Gas Reservoir Characterization Research Articles

Fractal Evolution Characteristics on the Three-Dimensional Fractures in Coal Induced by CO2 Phase Transition Fracturing

Fractal Evolution Characteristics on the Three-Dimensional Fractures in Coal Induced by CO2 Phase Transition Fracturing

Application of multicomponent seismic data to tight gas reservoir characterization: A case study in the Sichuan Basin, China

Combining PP and PS-waves from multicomponent data is an effective hydrocarbon characterization strategy because these two wave types are sensitive to different subsurface properties. We present a case study using multicomponent data to characterize tight sandstone gas reservoirs in the Jurassic Shaximiao Formation, the western Sichuan Basin, China. In the study area, PP data have difficulties to distinguish sandstones, mudstones and gas sand, while recently acquired multicomponent data show potential for the joint characterization of lithology, porosity, and gas saturation from the combination of PP and PS reflections. Sandstones and mudstones show small P-velocity contrasts and large S-velocity contrasts. Thus, PS data provide a more accurate description of sandstones as a substantial proportion of sandstones are undetectable from PP sections. P-impedance is sensitive to sandstone porosity variation, and seismic-predicted porosities based on impedance inversion are in good agreement with log-interpreted porosities. The ratio of P-velocity to S-velocity is sensitive to gas accumulation, and the ratios derived from joint PP-PS prestack inversion are determined to be better than from PP prestack inversion in terms of their agreements with logs and distinct gas-sand boundaries.

Fine quantitative characterization of high-H2S gas reservoirs under the influence of liquid sulfur deposition and adsorption

In order to clarify the influence of liquid sulfur deposition and adsorption to high-H2S gas reservoirs, three types of natural cores with typical carbonate pore structures were selected for high-temperature and high-pressure core displacement experiments. Fine quantitative characterization of the cores in three steady states (original, after sulfur injection, and after gas flooding) was carried out using the nuclear magnetic resonance (NMR) transverse relaxation time spectrum and imaging, X-ray computer tomography (CT) of full-diameter cores, basic physical property testing, and field emission scanning electron microscopy imaging. The loss of pore volume caused by sulfur deposition and adsorption mainly comes from the medium and large pores with sizes bigger than 1 000 μm. Liquid sulfur has a stronger adsorption and deposition ability in smaller pore spaces, and causes greater damage to reservoirs with poor original pore structures. The pore structure of the three types of carbonate reservoirs shows multiple fractal characteristics. The worse the pore structure, the greater the change of internal pore distribution caused by liquid sulfur deposition and adsorption, and the stronger the heterogeneity. Liquid sulfur deposition and adsorption change the pore size distribution, pore connectivity, and heterogeneity of the rock, which further changes the physical properties of the reservoir. After sulfur injection and gas flooding, the permeability of Type I reservoirs with good physical properties decreased by 16%, and that of Types II and III reservoirs with poor physical properties decreased by 90% or more, suggesting an extremely high damage. This indicates that the worse the initial physical properties, the greater the damage of liquid sulfur deposition and adsorption. Liquid sulfur is adsorbed and deposited in different types of pore space in the forms of flocculence, cobweb, or retinitis, causing different changes in the pore structure and physical property of the reservoir.

Differences in stress sensitivity of natural-artificial fracture networks in tight sandstone gas reservoirs

Abstract The stress sensitivity of fractures has a significant impact on the production characteristics of tight sandstone gas reservoirs. However, there has been a lack of attention to and research on the differences between different types of fracture and their stress sensitivity. Based on the core samples of the Keshen gas reservoir in Xinjiang, China, this paper conducts a comprehensive comparison of the flow capacity, stress sensitivity, and the production characteristics of the structural fracture, diagenetic fracture, and artificial fracture. The findings reveal that the flow capacity of a single structural fracture is higher than that of a diagenetic fracture. Additionally, both structural and diagenetic fractures contribute to increasing the flow capacity of the porous system by 63 and 88%, respectively. The stress sensitivity of fractures varies from strong to weak, structural fractures exhibit a higher sensitivity compared to diagenetic fractures, and artificial fractures demonstrate the weakest stress sensitivity. Based on the fitting formulas of stress-sensitivity curves for different fractures, a new seepage model considering different stress sensitivities was established and numerical simulations were conducted. The numerical simulation results indicate that the gas well with a diagenetic-artificial fracture network yields a higher production, the 10-year production is 35.01% higher than that with a structural-artificial fracture network. This study is of great significance for understanding the production differences of fractured tight sandstone gas reservoirs and provides valuable insights for selecting optimal well locations.

Integrated reservoir characterization of the Permo-Triassic gas reservoirs in the Central Persian Gulf

The Upper Dalan and Kangan or Permian-Triassic carbonate formations in the central the Persian Gulf are considered as world’s giant gas reservoirs. The primary purpose of this research is to model and evaluate the relationship between hydraulic flow units (HFUs), electrofacies and microfacies with systems tracts of Permian-Triassic sequences. By integrating the results of core data, petrographic studies, and petrophysical logs of the studied formations, hydraulic flow units and electrofacies were identified. Based on the results of petrographic studies, twelve microfacies were identified in terms of textural and depositional characteristics. Based on depositional setting, sedimentary facies and INPEFA values obtained from gamma ray log and gamma deviation log (GDL) in the context of sequence stratigraphy, zonation of Dalan and Kangan reservoirs is carried out. The zonation boundaries correspond to the key stratal surfaces (sequence boundary and maximum flooding surface). Seven petrographic rock types (PRT) were identified for the upper Dalan-Kangan reservoirs based on sedimentary texture, diagenetic process and dominant pores. Using porosity and permeability data from the core analysis, five hydraulic flow units were identified based on the flow zone indicator (FZI) method. Using multi-resolution graph-based clustering (MRGC) four electrofacies were detected from petrophysical data (gamma, neutron, density and acoustic logs). Subsequently, the INPEFA, GDL and electrofacies were spatially modeled using the sequential indicator simulation (SIS) and sequential Gaussian simulation (SGS) geostatistical methods. Finally, a clear agreement was revealed between the reservoir zones and the stratigraphic sequence framework. It this regard, the microfacies belonging to the high-energy and grain-dominated settings (packstone, grainstone) of leeward shoal, shoal and seaward shoal belts have the best reservoir units due to the influence of dissolution and dolomitization. The best reservoir units in the Permian-Triassic deposits in the middle of the upper Dalan and lower Kangan are developed in UDS4, upper KS2 and middle KS1 units. On the other hand, mud-dominated facies (mudstone, wackestone) and anhydrite textures are mostly associated with the low-energy lagoonal environments, between tidal flat and Sabkha. Non-reservoir units have been formed in the upper Dalan/Kangan and in the transgressive systems tract of UDS3-a, KS2-a and the lower and upper part of KS1 transgressive-highstand systems tract.

Deep learning CNN-APSO-LSSVM hybrid fusion model for feature optimization and gas-bearing prediction

Conventional machine learning (CML) methods have been successfully applied for gas reservoir prediction. Their prediction accuracy largely depends on the quality of the sample data; therefore, feature optimization of the input samples is particularly important. Commonly used feature optimization methods increase the interpretability of gas reservoirs; however, their steps are cumbersome, and the selected features cannot sufficiently guide CML models to mine the intrinsic features of sample data efficiently. In contrast to CML methods, deep learning (DL) methods can directly extract the important features of targets from raw data. Therefore, this study proposes a feature optimization and gas-bearing prediction method based on a hybrid fusion model that combines a convolutional neural network (CNN) and an adaptive particle swarm optimization-least squares support vector machine (APSO-LSSVM). This model adopts an end-to-end algorithm structure to directly extract features from sensitive multicomponent seismic attributes, considerably simplifying the feature optimization. A CNN was used for feature optimization to highlight sensitive gas reservoir information. APSO-LSSVM was used to fully learn the relationship between the features extracted by the CNN to obtain the prediction results. The constructed hybrid fusion model improves gas-bearing prediction accuracy through two processes of feature optimization and intelligent prediction, giving full play to the advantages of DL and CML methods. The prediction results obtained are better than those of a single CNN model or APSO-LSSVM model. In the feature optimization process of multicomponent seismic attribute data, CNN has demonstrated better gas reservoir feature extraction capabilities than commonly used attribute optimization methods. In the prediction process, the APSO-LSSVM model can learn the gas reservoir characteristics better than the LSSVM model and has a higher prediction accuracy. The constructed CNN-APSO-LSSVM model had lower errors and a better fit on the test dataset than the other individual models. This method proves the effectiveness of DL technology for the feature extraction of gas reservoirs and provides a feasible way to combine DL and CML technologies to predict gas reservoirs.

Evaluation of Saturation Interpretation Methods for Ultra-Low Permeability Argillaceous Sandstone Gas Reservoirs: A Case Study of the Huangliu Formation in the Dongfang Area

Ultra-low permeability argillaceous sandstone reservoirs have become a significant focus for exploration and development. Saturation is a crucial parameter in evaluating such reservoirs. Due to the low porosity, low permeability, complex pore structure, and strong heterogeneity in ultra-low permeability argillaceous sandstone reservoirs, traditional evaluation methods are unable to achieve the required level of interpretation accuracy. To improve the accuracy of gas saturation calculations in ultra-low permeability argillaceous sandstone gas reservoirs, the conductivity characteristics of the ultra-low permeability argillaceous sandstone gas reservoirs in the Huangliu Formation in the Dongfang area, China, were analyzed through rock physics experimental data and geological information. The results revealed the clay content in the study area to range from 6% to 33.4%. Influenced by burial depth and temperature, kaolinite and montmorillonite transform into illite and chlorite, and the cation exchange capacity is not correlated with the clay content. This suggests that the effects of cation-attached conductivity can be ignored. The regional variation in rock electrical parameters is significant. When the lithology coefficient is a = 1, the consolidation index m varies between 1.25 and 1.75. When the lithology coefficient is b = 1, the saturation index n varies between 1.6 and 1.96. Under the influence of high temperature and pressure, the reservoirs in the study area exhibit two distinct characteristics on the capillary pressure curve, fractal dimension, and effective porosity index intersection diagram, (1) In Class I reservoirs, there is a strong correlation between the formation factor and natural gamma, as well as porosity, and a logarithmic relationship between the saturation exponent and the formation factor; and (2) in Class II reservoirs, there is a strong power-law relationship between the formation factor and porosity, as well as a logarithmic relationship between the saturation exponent and formation factor. Based on experimental and logging data, reservoir classification was conducted using core-scale logging and principal component analysis. Additionally, a saturation interpretation model was developed using multivariate regression, based on rock electrical parameters. The actual application results demonstrate that compared to the fixed rock resistivity saturation model, this model has reduced the average absolute error by 5.9%. The calculated values are consistent with the gas saturation analysis of the core at the pure gas section as determined by cable testing sampling. This model meets the requirements of practical production. The study of this interpretation method is of great significance for the formulation of development plans for ultra-low permeability offshore argillaceous sandstone gas reservoirs.

Characteristics of Tight Gas Reservoirs in the Xujiahe Formation in the Western Sichuan Depression: A Systematic Review

In current energy structure adjustments, the prominence of unconventional oil and gas resources continues to grow, with increasing attention being paid to tight gas, a major component of natural gas production. The Xujiahe Formation gas reservoir in the Western Sichuan Depression represents a typical tight gas reservoir and the study of its reservoir characteristics is a key focus for current and future exploration and development efforts. This review employs the PRISMA method to screen and integrate the primary findings of 26 documents spanning the period from 2008 to 2023, with the aim of providing a comprehensive overview of the progress and outcomes of research on the tight gas reservoir characteristics of the Xujiahe Formation in the Western Sichuan Depression. The selected research documents summarize the characteristics of the Xujiahe Formation tight gas reservoir in the Western Sichuan Depression from four perspectives: lithology, physical properties, reservoir space, and the main factors influencing reservoir quality. Through a review of these previous studies, it is evident that existing research has predominantly focused on the relationship between diagenesis and reservoir densification, indicating certain limitations. We also delve into the characteristics of tight gas sandstone reservoirs in the study area, considering their depositional systems, fracture development, cementation, and impact on the exploration and development of tight gas reservoirs. Additionally, we propose measures to stabilize and enhance tight gas production in the Xujiahe Formation in the Western Sichuan Depression. Moreover, we outline the next steps for further research and exploration.

Sedimentary Characteristics and Internal Architecture of a Sandy Braided River: Insights from a Numerical Model

Sandy braided river deposits are widely observed in ancient stratigraphic records and modern sedimentary basins. Frequent channel migration shapes intricate internal architecture, while research on its influence on fine sedimentary architecture remains limited. This study utilizes DELFT3D to simulate and analyze the sedimentary processes and architecture of the channel bar in a sandy braided river. The results show that: (1) The channel bar consists of downstream accretion (DA), lateral accretion (LA), and aggradational accretion (AA). (2) Channel bars can be divided into three types: unit bars, compound bars, and complex compound bars. Unit bars are lobate-shaped and consist of multiple accretions, including DA in the core, AA layered above, and LA deposited on the sides. Compound bars result from the migration and amalgamation of multiple unit bars, characterized by a greater number of accretions. Compound bars can further be classified as DA-dominated or LA-dominated, depending on the dominant accretion type. Complex compound bars form from the merging of multiple unit bars and compound bars. In this paper, insights from a braided river on its sedimentary processes and evolution may help to improve river management and water resources research. The in-depth understanding of sedimentary architecture on channel bars can be utilized for detailed subsurface oil and gas reservoir characterization.

Wide azimuth seismic data processing technology and application: a case study of tight gas reservoirs in western China

As the difficulty of oil and gas field exploration and development increases both domestically and internationally, onshore exploration targets have gradually shifted from the shallow to the deep and from conventional oil and gas reservoirs to unconventional ones. Particularly in the exploration and development of unconventional oil and gas horizontal wells, there is an increasing demand for higher precision and quality of seismic data to better identify formation lithology, rock fractures, and improve the characterization of reservoirs, reservoir positioning, and connectivity. Wide-azimuth seismic exploration possesses significant technical advantages in addressing exploration challenges such as lithologic exploration, small fault imaging, and detailed characterization of oil and gas reservoirs. Wide azimuth seismic data reduces blind spots in seismic acquisition and improves the imaging accuracy of small faults. Notably, there exist distinct anisotropic characteristics in fault areas and fractured reservoirs. Wide azimuth seismic data is particularly advantageous for studying amplitude variation with variations in amplitude with offset (AVO), incident angle (AVA), or azimuth (AVAZ), as well as velocity with azimuth (VVA). These variations aid in identifying faults, fractures, and changes in formation lithology. As the focus of oil and gas exploration gradually shifts to complex lithological reservoirs and unconventional oil and gas reservoirs, narrow azimuth seismic exploration has been gradually replaced by wide azimuth exploration. However, as observation azimuth increases, challenges related to velocity variations with azimuth, azimuth-related traveltime differences, and azimuth-related anisotropy arise. Based on wide-azimuth seismic data from tight gas reservoirs in western China, this study conducted wide-azimuth anisotropic velocity analysis, OVT domain data regularization processing, OVT domain prestack time/depth migration, and horizontally transverse isotropy (HTI) azimuth anisotropy correction techniques. After applying specialized processing to the wide-azimuth seismic data, significant improvements were observed in the S/N and resolution of the target layer. The delineation of fractures related to hydrocarbon sources also became more distinct. These advancements not only provided high-quality results for high-fidelity, high-resolution imaging of tight gas reservoirs but also provided azimuth volume corresponding to fast and slow wave velocities for seismic data interpretation, facilitating velocity variation with azimuth (VVAZ) fracture detection and AVO analysis research.

Mining and Analysis of Production Characteristics Data of Tight Gas Reservoirs

The production characteristics of gas reservoirs are one of the important research subjects in gas reservoir development. To better guide the production development and strategy formulation of tight gas reservoirs, it is necessary to utilize data mining techniques to clarify the production characteristics of different reserves types of tight gas reservoirs. The production varies with the size of the recoverable reserves. In this study, 261 tight gas reservoirs worldwide were divided into three categories based on the size of their recoverable reserves. By considering the complete lifecycle of tight gas reservoirs, the production variations were classified into 16 production features, and these features were compiled into a dataset. Three algorithms, namely random forest, LightGBM, and CatBoost, were trained separately to analyze the relationship between the production characteristics and the size of the recoverable reserves of tight gas reservoirs. The objective was to define the production characteristics of tight gas reservoirs with different reserve sizes. Consequently, a set of production characteristic judgment rules that align with the size of the recoverable reserves of tight gas reservoirs was established. The findings revealed that LightGBM provided accurate predictions for the development characteristics of tight gas reservoirs with different reserve sizes. The production characteristics of large-scale tight gas reservoirs are as follows: the cumulative production at the end of the production increase phase ranges from 10 to 115.8 billion cubic meters, while the cumulative production at the end of the stable production phase ranges from 7.9 to 154.9 billion cubic meters. The peak production ranges from 2.3 to 3.8 billion cubic meters, and the decline period is estimated to last between 40 to 51 years. For medium-scale tight gas reservoirs, the production characteristics are as follows: the cumulative production at the end of the production increase phase ranges from 2.5 to 10 billion cubic meters, while the cumulative production at the end of the stable production phase ranges from 2.4 to 7.9 billion cubic meters. The peak production ranges from 0.8 to 2.3 billion cubic meters, and the decline period ranges from 20 to 40 years. As for small-scale tight gas reservoirs, the production characteristics are as follows: the cumulative production at the end of the production increase phase ranges from 0.1 to 2.5 billion cubic meters, while the cumulative production at the end of the stable production phase ranges from 0.2 to 2.4 billion cubic meters. The peak production ranges from 0.005 to 0.8 billion cubic meters, and the decline period ranges from 3 to 20 years. This study can provide potential references for the formulation of development technology policies for tight gas reservoirs and the assessment of reservoir production potential.

Petrophysical properties identification and estimation of the Wufeng-Longmaxi shale gas reservoirs: a case study from South-West China

Abstract Petrophysical properties are critical for shale gas reservoir characterization and simulation. The Wufeng-Longmaxi shale, in the south-eastern margin of the Sichuan Basin, is identified as a complex reservoir due to its variability in lithification and geological mechanisms. Thus, determining its characteristics is challenging. Based on wireline logs and pressure data analysis, a shale reservoir was identified, and petrophysical properties were described to obtain parameters to build a reservoir simulation model. The properties include shale volume, sand porosity, net reservoir thickness, total and effective porosities, and water saturation. Total and effective porosities were calculated using density method. Shale volume was estimated by applying the Clavier equation to gamma-ray responses. Sand porosity and net reservoir thickness were evaluated using the Thomas–Stieber model, and the Simandoux equation was used to compute water saturation. The results indicate that the reservoir is characterized by a relatively low porosity and high shale content, with shale unequally distributed in its laminated form (approximately 75%), dispersed (about 20%), and structural form (5%). This research workflow can efficiently evaluate shale reservoir parameters and provide a reliable approach for future reservoir development and fracture identification.

Shale Gas Reservoir Pore Pressure Prediction: A Case Study of the Wufeng–Longmaxi Formations in Sichuan Basin, Southwest China

Pore pressure prediction is critical for shale gas reservoir characterization and simulation. The Wufeng–Longmaxi shale, in the southeastern margin of the Sichuan Basin, is identified as a complex reservoir affected by overpressure generation mechanisms and variability in lithification. Thus, standard methods need to be adapted to consistently evaluate pore pressure in this basin. Based on wireline logs, formation pressure tests, and geological data, this study applied the Eaton–Yale approach, which extends the theoretical basis of Eaton and Bowers methods to reservoir geological conditions and basin history. The method was developed by integrating petrophysical properties, rock physics interpretations, and geology information. The essential steps include (1) a multi-mineral analysis to determine mineral and fluid volumes; (2) a determination of the normal pressure trend line and extending it to overpressured sections; (3) predicting pore pressure using the basic Eaton approach and identifying overpressured zones; (4) correcting compressional velocity using lithology logs and a rock physics model; (5) determining the Biot Alpha coefficient and vertical-effective stress and estimating the new pore pressure values using the Eaton–Yale method. Overpressure zones were corrected, and reservoir pore pressure varied between 30.354 and 34.959 MPa in the wells. These research results can provide a basis for building reservoir simulation models, identifying reservoir boundaries, and predicting relative permeability.

A Composite Framework Model for Transient Pressure Dynamics in Tight Gas Reservoirs Incorporating Stress Sensitivity

Natural gas is an eco-friendly energy source with low carbon emissions, making it attractive globally. Understanding gas reservoirs is crucial for sustainable extraction and optimizing potential. However, the complicated fluid flow and production dynamics within intricate gas reservoirs, particularly those characterized by abnormally high pressures and tight porous media, remain partially understood and demand further investigation. In a tight porous medium subjected to high pressure, the assumption of constant permeability is no longer valid. Consequently, a novel composite seepage model has been developed in this study, which considers the responsiveness of permeability to stress. Perturbation theory is employed to address the inherent non-linearity demonstrated by the permeability modulus. The solution of dimensionless pressure responses under constant production conditions is accomplished in the Laplace domain by implementing integral transformation methods. Overall, a comprehensive model is provided to understand the production behaviors of tight gas reservoirs. Moreover, in order to comprehend the transient flow characteristics of tight gas reservoirs, log–log plots are generated through the Stehfest numerical inversion approach, with the flow regimes categorized based on the normalized time phases of the pressure curves. Parametric investigations reveal that stress sensitivity detrimentally affects permeability, resulting in more pronounced pressure declines during the intermediate and late flow phases. The transient seepage model elaborated in this study is able to consider the pertinent formation and well parameters. These interpreted parameters bear significance in designing hydraulic fracturing operations, assessing the potential of tight gas reservoirs, and ultimately enhancing gas production. The presented model not only enhances our understanding of the behavior of horizontal wells in stress-sensitive tight gas reservoirs but also makes a valuable contribution to the broader discussion on transient flow phenomena in petroleum engineering.

A 3D Geological Modeling Method for Grain-size Lithofacies of Tight Sandstone Gas Reservoirs: A Case Study of Xujiahe Formation Gas Reservoir in Sichuan Basin, China

Tight sandstone gas reservoir has strong heterogeneity, and it is difficult to control the change of internal storage and permeability properties by simple sedimentary facies. It is necessary to explore a geological modeling method that can more accurately characterize the distribution of high-quality reservoirs. Taking the Xujiahe Formation gas reservoir in Xinchang area, Sichuan Basin, China as an example, this paper introduces the modeling method of three orders: sand-mudstone facies, sedimentary facies and grain-size lithofacies, so as to realize the spatial characterization of high-quality tight sandstone reservoirs with strong heterogeneity. In this technical process, the sand-mudstone model is first established. Based on the sand and mudstone model, four sedimentary types (or sedimentary facies) of distributary channel, channel edge, interdistributary bay and mouth bar are further divided. The sedimentary facies model is constructed by multi-point geostatistical modeling method. The quantitative relationship between sedimentary facies and grain-size lithofacies is linked by using argillaceous content as a “bridge”. The spatial distribution probability of grain-size lithofacies is constrained by the neural network clustering of argillaceous content and natural gamma-ray data in three-dimensional space. By controlling the types, ratios, and boundaries of grain-size lithofacies through sedimentary facies, and combining probabilistic bodies to cooperate with constraints, precise simulation of lithofacies can be achieved. The grain-size lithology lithofacies model established by this method follows the depositional law in space and has more reasonable contact relations between various sand bodies. The anastomosis rate of the model reached 85% with the new drilling test. This paper provides a new modeling idea for quantitative characterization and prediction of high-quality tight sandstone gas reservoirs, and provides a more accurate model basis.

Greenhouse gas protection and control based upon the evolution of overburden fractures under coal mining: A review of methods, influencing factors, and techniques

In accordance with the Paris Agreement, many nations have set out a global framework to stabilise and prevent greenhouse gas (GHG) emissions to mitigate climate change. This study reviewed the literature on the GHG protection and control (GHGPC) impacts of overburden fractures in relation to coal mining. Different factors, such as geological conditions, mining conditions, and gas extraction methods, were compared because they influence GHGPC. Carbon emissions, coal mining safety, and environmental protection are crucial parameters. GHGPC can (1) improve the safety and efficiency of mining, (2) reduce GHG emissions, and (3) generate clean gas resources. During mining, cracks appear in overburden strata, causing GHG emissions. Various techniques, including scanning electron microscopy, nuclear magnetic resonance, two-dimensional and three-dimensional physical similarity simulations, permeability testing, and numerical simulations, have been adopted to determine the macroscopic and microscopic features of overburden fractures. Finally, the extraction method of GHG was optimised through field practice, namely, roadway, borehole, and pipe extraction, were analysed, and the comprehensive GHG extraction method was preferred to achieve superior management results. This paper reviewed studies that examine the development of fractures to elucidate the significance of GHGPC. Moreover, this article provides new insights into the achievement of the “dual carbon strategy” with particular reference to coal mining; it also summarises the holistic life cycle of gas management in terms of overburden activity, gas transport patterns, reservoir characteristics and typical technologies. It also summarises the holistic life span of GHGPC management in terms of overburden activity, GHG transport patterns, reservoir characteristics, and typical technologies. Finally, the authors discuss and conclude the article with proposed methods for future research directions.

Significance of organo-mineralogical constituents on pore distribution, fractals and gas sorption mechanism of Permian shale beds in Korba sub-basin of the Son-Mahanadi Valley, India

In this study, shale samples obtained from the Korbasub-basin of Central India have been evaluated for the significance of organo-inorganic constituents in terms of their source potential of gas genesis, pore-matrix setup, and gas adsorption and desorption. The samples were analysed for various properties, such as megascopic features, lithological variations, depositional facies, and sources of organic and inorganic sediments. Also, maceral content, mineralogical constituents, kerogen type, pore distribution, pore structure, fractal characteristics and gas storage capacity were examined. The analysis revealed a trend of alternating bands of carbonaceous matter, silts, intercalations, and fluvial bedding lithofacies patterns indicating that the sediments were deposited under fluvio-terrestrial-lacustrine depositional conditions. Ternary facies analysis of maceral composition and van Krevelen diagram suggested the evolutionary path of type IV kerogen and are thermally matured source material located within the dry hydrocarbon generation window. Evaluation of pore types and pore structures using BET sorption plots (hysteresis H3 and isotherm type IV) revealed the presence of cylindrical, slit and combined cylindrical-slit pores with two distinct fractal characteristics. The discrete macerals underwent partial decomposition during transportation and mixing with inorganic components (clay and minerals), which influenced organic matter preservation, gas genesis, pore fractals and storage mechanism. The chemical index of alteration (CIA – 88.36 to 91.97), weathering (CIW – 96.60 to 98.80) and compositional variation (ICV – 0.31 to 0.70) demonstrated the influence of partial decomposition and strong weathering patterns on the organo-inorganic matter. A significant correlation was observed between pore fractals and elemental composition, particularly related to the resistance of weathering elements such as MgO, Al2O3, Fe2O3, SiO2, P2O5, TiO2, etc., which partially contributed to the formation of pore rugged surfaces. Microscopic and XRD analyses were employed to determine the mineral type, grain shape and size, and their amount leading to the development of the shales brittleness index (MBI). The importance of brittle characteristics, governed by minerals and clays within the shale, is discussed in relation to the hydro-fracturing technique for permeability enhancement. The results of high-pressure methane sorption indicated a moderate gas storage potential. The variation in sorption capacity (VL – 6.65 to 8.25 cc/g) is described through relationships with the ICV, pore diameter, pore volume, liptinite and total maceral content. Fractal dimensions D1 (2.4571–2.5611) and D2 (2.5804–2.7529) exhibited a direct relationship with adsorption properties, indicating the presence of rugged surfaces associated with meso- and macro-scale pores, which primarily control gas storage in shale. This research offers detailed insights into shale gas, providing valuable information for CBM and petroleum operators engaged in methane gas exploration and production. While commercial CBM production has been ongoing in India for over a decade, the exploration and understanding of shale gas reservoir characteristics are still in progress. This investigation adds significant value and highlights the extensive opportunities for research and potentially commercially recovering shale gas in the Korba sub-basin.

Research on types of gas reservoirs divided by seepage capacity and their seepage mechanism, law and productivity

In view of the diversity of gas reservoir classification and the differences of characteristics of geology and development in different gas reservoirs, it is necessary to study the adaptability of gas reservoir classification. This paper analyzes and summarizes the current classification methods of gas reservoirs, studies the microscopic pore characteristics and seepage mechanism of different gas reservoirs. The commonalities and individualities of seepage laws in different gas reservoirs are determined, the key factors that determine the development dynamics and effects of gas reservoirs are proposed, and the gas reservoirs types are divided from the perspective of development. The results show that the development characteristics of gas reservoirs are determined by the seepage law, and the seepage law is determined by the microscopic pore characteristics. Therefore, from the perspective of development, the microscopic pore characteristics are the fundamental of gas reservoir classification. Gas reservoirs can be divided into four types: tight, low permeability, medium and high permeability, and fractured. This classification method can unify the types of gas reservoirs according to the seepage laws of different gas reservoirs, establish corresponding seepage models, evaluate productivity, and predict performance. It is of great significance for rational, efficient and scientific development of gas fields.

The gas bearing and reservoir characteristics of finely divided lithofacies and dominant lithofacies: an example of Longmaxi Formation shale in northern Yunnan-Guizhou

The gas bearing and reservoir characteristics of finely divided lithofacies and dominant lithofacies: an example of Longmaxi Formation shale in northern Yunnan-Guizhou

Carbon and oxygen isotopes and molecular fossil characteristics of unconventional gas reservoirs in Permian Maokou Formation, West Chongqing, Sichuan Basin

Carbon and oxygen isotopes and molecular fossil characteristics of unconventional gas reservoirs in Permian Maokou Formation, West Chongqing, Sichuan Basin