properties of coal are key parameters for geological evaluation of coalbed methane, reflecting its reservoir capacity and compressibility. The study investigated four coal samples from the Qinshui and Datong basins in Shanxi Province, including Jurassic coal from Datong (Ro=0.91%), No. 2 coal from the Shanxi Formation in Gujiao (Ro=1.34%), No. 8 coal of the Taiyuan Formation in Gujiao (Ro=1.70%), and No. 2 coal of the Shanxi Formation in Yicheng (Ro=1.77%). Using atomic force microscopy (AFM), a combined characterization technique was established for microscopic pore structure and mechanical properties based on image segmentation and Derjaguin-Muller-Toporov (DMT) mechanical model. This method clarified the microscopic pore structure and mechanical properties of coal samples and revealed the influence of material composition, pore structure, and thermal evolution level on their microscopic mechanical properties. The results showed that the surface porosity of coal samples mainly ranged from 2.72% to 4.60%, with an average of 3.58%. The total pore surface area and total pore volume were (3.413-5.638)×10-2 μm2/μm2 and (0.5-3.9)×10-4 μm3/μm2, respectively. The pore sizes were mainly distributed between 10-100 nm, and the Young's modulus ranged from 2.24 to 3.10 GPa, with an average of 2.77 GPa. The mechanical properties of coal were influenced by the material composition, pore structure, and thermal evolution level. As moisture decreased and volatile and mineral content increased, the Young's modulus showed an increasing trend. With an increase in surface roughness, mean pore size, porosity surface, specific surface area, and total pore volume, the Young's modulus decreased. As thermal evolution progressed, the Young's modulus decreased. AFM enables simultaneous analysis of microscopic pore structure and mechanical properties of coal, providing new methods and insights for studying reservoir capacity and mechanical behavior of coal reservoirs. It holds significant implications for the evaluation of reservoir capacity and compressibility in unconventional reservoirs.

Since 2021, China has achieved significant breakthroughs in deep coalbed methane (CBM) exploration and development, making it a strategic resource for increasing natural gas reserves and production. To further support the high-quality development of deep CBM in China, it is urgent to study the CBM resource endowments and exploration and development status in worldwide major coal-bearing basins. The exploration and development of CBM in the United States, Australia, and Canada started early, currently mainly focusing on the development of medium- to low-rank shallow CBM, characterized by shallow coal seams and high permeability, with production exceeding 10 000 m3/d using vertical wells. However, due to adjustments in oil and gas strategies, the United States and Canada no longer prioritize CBM exploration. Australia, on the other hand, experiments with combined production of coal measures, propelling it to the top of global CBM production. In China, deep CBM exploration mainly focuses on medium- to high-rank deep CBM. The coal seams are characterized by significant depth variation and low permeability. The Ordos Basin has become the largest deep CBM production base. Multiple horizontal wells in the Daning-Jixian and Daniudi gas fields produce more than 100 000 m3 of gas per day. Deep CBM exploration in the Sichuan Basin has made positive progress, and the Junggar Basin shows potential for deep CBM exploration. Experiences from CBM exploration and development shows that breakthroughs in understanding enrichment patterns, advancements in engineering technologies, integrated management models, and industry- supportive policies are important factors for the rapid development of the CBM industry. Increasing exploration efforts for different types of deep CBM, strengthening theoretical and technological research, accelerating the construction of standard systems, and enhancing industry support policies will help foster high-quality exploration and efficient development of deep CBM in China.

The relationship between fractures and gas logging in Nanchuan-Wulong area in eastern Sichuan Basin is utilized to study the identification of fractures in shale gas horizontal wells based on geological (core), imaging logging, logging evaluation, seismic prediction, and other data. First, to solve the problems of lack of core and imaging logging and difficulty in identifying natural fractures in shale gas horizontal wells, a core scale shale natural-fracture identification model is established through vertical wells from a geological perspective in this paper, and the development of high angle fractures in the core is consistent with the high values and peaks of total hydrocarbon anomalies. Second, in combination with the fracture identification mode, the fracture development section of non-coring vertical wells can be quickly and qualitatively identified at a low cost based on total hydrocarbon information. There will be a sudden increase in the total hydrocarbon value in the fracture development section, especially in the shale section with low total organic carbon (TOC). The sudden increase in the total hydrocarbon value also represents the existence of fractures. Finally, the plate method of TOC and normalized total hydrocarbon correlation is used to quantitatively identify vertical and horizontal well fracture sections without coring and imaging logging data. The area delineated by a normalized total hydrocarbon value ≥0.4 and TOC ≥0.5% are considered as the fracture development section of a horizontal well. Based on the identified horizontal well fracture section, from the perspective of geological engineering integration, it is possible to avoid or pay attention to these densely developed large or giant fractures in advance, thereby increasing the production of a single well.

Risk and uncertainty are coherent attributes in hydrocarbon play exploration, and comprehensive exploration strategy requires a deliberate consideration of risk aversion and an faithful understanding of uncertainty. According to the characteristics of SINOPEC oversea oil and gas exploration projects, as well as the exploration project evaluation criteria of international oil companies, this paper describes the establishment of value-determined standards and hydrocarbon play risk workflow by quantitative assessment of hydrocarbon generation and charge capability, reservoir quality, preservation condition, and trap validity of a play. According to data density, coverage and geological understanding, in accordance with bucket theory, the probabilities of occurrence of four risk factors were determined, and the chance of geologic success (COGS) of a play was obtained by multiplying the probabilities of each risk factor. This workflow provided a method for transferring qualitative geological understanding and exploration data to quantitatively assess the risk probability of each factors and overall COGS. The COGS values determine the play risk, which is a comprehensive reflection of the exploration phase and geological characteristics of the study block. The play risk workflow facilitates high grading areas, allows a focus on the exploratory and appraisal aspects, and provides a scientific basis for exploration investment decision.

The resource potentials for the exploration and development of tight sandstone gas, shale gas, and coalbed gas in marine-continental transitional environments are very attractive. However, previous studies have mostly focused on the geological and geochemical characteristics of marine-continental transitional shales and coals, and less attention has been paid to the associated tight sandstones. This paper takes the sandstones in the west Guizhou as an example. The Longtan marine-continental transitional tight sandstones have been investigated using various techniques (e.g., thin section, mercury injection capillary pressure, and nuclear magnetic resonance) to illustrate the reservoir characteristics. The Longtan sandstones, according to our study, are classified as litharenites, and are characterized by thin layers, high rock fragment and clay contents, abundant micropores, complex pore-throat structures, and low porosities and permeabilities. Compared with other typical tight sandstones in China, the Longtan sandstones have more lithic content and tighter pore throat structures. Therefore, tight-gas potential is interpreted to be limited in the Longtan sandstones. However, a model for the commingled production of tight-sand gas, shale gas and coalbed methane could be viable since the Longtan sandstones are interbedded with coals and shales, which provides an opportunity for unconventional gas development in marine-continental transitional environments.

Interbedded sandstones, shales, and coal seams were formed in marine-continental transitional environments of coal measures, and the gas source of its tight sand gas has been uncertain, which hinders the progress of natural gas exploration. This article uses the Longtan tight sand gas in west Guizhou as an example to investigate the reservoir features, gas charging history, and main source rock of tight sand gas by examining thin sections, scanning electron microscopy images, X-ray diffraction results, and the fluid inclusions with burial and thermal histories and noble gas analysis. The Longtan sandstones in this study are classified as litharenites which are characterized by low compositional and textural maturities, and high clay contents, and are distinguished petrographically from conventional sandstones by the extensive existence of micropores and microfractures. The results of the homogenization temperatures of the fluid inclusions show that the Longtan tight sand gas is a single-stage accumulation which occurred during the Late Triassic. Furthermore, through the analysis of the helium and argon isotopes of noble gases, a calculation model was established for determining the shale and coal contributions to the tight sand gas. The research results show that the Longtan tight sand gas mainly belongs to the crust-derived gas, mostly from the Longtan shale-derived contribution and to a lesser extent from the Longtan coal-derived contribution. The measured 40Ar/36Ar values of the Longtan shales and coals are consistent with the forecasted 40Ar/36Ar values from the calculation model, demonstrating that the model is viable to calculate the source rock contribution to the tight sand gas. Therefore, the Longtan shales as main source rocks can generate hydrocarbons to charge neighboring tight sandstones to form tight gas accumulation in the Longtan Formation, which provides an opportunity for tight gas development in west Guizhou.