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.

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.

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.

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.

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.

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.

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.

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 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.

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.

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.

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.

Palaeogeomorphology and palaeo-environment conditions are the main environmental factors affecting the sedimentation. Due to the frequent water change, complex terrain and high difficulty in seismic identification and tracking, the reconstruction research of palaeogeomorphology and palaeo-environment in the 3rd member of Funing Formation in Qintong Sag of Subei Basin is still insufficient, which affects the overall exploration evaluation of the study area. In order to clarify the palaeogeomorphology and palaeo-environmental conditions of the 3rd member of Funing Formation in Qintong Sag during the deposition period, the formation core, logging data and rock material data are comprehensively analyzed. The semi-quantitative reconstruction of the palaeogeomorphology of the 3rd member of Funing Formation is carried out by combining the palaeo-geologic map, impression method and residual thickness method, and the pyrolysis experiment data, TOC and trace element content data of 33 rock samples from two wells are selected to carry out the palaeo-environment reconstruction analysis. Accordingly, paleogeomorphology reconstruction in map form and the curves of palaeo-environment changes of the 3rd member of Funing Formation in Qintong Sag are drawn, which prove that the study area is a half-graben, lower in the South and higher in the North with the convergence across the east-west direction, the climate is warm and humid during the sedimentary period, the water body activity is frequent and recurrent, the water salinity is low, the multiple source is supplied intermittent, the material source input continues to increase, and the deposition rate is fast. Therefore, the corresponding relationship between stratigraphic physical parameters and paleogeomorphology, geochemical parameters and paleoenvironment in the study area are clarified, which provide reference for the further exploration and development.

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.

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.

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.

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.

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.

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.

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.

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.

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 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.

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.

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.

Offshore natural gas hydrate reservoirs are often accompanied by a large amount of free gas. However, the low permeability of the reservoir limits the flow of gas and water in different layers. Therefore, the fully exploitation of the hydrate-dissociation gas and free gas in the reservoir is the key to improve gas production efficiency. Based on the actual geological data in the Shenhu area of the South China Sea, the TOUGH+HYDRATE code is used to establish the numerical model of the combined exploitation of three different hydrate reservoirs with vertical wells. The spatial changes of gas production, water production, temperature, pressure field and hydrate saturation are analyzed, and then the optimized depressurization production strategy of natural gas hydrate is put forward. The results show that during the depressurization production, gas and water are continuously collected to the production well, and the temperature and pressure around the well drop rapidly. After continuous production for ten years, the water production rate continues to increase with the decrease of gas production rate. The cumulative gas production of three-layer combined mining method is up to 4.59×10⁶ m³, and the cumulative water production is 8.31×10⁵ m³. Hydrate dissociation is controlled by the depressurized gradient, hydrates around the well are preferentially dissociated, and the flow of underlying water will accelerate the dissociation of reservoir hydrates.

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.

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 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.

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.

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.

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.

Accurate characterization of the flow characteristics of shale gas horizontal wells is the key basis for quantitative evaluation of production performance and further guidance of development program optimization design. In order to explore the gas-liquid two-phase flow law of shale gas horizontal wells at different inclination angles, a three-dimensional simulation wellbore model with the pipe diameter of 0.124 m, pipe length of 10 m and inclination angles of 0°, 5°, 10°, 15°, 20°, 30°, 45°, -5°, -10°, -15°, -20°, -30°, -45° respectively is constructed. The volume model is used to track the gas-liquid interface. The characteristics of gas-liquid two-phase flow in wellbore are dynamically monitored. The flow pattern, velocity and holdup distribution characteristics of wellbore with 300 m³/d liquid volume and 500 m³/d gas volume are obtained by simulation experiments under various well inclination angles, and the influence law of well inclination angle on gas-liquid two-phase flow characteristics of shale gas horizontal wells is deeply analyzed. The results show that the flow pattern of up-dip pipe（well angle is larger than 0°） is characterized by slug flow, and the average fluid velocity changes in a single-peak form with the increase of well angle, and the peak appears when the well angle is 15°. The flow velocity at the gas-liquid interface is the lowest, and the bottom water holdup is larger with lower well angle is than that with higher well angle, and reaches the maximum value when the well angle is 10°. The flow pattern of down-dip pipe（well angle is less than 0°） is characterized by stratified flow, and the average fluid velocity is linearly increasing with well inclination angle. The flow velocity at gas-liquid interface is between the top and bottom value, and the bottom water holdup decreases with the increase of well inclination angle.

The development of the natural gas hydrate reservoirs has the typical characteristics of high risk, high difficulty and high investment, so the correct evaluation of development quality is a prerequisite and the key to the issue. In order to solve the problems that the evaluation index has limitations and the evaluation results has ambiguity for the development of the natural gas hydrate reservoirs, the factor set is chosen based on the main controlling factors, and the scoring criteria of main controlling factors are defined. The weight set is established by the comprehensive weight calculated by analytic hierarchy process, and then fuzzy comprehensive evaluation of development quality of natural gas hydrate reservoir is further completed. This method is used to evaluate the development quality of Messoyakha and other typical natural gas hydrate reservoirs, and the applicability and feasibility of the method are verified, so as to provide theoretical basis and technical support for the efficient development of the natural gas hydrate reservoirs.

Lithofacies analysis serves as the foundation for reservoir evaluation. However, due to the limited coring quantity and cost constraints, identifying lithofacies using logging data for uncored wells becomes crucial. In the Longdong area of the Ordos Basin, the lithofacies of the Chang-7 member have been classified into six types dependent on core identification results and imaging logging data. Based on core calibration, the logging response characteristics of different lithofacies were summarized, leading to the establishment of the lithofacies recognition mode using conventional logging curve. To achieve automatic lithofacies recognition in the study area, machine learning algorithms were employed. The traditional classification algorithms were affected significantly by the unbalanced sample. After comparing the application effects of different unbalanced data classification algorithm in the region, it’s found that bagging algorithm of ensemble learning notably improved the classification performance of all lithofacies by combining multiple classifiers. As a result, the overall lithofacies identification precision of this region has been improved by 20 %. According to the regional application results, the identification accuracy of single well can reach 84.33 %, demonstrating its practical applicability and effectiveness.

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.

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.

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.

Currently, the large-displacement slickwater fracturing process has become the primary method for developing unconventional oil and gas resource. However, the efficiency of this process is limited by the sand carrying capacity of slickwater, which results in rapid settlement and short migration distance of the proppant within the fractures, leading to a need for further improvement in the reservoir transformation effect. To address this issue, a water-soluble material is applied to coat the surface of the self-suspending proppant, enhancing its suspension effect in slickwater or clear water and thereby increasing the crack support volume. The self-suspending proppant meets the required technical standards, showing a total suspension time of less than 40 seconds in tap water at a 20 % sand ratio, and maintaining stable suspension for over two hours at 90 ℃ even during thorough mixing. In a practical on-site test at Mahu sandstone reservoir in Xinjiang Oilfield, continuous sand carrying was achieved using clean water, reaching a maximum sand concentration of 480 kg/m3 while maintaining stable construction pressure. The successful application of self-suspending proppant clear water fracturing technology in Xinjiang oilfield serves as a valuable reference for the selection of oil and gas resource technology in the future stage.

The stability of foam system is very important in the application of foam flooding and gas reservoir foam drainage agent. The influence of surfactant molecular structure and interface arrangement on the permeability and stability of foam liquid film is of great significance for the construction of highly stable CO₂ foam, but there is no systematic understanding at present. The betaine surfactant with four molecular structures is used as the research object, and the foam phase property evaluation is used as the research method. For the saturated adsorption capacity, foam liquid film permeability, foam stability and other phase properties, the surfactant molecular structure, interface arrangement, CO₂ foam liquid film permeability, foam stability and their correlation experiments are carried out. The results show that when the molecular head groups of surfactants are consistent, the hydrophobic carbon chain length increases, the hydrophobic effect increases, the molecules on the liquid film surface are arranged more closely, the permeability of foam liquid film decreases, and the stability of foam increases. When surfactant molecules have longer hydrophobic carbon chains, the enhanced hydrophobicity leads to a tighter arrangement of the liquid membrane and an increase in adsorption capacity, hindering the permeation behavior of CO₂ gas within the bubble and weakening the foaming ability of the foaming solution. Based on the regression analysis of the parameters obtained from four foaming systems, the correlation coefficient R² between foam life, foam liquid film molecular adsorption capacity and foaming capacity and foam liquid film permeability K is established. The fitting shows that R²>0.90. Therefore, the permeability of foam liquid film K can be used as one of the parameters to evaluate the stability of foam system and provide a reliable evaluation parameter for the screening of highly stable foam system.

At present, the researches on the heat transfer of the steam cavity edge in the SAGD production process mainly pay attention to the heat conduction between steam and the reservoir, while little attention has been paid to the convective heat transfer and changes of the reservoir physical properties affected by the temperature. However, the influence of both on the heat transfer effect and temperature field distribution cannot be ignored. By the comprehensive consideration of two heat transfer mechanisms of heat conduction and heat convection, as well as the influence of reservoir physical properties changes on heat transfer, a semi-analytical model is established through the conservation of mass, energy and mathematical coordinate transformation, and the temperature distribution at the edge of the steam chamber and the physical property distribution of the reservoir under the influence of temperature are obtained by differential solution. The results show that: ① the model proposed in this paper is more practical, with an accuracy improvement of 34 % and 11 % compared to the Butler's model and the Dong's models, respectively. ② By analyzing the relative relationship between convection and conduction under the change of reservoir physical properties, it is concluded that the proportion of the conduction heat transfer in the crude oil movable area is more than three times higher than that of the conduction heat transfer, the convection heat transfer accounts for the main proportion in the movable area of crude oil, but at the locations far away from the steam cavity, the conduction and convection work together, and it also gives relevant measures to improve heating efficiency.

In southern Sichuan, thousands of shale gas wells have been drilled, generating a vast amount of high-dimensional data during geological evaluation, drilling, and production processes. Predicting reserve recovery ratios through data exploration and analysis is essential for guiding the exploration and development of shale gas resources. To achieve this goal, a novel approach is introduced, which couples principal component analysis（PCA） and orthogonal partial least square（OPLS） analysis, enabling rapid and accurate prediction of reserve production degree. The new method is put to the test using Zhaotong shale gas well samples to evaluate its effectiveness in predicting reserve recovery ratios. The results show that the average accuracy of reserve recovery ratio prediction using PCA-OPLS method surpasses the anticipated result, that this algorithm can swiftly and precisely predict recovery ratios. With its advantages of simplicity, high accuracy, and promising application prospects, this method holds great potential for efficiently evaluating the production and recovery ratios of shale gas reserves.

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.

CCUS（Carbon capture, Utilization and Storage） technology is of great significance to the green and low-carbon transformation and the realization of the “dual carbon” goal, It includes important strategies like CO₂ enhanced oil recovery（EOR） and sequestration. Jiangsu Oilfield has been focusing on CO₂ EOR to improve recovery rates in the challenging fault block reservoirs of the Subei Basin. The company has developed four unique CO₂ EOR models suitable for these complex reservoirs, featuring techniques like gravity-stable displacement. A notable achievement is the successful pilot of the methods such as “simulated horizontal well” GAGD technology in Hua-26 fault block, which led to the one hundred thousand CCUS project tailored for such reservoirs. According to statistics, Jiangsu Oilfield has injected a total of 30.34×10⁴ t of liquid CO₂, with a cumulative oil increase of 9.83×10⁴ t, realizing a better production increase and economic benefits. These technical researches and tests can provide valuable insights for applying CO₂ EOR in similar complex reservoirs.

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.