Gas Reservoir Characterization Research Articles

Key Techniques for Fine Three-Dimensional Geological Modeling of Coalbed Methane

China's proven coalbed methane reserves exceeding 30 trillion cubic meters, and two major coalbed methane industrial bases have been established in the Qinshui and Ordos Basin. Among them, the eastern margin of the Ordos Basin is one of the main blocks for shallow coalbed methane development, holding immense exploration and development potential. Nowadays, the reservoir characteristics of the eastern margin of the Ordos Basin remain unclear, necessitating further research to study reservoir features through fine reservoir description studies. Threedimensional geological modeling can effectively characterize reservoir heterogeneity, especially for predicting geological features between wells and in undrilled gas reservoirs. This study primarily focuses on conducting fine characterization of gas reservoirs and establishing a fine threedimensional geological model through techniques such as multi-attribute fusion in the eastern margin of the Ordos Basin, providing guidance for making and adjustment of development schemes.

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

AbstractPetrophysical 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

Enhancing identification of digital rock images using super-resolution deep neural network

Identification of pore and minerals from digital rock images plays an important role in characterization of oil and gas reservoirs. Traditional methods usually require high costs of time and labor. With the rapid development of artificial intelligence, deep learning methods have been applied to geosciences. Among them, semantic segmentation neural networks are used to identify rock images, but traditional semantic segmentation networks require high-resolution input images to improve performance and can only generate masks with the same resolutions as the input images, which again requires high-performance equipment and increases computational and equipment costs. In this paper, we propose an approach to enhancing identification of digital rock images with super-resolution neural network (SSRN) which enables low-resolution input images to generate high-resolution representations. We use SSRN to train the 10-classification thin-section images, and compare it with traditional deep learning methods. It indicates that SSRN can effectively improve the performance of the generated high-resolution masks.

Fisher-Bayesian inversion for estimating shale gas facies

The classification of shale gas facies from seismic properties is critical for shale gas reservoir characterization. Shale gas facies are affected by many petrophysical properties. Therefore, the characterization of shale facies should be carried out by multiple parameters, which is more reasonable and accurate. However, multiparameter inversion often leads to unstable results, and coupled properties are generally a way of solving this problem. We develop a Fisher-Bayesian inversion method for estimating shale gas facies by combining the Fisher projection and Bayesian inversion method. The mathematical method adopted for the inversion is the Bayesian framework. The link between different facies and coupled properties is given by a joint prior distribution. We derive the analytical formulation of the Bayesian inversion under the Gaussian mixture assumption for coupled attributes and different shale gas facies. Our approach realizes the fusion of multidimensional petrophysical parameters and establishes a shale gas facies prediction method based on coupled properties. The application to real data sets delivers accurate and stable results, wherein shale gas facies and coupled attributes are accurately predicted and inversed.

Major advancement in oil and gas exploration of Jurassic channel sandstone in Well Bazhong 1HF in northern Sichuan Basin and its significance

In January 2023, Well Bazhong 1HF in the northern Sichuan Basin obtained high-yield industrial oil flow of over 100 cubic meters from the Jurassic channel sandstone for the first time, realizing a major breakthrough. In order to provide more support for further oil and gas exploration in this area, this paper analyzes the sedimentary and reservoir characteristics of the Jurassic Lianggaoshan Formation in Bazhong region of northern Sichuan Basin and their control factors based on the exploration achievements of Well Bazhong 1HF. Then, oil and gas reservoir characteristics and oil and gas sources are comparatively analyzed. Finally, the key technologies for the exploration of channel sandstone oil and gas with multi-stage vertical superimposition, lateral migration, thin reservoir and strong heterogeneity are researched and developed, and the next oil and gas exploration direction in the Lianggaoshan Formation of northern Sichuan Basin is pointed out. And the following research results are obtained. First, in the second member of Lianggaoshan Formation (“Liang 2 Member” for short) in Bazhong region, multi-stage underwater distributary sand bodies of delta front are developed with sandstone thickness of about 25 m and average porosity of 5.6%. The pore types are mainly primary intergranular pores and feldspar/debris intragranular dissolved pores, the pore throat structure is good, and the development of good-quality reservoirs is controlled by the sedimentary microfacies of underwater distributary channel. Second, the oil and gas reservoir of Liang 2 Member is a highly oil-bearing condensate gas reservoir/volatile oil reservoir, whose oil and gas is mainly sourced from the semi-deep lacustrine shale of Liang 1 and 2 Members. Third, channel sand bodies are superimposed and developed continuously in the upper part of Liang 2 and Liang 3 Members, and the source-reservoir configuration is good, with the characteristics of near-source hydrocarbon accumulation and overpressure hydrocarbon enrichment. Fourth, for the channel sandstones with multi-stage vertical superimposition, lateral migration, thin reservoir and strong heterogeneity, the reservoir prediction technology of “high-frequency sequence stratigraphy slice, seismic frequency decomposition and facies-constrained seismic waveform indication inversion” is developed to precisely characterize the “sweet spot” target of narrow channel sandstone, and the key fracturing technology of “dense cutting + composite temporary plugging + high-intensity proppant injection + imbibition and oil-increasing” is formed to realize the large-scale reconstruction of channel sandstone reservoir. In conclusion, the breakthrough of Well Bazhong 1HF in the exploration of Lianggaoshan Formation oil and gas in Bazhong region reveals the huge potential of Jurassic oil and gas exploration in the Sichuan Basin, and plays a positive role in promoting the exploration and development of the Jurassic channel sandstone oil and gas in the Sichuan Basin.

Concept and key technology of “multi-scale high-density” fracturing technology: A case study of tight sandstone gas reservoirs in the western Sichuan Basin

There are abundant tight sandstone gas resources in the Sichuan Basin, which are the important objects of reserve and production increase and large-scale development. Due to their discontinuous sandbody distribution, narrow channels, and strong horizontal and vertical heterogeneity, however, conventional fracturing technologies cannot achieve the ideal stimulation effect here. In order to address this difficulty, this paper dissects the geology engineering characteristics of tight sandstone gas reservoirs in the western Sichuan Basin. Starting from the seepage mechanics theory, the concept of “multi-scale high-density” tight gas fracturing technology is put forward by fully referring to the experience of previous multi-round reservoir stimulation in the western Sichuan Basin and the idea of unconventional volume fracturing technology. In addition, its conceptual connotation, key technologies and implementation effects are illustrated. The following research results are obtained. First, the seepage characteristics make it necessary for the efficient production of tight gas reserves to increase fracture density and stimulated reservoir volume (SRV). Second, the “multi-scale high-density” fracturing technology emphasizes the rationality of high-density hydraulic fracture creation and the matching of multi-scale fracture flow capacity, and aims at establishing a multi-level fracture system with effective and steady gas flow in tight reservoirs through fracturing. Third, the “wide, dense, support, stable, and precise” fracturing technology is applied to improve single well production and estimated ultimate recovery (EUR). Fourth, the engineering practice of “multi-scale high-density” fracturing technology in the tight reservoirs of Jurassic Shaximiao Formation and Triassic Xujiahe Formation in the ZJ Gas Field realizes the average single well production rate of 15.6 × 104 m3/d, which is 1.96 times higher than that before the stimulation. Obviously, it provides powerful support for the operation of the ZJ Gas Field into a giant gas field with the reserves of 100 billion cubic meters. In conclusion, the formation of the concept and key technologies of “multi-scale high-density” fracturing technology effectively supports the efficient development of tight gas in the western Sichuan Basin and points out the following research direction of tight gas reservoir stimulation. The research results provide reference and guidance for the large-scale benefit development of tight gas in China.

Tight sandstone gas reservoir characterization via amplitude‐versus‐offset attributes

AbstractThe low porosity and low permeability of tight sandstone pose considerable challenges on characterizing the reservoir fluid. Moreover, the geophysical characteristics of the tight sandstone are usually similar to the surrounding rocks, leading to small impedance contrast, compounding the difficulty of reservoir parameters inversion. Amplitude‐versus‐offset technology is an important tool to invert the reservoir parameters from seismic data. The existing amplitude‐versus‐offset inversion methods are challenged to predict the tight sandstone reservoir parameters for the reasons above. In this paper, we propose a new workflow based on amplitude‐versus‐offset attributes to characterize the tight sandstone gas reservoirs in the Xihu Depression, East China Sea. The proposed workflow utilizes the Backus average method and Gassmann's equation to construct the rock physics model. Based on the analysis of the anisotropic model, we introduce Rüger's anisotropic equation for amplitude‐versus‐offset forward modelling. We compare the amplitude‐versus‐offset gathers with the real data and adjust the reservoir parameters. Through the sensitivity analysis, we select the gas saturation and porosity as the inversion parameters. The relationship between the reservoir parameters and amplitude‐versus‐offset attributes is established by fitting the fifth‐order polynomials. We use Shuey's equation and the least squares inversion method to calculate the amplitude‐versus‐offset attributes (intercept and gradient). For real data, we introduce the Toeplitz‐sparse matrix factorization method to calculate the reflectivity of the amplitude‐versus‐offset gathers. Finally, we proposed a multi‐well joint inversion approach to invert the gas saturation and porosity. The application results demonstrate the effectiveness of the proposed workflow for the characterization of the gas reservoir in tight sandstone for the describedcase.

Reservoir Characteristics and Gas Content of Black Shale of Wufeng-Longmaxi Formation in Qianjiang Area, Southeast Chongqing, China

The shale gas exploration in Changning, Weiyuan, Fuling Jiaoshiba, and other areas has achieved great success in the Sichuan Basin, and the basin margin of the Sichuan Basin will be an important target in the future. In view of the lack of understanding of shale gas reservoir characteristics of the basin margin area of the Sichuan Basin, this paper conducts a study on reservoir characteristics and gas-bearing properties of this area using qualitative and quantitative techniques. The results show that the thickness of the black shale reservoir in the Qianjiang area is up to 33 m, the kerogen sapropelic type (I) is dominant, and Ro ranges from 2.2 wt% to 3.39 wt%. The mineral composition is relatively complex, mainly composed of quartz and clay minerals. Quartz content is in the range between 9.4 wt% and 79 wt% ( average = 47.48 wt % ), while clay content is in the range between 10.02 wt% and 43.6 wt% ( average = 29.41 wt % ). There are various types of reservoir spaces, mainly including organic pores dominated by matrix pores, intergranular and intragranular pores, intergranular and intragranular dissolution pores, secondary dissolution pores, and microfractures, among which organic pores are the main pore types. The pore volume of nanopores is 0.009897-0.017177 cm3/g ( average = 0.01304 c m 3 / g ), and the specific surface area ranges from 12.1 m2/g to 35.1 m2/g ( average = 20.47 m 2 / g ). Micropores and mesopores are the main pore sizes for the development of organic pores. Quartz particles promote the development of reservoir space, while clay minerals are not conducive to the development of pores. The total gas content ranges from 0.5 m3/t to 4.43 m3/t ( average = 1.69 m 3 / t ). Its enrichment is controlled by many factors. The increase of organic matter abundance is the material basis for shale gas enrichment. The development of organic pores provides high-quality storage space for shale gas preservation. The development of different mineral components restricts the enrichment of shale gas.

Natural gas characteristics and gas-source comparisons of the Lower Triassic Feixianguan Formation, Eastern Sichuan Basin, China

There is great controversy regarding the origin and source of natural gas in the Lower Triassic Feixianguan Formation in the Eastern Sichuan Basin. This seriously restricts the study of natural gas dynamics in the Feixianguan Formation and thus hampers natural gas exploration in the region, so further study is urgently required. Using experimental tests of natural gas composition, stable isotopes, and noble gas isotopes with gas chromatography (GC) and mass spectrometry (MS) studies of source rock and reservoir asphalt saturated hydrocarbons, the natural gas geochemical characteristics, the genetic identification and a gas-source comparison of the Feixianguan Formation were studied. Then, constrained by the thermal history, the histories of gas generation and expulsion were restored by basin simulation technology. Finally, a gas accumulation model was established for the Feixianguan Formation. The results showed that (1) the H2S-rich and H2S-poor gas reservoirs of the Feixianguan Formation are distributed on the east and west sides of the Kaijiang-Liangping trough in the Eastern Sichuan Basin, respectively. The carbon and hydrogen isotope compositions of the natural gas in the gas reservoirs are generally heavy and have typical characteristics of high-maturity dry gas reservoirs. (2) The natural gas of the Feixianguan Formation is organic thermogenic gas, which is mainly oil-type gas generated by the secondary cracking of crude oil. The gas-generating parent material is mainly type II kerogen. (3) The natural gas of the Feixianguan Formation in the Eastern Sichuan Basin was mainly generated by argillaceous source rocks of the Upper Permian Longtan Formation. (4) Natural gas accumulation occurred as follows: the paleo-structure heights were filled with crude oil in the Early Jurassic, and paleo-oil reservoirs were formed in the Feixianguan Formation; during the Middle-Late Jurassic, the paleo-oil reservoirs were cracked when the reservoir temperatures rose above 160 °C, and paleo-gas reservoirs were formed. Since the end of the Late Jurassic, the paleo-gas reservoirs have been adjusted and reformed to form the present-day natural gas reservoirs. These results provide a basis for studying natural gas accumulation dynamics of the Feixianguan Formation in the Eastern Sichuan Basin.