The normal pressure shale gas reservoir within the complex structural belt of Nanchuan has been subject to the influences of multiple tectonic movements. The geological conditions in this region exhibit a high degree of complexity, thereby amplifying the challenges associated with efficient resource extraction. In response, an integrated geological engineering approach, tailored to the unique geological attributes of normal pressure shale gas in the intricate structural belt of Nanchuan, has been devised. This approach is aimed at mitigating challenges such as low rates of drilling in “sweet spots”, reduced mechanical drilling speeds, and suboptimal outcomes in fracturing transformations stemming from the intricacies of geological reservoir structures. In pursuit of optimizing the development of normal shale gas resources, a comprehensive investigation was undertaken, leveraging interdisciplinary knowledge spanning geophysical exploration, geology, drilling and completion, and fracturing techniques. An integrated process was established, fostering collaborative problem-solving and the mutual enrichment of geological and engineering insights. At its core, this approach emphasizes the synergy between geophysical exploration, geology, and engineering, thereby forming a pivotal development technology tailored for normal pressure shale gas reservoirs within complex structural zones. Through practical field applications, notable enhancements have been achieved. Mechanical drilling speeds and the rate of target window drilling in complex structural areas have witnessed significant improvements. Concurrently, the costs associated with fracturing operations have been consistently reduced, yielding improved gas well fracturing outcomes and enhanced productivity. These advancements collectively culminate in the efficient development of the Nanchuan normal shale gas field. Furthermore, they offer invaluable technological insights and experiential wisdom for the efficient extraction of normal shale gas reservoirs in the intricate regions of southeastern Chongqing.

Due to the complex lithology of fine-grained sedimentary rocks and the difficulty to determine the “sweet spot” of the fifth member of Xujiahe Formation（short for Xu-5 Member） of western Sichuan Depression, Sichuan Basin, a comprehensive geological analysis was conducted. This analysis encompassed various geological data sources, including X-ray diffraction, thin sections, scanning electron microscopy, physical properties, organic carbon content, and elemental analysis. Additionally, core observations were incorporated into the study. Upon scrutinizing this array of data, a classification of 14 distinct lithofacies types was established. This categorization was formulated based on the analysis of lithofacies and the evolution of sedimentary paleoenvironments. Furthermore, through a comparative examination of shale gas evaluation parameters, the primary lithofacies types constituting the “sweet spots” were identified. This not only sheds light on the composition of Xu-5 Member but also provides valuable guidance for the exploration of continental shale gas within this formation. The results indicate that: ①The main lithofacies of Xu-5 Member in western Sichuan Depression are massive clayey siltstone and massive mixed sedimentary rock, followed by laminated mixed sedimentary rock, laminated clayey siltstone and massive silty clay rock; ②The sedimentary paleoenvironment of Xu-5 Member undergoes the process from dry heat sedimentary with shallow brackish water to wet sedimentary with deep fresh water, then back to dry heat sedimentary with shallow brackish water. The land source input decreases first and then increases. The middle part of Xu-5 Member is the “sweet spot” for the enrichment of organic matter. ③Laminated clayey siltstone and laminated mixed sedimentary rock are favorable lithofacies types for “sweet spot” development due to the high organic matter content, debris particle dissolution pore, high content of brittle minerals and good fracturing performance.

A distinct category of fractures, characterized by a substantial proportion, shallow angle, and contentious origin, commonly referred to n as “cake-like” fractures or “laminar cake” fractures within the second member of Xujiahe Formation of Xinchang structural belt, has been chosen as the research target. This study employs meticulous core observation, precise thin section analysis, and a comprehensive comparative assessment of both macroscopic and microscopic traits. The primary objective is to classify these “cake-shaped” fractures for the first time and elucidate their corresponding lithofacies attributes and genesis. The discussion regarding the oil and gas geological significance of these “cake-like” fractures is rooted in the distinctions in gas-bearing properties. The analysis reveals the presence of three distinct types of “cake-like” fractures: thin layer “shortcake” fractures, medium-thick layer unequal spacing fractures and medium-thick layer isometric fractures. The thin layer “shortcake” fractures manifest within isolated distributary channels with coarse-grained textures and a high quartz composition. Conversely, the medium-thick layer unequal distance fractures are evident in interbedded distributary channels exhibiting fine, medium-grained, and coarse-grained textures with a notable feldspar content. The medium-thick layer isometric fractures occur within distributary channels or estuarine bar resulting from the deposition of alternating fine and medium-grained calcareous-rich sand and calcareous-poor sand. The initial two fracture types can not only improve reservoir permeability, but also intensify the dissolution effect, leading to higher gas content, while the latter type only increases the permeability and has a limited impact on the matrix pores, resulting in lower gas content. The “cake-like” fracture phenomenon represents a composite fracture formation influenced by sedimentary environment, tectonic stress, and differential diagenesis. It defies a simple classification as a tectonic shear fracture, sedimentary bedding fracture, or stress unloading fracture. The areas with high structural position, well-developed pie fractures and favorable reservoir properties, augmented by effective fracture network fracturing technology, present promising prospects for future exploration endeavors.

In the Dongfengchang area of Ziyang, the fifth member of Xujiahe Formation exhibits multiple phase of superimposed channels with rapid facies changes in the channel sandstones. The reservoirs are highly heterogeneous, with minimal differences in impedance between sandstones and mudstones. The seismic response characteristics of the reservoirs are multifaceted. Additionally, the pre-stack seismic data quality is suboptimal, compounded by an absence of shear wave logging data. In the preliminary stages, conventional post-stack attributes were used to characterize the boundaries of channel sand bodies and the distribution of high-quality reservoirs, but the accuracy of this characterization was limited. To address the mentioned challenges, high-quality pre-stack seismic data was obtained through noise suppression, data flattening, and optimal frequency enhancement techniques. An improved XU-WHITE model-based approach was utilized to predict shear wave velocities. Innovative indicators based on rock physics analysis were developed, and a seismic prediction volume for lithology and reservoir properties was obtained through simultaneous inversion of three pre-stack parameters. This approach allowed for a detailed characterization of sand body boundaries and distribution. In favorable facies zones, using property prediction attributes, the distribution of “sweet spots” within tight sandstone reservoirs was predicted. The research results indicate the following: ①High-fidelity pre-stack data optimization processing provides reliable and AVO-compliant pre-stack data, establishing a solid foundation for subsequent pre-stack inversion; ②The improved XU-WHITE model-based shear wave velocity prediction technique yields more accurate shear wave velocities, which are beneficial for rock physics analysis; ③The construction and inversion techniques of lithology and physical property indicator factors are effective in achieving a precise characterization of the lithology and physical properties of tight sandstone reservoirs. This technology has shown promising results in characterizing the tight sandstone reservoirs and predicting “sweet spots” in the Xujiahe Formation gas reservoirs in Ziyang. It holds potential for broader applications in similar geological settings.

The Hexingchang gas field of the western Sichuan Depression is an ultra-low porosity and ultra-low permeability tight sandstone reservoir, with well-developed and diverse types of fractures. The degree of fracture development plays a pivotal role in influencing on the migration, reservoir formation, and productivity of natural gas. In order to guide the exploration and development of the area, a comprehensive study was conducted to examine the development characteristics and underlying factors controlling fractures within the second member of Xujiahe Formation. This investigation drew upon a range of analytical techniques, including core observation, thin section analysis, imaging logging, and the examination of fracture filling inclusions. The fractures in the research area can be divided into three categories based on their genesis: structural fractures, diagenetic fractures, and abnormally high pressure fractures. There are three stages of development of structural fractures, corresponding to the late Indosinian period, mid late Yanshan period, and Himalayan period. Structural fractures have the characteristics of long extension, large width, and low filling degree of fractures; The diagenetic fractures are mainly bedding fractures, with a small amount of sutures developed; The development of abnormally high pressure fractures is relatively rare, which is related to hydrocarbon generation and pressurization. Building upon this foundation, the main controlling factors for the development of fractures were further clarified. The degree of structural fracture development is primarily influenced by a multitude of factors, including structural deformation, fractures, rock facies, rock layer thickness, and phase transformation; The development degree of diagenetic fractures is primarily influenced by rock facies and rock layer thickness; The development degree of abnormally high pressure fractures is chiefly influenced by hydrocarbon generation and pressurization. Based on the structural style and lithological combination of the second member of Xujiahe Formation in the research area, a fracture genesis model has been established. The fracture development area of the second member of Xujiahe Formation in the research area is located at the structural turning point, near the north-south trending fault, with a moderate thickness of single layer sandstone（sand mud interbedding, thick sand thin mud type）, a north-south trending lithofacies change zone, and an abnormal pressure development area.

The sandstone reservoirs in the Jurassic formation of gas fields such as ZJ, XC, and SF in western Sichuan Depression are characterized by their tight nature and are primarily situated within delta plain-frontal distributary channels. These reservoirs often pose a unique challenge in terms of geophysical analysis due to the significant impedance contrast between the type ③ reservoir and the surrounding rock formations. Therefore, the precise characterization of concealed channel distribution is a crucial focus for expanding exploration and development efforts. In this study, the rock physics characteristics of reservoirs and forward modeling of AVO（Amplitude Versus Offset） gathers were conducted to determine the relationship between different reservoir types and AVO responses. Furthermore, a method known as the FN stacking method was developed. By optimizing the processing of gathers and selecting far/near offset stacking, the identification capability of concealed channels was significantly enhanced. This technology accurately reveals the distribution of hidden channels, precisely traces their shape and boundaries, and has successfully discovered new channels that have been confirmed through actual drilling, thus expanding new exploration and development fronts.

The second member of Xujiahe Formation in Xinchang western Sichuan Depression, a tight sandstone reservoir, exhibits strong heterogeneity and thin reservoir characteristics. Previous interpretations of lithology and reservoir properties obtained directly through seismic attributes and inversion techniques were limited by individual understanding and interpretation accuracy. Consequently, the interpretation results often fell short of meeting the requirements for detailed reservoir development in gas fields.To address these challenges, a novel approach was implemented. Sensitivity parameters related to pre-stack lithology and reservoir properties were used as learning samples. Pre-stack inversion techniques were combined with machine deep learning algorithms to construct an interpretation model. This innovative method ultimately achieved quantitative predictions of sandstone thickness and reservoir properties. This method not only improves the resolution of reservoir prediction, but also greatly improves the prediction accuracy. The prediction results provide effective support for sedimentary microfacies research, reservoir formation analysis, and well location deployment, and have achieved good application results in the development of the second member gas reservoir of Xujiahe Formation in Xinchang. This article introduces a new interpretation approach for quantitative prediction of lithology and reservoirs, and serves as a valuable reference for gas field development in other regions.

Shaximiao Formation gas reservoir in Zhongjiang Gas Field has great exploration and development potential. However, it is primarily characterized by ultra-low porosity and ultra-low permeability, with pronounced reservoir heterogeneity. Addressing the challenges related to the early-stage reliability of lithology and gas-bearing identification, as well as the accuracy of reservoir porosity and thickness predictions, a comprehensive seismic rock physics analysis was undertaken. The analysis focused on assessing the feasibility of reservoir prediction through forward modeling, fluid substitution, and rock physics scaling. The objective was to elucidate the specific relationship between seismic elastic parameters, lithological parameters, and reservoir parameters for gas reservoirs. By optimizing sensitive parameters related to lithology, physical properties, and gas-bearing properties, qualitative and quantitative prediction models for reservoirs were established. This entailed using attributes such as the maximum trough attribute, minimum wave impedance attribute, and the ratio of minimum longitudinal and transverse wave velocities to predict reservoir distribution. The lithology and gas-bearing property are identified by P-wave velocity ratio and P-wave impedance intersection. The shale content is quantitatively predicted by P-wave velocity ratio fitting or co-simulation. The porosity is quantitatively predicted by P-wave impedance fitting or co-simulation in sandstone. The gas saturation is quantitatively predicted by Lamda/Mu fitting or co-simulation in gas-bearing sandstone, which lays a solid foundation for the fine prediction of Shaximiao reservoir in the study area.

Due to the inadequacy in the pre-assessment of natural fracture growth in shale, the exploration and development effect of Weirong shale gas field is seriously affected. It is imperative to enhance research on fracture prediction. In this paper, we applied the post-stack seismic dip-azimuth attribute to detect fractures in the WY23 Pad, and evaluated the reliability of the detection results from four aspects: geology, seismic, logging and engineering. The method employed for fracture detection revealed that fractures exhibit layer-controlled characteristics. They can be divided into two sets of upper and lower fracture systems roughly bounded by the top surface of the ③ thin layer. These fracture systems dip toward each other in the profile, with a predominant strike direction of 310° and dip angles of less than 20°. This configuration is the result of NE-SW compression. The application of this method for fracture detection has a high degree of confidence and can be promoted and applied in other development pad than WY23.

After hydraulic fracturing in shale gas reservoir, a significant volume of fracturing fluid retains in the matrix pores and induced fracture network. Currently, the pore scale fracturing fluid occurrence mechanisms are unclear. As a result, it is difficult to accurately understand the difference of fracturing fluid backflow rate of shale gas wells in the backflow process. In this work, the pore scale fracturing fluid occurrence mechanisms analysis method in shale multi-scale matrix-fracture system is developed and the fracturing fluid occurrence mechanisms in shale gas reservoir are elucidated in detail. To understand fracturing fluid occurrence pattern in shale matrix, singe pore gas-water occurrence method is established considering rock-fluid interaction and gas-water capillary pressure and is further extended into the pore network. Invasion percolation is applied to analyze the fracturing fluid occurrence pattern variation during different flowback stages. To understand fracturing fluid occurrence pattern in induced fracture network, the level-set gas-water interface tracking method is applied to calculate gas-water distribution at different flowback pressure based on induced fracture network CT imaging and the fracturing fluid occurrence pattern variation at different flowback stage is studied. Study results reveal that the fracturing fluid flowback rate in shale matrix first increases slowly and then increases fast. In the final stage, the fracturing fluid flowback rate in shale matrix reaches plateau. The fracturing fluid in shale matrix distributes in the forms of water saturated pores, corner water and water film. The fracturing fluid flowback rate in induced fracture network is influenced by pore connectivity around the induced fracture network. The fracturing fluid flowback rate first increases fast and then reaches plateau. The retained fracturing fluid distributes in the dead-end matrix pores around induced fracture network at the final stage.

Adsorbed gas represents a primary mode of shale gas occurrence and is a major source of shale gas production in the later stages of development. It primarily resides within the organic kerogen and clay minerals of shale formations, with organic kerogen being the dominant host. Consequently, the study of organic kerogen characteristics and its adsorption mechanisms is crucial for understanding shale gas development. In this paper, the kerogen of Longmaxi Shale in the Sichuan Basin is taken as the research object. The microstructure of kerogen is expressed by combining methods through the solid-state NMR experiment, Fourier transform infrared spectroscopy experiment, X-ray photoelectron spectroscopy experiment, and the molecular structure model of kerogen is constructed. The adsorption mechanism and characteristics of CH₄ in kerogen of Longmaxi Shale are analyzed by magnetic levitation weight experiment, molecular simulation methods of the Grand Canonical Monte Carlo（GCMC）, and Molecular Dynamics（MD）. The results show that the molecular formula of the kerogen of shale experimental sample of Longmaxi Formation is C₂₃₇H₂₁₉O₂₁N₅S₄. The excess adsorption gas volume of CH₄ in kerogen increase first and then decreased with the increase of pressure. Under the same pore size and pressure, the excess adsorption gas volume and total gas volume of CH₄ decrease with the increase in temperature. The C and S atoms in kerogen are the main cause of CH₄ adsorption. The CH₄ near the kerogen pore wall presents an adsorption state, while the CH₄ far from the kerogen pore wall presents a free state. As the pore size increase, the distance between the two peaks of CH₄ density gradually increases, and the peak value decreases gradually.

In order to address the challenges posed by the unclear production decline patterns and the difficulty in predicting production for normal pressure shale gas wells, a novel production prediction approach has been developed. This approach combines shale gas well production decline models with Long Short-Term Memory（LSTM） neural network models, leveraging machine learning techniques and different decline models for improved accuracy. Firstly, Nanchuan shale gas wells are divided into two types according to the characteristics of water production. For type 1, gas and water are produced simultaneously at the early stage, then water production decreases significantly in the later stage; while for type 2, gas and water are produced simultaneously for a long time. Secondly, double logarithmic diagnostic curves and characteristic curves are used to identify the flow stages of gas wells; then seven gas production decline models are used to analyze the production variety. Finally, the error of the decline models are used as the inputs of the LSTM model, meanwhile the yield prediction under the coupling method is obtained after superposition. The results show that a type 1 gas well, Well-X1, is in the pesudo-steady flow stage, its optimal decline model is the improved hyperbolic decline model or the AKB model; a type 2 gas well, Well-X2, is in the linear flow stage, the preferred models are SEPD decline and Duong decline model. When the error of the decline model is large, the production prediction accuracy of shale gas wells is effectively improved after coupling the LSTM model but the effect is not obvious when the error of the decline model is small.

The understanding of fracture propagation and evolution during dual well synchronous hydraulic fracturing, particularly under various conditions, remains limited. Meanwhile, the interaction between fractures will cause fracture reorientation and affect the hydraulic fracturing effect. In order to solve these problems, the fracture propagation law and failure mode under the influence of different factors are studied by the discrete element method. The results show that when the angle between the interwell connecting line and the maximum principal stress （θ） is 0°, and under the influence of the horizontal stress difference, the stress around the borehole wall can be divided into two stages: the stable stage before the fracture intersection and the steep rise stage after the fracture intersection. With the decrease of the horizontal principal stress difference, the failure mode changes from single fracture to multi fracture failure. When θ≠0°, the in-situ stress field of the formation changes, which causes the fracture deflection and forms an inclined fracture connecting the two wells. During the fracturing process, the expansion of the fracture exerts great stress on the surrounding area, and the magnitude and direction of local stress state change due to the expansion of the main fracture. So that the crack spreads away from the direction of the maximum principal stress.

There are two types of shale gas reservoirs in the Wufeng-Longmaxi shale formation of southeast margin of Sichuan Basin: normal pressure shale gas reservoir in Wulong residual syncline and abnormal over-pressure shale gas reservoir in Fuling anticline. This study takes an integrated geology-engineering approach to analyze the genesis and formation mechanisms of normal pressure shale gas reservoirs in the Wulong area. The analysis is based on shale burial history curves, drilling data, horizontal well fracturing parameters, and the geological characteristics specific to normal pressure shale gas reservoirs. Combined with the actual production effects of two horizontal shale gas wells, the fracturing process parameters of normal pressure shale gas reservoirs are optimised. Then three main points have been obtained in this study: ①The normal pressure shale gas reservoir of the Wufeng-Longmaxi Formation in Wulong area is formed during the structural destruction adjustment of the Yanshanian and Himalayan tectonic periods. ②The shale gas escaping caused by tectonic elevation is the main reason for the formation of normal pressure shale gas. ③Compared with the Marcellus normal pressure shale gas reservoir, Wulong normal pressure shale gas reservoir has the similar geological characteristics, but the development effect varies greatly. The fracturing scale simulation shows that it is necessary to further optimise the horizontal well segmented fracturing parameters, increase the output of single wells, and reduce development costs. Only in this way can effective development be realised.

The challenge of reliably predicting temperature profiles in horizontal wells in tight oil reservoirs, coupled with an incomplete understanding of the factors influencing these profiles, has hindered the quantitative interpretation of tight oil horizontal well production using distributed optical fiber technology. To address this issue, a comprehensive model has been developed to estimate temperature profiles in horizontal wells in tight oil reservoirs, accounting for various microthermal effects. The temperature profiles of horizontal wells in tight oil reservoir under different single factors were simulated and analyzed. Then, through orthogonal experiment analysis, it demonstrates that the sensitivity of different factors from strong to weak is production rate, fracture half-length, reservoir permeability, wellbore diameter, horizontal inclination angle, fracture conductivity, and total reservoir thermal conductivity（Q>x_f>K>D>θ>F_CD>K_t）. It is worth noting that fracture half-length and formation permeability emerged as the primary factors influencing the temperature profile of horizontal wells in tight oil reservoirs. The research results provide available basic models and theoretical support for quantitative interpretation of production profile and artificial fracture parameters for horizontal wells in tight oil reservoir.

The analysis of the well bottom pressure of the pressure-drive injection wells is of great significance for the evaluation of the pressure-drive effect and the inversion of reservoir parameters. In order to obtain the bottom hole pressure response of pressure-drive injection wells and the dynamic fracture parameters generated by pressure drive water injection, and from an fracture propagation perspective, the seepage mechanics theory and numerical simulation method are used to form a pressure analysis model of water injection wells considering the effects of fracture propagation, fracture morphology, filtration of injected fluid and other factors, and obtain the bottom hole pressure response of pressure drive water injection wells. The effects of injection flow, liquid production, formation permeability and well spacing on pressure are analyzed respectively, and applied to actual pressure drive wells to verify the accuracy of the model. It is found that the fluid flow in pressure-drive injection wells can be divided into five flow stages, namely, initial fracturing stage, fracture expansion stage, linear flow stage, transitional flow stage and boundary controlled flow stage. With the increase of injection flow rate, the fracture expansion stage is more obvious, the liquid production is greater, and the upwarping amplitude of the double logarithmic pressure analysis curve gets smaller in the late stage of pressure drive water injection. This study is of great significance to the study and understanding of the mechanism of unstable seepage flow in low permeability reservoirs developed by pressure drive water injection, and to the influence of dynamic fractures in water injection wells on bottom hole pressure.

Staged fracturing technology for offshore horizontal wells is still in an exploratory phase due to operational limitations. The effectiveness of fracturing horizontal wells has a significant impact on their productivity. Therefore, evaluating the fracturing effect and guiding the fracturing development of horizontal wells is a pressing concern. This paper firstly introduced the geological situation of low permeability reservoir in the East China Sea in detail, and the process of stage fracturing of the first open hole horizontal well was described. Then the fracturing effect of the multi-stage fractured horizontal well was evaluated successfully using the latest fracturing effect evaluation method of SPEE（Society of Petroleum Evaluation Engineers）. By analyzing the fracturing operation parameters of the well and comparing EUR（Estimated Ultimate Recovery） before and after fracturing, the fracturing effect evaluation method is verified to prove the correctness and reliability. Finally, it is concluded that the gas recovery rate of this horizontal well after fracturing is increased by 9.3 % and the oil recovery rate is increased by 6.6 %. The successful implementation of staged fracturing and the subsequent evaluation of its effects on the first horizontal well in the East China Sea set the stage for future development of horizontal well staged fracturing in offshore low-permeability reservoirs.