CCUS is an important technical means to achieve the carbon neutrality goal. At present, China is in the implementation stage of the “dual carbon” goal, and there is still a lack of mature technical system in the economic boundary assessment, source-sink optimization and safety monitoring of geological sequestration of CO₂. This paper summarizes the development process of China's CO₂ geological sequestration technique from three aspects, economic boundaries of sequestration technology, source-sink matching technology, and sequestration safety and monitoring, reviews the economic costs of CCUS technology in the capture, transportation, injection and burial period, and further summarizes the current technical and economic boundaries and influencing factors of each period. In addition, by summarizing the current development status of CCUS source-sink matching technology at home and abroad, the source-sink characteristics and distribution of China have been clarified, and further development directions for source sink matching optimization technology have been proposed. Finally, by summarizing the safety risk assessment and burial monitoring techniques for geological sequestration of CO₂, it is clear that economically efficient, effective, and quantitative monitoring methods are the focus of future research.

CO₂ storage in saline aquifers is one of the feasible technical deployment schemes, and it is also the main approach to reduce CO₂ emission in the medium and long term. To meet the assessment requirements of the storage potential in saline aquifers, four CO₂ geological storage mechanisms are systematically expounded. Based on the storage mechanism, an evaluation index system for the suitability of CO₂ geological storage in saline aquifers is established, including four evaluation index layers of safety, technology, economy, and social environment. The weight of each evaluation index factor is calculated using the analytic hierarchy process. For saline aquifers with an open structure and rich hydrogeology, it is recommended to consider the combination of residual trapping and solubility trapping to evaluate CO₂ storage potential. The CO₂ geological storage suitability evaluation index system of saline aquifers provides a reference for conducting the national CO₂ storage suitability evaluation.

Deep coalbed methane（CBM） development in East China is of great significance to ensure regional energy demand, optimize regional energy structure and realize the dual carbon goal. Based on the systematic investigation and previous works, the current situations of CBM extraction in East China were summarized, and the gas-bearing attributes and resources potential of deep CBM were analyzed. Then, the applicability of existing deep CBM exploration and development technologies in East China was discussed, and the potential favorable areas of deep CBM exploration and development in East China were discussed and predicted. Finally, the advantages and challenges of deep CBM exploration and development in East China are put forward. Previous results show that: East China has a good CBM development accumulation on the tectonically deformed coal and in the coal mine area, such as “Huainan CBM extraction model” and horizontal well staged fracturing in the roof of the tectonically deformed coal. Deep coal in East China has a high gas content（greater than10 cm³/g） and gas-bearing saturation（greater than 80 %）. The predicted geological resources of deep CBM are 8 984.69×10⁸ m³ in the Huannan-Huanbei mining area, suggesting that Huainan and Huaibei coal field has an attractive deep CBM resources potential. Horizontal well development and hydraulic fracturing techniques for deep CBM have great application prospects in East China. Panxie mine area in Huainan coal field is expected to be a pilot area for deep CBM exploration and development in these areas. However, the overall exploration and development degree of deep CBM is low, so it is necessary to carry out the more detailed resource evaluation and analysis of deep CBM geological accumulation in the type area, like deep Panxie coal mine in Huainan coal field.

Under the situation of intensifying CO₂ emissions and increasingly serious environmental problems, carbon emission reduction is urgent. CO₂-EOR is the main means of geological storage of CO₂, but most of the researches on CO₂-EOR at home and abroad are to study the residual oil, and there are few studies on the form of CO₂ storage during oil flooding. In this paper, nuclear magnetic resonance is used to detect CO₂ displacement online combined with numerical simulation is used to study the CO₂ storage morphology and distribution characteristics of different core saturated oil after gas flooding. The results show that the NMR technology combined with the microscopic gas flooding oil numerical simulation method can effectively study the microscopic storage morphology of CO₂. When CO₂ in the core replaces crude oil, it first enters the large pore to drive oil, and after the pressure in the large pore reaches a certain level, the crude oil flows to the small hole throat with uneven distribution of capillary force around it, and the gas continues to drive the crude oil until the small pore pressure accumulates to a certain value in the small pore. Numerical simulations are performed using COMSOL Multiphysics software. Microscopic simulation results shows that CO₂ in large pores mainly exists in the form of continuous free gas, while CO₂ in small pores is first retained in dissolved form. There is no CO₂ completely stored in free gas or dissolved gas in both large and small pores.

Coal-bed methane reservoirs are characterized by low porosity, low permeability and low pressure, making their industrial exploitation primarily reliant on techniques like hydraulic fracturing. Currently, more than 50 percent of the gas wells in the Shizhuang block in the Qinshui Basin currently produce less than 500 m³/d of coal bed methane. However, the increase in production after gas well retrofitting has not been ideal and the main factors affecting gas well productivity remain unclear, directly impacting the overall improvement. To address this, the degree of influence of geological and engineering factors on fracturing productivity in coal-bed gas wells is described using the gray correlation method, and the main factors controlling gas well productivity after fracturing are analyzed. A correlation mathematical model between the main control factors and gas well production is established using the Pearson correlation analysis method to predict gas well productivity. The reliability of the prediction model is verified through gas well data validation. Furthermore, a classification decision tree is established using the chi-square automatic interactive detection decision tree method, in conjunction with gas well productivity data, to understand the impact of geological and engineering factors on gas well productivity in fractured wells. Under high gas content conditions, engineering factors have a relatively small impact on the productivity improvement of gas wells. However, as the gas content decreases, the impact of different engineering factors on the gas well productivity gradually increases, which helps optimize the main design parameters such as displacement, sand volume, and total liquid volume, enriching the evaluation methods for post fracturing productivity of coal seam pressure.

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 fracture network developed in coal rock serves as the primary channel for gas migration, significantly influencing the seepage capacity of coal reservoir. The geometric characteristics of fracture plays a crucial role on determining the flow characteristics of coal-bed methane. To study this, a two-dimensional fracture network model of coal rock was established using COMSOL Multiphysics simulation software, focusing on the coal samples of Baode block as the research subject. The effects of fracture length, density, opening degree and angle on production were investigated, providing valuable theoretical guidance for enhancing coal-bed methane production. The results indicate that fracture length, density, and opening degree have a positive correlation with the seepage capacity of coal rock, while the angle with the flow direction negatively impacts it. However, with the increase of length, density and opening degree, the improvement in flow rate slows down, and the effect of increasing single factor to improve coal-bed methane mining can be neglected, making it difficult to control the cost-benefit ratio. Among the factors influencing outlet, angle and density exert a more significant effect than length and opening degree. Considering the surface directional well plus the high pressure hydraulic cutting method, we can enhance the efficiency of coalbed methane development. This approach connects the natural fracture system using directional borehole and hydraulic slot, fully utilizing the permeability advantage of parallel surface cutting direction. The high-pressure hydraulic cutting process induces cracks in the coal seam, increasing the number and connectivity of diversion channels, thereby bolstering the production of coal-bed methane.

In order to solve the problem of frequent well laying in the coalbed methane field in south Yanchuan due to sand production（pulverized coal）, a novel drainage pump in south Yanchuan coalbed methane well has been developed. The novel drainage pump is designed as a forced pull rod hemisphere-type seal, and the plunger assembly adopts a hollow design. The pump diameter is ø38 mm, the stroke is three meters, the stroke time ranges from one to three times per minute, and the displacement is 4.8~14.6 m³/d. The novel drainage pump is used together with hollow rod and tubing, forming a dual-channel integrated pipe string for production and cleaning. It can not only meet the normal drainage gas production, but also facilitates well flushing and discharging pulverized coal. In addition, the flushing fluid does not enter the stratum during well flushing, avoiding the pollution of the flushing fluid to the stratum and preventing the failure of the fixed valve and the pump from being stuck caused by the deposition of pulverized coal or sand in the coalbed methane field drainage well. In 2022, the novel drainage pump was applied in two wells in the south Yanchuan coalbed methane field, and since then, no fixed valve failure or pulverized coal card pump has occurred. As a result the average pump inspection period of measure wells has been extended by 285 days. Field tests demonstrate that the novel drainage pump has the dual functions of normal gas drainage and coal powder discharge through well flushing, providing a new technical support for improving the overall development level of coalbed methane field in south Yanchuan.

Considering complex shape and non-uniform distribution of fracturing fractures in shale reservoir, on the basis of multiple migration mechanisms a unified apparent permeability model is developed, incorporating two types of pore apparent permeability based on multiple migration mechanisms. This model serves as the foundation for establishing a gas reservoir-fracture-wellbore coupled seepage model, utilizing real space source function theory and pressure drawdown superposition principle. Through simulations and analyses, the study investigates the effects of micro seepage, fracture shape and non-uniform distribution of fractures on shale gas productivity. The demonstrate that micro seepage significantly impacts shale gas well production, with daily gas production being 20.3 % higher when considering micro seepage during the initial stage compared to neglecting it. Furthermore, the productivity of wells with complex fractures is lower than that of wells with ideal rectangular fractures, and star-shaped fractures exhibit the lowest productivity. The non-uniform distribution of fractures also affects the productivity of horizontal wells, and an optimal fracture layout is identified. The model takes into account both the micro seepage mechanism and actual fracturing fracture of shale gas, providing valuable guidance for the productivity research of fractured horizontal wells in shale gas reservoir.

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.

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.

Traditional methods for predicting shale gas well production often struggle to effectively analyze the complex relationship between reservoir parameters, fracturing parameters and production. To address these challenges, a novel approach is introduced, involving the construction of characteristic parameters based on physical meaning and random combination. The small batch gradient descent method（MBGD） is adopted as the training function to develop an improved artificial neural network prediction model for shale gas well production. An example is utilized to demonstrate the effectiveness of the improved artificial neural network model in predicting shale gas well production. The model’s performance is evaluated using the mean squared error（MSE） and the modified determination coefficient（T）. The results indicate that the predictions from the improved network model align well with the actual production data. Moreover, the model exhibits superior prediction accuracy and stability compared to the traditional BP（error backpropagation algorithm） neural network model. With its high accuracy and reliability, the proposed model can provide valuable support for fracturing optimization design and productivity evaluation in shale gas reservoirs.

Peak shaving and supply guarantee are the functions of Underground Gas Storage（UGS）. The accurate prediction of the UGS construction index is related to the number of new wells and investments. When a complex fault block reservoir is transformed into UGS, it encounters three-phase flow（oil, gas, and water） during multi-cycle and high-velocity operations. The petrophysical properties of oil and gas are greatly affected by temperature. Without considering the temperature disturbance after cold gas injection and the additional pressure loss of high-velocity turbulence, the index prediction accuracy of the existing numerical simulation methods for UGS is low. To improve the accuracy of index prediction for a UGS rebuilt from a complex fault block oil reservoir, combined with fluid viscosity-temperature and high-velocity turbulence experiments, a coupled mathematical model of seepage and temperature is established. The model is solved discretely using the Finite Volume Method（FVM）, with a Two-Point Flux Approximation（TPFA） scheme for spatial discretization and a backward （implicit） Euler scheme for temporal discretization. The material balance and pressure of the reservoir and single well in the depletion development stage are matched with high precision. The sensitivity analysis of the UGS operation index is carried out in an example. The results show that the disturbance of the cold gas injection temperature field and high-velocity non-Darcy effect is the main controlling factors of accumulative oil production and gas volume error respectively. The well control temperature range increases logarithmically with the gas injection rate and the water-phase seepage capacity increases when the oil-phase and gas-phase seepage capacity decreases significantly, resulting in the increase of the produced liquid volume and the decrease of formation pressure. The additional pressure drop caused by high-velocity turbulent flow results in some injected natural gas not being produced, leading to an increase in natural gas reserves and pressure over successive cycles.

The medium-deep geothermal exchanger featuring a U-shaped pipe configuration presents an optimal solution for geothermal energy heat exchange due to its capability to deliver higher temperature water, achieve greater heat extraction rates, and maintain minimal flow resistance. A layered analytical model for such exchanger is established based on the theory of thermal resistance in series methods. Experimental results are employed to validate the accuracy of this layered analytical model. By focusing on the Guanzhong Basin in Shaanxi Province as the focal point of research, the model investigates the influence of subterranean stratification in thermal conductivity and volumetric specific heat on the outlet water temperature and heat extraction rate throughout an entire heating period for a 3 000 m deep geothermal exchanger with U-shaped pipe. The findings reveal that the underground thermal conductivity stratification has a significant impact on the heat transfer performance. A simplistic approach using average thermal conductivity, as opposed to a detailed accounting of layered conductivities, results in an overestimation of outlet water temperature and heat extraction rate by approximately 6 % to 15 %. However, specific heat stratification exerts minimal influence on the subterranean heat transfer dynamics. This underscores the importance of considering the effects of underground thermal property stratification in the design and analysis of the heat transfer performance of a medium-deep geothermal exchanger with U-shaped pipe. For precise modeling and results, it is recommended to segment the underground area into at least eight distinct layers.

Cap rock is the most important geological structure in CO₂ storage, and the characterization method of its sealing capacity is a hot research topic at present. Aiming at the problem of evaluating the sealing ability of caprock, based on the theory of coupling parallel capillary bundle and DLVO（microscopic force of charged surface passing through liquid medium）, considering slip effect and water film effect, the theoretical calculation method of caprock breakthrough pressure is established, and the accuracy is verified with experimental data. The variation of breakthrough pressure with slip length and effective capillary radius is studied by analyzing the influencing factors. The results show that the relative error between the calculated breakthrough pressure and the experimental data of six core samples is between 0.317 % and 10.800 %. The smaller the slip length and the larger the effective capillary radius, the smaller the breakthrough pressure.

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.

To address the challenges of test instrument obstruction and the suboptimal deployment of concentric stratified water injection in the Subei complex fracture block oilfields, an innovative approach involving the use of a hollow rod for pipe cleaning was introduced. This method focused on two key areas: the implementation of a flowback preventing water dispenser and the application of chemical sand control technology to maintain the cleanliness of the water injection pipe. In addition, a polymer gel profile control system was designed to mitigate the disparities between layers, aiming to minimize the influence of stratum grade differences on measurement and adjustment processes. This suite of supporting technologies has been applied to testing wells a total of thirteen times. The on-site tests have demonstrated that this approach is effective in preventing the obstruction of testing instruments and in simplifying the deployment process for layered water injection. Notably, the success rate of testing wells for these annual supporting measures reached 100 %, marking a significant achievement. Furthermore, the overall success rate of concentric layered water injection wells increased from 74.4 % to 84.4 %. The implementation of this method offers a dual advantage of reducing costs and enhancing efficiency, particularly in the context of optimizing fine water injection.

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.

In order to study the physicochemical reaction law of carbonate rock reservoirs under the condition of CO₂ geological storage, lab experiments on the reaction of carbonate rocks and supercritical CO₂ under reservoir conditions were carried out with the carbonate reservoir of the Sinian Dengying Formation reservoirs in the Sichuan Basin as the research object. The response characteristics of carbonate porosity, permeability, and pore structure to supercritical CO₂ environment were investigated by the pressure pulse attenuation method, scanning electron microscopy method, and nuclear magnetic resonance method. The test resulted in an increase both in the porosity and permeability of the carbonate rock. The maximum porosity change rate is 32.35 % and the permeability increases by eleven times. Additionally, micro-fractures appear after the test, and the proportion of the micro-fractures with the aperture of 20~50 μm increases. By using X-ray diffraction and contact angle techniques, the mineral makeup and wetability of carbonate rocks were examined. The average content of main minerals quartz increased by 12.6 %, the average content of calcite decreased by 22.3 %, and the hydrophilicity increased. Brazilian splitting technique was used to examine the mechanical characteristics of carbonate rocks both before and after supercritical CO₂ immersion. The tensile strength of carbonate rocks was discovered to have fallen by 18.28 %, causing damage to the rocks, and the compaction stage of the load-displacement curve was longer. This work examines the effects of supercritical CO₂ dissolution on the porosity, permeability, mineral composition, and rock mechanical characteristics of carbonate rocks, and provides theoretical evidence for the geological storage of CO₂ in carbonate reservoirs.

Shallow geothermal energy, with applications ranging from road snow melting and deicing to building heating/cooling, primarily utilizes closed-loop vertical buried pipes for resource exploitation. These pipes function by exchanging heat with the subterranean zone under specific cooling or heating loads. Given the limited capacity of a single vertical ground heat exchanger to harness geothermal resources, arrays of these exchangers are more commonly employed to effectively tap into shallow geothermal resources. However, the underground temperature field can be significantly affected by the heat exchange process between the ground heat exchanger array and the surrounding soil. Improper design and operational conditions can lead to an imbalance in the underground temperature field, potentially resulting in energy deficiencies and the malfunctioning of Ground Source Heat Pump Systems（GSHPS）. Therefore, optimizing the design and operation scheme of ground heat exchanger array is the key to solve the imbalance of underground temperature field. The review summarizes the domestic and foreign research results, outlining various methods for energy storage and removal, incorporating auxiliary heating and cooling sources, and exploring relevant optimization techniques. The borehole array design optimization methods include primarily the distance between the pipe and the borehole layout. The energy storage/removal section mainly introduces the latest research results of borehole heat exchanger array by using external heat/cold sources such as solar energy and industrial waste heat. The auxiliary method mainly describes the latest researches on the application of resources like solar energy and heating towers. The operation control strategy mainly analyzes the operation control of the ground source heat pump system, including the peak cooling and heating load operation, intermittent operation, partition operation, system control strategy, etc. By thoroughly examining these optimization approaches and operational control strategies, the review provides a comprehensive analysis of the advantages and disadvantages of each scheme. This detailed evaluation serves as a valuable reference for improving the energy efficiency of GSHPS, ensuring sustainable and effective utilization of shallow geothermal resources.

Underground Gas Storage（UGS） is a complex, multifaceted process with multiple stages and a long operational cycle, making it a long-term systemic endeavor. The lifecycle of gas storage encompasses various phases including site selection evaluation, scheme design, engineering construction, production and operation, optimization of operations, and eventual abandonment. The integration of these phases is crucial for the safe construction and efficient operation of gas storage facilities. Given the complexity and scope of UGS, there is a pressing need for a comprehensive system that encompasses “management decision-making, monitoring, early warning, simulation analysis, and production control” to facilitate the integrated application of the entire gas storage process. This paper specifically addresses the construction plan of Sinopec gas storage, aligning with the national mandate for “industrialization and informatization” integration. It aims to bridge the gap between management, research, and production in gas storage, addressing both managerial and technical challenges throughout the entire process of site location, design, operation, and analysis. The ultimate objective is to enhance quality and efficiency in gas storage operations. An integrated platform for UGS has been designed and developed, focusing on “production monitoring, tracking analysis, remote control, and auxiliary decision-making” as its core components. Research indicates that this platform has significantly advanced the digitalization of various aspects of gas storage, such as site optimization, geological research, injection and production control, and peak shaving optimization, across all nodes. It enables precise control over production process nodes, intelligent analysis of production and operational trends, and scientific decision-making for production and control. The research shows that the platform has realized the digital improvement of the gas storage site optimization, geological research, injection and production control, peak shaving optimization and the whole node, accurately controlled the production process nodes, intelligently analyzed the production and operation trend, scientifically made the production and control decisions, and realized the integrated management and research of the gas storage site optimization, scheme design, production and operation, and dynamic analysis.

With the continuous development of shale gas, the interference of adjacent wells is increasing during the fracturing of horizontal wells, which has a great impact on the production of gas fields, the safety of casings, and the string of gas wells. The influencing factors of the interference between fracturing wells and the countermeasures to reduce the interference need to be clarified.The field performance of fracturing interwell interference is confirmed by downhole pressure monitoring. Through production dynamic tracking analysis and microseismic monitoring results, it is basically clear that well spacing, fracturing transformation intensity, and natural fractures are the main factors affecting the interference between horizontal wells during fracturing. Three governance strategies have been proposed to reduce fracturing interference, including optimization of fracturing design source, on-site management of gas production wells, and production operation adjustment. These measures have achieved good improvement effects in on-site applications.

The South China Sea's natural gas hydrate reservoirs, primarily composed of clayey silt with non-diagenetic properties, undergo creep during depressurization development. The implications of this creep on key reservoir characteristics such as permeability, porosity, pressure, temperature, hydrate saturation distribution, and gas well productivity remain unclear. To address this, a combination of water seepage experiment data from clayey-silt cores and numerical simulation methods was employed to study the development of these hydrate reservoirs through depressurization-induced vertical wells. The simulation results show that the creep effects reduce the effective reservoir porosity and permeability while developing South China Sea natural gas hydrate reservoirs using a depressurization-induced vertical well. Specifically, the pressure drop is predominantly observed near the well, accompanied by a significant decrease in temperature around the well. Additionally, the reservoir creep results in a more pronounced pressure drop funnel within the reservoir. The hydrate decomposition mainly occurs at the regions of the near-well, the top of hydrate layer A, and the bottom of hydrate layer B, and the radius of hydrate decomposition is decreased by 66.7 % due to creep effects. The reservoir creep effects reduced the gas well productivity, and the cumulative production of the gas well in five years decreased by 87 %. The creep of the South China Sea natural gas hydrate reservoir dominates while the production pressure difference is greater than 4 MPa. As the production pressure difference is larger, the increasing degree of cumulative production gradually becomes smaller. A production pressure difference lower than 4 MPa is recommended for future long-term development. This study provides a reliable theoretical basis for developing South China Sea natural gas hydrate efficiently.

For designing effective injection and production well spacing in low permeability reservoirs, it's essential to consider the pressure-sensitive effects arising from various pressure changes during the operation of injection and production wells, along with the impact of changes in the start-up pressure gradient. This study builds upon the basic seepage laws of low-permeability reservoirs to establish a seepage equation that incorporates the effects of the starting pressure gradient and pressure sensitivity. Utilizing the stable successive substitution method, the study examines the pressure distribution and the mechanism of reserve production under typical injection-production patterns. Based on the different requirements of the daily output of oil wells in an actual oil fields, a method for solving the effective injection-production well spacing of low-permeability pressure sensitive reservoir is determined. The study shows that, using the pressure sensitivity of the injection and production well area as a benchmark, there is a notable difference in the calculated results for well spacing when compared with scenarios where pressure sensitivity is either not considered or only considered for the production well area. Specifically, these differences are +9.8 % and -20.6 % under the same conditions. Considering the production limit requirements, the effective injection-production well spacing is about 0.7 ~ 0.9 times of the limit injection-production well spacing under normal conditions, which can better guide the reasonable deployment of the development well pattern of low permeability pressure sensitive reservoirs.

CCUS technology is a crucial technology for achieving the goal of “dual carbon”, involving process such as capture, transportation, injection, extraction and re-injection. Shengli Oilfield has developed essential engineering technologies for transportation and injection through years of exploration. To manage the phase changes of CO₂ and the risks of long-distance leakage due to pressure loss and temperature variations, a safety transportation technology for long-distance CO₂ pipelines was established. This technology is based on phase state control, ensuring efficient and cost-effective transportation. developed China’s first casing pipeline transport pump; and built China’s longest long-distance supercritical pressure CO₂ pipeline, which makes up for the shortcomings of the long-distance CO₂ transport in China. In order to meet the needs of high-pressure injection of large-displacement CO₂ in the demonstration project, China’s first high-pressure dense-phase injection pump has been developed, realizing high-pressure dense-phase injection of 40 MPa. In view of the problems of high injection pressure, high gas-to-liquid ratio, low pumping efficiency, and corrosion of CO₂, the engineering process technology of injection and extraction supporting such as safe injection of gas pipeline columns for pressure-free wells, multi-functional oil recovery pipeline columns, and corrosion prevention of CO₂ repulsion has been formed to realize high-efficiency, safe injection and extraction and long-lasting corrosion protection. China's first multi-field, multi-node, one-million-ton CCUS demonstration project integrating pipeline transport engineering, injection equipment, flooding and sequestration, injection-extraction process, and gathering-transmission and re-injection, has been operating well and realizing “smooth, safe, efficient and green” operation in all aspects. This summary of the one-million-ton CCUS transportation-injection-extraction process and supporting equipment in Shengli Oilfield is intended to provide reference and guidance for the construction of subsequent CCUS project.

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.

CO₂ solubility in saline aquifer is an important parameter for estimating the volume of CO₂ that can be dissolved and stored underground. To rapidly and economically evaluate and analyze the solubility of CO₂ in saline aquifers, a study was conducted using grey GM（1,1） modeling based on existing data of CO₂ solubility in water under various temperatures, pressures, and salinities. By using Markov theory, the state interval was divided, the state transition probability matrix was constructed, and the prediction results were revised. A prediction model of CO₂ solubility in saline aquifer based on grey Markov theory was proposed. The results showed that the average relative errors between the predicted values of the grey Markov theory and the measured values were 1.52%、17.73%、0.21% and 3.97%, respectively. The average relative errors between the prediction results of the gray GM（1,1） model were 2.37%、19.29%、3.62% and 3.94%, respectively. The predicted values of the grey Markov model were more consistent with the measured data, and the prediction performance of the model was better, so as to provide a new method for predicting the solubility of CO₂ in underground salt water.

In order to explore the characteristics of fracturing fractures of shale with weak plane development, a fracture propagation model of shale reservoirs taking the weak plane of bedding and natural fractures into account is established by the three dimension discrete element method to analyze characteristics of fracturing fractures under different injection rates, fracturing fluid viscosity, bedding tensile strength and natural fracture cohesion. The research results show that the high-displacement injection and high fracturing fluid viscosity can reduce the restriction of near-wellbore bedding on hydraulic fractures and increase the ability of hydraulic fractures to penetrate layers. The hydraulic fractures can continuously pass through six beddings when the fracturing fluid viscosity is increased to 10 mPa·s. The tensile strength of the bedding connected to the natural fracture is not the main factor affecting its own opening. The greater the natural fracture cohesion is, the greater the natural fracture shear strength and the lower the degree of opening of natural fracture will be. When bedding and natural fractures develop near the wellbore, the hydraulic fractures can be fully extended by increasing the injection rates and the fracturing fluid viscosity in the early stage. For shale which is easy to form simple double-wing fractures, pumping an appropriate amount of acid in the early stage can dissolve the natural fracture filler, so as to reduce the natural fracture cohesion, increase its opening degree, and improve the complexity of fractures.

The classification and identification of shale gas “sweet spot” involves a variety of different factors, which requires personal experience, and is usually time and resources consuming. In order to solve this problem, an efficient and effective classification and identification method for shale gas “sweet spot” based on the Random Forest method is proposed. Firstly, data from ten wells in Changning area are selected and eleven features are selected for “sweet spot” classification by the Kendall correlation. Then, the single decision tree and the Random Forest method are used for the “sweet spot” classification and identification. Finally, the results are verified and the Random Forest parameters are optimized. The experimental results show that although the prediction accuracy of a single decision tree can reach 97.7 %, it shows a trend of overfitting, and the fitting accuracy is greatly reduced by only 70.7 % after pruning. The Random Forest method avoids the disadvantage of the single decision tree method, and the prediction accuracy reaches 98 %. Moreover, the computational cost is low, which can effectively reduce the time loss and save the labor cost. As a result, the proposed Random Forest machine learning method with multi-source information is an effective shale gas “sweet spot” classification and identification method.

In the process of CO₂ injection and storage of a single well in depleted gas reservoirs, the injected CO₂ causes the rebalance among gas, water and solid, and the accompanying CO₂ dissolution, water evaporation and salting out affect the physical properties of the formation near this well. Therefore, taking depleted gas reservoir in western Sichuan as an example, the SRK-HV equation and salting out model are used to analyze the three-phase change rule during the CO₂ injection process of the depleted gas reservoir. The researches show that during the CO₂ injection process in the constant volume system, with the increase of the number of mole of CO₂, the gas phase pressure increases, the CO₂ solubility gradually increases, and the mole fraction of H₂O in the gas phase gradually decreases, but the total number of mole of H₂O in the gas phase continuously increases, indicating that the total evaporation of water increases. In addition, the water phase volume reduction caused by water evaporation is smaller than the initial water phase volume, so the increase of formation water salinity is small. The dissolution of CO₂ accelerates the precipitation of CaCO₃, while inhibiting the precipitation of CaSO₄ and CaSO₄·2H₂O. In calcium chloride type formation water, CaCO₃ and CaSO₄ will be separated with the increase of salinity. The research results has certain reference significance for the study of water evaporation and salting out during CO₂ injection in depleted gas reservoirs.

The pore utilization characteristics of CO₂ during shale oil displacement are a crucial indicator for evaluating its effectiveness in enhancing shale oil reservoir recovery rates. Therefore, experiments on supercritical CO₂ displacing shale cores were conducted in the laboratory, and nuclear magnetic resonance（NMR） online core scanning technology was used to study the pore utilization characteristics and patterns of CO₂ displacement in shale oil reservoirs. The results indicate that immiscible flooding by supercritical CO₂ mainly develops the oil in shale pores with radius of 0.1~3.0 μm, but the oil content in pore radius less than 0.008 μm actually increases. The analysis shows that CO₂ brings shale oil from large pores into small pores through pressure difference and diffusion effect in the shale layer and makes oil undergo adsorption and retention. After a displacement time of five hours, the recovery rate of shale oil by CO₂ displacement reached 35.7%, indicating a relatively effective oil displacement result.

Carbon Capture, Utilization, and Storage（CCUS） technology is pivotal for global carbon emissions reduction and plays a crucial role in ensuring China's energy security and fostering the concurrent growth of its economy. It also supports China's path towards sustainable development and ecological advancement. While significant strides have been made in CCUS technology within China, challenges persist that hinder its widespread adoption. Based on literature research and work accumulation, the current status of CCUS technology both domestically and internationally is described, and the current technical challenges and research directions that CCUS technology are pointed out. The existing research efforts have provided countermeasures to address the challenges of high energy consumption and cost of capture technologies, the need for further research on oil recovery and storage technologies, the high energy consumption and low conversion efficiency of chemical utilization technologies, and the lack of a technical system for monitoring and evaluating the safety of storage. These countermeasures are as follows: ①Diversified integration of different carbon capture methods to achieve cost reduction at the source based on the characteristics of different emission sources; ②Tackling multi-objective optimization techniques, coordinating and optimizing oil recovery efficiency and CO₂ storage rate; ③Continuously developing new catalysts to accelerate the conversion reaction of CO₂ and improve conversion efficiency; ④Fully draw on the carbon tax policies of countries such as the United States and Australia, explore fiscal and tax incentive policies suitable for China's CCUS industry, increase economic benefits, and enhance enterprise enthusiasm; ⑤Establish a series of standard specifications covering all aspects of the CCUS entire chain, guide the implementation of engineering construction, and reduce enterprise risks from a standardized perspective. Through the implementation of these measures, the rapid development of CCUS technology in China will be promoted, and greater contribution will be made to achieving the goal of carbon neutrality.

As geothermal resource development continues to advance, addressing the challenge of sustainably and efficiently harnessing these resources becomes increasingly critical. This involves achieving a balance between the exploration and sustainable use（or "irrigation"） of geothermal resources. To this end, the application of Petrel, a geological modeling software originally designed for the petroleum industry, has been adapted for geothermal geological modeling, offering a promising solution. The adaptation of Petrel for geothermal purposes involves establishing a geospatial platform within the software to manage and analyze a wide range of geothermal geological data. This platform enables comprehensive research into geothermal geological elements by integrating diverse data sets to the fullest extent, thereby enhancing the quality and scope of geothermal geological studies. This approach involves scaling up from traditional small-scale oil and gas reservoir modeling to large-scale thermal reservoir modeling. Such a transition not only maintains the accuracy of the models but also aligns with the scale requirements unique to geothermal geology. Utilizing Petrel, models of the thermal reservoir temperature field, pressure field, and effective thermal reservoir can be constructed. This is achieved by combining various types of data and employing both deterministic and stochastic modeling techniques, thereby establishing a robust method for thermal reservoir geological modeling using Petrel. A key advantage of employing a 3D geological model for calculating effective thermal reservoir resources is its reduced sensitivity to reservoir heterogeneity. This approach more accurately reflects real subterranean conditions, providing a more reliable basis for resource evaluation. The resulting accurate 3D geological models and resource assessments lay a solid foundation for the numerical simulation of thermal reservoirs and the development of comprehensive thermal reservoir management plans. This, in turn, supports the scientific and sustainable exploitation and utilization of geothermal resources in the area, ensuring their efficient and responsible development.

CO₂ storage in abandoned oil and gas reservoirs can reduce the direct emissions of greenhouse gases in the atmosphere, which is one of the effective ways to mitigate the greenhouse effect. Improving the conventional gas-liquid phase equilibrium theory and applying the thermodynamic equation of state to study the CO₂-hydrocarbon-groundwater system are of great significance to reveal the dissolution mechanism of CO₂ buried in the subsurface. The research progress of thermodynamic equation of state in the phase equilibrium calculation of CO₂-hydrocarbon-formation water system at home and abroad is summarized.The shortcomings in its practical application are pointed out, and its development trend is analyzed, including: the equation of state and mixing rules suitable for non-ideal systems should be further studied to accurately predict the change law of thermodynamic properties of the system; the expansion of the difference of formation water ions in the research system to make it consistent with the real CO₂ storage conditions; the physical process of phase change in CO₂ is coupled with the chemical process of mineral dissolution and precipitation in formation water.

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.

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.

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.

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 issue of coal fine production is increasingly prominent in the development of coal-bed methane. Implementing appropriate measures to control the migration and production of coal fines is crucial for achieving stable and high production of coal-bed methane wells. However, the characteristics of coal migration and production in the coal seams of Baode block remain unclear, which hinders the efficient development of coal-bed methane in some wells in this area. To address the problem of coal fine production in coal-bed methane development, core flooding experiments were conducted to investigate the migration and production characteristics of coal fines concerning influencing factors such as formation water velocity, salinity, gas-water ratio, effective stress, etc. The experimental results revealed that during the drainage stage, the amount of coal fines produced at low formation water flow is minimal, with coal fines moving within fractures and accumulating at the outlet, forming a coal powder filter cake. However, when formation water flow surpasses the critical flow, a significant amount of coal fines is produced. A substantial pressure fluctuation can flush out the coal fines obstructing the outlet. Furthermore, the salinity of the formation water plays a role in carrying coal powder, with higher salinity increasing its transport capacity. While single gas phase flow is not effective in displacing the coal fine migration and production, two-phase flow with a gas-water ratio of 50∶50 exhibits a stronger ability to carry coal powder. The concentration of coal fine in the produced liquid continued to decline with the increase of the effective stress loaded on the coal, Similarly, the holding pressure at the outlet follows a downward trend, but the displacement pressure difference increases. The research findings provide essential data and a theoretical basis for implementing on-site prevention and control of coal fine production.

The exploration and development of shale gas in Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation in Nanchuan and its adjacent blocks have yielded fruitful results. However, it is crucial to pay closer attention to the comprehensive use of fluid characteristics for analyzing the differences in shale gas preservation conditions in each block. Research findings reveal the following key points: ① With the prolongation of recovery time, the mineralization degree of the produced water gradually increases, exhibiting notable differences from fracturing fluid. This suggests the presence of the presence of movable CaCl₂-rich formation water in shale layer, characterized by a mineralization degree exceeding 50 g/L; ② Enriched and high-yield wells exhibit low water production, low mineralization and rich in NaHCO₃, which are indicative of condensate water; ③ Under different preservation conditions, the deuterium oxygen isotopes of the produced water vary with time. The high pressure stable block in the basin gradually deviates from the atmospheric precipitation line, while the normal（low） pressure complex block outside the basin remains close to the atmospheric precipitation line; ④ From the inside to the outside of the basin and from deep to shallow, the homogenization temperature of fluid inclusions in shale fracture filled calcite veins gradually decreases（from 240 ℃ to 90 ℃）. Simultaneously, the metamorphism coefficient of the inclusions also gradually increases, reflecting the degree of differential damage of shale gas preservation conditions.

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.

The shale oil of Lucaogou Formation in Jimsar Sag has the characteristics of extremely low original permeability and high viscosity of crude oil, making it uneconomical to produce under natural conditions. Field practices have demonstrated that dense drilling combined with high-intensity volume fracturing is one of the most effective means to achieve large-scale development of shale oil. However, how to slow down the decline rate of oil wells and improve the recovery rate per well remains a pressing issue to be addressed. From 2019 to 2022, the researches and field tests of CO₂ pre-fracturing assisted production technology were carried out in Jimsar shale oil block. The application effect of CO₂ pre-storage fracturing and CO₂ huff and puff in Jimsar shale oil block was systematically studied and analyzed. The results indicate that supercritical CO₂ has the effects of miscible energy increase, dissolution to improve reservoir conditions, improve imbibition replacement efficiency, and increase the complexity of fracture network. The optimal injection volume, injection speed, and injection methods were determined, and a preliminary technological system for CO₂ pre-fracturing in shale oil reservoirs was established. According to the prediction of production data, the CO₂ pre-fracturing process can increase the final recovery rate by about 20%, which provides a reference for realizing the benefit development of shale oil and improving the development effect of other types of shale reservoirs.

To quantitatively assess the quality of deep hydrothermal geothermal resources in the target area, with a focus on middle-deep hydrothermal resources in sedimentary basins, a comprehensive analysis is conducted. This analysis delves into the effects of geothermal geological conditions, the nature of the geothermal resources themselves, and the quality of geothermal fluids on the overall resource quality. For this assessment, sixteen indicators that significantly impact the quality of geothermal resources are identified. These indicators are then incorporated into an Analytic Hierarchy Process（AHP） framework, which assigns weights to each indicator, facilitating a quantitative evaluation. The middle-deep hydrothermal geothermal resources are divided into three levels and seven categories. Level Ⅰ areas are resource advantage areas that can be efficiently developed; Level Ⅱ areas are resource rich areas that meet the requirements of industrial development; Level Ⅲ areas are resource non enriched areas. Ultimately, a quantifiable resource evaluation system is formed to provide data analysis conclusions on whether geothermal resources can be utilized. The relevance and practicality of this evaluation system are demonstrated through its application in a case study. The example of geothermal development and usage in the Caofeidian District of Tangshan City, Hebei Province, serves as a testament to the system's effectiveness in guiding decision-making processes for geothermal resource utilization.

The adjustment of the flow field proves to be an effective way for enhancing the recovery of remaining oil during the high water cut development stage in a water-flooding oilfield. As the water flooding oilfield enters the high water cut development stage, a dominant flow field gradually forms between oil and water wells, resulting in the ineffective circulation of injected water. As a result, the effect of reservoir development is reduced. To address this issue, a flow field adjustment model is established based on standard determinant well pattern arrangement using Python programming language, guided by the working principle of flow field adjustment. In this model, the flow field streamlines transition angles are 27°, and 45° respectively. The finite difference method is employed to simulate the dominant flow field range before and after the adjustment. The results demonstrate that the nine-spot method and the five-spot method could enhance the oil displacement efficiency, while the flooding efficiency of the M-shaped well-mesh is relatively low. Moreover, the 45°-streamline transition proves to be particularly beneficial for oil exploitation during the high water cut development stage in a water-flooding oilfield. The study holds significant guiding significance for adjusting the well pattern and enhancing the recovery efficiency, thereby facilitating the extraction of remaining oil in the high water cut development stage.

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.