The elastic two-phase method, also known as the pseudo-steady-state method or reservoir limit testing method, is a pivotal dynamic technique for estimating the original gas in place（OGIP）in well-controlled scenarios. This method is primarily employed in the initial testing of gas wells and for the OGIP assessment in varied lithologies, fault blocks, and fracture types of gas reservoirs. Since 1994, the pressure squared variant of this method has been recognized in the Chinese national oil and gas industry standards across four editions: SY/T 6098—1994，SY/T 6098—2000，SY/T 6098—2010，SY/T 6098—2022. This method, based on the pressure squared calculation, offers a robust approximation compared to its pseudo-pressure counterpart. The theoretical derivation of the elastic two-phase equation for pseudo-pressure, originally proposed by AL-HUSSAINY（1966）, and further simplified using WATTENBARGER's（1968）study on the relationship between μ_gZ and p, allows for representations using both pressure to the first and second powers. Notably, while the pressure to the first power method tends to under-estimate OGIP, the pressure squared method is inclined to over-estimate, as evidenced by practical applications. Currently, there is a lack of substantial literature on the pseudo-pressure elastic two-phase method both domestically and internationally.

The southwest margin of Ordos Basin has developed faults and fractures to varying scales, significantly enhancing the permeability of tight reservoirs and forming high-quality fault-fracture reservoirs against a backdrop of low permeability reservoir types. However, this also complicates the reservoir's homogeneity and the variability of its capacity, posing challenges for fine characterization of the reservoir's internal structure and for researching capacity control factors. To address these issues, the study employs spatial characterization of the fracture system, fracture classification, and capacity comparative analysis. Further, the development characteristics of the fault-fracture reservoir are defined through joint well-seismic and reservoir research. Key findings from this research include: 1） Establishment of the “binary four zones” model for fault-fracture reservoirs, which divides the reservoir into four distinct zones: the core fracture zone, the induced fracture zone, the micro-fracture transformation zone, and the matrix pore zone. Among these, the core fracture zone is identified as the primary contributor to production yield. 2） It is observed that the longer the fault extension length and the higher the solid drilling structure position, the higher the single well production capacity in the core fracture zone. The induced fracture zone's proximity to the fault correlates with higher production capacity, demonstrating the spatial impact of fault structures on reservoir productivity. 3） The production characteristics of fracture wells are categorized into three stages: ① the fracture system acts as the high yield stage; ② the fracture system serves as the storage stage and plays the role of diversion; ③ the fracture's primarily function in diversion. This research significantly increases the proportion of high-yield wells in the fault-fracture reservoir, providing crucial insights for guiding efficient, ongoing exploration and development activities in the Mesozoic reservoirs on the southwest margin of the basin. This strategic approach enhances understanding and management of fault-fracture reservoirs, optimizing resource extraction and improving operational efficiencies.

Under the “dual carbon” initiative, geothermal energy is gaining attention as a focus of development due to its stability, high quality, abundant reserves, and green, low-carbon attributes. Petroleum companies have inherent advantages in geothermal energy development, yet effective reference models and experiences for market-oriented and large-scale applications remain limited. Leveraging these advantages to advance geothermal energy development has become a new developmental challenge for petroleum enterprises. PetroChina Jidong Oilfield seized the opportunity to expand its geothermal business by utilizing a comprehensive resource assessment system, scientific planning, efficient project execution, and extensive management experience. The introduction of advanced sandstone reservoir pressure-free reinjection technology has successfully addressed the challenge of large-scale sandstone geothermal reservoir development, establishing a new model for urban district heating and clean energy substitution. This replicable and scalable “Jidong Model” provides a blueprint for traditional petroleum companies in geothermal resource development, fostering a green, low-carbon, and high-quality transformation in the industry through new productivity models.

Distributed optical fiber sensing technology, a cutting-edge method for monitoring hydraulic fracturing, has been successfully applied in various oil fields to enable real-time monitoring, achieving notable results. This paper aims to enhance industry understanding of the basic principles, theoretical model research progress, and field applications of different types of sensing technologies. The discussion begins with the foundational principles of distributed optical fiber temperature sensing and acoustic sensing technologies used in hydraulic fracturing. It systematically reviews the research progress of theoretical models for these technologies and their application in monitoring liquid production profiles and crack propagation morphologies. The paper concludes by suggesting future directions for the development of distributed fiber sensing technology. The findings indicate that: ① Distributed optical fiber sensing technology can convert temperature or acoustic wave signals into data reflecting ambient temperature or strain changes, facilitating real-time monitoring during hydraulic fracturing. ② Maturity of Temperature Sensing Models: Compared to acoustic sensing, the theoretical models for temperature sensing technology are more mature, enabling accurate calculations of liquid production profiles and fracture morphologies. ③ Application in Hydraulic Fracturing: The technology is primarily used to monitor fracturing fluid injection and fracture propagation, crucial aspects of the hydraulic fracturing process. In conclusion, distributed optical fiber sensing technology significantly advances the exploration and development of unconventional reservoirs in China. It enhances hydraulic fracturing effect evaluation techniques, playing a vital role in the sustainable development of the Chinese oil and gas industry.

Significant progress has been made in shale oil exploration within the second member of the Funing Formation in the Qintong Sag, Subei Basin. However, geologists have noted that the measured Total Organic Carbon（TOC） contents are generally below 2%. Despite this, it is believed that source rocks in saline lacustrine basins can generate substantial amounts of petroleum even with low organic matter abundance, a concept known as the “low TOC” and highly efficient hydrocarbon generation mode of saline lacustrine source rocks. As hydrocarbon generation and expulsion occur during thermal maturation, the TOC levels in source rocks decrease. Therefore, accurately restoring the original TOC of these source rocks is crucial for a proper understanding of their hydrocarbon generation capacity, as well as for evaluating petroleum resources and supporting reserve growth and production enhancement. This study focuses on the typical mudstones and shales of the second member of the Funing Formation in the Qintong Sag. Techniques such as hydrocarbon generation simulation experiments, rock pyrolysis data, TOC and productive carbon content evolution during thermal simulation, and an element mass conservation method were employed to restore the original TOC of these mudstones and shales. The findings reveal that the TOC recovery coefficient of these saline source rocks can exceed values between 3 to 4, and this coefficient is significantly influenced by the lithology. The study found that: the TOC recovery coefficient increases with thermal maturity, the coefficient for laminated shale is higher than that for massive mudstone, and the TOC recovery coefficients for mudstones in the Ⅳ sub-member and shales in the Ⅰ to Ⅲ sub-members of the second member of the Funing Formation range from 1.1~1.5 and 1.5~3.0, respectively. These variations are attributed to differences in the type of organic matter and the hydrocarbon generating activation energy, leading to a higher hydrocarbon transformation rate and TOC recovery coefficient in shales compared to mudstones.

The economic development of oil and gas reservoirs in the Tarim Basin is challenged by their complex nature and substantial investment costs. This paper primarily summarizes the intricacies of deep oil and gas reservoirs across four dimensions: accumulation conditions, reservoir space types, internal structures, and changes in hydrocarbon composition. It also explores three core issues that hinder efficient utilization, enhanced recovery, and economic growth of these reservoirs, along with proposed countermeasures. To address these challenges effectively, the paper proposes four research directions: ①A prediction method for reservoir characteristics that integrates the processes of near-source generation, transportation, storage, and cap rock formation. ②A quantitative parameter characterization method for identifying deep fractures and preserving caverns. ③A characterization method for differentiating fracture boundaries and assessing their internal connectivity. ④The establishment of a comprehensive life cycle economic evaluation system for ultra-deep domains, alongside differentiated development strategies. These strategies offer valuable suggestions towards achieving efficient development of deep to ultra-deep carbonate reservoirs and ensuring national energy security.

The transition from depletion mining to gas flooding in deep low permeability condensate gas reservoirs poses significant adaptability challenges. To address these, a series of evaluation studies were conducted using the Pressure-Volume-Temperature（PVT）analyzer, long core displacement physical simulation technology, and numerical simulation calculations. This research specifically examines the impacts of CO₂ injection, natural gas（associated gas or pure CH₄）, and nitrogen（N₂）on the high-pressure physical properties of condensate gas systems and their potential to improve condensate oil recovery. Comparative analyses reveal that CO₂, due to its high solubility and favorable gas-oil dissolution ratio in condensate oil, significantly reduces the saturation pressure and dew-point pressure of condensate gas reservoirs, thereby offering the most substantial improvement in oil recovery rates. Further optimization studies using long core physical simulation technology focused on injection timing, modes, and rates for CO₂ flooding. It was determined that pulsed gas injection strategies are particularly effective when implemented above the dew-point pressure. These findings provide essential data to support the formulation of technical policies and field plans for gas injection development in such challenging reservoir conditions.

Injecting CO₂ into depleted gas reservoirs can simultaneously achieve enhanced oil recovery and CO₂ geological storage, offering broad application prospects under the "dual carbon" background. Currently, CO₂-EGR（CO₂ enhanced gas recovery） is still largely in the theoretical research phase. To address the unclear mechanisms, this review summarizes the mechanisms of CO₂-EGR in different gas reservoirs. For conventional gas reservoirs, the mechanisms include pressure restoration and displacement effects, gravity segregation, viscosity-difference-assisted displacement, and dissolution-enhanced reservoir modification. For condensate gas reservoirs, pressure-maintained production is possible, along with viscosity reduction, dissolution expansion, and extraction-deblocking effects. For shale gas, coalbed methane, and tight gas reservoirs, the adsorption displacement effect is more significant. In water-bearing gas reservoirs, injecting CO₂ can effectively inhibit water invasion. The contributions of each enhanced recovery mechanism to different types of gas reservoirs vary. CO₂-EGR has been proven feasible at the theoretical level, but to achieve field application, further breakthroughs are needed in several areas, including gas phase characteristics of mixed gases, diffusion and gas mixing mechanisms, enhanced recovery potential evaluation, and characterization of enhanced recovery mechanisms. Research shows that injecting CO₂ into depleted gas reservoirs can restore formation pressure and replenish formation energy. Due to physical property differences, a stable displacement process is formed, achieving enhanced recovery under the combined action of multiple mechanisms. It is a highly promising method for increasing production.

In the deep shale reservoirs of the southern Sichuan Basin, the development of fractures directly impacts the engineering construction and effective production of horizontal shale gas wells. Taking the shale cores in the Wufeng-Longmaxi Formation in the southern Sichuan Basin as a case study, rock physics experiments and numerical simulations were conducted to obtain the acoustic response characteristics of fractures at different scales, orientations, and fillings. The study analyzed the factors affecting the attenuation capability of acoustic waves on fractures and established a set of fracture identification and effectiveness evaluation methods for horizontal shale gas wells. The results showed that the amplitude attenuation of P-waves, S-waves, and Stoneley waves was influenced by both the fracture dip angle and fracture width, with attenuation capacity exponentially increasing with fracture width and decreasing with the dip angle. Stoneley waves were sensitive to fluid-filled fractures and could be used to identify and evaluate gas-bearing and water-bearing effective fractures. P-waves and dipole S-waves were sensitive to calcite-filled fractures, able to identify and evaluate ineffective calcite-filled fractures. The fracture identification results based on reflected wave imaging were consistent with the results obtained from imaging logging and core identification, verifying the reliability of the effectiveness evaluation method. The research findings were applied to the actual data from horizontal shale gas wells, thoroughly evaluating the fracture risk positions in horizontal shale gas wells and effectively ensuring the optimized and tailored design for fracturing segments.

Under the “Dual Carbon” goals, achieving a green and low-carbon transformation in offshore oil and gas has become a significant challenge for enterprises. Based on an analysis of the current status of low-carbon development in the domestic and international oil and gas industries, and considering the characteristics of offshore oil and gas development in China, this study first examines the main measures and technologies adopted for green and low-carbon transformation in recent years from three aspects: establishing standards and source intensity analysis to strengthen source control, implementing clean energy substitution and energy efficiency improvement for process management, and end-of-pipe management through CO₂ geological storage, CO₂-EOR（Enhanced Oil Recovery）, and CO₂ hydrate storage. The emissions reduction effectiveness of various low-carbon technologies is clarified. Secondly, by analyzing the development level and roadmap of each technology, the study forecasts emissions reduction contributions of source carbon control, process management, and end-of-pipe storage technologies, and explores a low-carbon transformation pathway for offshore oil and gas to achieve carbon neutrality by 2050. Finally, the study proposes future directions for low-carbon development in offshore oil and gas, including collaboration between marine oil and gas and new energy, construction of new offshore oil and gas power systems, digital and intelligent offshore oil and gas development, large-scale offshore CCUS（Carbon Capture, Utilization, and Storage）, and marine carbon sinks. The findings can serve as a reference for the low-carbon development pathway of offshore oil and gas and provide insights for the green and low-carbon transformation of energy enterprises.

Heavy oil reservoirs are crucial strategic resources that play a significant role in ensuring national energy security. The development of heavy oil both domestically and internationally primarily involves four technologies: steam huff and puff, steam flooding, Steam Assisted Gravity Drainage（SAGD） and fire flooding. However, due to issues such as technical adaptability, high costs and environmental concerns, the promotion and application of these technologies face certain limitations. At Shengli Oilfield, three innovative technologies have been developed to overcome these limitations: thin-layer horizontal wells, thermochemical composites and chemical viscosity reduction. These advancements have pushed the boundaries of development technology, reducing the effective thickness limit of heavy oil reservoirs to two meters, the depth limit to 2 000 meters, and the permeability limit to 100×10^-3 μm². Based on the technical characteristics and field application effects, a new classification standard of heavy oil based on technical adaptability has been established. This standard divides heavy oil reservoirs into five categories to guide the selection of development technology at the field level. Looking forward, it is projected that “multi-thermal composites”, “non-thermal development” and “nano-materials” will be the three main trends in heavy oil development technology.

Fracture-cavity carbonate reservoirs are highly heterogeneous, presenting complex relationships between reservoir pore space and seepage flow. These complexities pose significant challenges for in-situ stress analysis, selection of injection and production parameters, and evaluations of mechanical integrity. In order to further clarify the variation of in-situ stress during the operation of fracture-cavity carbonate underground gas storage（UGS）, ensure the mechanical integrity during the operation of UGS and increase the upper limit pressure, the model was developed to analyze the stress distribution in fracture-cavity carbonate gas storage and to monitor the variations in four-dimensional in-situ stress. This model also assesses the mechanical integrity across different pore spaces. The findings reveal that: ① Stress concentration is more pronounced in fracture-cavity carbonate reservoirs than in homogeneous ones, with the lowest stress levels often occurring at cavity boundaries. ② Pore pressure and stress fluctuations are more severe in fracture-cavity environments, increasing the likelihood of shear or tensile failures at cavity boundaries during UGS operations. ③ During gas production, shear failure tends to occur along the direction of minimum principal stress, whereas tensile failure is more probable along the direction of maximum principal stress during gas injection. ④ Compared to homogeneous reservoirs, fracture-cavity reservoirs are more prone to tension or shear failures during gas injection but are generally safer during gas production, though shear failures around cavities are more likely. These results provide valuable theoretical and methodological insights for in-situ stress analysis and mechanical integrity assessments of fracture-cavity carbonate UGS.

The global energy structure is undergoing a fundamental shift from a reliance on fossil fuels with clean energy as a supplement, to a focus on clean energy supported by fossil fuels. Clean, renewable geothermal resources are gradually becoming a key energy source for sustainable development. This study focused on Gaocheng District in southwestern Hebei Province, leveraging its unique geological structural characteristics and abundant geothermal reserves. A refined geothermal resource assessment system was established, forming the basis for optimal well placement and spacing for efficient geothermal resource development. Results indicated that the development area had excellent heat source conditions, a highly favorable reservoir-caprock system, and low scaling and corrosion risks from formation fluids, indicating high-quality geothermal resources. Forty extraction and reinjection wells were deployed with a 1:1 ratio（20 extraction wells and 20 reinjection wells）. With a well spacing of 380 m and a projected operational lifespan of 30 years, the setup was expected to support sustainable heat exchange and heating needs. Based on geological structural characteristics, this study provides a valuable reference for the sustained and efficient exploitation of geothermal resources.

The identification and classification of shale lithofacies are crucial for both theoretical understanding and practical applications in shale gas exploration and exploitation. This study focuses on the shale of the second member of the Paleogene Funing Formation in the Qintong Sag, Subei Basin, using core samples from a typical drilling well, Well-Qinye-1. The research involves whole rock/clay X-ray diffraction analysis on these core samples and employs a previously developed three-terminal diagram of shale mineral components to categorize the types present in this area. Additionally, a BP neural network method optimized by the ASO（Atom Search Optimization） algorithm was utilized to perform data mining on logging information. This process aimed to establish a prediction model for the relative content of clay minerals, siliceous minerals, and carbonate minerals, achieving quantitative characterization of shale mineral content through natural gamma ray spectrometry. Ultimately, the model was applied to predict lithology and identify lithofacies in the second member of Well-Qinye-1 and Well-Shaduo-1. The identification results closely aligned with the data measured from the samples, demonstrating high consistency. This study provides an economical, rapid, and efficient method for predicting shale lithofacies and main mineral components. It also offers a foundational approach for identifying well facies in scenarios where coring and direct testing data are unavailable.

Oil shale in the Sinopec exploration areas is abundant and serves as an important strategic reserve and supplementary energy source for the country. Accelerating the exploration and development of oil shale is crucial for improving China’s energy structure and ensuring national energy security. To achieve large-scale exploration and cost-effective development of oil shale, the technologies of in-situ exploitation field tests successfully conducted both domestically and internationally were reviewed and summarized. Based on this review, the characteristics of test areas, geological and engineering adaptability, and selection layer requirements were analyzed. It was concluded that field pilot tests of Shell’s electric heating method, Jilin Zhongcheng Company’s in-situ fracturing chemical retorting technology, and Jilin University’s local chemical reaction-based in-situ pyrolysis technology have been successfully carried out. However, the maturity and feasibility of two technologies in China need to be further studied and validated, and the adaptability of existing in-situ exploitation technologies to deep oil shale remains unverified. The technical characteristics, geological resource conditions, and exploitation engineering conditions of in-situ oil shale exploitation were reviewed and analyzed. Based on the key factors restricting in-situ exploitation of oil shale in China and the heating method, four geological parameters, six engineering parameters, and classification evaluation limits were determined. Additionally, the weights of each parameter were assigned according to the degree of constraints on in-situ exploitation and utilization of oil shale. A two-factor evaluation model of geological and engineering for identifying favorable areas for in-situ oil shale exploitation was then established, leading to the selection of 15 Class Ⅰ favorable areas in Sinopec exploration areas and adjacent areas. The effects of key factors, including roof and floor, fractures, and movable water, on the selected favorable areas were further analyzed. Through comprehensive evaluation, four target areas were selected: the Xunyi mining area on the southern margin of the Ordos Basin, the Shanghuangshan Street mining area on the southern edge of the northern piedmont of the Bogda Mountains, the Dianbai mining area in the Maoming Basin, and the Fushun mining area in the Fushun Basin.

Shale oil reservoirs present complex pore structures and ultra-low permeability, making the evaluation of flow capacity in both the reservoir matrix and various fracture types after fracturing crucial for developing effective work systems. In this study, the Brazilian splitting method was utilized to simulate different fracture morphologies. We constructed a set of methods for evaluating matrix and fracture flow capacity based on nuclear magnetic resonance（NMR）technology. This evaluation was conducted on shale cores from the second member of Funing Formation of Gaoyou Sag in Subei Basin（referred to as the Fu-2 member）. Techniques including NMR, Brazilian fracturing, and high-pressure saturation were applied to develop these evaluation methods. The experimental results indicate that the minimum flow pore size of the shale reservoirs is 10 nm. Under stress conditions, the flow pattern exhibits a two-stage equation: nonlinear and linear. Factors affecting the fracture system’s conductivity include crack type, opening degree, stress magnitude, and driving pressure difference. Higher stress levels result in greater permeability loss, reaching up to 95%. The more complex the fracture network and the larger the opening, the greater the permeability loss. During production, it is essential to manage the pressure difference between the formation fluid and the bottomhole flow based on the crack development and effective stress characteristics of the overlying strata to ensure stable oil well production and uniform pressure propagation. For the shale oil in Fu-2 member of Gaoyou Sag, it is recommended to maintain an effective stress range of 7 MPa to 10 MPa and a flow pressure difference range of 10 MPa to 15 MPa as optimal for pumping or reservoir energy replenishment. These research findings significantly contribute to the theoretical understanding and practical application of the shale seepage mechanism.

Reservoir evaluation serves as a foundational aspect in the development of tight sandstone gas reservoirs, with the accuracy of these evaluations critically influencing potential development analyses. The selection of evaluation methodologies is pivotal in ensuring the reliability of development index predictions and the scientific integrity of adjustments and deployment strategies. Addressing the challenges inherent in evaluating tight sandstone gas reservoirs—such as numerous influencing factors, ambiguous controlling factors, unknown parameter sensitivity, and unquantified evaluation indices—this study develops a quantitative analysis model using the analytic hierarchy process（AHP）. This approach simplifies complex issues and quantifies qualitative aspects, facilitating a more structured evaluation. Utilizing geophysical data, logging interpretation, and geological fundamentals as criterion indices, the study constructs a judgment matrix to establish a quantitative evaluation model. This involves determining index weights, conducting consistency tests, and deriving a weight vector. The model is then validated through correlation analysis between the recoverable reserves, open flow, and evaluation values of actual wells. Findings demonstrate the method's reliability and further refine the criteria for reservoir classification. The evaluation indices defined through this research enhance the understanding of “sweet spots” for tight sandstone gas reservoir development within the same region, improve the precision of reservoir prediction, and aid in the strategic deployment of development activities. Ultimately, this study offers valuable insights and a methodological framework for the efficient development of similar gas reservoirs.

The objective of this study is to delve deeper into the hydrocarbon generation potential and oil-bearing characteristics of various source rocks within the second section of the Funing Formation in Qintong Sag, Subei Basin, and to assess the degree of shale oil enrichment. Through geochemical analysis and simulation experiment research, this investigation proposes a method for characterizing shale oil content that is adapted to the geological features of the second section of the Funing Formation. The study establishes the oil content, occurrence state, and distribution characteristics of shale oil within this section. Findings indicate that the mudstone and calcium mudstone of the fourth and fifth sub-members demonstrate higher total oil content, lower free hydrocarbon content, medium to high adsorbed hydrocarbon content, and limited mobility. Meanwhile, the calcium shale, calcareous shale, and laminated marlstone of the first to third sub-members exhibit higher total oil content and free hydrocarbon content, but lower adsorbed hydrocarbon content, which enhances their mobility. The calcium mudstone and calcareous mudstone of the first to third sub-members display a moderate level of total oil content and adsorbed hydrocarbon content but relatively low free hydrocarbon content. The marlstone from these sub-members shows comparatively low levels of total oil content as well as free and adsorbed hydrocarbon contents. The study also reveals the distribution of shale oil enrichment intervals. Class Ⅰ and Class Ⅱ shale oil enrichment intervals are primarily located in the middle and lower sections of the first and second sub-members in the deep depression zone. In contrast, the slope zone features limited development of shale oil enrichment strata but contains Class Ⅱ and Class Ⅲ shale oil.

The exploration of Well-Fuye-10 in the Dongyuemiao section has provided valuable characteristic parameters of typical continental shale, revealing a reservoir with well-developed mesopores and macropores and significant heterogeneity. The predominant pore sizes are around 10 nm. Notably, deviations in the critical parameters of the confined fluids alter the condensate gas properties within these nanopores, differentiating them from conventional laboratory results. This study combines indoor phase state experiments, critical parameter migration calculations, and numerical simulations of confined fluids to analyze the phase state characteristics and extraction properties of shale condensate gas. The findings elucidate the phase state transformation and extraction dynamics of the condensate gas. Adjustments in the calculations for condensate gas phase characteristics to account for critical parameter offsets indicate that as pore radius decreases, there is a corresponding reduction in critical temperature and pressure of the system components. This results in a contraction of the phase diagram towards the lower left, a decrease in dew point pressure, reduced gas phase viscosity, an increase in deviation factor, and a gradual decrease in retrograde condensate saturation. Additionally, a mechanism model was employed to assess the impact of critical parameter shifts on depletion extraction effectiveness. Results demonstrate that while the recovery rate of natural gas remains relatively unchanged, the recovery rate of condensate oil shows a significant increase, rising by 9.93% as the pore radius decreases to 10 nm. These insights offer pivotal guidance for the development of shale condensate gas reservoirs, particularly in managing the unique phase behavior and optimizing recovery strategies.

The deployment of horizontal well groups for shale oil development represents an innovative approach to fracturing, addressing the constraints observed in single horizontal wells. This study focuses on the fracturing dynamics within groups of horizontal wells, where the interplay of multiple wells and artificial fractures introduces complex variations in stress around the fractures and the in-situ stress distribution between wells. Such complexities significantly influence the morphology of fracture propagation. A comprehensive investigation into the stress field dynamics under various fracturing methods in horizontal well groups was conducted using a hydraulic fracturing numerical model. This research is crucial for manipulating fracture morphology and enhancing fracture complexity. The study systematically explored the stress distribution during the shale oil reservoir fracturing reconstruction, analyzed fracture morphologies, and quantitatively assessed the fracturing outcomes. Key findings include: ① Synchronous fracturing effectively alters inter-well ground stress, with the staggered pattern inducing a 24% higher stress compared to the opposite pattern, thereby influencing the direction and reversal of ground stress under identical well spacing. ② Staggered layout exhibit superior shape and fracturing effects than those under the opposite layout, significantly increasing the length, width, surface area, and volume of fractures by 4.6% and 21.1%, respectively. ③ Zipper fracturing enhances fracture dimensions more effectively than synchronous fracturing, increasing the total surface area and volume of the fractures by 1.3% and 0.1%, respectively.

To address issues such as the significant variance in shut-in effects between wells and the unclear effectiveness and timeliness of shut-ins during fracturing in shale formations, a numerical model integrating fracturing, shut-in, and production processes was developed. This model considers the synergistic effects of fracture closure, oil-water imbibition replacement, and fracturing fluid retention. The model's reliability was verified through simulations, exploring the oil-water migration law in the formation during the shut-in period of shale oil fractured wells and determining the optimal shut-in duration. Research indicates that: ① The oil-water migration characteristics during well shut-in undergo phased changes over time, which can be categorized into three main control stages: fracture closure, imbibition replacement, and energy balance. Additionally, these migration laws are closely related to the complexity of hydraulic fractures in space. ② Under the influence of capillary imbibition, extending the shut-in time appropriately benefits the initial production of fractured wells. However, an increase in fracturing fluid retention within the matrix can also exacerbate oil phase permeability damage. Based on the law of change in incremental oil volume, a reasonable shut-in time is identified to be between 30 to 45 days. ③ Considering real working conditions, “fracturing & well shut-in time” is proposed as an indicator for optimizing well shut-in, which aims to improve time efficiency and reduce differences between wells. This paper proposes an evaluation method and simulation workflow for assessing the well shut-in effects of volume fractured horizontal wells, offering valuable guidance in optimizing the reasonable shut-in time for shale oil fractured wells.

Geothermal energy and petroleum are both vital subsurface energy resources. Numerical simulation of geothermal and reservoir systems is a key technology for evaluating and optimizing the development and utilization of these resources, playing an essential guiding role in the energy sector. By comparing the foundational mathematical models, numerical methods, and case studies of geothermal and reservoir simulations, this study highlights the similarities and differences in their application to the development of these two energy sources. In terms of simulation methods, geothermal numerical simulations focus on heat conduction and geothermal field variation, whereas reservoir numerical simulations emphasize fluid dynamics and the oil extraction process. Regarding simulation results, geothermal simulations are used for geothermal resource development planning and the optimization of key production parameters, while reservoir simulations are primarily applied to reserve estimation, injection-production parameter optimization, and well production management. This comparative analysis provides theoretical and practical guidance for research and applications in geothermal energy and petroleum engineering, promoting the efficient and sustainable utilization of both energy resources.

Significant productivity breakthroughs have been achieved in key production layers of the shale in Jiyang Depression, notably the lower sub-member of the third member and the upper sub-member of the fourth member of Shahejie Formation. Despite these achievements, the development of these layers is relatively recent, and they exhibit considerable variation in individual well production. The primary factors influencing production remain unclear. Currently, a major focus of research is the comprehensive analysis of the main control factors for high production and the selection of reasonable fracturing parameters for shale oil horizontal wells. To better understand the impact of various factors on horizontal well production, factor correlation and pattern analysis are conducted using field data. Techniques such as gray correlation analysis and principal component analysis are employed to quantify the relationships between the average daily oil production over 90, 180, and 270 days and factors like the volume of fracturing fluid used and sand addition. Subsequently, a shale oil productivity prediction model is constructed, and fracturing parameters are optimized using SHAP（SHapley Additive exPlanations）. The research findings suggest that the volume of fracturing fluid, the amount of sand added, and the number of fracture events are the main engineering parameters affecting production. In contrast, geological parameters such as gray matter content, Total Organic Carbon（TOC）, and porosity significantly influence production as well. Over time, the impact of geological factors on production increases, while the influence of engineering factors diminishes during the later stages of production. Optimization analysis of fracturing parameters determined that a stage length of 40~45 meters, a fracturing fluid volume of 2 700 m³, and a sand addition volume of 180 m³ per stage are the optimal settings. These findings offer new insights for development determination and fracturing design in shale oil horizontal wells.

This study explores oil-water imbibition dynamics in rock samples of tight sandstone with similar physical properties using a novel NMR signal calibration method. This method can translate the total NMR signal output into oil volume via a regression model, offering enhanced convenience and accuracy compared to traditional approaches. The imbibition process is characterized by two distinct phases: a rapid imbibition stage and a stable imbibition stage. Optimal imbibition times were identified as approximately 68 hours for oil from coal samples and 188 hours for tight oil samples. When imbibition times are sufficient, the recovery ratios for oil from coal and tight oil are comparable. However, with insufficient imbibition time, the recovery ratio for oil from coal is lower than that for tight oil. Within the same stratigraphic layer, samples with identical viscosity exhibit similar imbibition dynamics, with tight oil samples reaching the stable stage more quickly than oil from coal samples. The pivotal radius distinguishing large and small pores is established at 0.5 μm. In low-viscosity crude oil samples, small pores significantly dominate the imbibition process, contributing 83.93% to the recovery, while large pores contribute only 16.07%. The overall mobilization of crude oil is low at 8.50%, frequently resulting in the formation of water locks. In contrast, tight oil samples show a more balanced contribution across all pore sizes during the soaking period. The average utilization ratios of crude oil are 14.82% in small pores and 29.82% in large pores.

The tight sandstone gas reservoirs of the Xujiahe Formation in the western Sichuan Depression of the Sichuan Basin are characterized by thick sand bodies, poor physical properties, strong heterogeneity, and complex gas-water distribution. These factors significantly challenge the development evaluation and productivity zone selection for this gas reservoir. The second member of Xujiahe Formation in Xinchang-Hexingchang gas reservoir has been chosen as the subject of in-depth research to facilitate efficient evaluation and development. The research includes analyzing both static and dynamic characteristics of the gas reservoir, as well as examining the ancient and modern structural positions, fault characteristics, fractures, and reservoir quality of typical wells. These analyses help to identify the main factors controlling high production in gas wells. By considering the comprehensive effects of various controlling factors and integrating the findings from reservoir formation studies, the pattern of natural gas enrichment and high productivity is explored.The results indicate that the gas wells of the second member of Xujiahe Formation gas reservoir in Xinchang-Hexingchang can be categorized into three types: high yield and high efficiency, medium yield and medium efficiency, and low yield and low efficiency. Wells with good geological conditions—those that are high-yield and high-efficiency or medium-yield and medium-efficiency—are found to have high and stable production. They are primarily located near the north to south fourth-level and fifth-level hydrocarbon source faults, where fractures are well-developed and the thickness of high-quality reservoirs is considerable. The enrichment and high productivity of the gas reservoirs are governed by the interplay of several factors: ancient and modern structures that control the reservoirs, hydrocarbon source faults that dictate enrichment, effective fractures that enhance production, and high-quality reservoirs that ensure stability. These insights provide a solid foundation for the efficient development of gas reservoirs in the region.

Significant advancements in deep Coal Bed Methane（CBM）development have been achieved through the adoption of reservoir reforming technology, characterized by the utilization of large sand volumes and large fracturing fluid volumes in Yanchuannan CBM Gas Field of Ordos Basin. This study conducts field tests on coal reservoirs with varying fracturing scales to explore the patterns of fracture expansion post-hydraulic fracturing and assesses the resultant reservoir reform areas. The analysis identifies distinct fracture patterns across different types of gas wells and fracturing scales, examines the impacts on gas production post-commissioning, and develops fracturing technology tailored to Yanchuannan CBM Gas Field. Multiple moderate-scale fracturing interventions in inefficient old wells and large-scale fracturing in new wells effectively extend fracture lengths and expand the area of reservoir reconstruction. However, the morphology of the resulting fracture networks varies significantly. Inefficient old wells subjected to multiple medium-scale fracturing develop a “rose-shaped” fracture network with primary and secondary fractures, whereas new wells exhibit a “long elliptical” fracture pattern. Notably, the use of a single ultra-large-scale fracturing fluid achieves greater efficiency, producing longer half-length fractures and larger renovation areas under the same scale. The fracture half-length and renovation area demonstrate a logarithmic increase with the frequency of fracturing, significantly enhancing the efficiency. Economic evaluations of trial production confirm that two large-scale fracturing operations are economically viable, providing a foundation for future well network deployment. Fracturing equipment powered by diesel struggles to adapt to continuous operations at scaled-up levels, suggesting that electric-driven fracturing devices present a reliable alternative for the sustainable development of integrated CBM gas fields. These insights not only enhance understanding of fracture dynamics in deep CBM reservoirs but also guide the optimization of fracturing strategies and equipment choices for future developments.

At present Sulige Gas Field holds the distinction of being the largest in terms of natural gas reserves and annual production among tight sandstone gas reservoirs in China. However, as development progresses, there is a noticeable decline in the quality of gas field reserves and an increasing fragmentation of untapped reserves, escalating the uncertainties surrounding future development. This study builds upon a deepened geological and gas reservoir engineering comprehension acquired during earlier phases of gas field development. It methodically identifies the factors influencing the advantageous development of the gas field and formulates technical countermeasures to ensure its sustainable development. Key findings from the research include: ① An empirical analysis, centered on economic production, evaluates the economic benefits of each block within the gas field. This model assesses the current benefit status and directs future overall development strategies. ② To foster the continued advancement of the tight gas industry within the field, the study evaluates the benefits of individual blocks and explores supportive measures for effective development. These measures include classified management and specific technical strategies, derived from geological and gas reservoir engineering perspectives. This approach culminates in the formulation of technical countermeasures aimed at enhancing the effective development of Sulige Gas Field, thereby ensuring its continued economic viability.

The Jurassic coal seam in the Baijiahai area of the Junggar Basin is characterized by a low elastic modulus, high Poisson's ratio, and low hardness, presenting challenges in vertical well hydraulic fracturing such as difficulty in sanding and low gas production. To address these issues, a technical approach of “verification + exploration” was implemented. This involved on-site verification of cluster interference and exploration of the effects of different fracturing fluids on increasing production. Key findings from this approach include: ① Field Tests on Vertical Wells: It was observed that targeting coal seams as the preferred layer for horizontal well drilling could yield better development outcomes. ② Optimization of Fracturing Parameters: Important parameters that affect sanding difficulties and stimulation volume include cluster spacing, displacement, viscosity, proppant particle size, and sanding scale. A fracturing technology combining large displacement, high viscosity, and extensive sanding is recommended. ③ Field Application of Fracturing Fluids: The use of gel fracturing fluids for long fractures and the subdivision cutting volume transformation in horizontal wells have proven to be effective techniques. These processes have significantly enhanced the production benefits of deep Jurassic coal-rock gas in the Baijiahai area, achieving remarkable results. The success of this study provides a technical breakthrough and support for the exploration and development of deep coal-rock gas, holding significant implications for the development of coal-rock gas resources in the Junggar Basin.

Shale gas reservoirs are characterized by high compactness and significant heterogeneity, with naturally low production that necessitates hydraulic fracturing technology for enhanced productivity to achieve industrial gas flow. The key to evaluating the effectiveness of fracturing operations and optimizing process parameters lies in obtaining accurate fracture network parameters. Traditional fracture monitoring techniques, such as microseismic monitoring, are costly and cannot achieve full coverage monitoring of well areas. Numerical simulation prediction models require a large number of engineering geological parameters, leading to poor prediction effects for geological data that are incomplete or missing well sections. There is an urgent need for a new method that is economically efficient in obtaining fracture network parameters. To address this, a shale gas reservoir fracture network inversion method based on deep learning was proposed. The core of this method is to quantitatively analyze the fracturing curve characteristic parameters based on the site fracturing curve data, using strongly correlated indicators of fracture network parameters as inputs and microseismic monitoring fracture network parameters (including length, width, height, and volume) as target outputs. A back-propagation (BP) neural network inversion model was established to achieve accurate inversion of fracture network parameters. The model was trained and optimized using 450 fracturing curve segments from shale gas wells in western Chongqing, with the average relative error of fracture network parameter inversion results in the test set being below 15%, which verified the feasibility of this new method for inversion of shale gas reservoir fracture networks.

The shale lithofacies in the second member of the Funing Formation (hereafter referred to as Funing Formation Member 2) in the Gaoyou Sag of Subei Basin exhibits significant heterogeneity, with complex lamination types that are challenging to quantify using well logging, thus limiting the identification of favorable “sweet spots” for shale oil. Therefore, this study investigates the methods for quantitative characterization of shale lamination types and their development in Funing Formation Member 2 of Gaoyou Sag, by integrating data from core thin sections, whole rock diffraction, elemental logging, and well logging, based on the climatic and environmental evolution during different sedimentary stages. The results show that shale lamination types mainly include quartz-enriched, clay-enriched, calcite, and dolomite bands. Influenced by ancient climatic evolution, the proportions of different lamination types vary across intervals, and the vertical superposition and coupling of these lamination types lead to differential shale oil enrichment, with more developed laminations corresponding to higher oil enrichment. During the deposition of intervals Ⅴ-6 to Ⅴ-10, the sediments exhibit a high aridity index, low Sr/Cu ratio, significant variation in the Sr/Ba ratio, and high V/(V+Ni) ratio. These characteristics suggest a strongly reducing, semi-arid to arid saline water environment with fluctuating water depths and periodic variation in lake nutrients. Saline stratification and diagenesis facilitate the development of abundant bright calcite layers, fibrous calcite layers, and dolomite layers, providing favorable reservoir properties for shale oil. During the deposition of intervals Ⅴ-1 to Ⅴ-5, the Sr/Cu ratio increases significantly while the aridity index decreases. The overall environmental characteristics indicate a strongly reducing, arid saline water environment. The shale is predominantly composed of clay-rich to sandy-mixed lithology, with clay-enriched layers and clay-rich laminations as the dominant lamination types. Due to the influence of recrystallization degree, the proportion of bright calcite layers decreases while the proportion of mudstone-like calcite layers increases. During the deposition of intervals Ⅳ-5 to Ⅳ-8, the Sr/Cu ratio exhibits a periodic variation of “decrease followed by increase”, indicating a decrease in lake water salinity. The lithology primarily consists of clay-rich to sandy-mixed shale, with the development of clay-enriched layers, clay-rich laminations, bright calcite layers, fibrous calcite layers, and dolomite layers. These intervals demonstrate excellent reservoir properties and are regarded as high-quality sweet spot layers for shale oil. During the deposition of intervals Ⅳ1-Ⅳ4, the Sr/Cu ratio increases, indicating intensified arid conditions. The climate characteristics suggest a strongly reducing, arid saline environment. The recrystallization degree of calcite is higher, leading to the development of bright calcite, fibrous calcite, and dolomite layers. Additionally, the proportion of mudstone-like calcite layers increases, indicating a higher overall carbonate mineral content influenced by the depositional environment. During the deposition of the subinterval Ⅲ, the climate alternates between humid and arid conditions, with a higher degree of calcite crystallization and the development of bright calcite layers. Subintervals Ⅱ and Ⅰ exhibit a significant decrease in Fe/Mn and Sr/Ba ratios, indicating intensified humid conditions. Water depth increases, and the shale gradually transitions to blocky structure. The content of gray and muddy minerals decreases, limiting the development of gray and muddy laminations. The study further confirms a positive correlation between the degree of shale lamination development and shale oil enrichment. Based on the geological characteristics of the shale lamination distribution, further analysis was conducted using methods such as edge detection from electrical imaging well logging and shale deposition rate calculation. The study identified intervals Ⅳ-3 to Ⅳ-7 and Ⅴ-6 to Ⅴ-8 in Funing Formation Member 2 as having well-developed laminations and higher total organic carbon (TOC) compared to other intervals, marking them as vertical shale oil sweet spot layers. The image edge detection method using electrical imaging well logging offers high accuracy for shale bedding identification and is suitable for detailed geological evaluation of vertical shale oil sweet spot layers in different blocks. Furthermore, as the climate change during shale deposition becomes more frequent and the sedimentation rate varies more drastically, the vertical heterogeneity and lamination development of shale increase. Thus, sedimentation rate variations can serve as an indicator of shale lamination development. An analysis of stratigraphic cycles in the Huazhuang area's Funing Formation Member 2 revealed that natural gamma MTM spectrum analysis of well Huaye 7 identified eight dominant frequencies, corresponding to cycle thicknesses of 39.84, 11.76, 9.43, 4.20, 3.19, 2.32, 2.13, 1.82 m. The ratio of cycle thicknesses is 21.91:6.47:5.19:2.13:1.76:1.28:1.17:1.00, which is close to the theoretical cycle ratio of 21.32:6.58:5.26:2.74:2.00:1.21:1.16:1.00 for this period. Therefore, the shale deposition process of the Funing Formation Member 2 is controlled by the Milankovitch astronomical cycle. The optimal sedimentation rate for this interval was determined to be 10.8 cm/kyr. Using this optimal rate, the eCOCO statistical method was applied to track and analyze sedimentation rate variations in the Funing Formation Member 2. The results indicate significant differences in sedimentation rates among different sub-layers of the Funing Formation Member 2 due to the influence of periodic climatic fluctuations. Moreover, the degree of lamination development indicated by the sedimentation rate variation correlates well with the overall proportion of lamination development obtained from thin section analysis, and is consistent with the lamination development detected by imaging logging in different intervals. Consequently, this method can predict the spatial distribution of lamination development, providing guidance for three-dimensional shale oil exploration. In summary, this study provides insight on the lithological heterogeneity and quantitative logging characterization of the Funing Formation Member 2 in the Gaoyou Sag, Subei Basin. These findings contribute to the identification and evaluation of shale oil sweet spot layers, promoting shale oil exploration and development.

Deep shale gas reserves in southern Sichuan represent a significant opportunity for augmenting China's natural gas reserves and production. One critical factor influencing the permeability and productivity of individual wells in these deep shale gas reservoirs is fault connectivity. Previous research has primarily focused on fault morphology and combination styles, with little systematic quantitative assessment of fault connectivity. This study targets the Wufeng Formation reservoir in the central Luzhou section of the southern Sichuan Basin, initiating a detailed analysis of the fault network structure and connectivity using multiple faults as reference points. Findings indicate that faults in the Wufeng Formation of the central Luzhou area are well-developed, with an average of 1.12 connection points per branch network. These networks potentially form highly permeable channels favorable for shale gas transport. The central and southern parts of the study area exhibit higher fault dispersion, fault length dispersion, and fault density, which contribute to a greater number of connecting nodes and branches. This enhanced connectivity is conducive to the development of high-production wells. The connectivity assessment results from these regions are superior to other studied areas, indicating notable potential for high-yield well development in the Wufeng Formation.

The efficient evaluation of the oil properties, capabilities, and compressibility of reservoirs using conventional logging data is essential for the large-scale development of shale oil in northern Jiangsu. Utilizing conventional logging data alongside core experiment data, this study develops a robust model to calculate several critical reservoir characteristics. These include total organic carbon content, effective porosity, bedding fracture density, and mineral composition content. The model employs a variety of mathematical methodologies such as physical concept analysis, optimization, fitting, and both forward and backward numerical simulations. Furthermore, this research classifies the sedimentary structure and lithofacies of the reservoir. Results indicate that the shale within the second member of Funing Formation in Qintong Sag predominantly consists of organic-rich layered/laminated mudstone and block mudstone. Among these, the layered or laminated mudstone represents the favorable lithofacies, intersecting vertically with non-favorable rock types. The “sweet spot” layers identified by the model correlate well with the layers analyzed using specialized logging techniques, and field applications have yielded positive outcomes. This technology has been successfully applied in identifying geological and engineering “sweet spots” within the shale oil reservoirs of the Subei Basin, offering significant guidance for the strategic development of shale oil in the region.

Waterflooding characteristic curves are widely used in analyzing oilfield production dynamics. Most existing waterflooding characteristic curves are derived from statistical analyses of production data from sandstone reservoirs, commonly categorized into four types: Type A, Type B, Type C, and Type D. To assess the applicability of these curve types to fractured-cavity carbonate reservoirs, the Tahe fractured-cavity carbonate reservoir was selected as a case study. By analyzing reservoir fracture-cavity structures and oil-water production data, the Type A waterflooding curve was identified as more suitable for the Tahe reservoir. The study of 255 wells with long-term production data revealed six water cut increase patterns and four waterflooding characteristic curve types. Wells controlled by single cavities exhibited single-straight-line waterflooding characteristic curves and slow water cut increase patterns. Wells controlled by dual cavities displayed double-straight-line waterflooding characteristic curves, with water cut increase patterns categorized as slow rise, rapid rise, or fluctuating. For wells affected by water injection in dual-cavity structures, triple-straight-line waterflooding characteristic curves were observed, with water cut increase patterns featuring rapid rise and catastrophic flooding. Wells located in multi-cavity, complex fracture-cavity structures demonstrated irregular waterflooding characteristic curves, with water cut patterns including slow rise, rapid rise, fluctuating, and catastrophic flooding. A comparison with waterflooding characteristic curves of sandstone reservoirs clarified the applicability conditions for fractured-cavity carbonate reservoirs: adherence to the stable waterflooding principle（i.e., the straight-line principle） and the absence of a fixed water cut threshold. This study provides a foundation for predicting production dynamics in fractured-cavity carbonate reservoirs.

Shale oil resources in the Subei Basin show significant potential. The second and fourth members of the Funing Formation (hereafter referred to as Funing Member 2 and Funing Member 4) are the main target layers for exploration. These layers are characterized by substantial thickness, wide distribution, high content of brittle minerals, well-developed laminated structure, and favorable organic matter types, with typical geological features, including low to medium total organic carbon (TOC), complex tectonics and lithology, and developed faults/fractures. Since 2011, Jiangsu Oilfield has strengthened basic research and exploration practices, leading to the establishment of the theory of differential enrichment of shale oil in complex fault blocks with low to medium TOC. Key technologies for exploration and development have been integrated and innovated, green and low-carbon development models have been explored, and significant breakthroughs have been achieved in shale oil exploration of Funing Member 2 and Funing Member 4 in the Gaoyou Sag. However, there are still many challenges, such as an unclear understanding of the patterns of shale oil enrichment and high yield, insufficient adaptability of engineering technologies, undefined technical policies for cost-effective development, and high development costs. Main approaches to achieving large-scale production and cost-effective development of shale oil include: deepening the fundamental research on the main controlling factors of shale oil enrichment and high yield, tackling main challenges and advancing key technologies, optimizing integrated organizational management and operation mechanisms, and maximizing the drilling success rate in high-quality reservoirs, the utilization rate of shale oil reserves, and the recovery efficiency to further reduce costs and improve efficiency.

The lithofacies of shale oil within the Dongying Sag of the Jiyang Depression are distinguished by their complex lithology, strong heterogeneity, and marked regional distribution variances. Current logging methods inadequately identify and evaluate the lithofacial characteristics of shale oil in this region. This study delves into the lithofacies characteristics of the upper submember of Chunhuazhen Formation of the fourth member of the Shahejie Formation in Dongying Sag, employing core calibration logging integrated with core, thin section, experimental analysis, and testing data. Utilizing the “three terminal elements and four elements” shale lithofacies partitioning scheme as a guiding principle, this research selects responsive characteristics of different lithofacies logging and sensitive parameter logging curves to develop an appropriate shale oil logging lithofacies partitioning method. The approach combines stratification, clustering through Agglomerative Hierarchical Clustering（AHC）, Fisher discriminant analysis, wavelet frequency extraction, and genetic optimization neural networks to discern the rock composition, sedimentary structure, rock texture, and organic matter content of different lithofacies. This methodology addresses the challenges posed by complex lithology, limited logging resolution, incomplete special logging data, and inadequate Total Organic Carbon（TOC）model accuracy. By identifying the “four characteristics” of lithofacies, the study establishes a quantitative logging identification method and technology for shale oil lithofacies in Dongying Sag, pinpointing concentrated lithofacies segments. The findings provide a critical geological basis for the large-scale exploration and development of shale oil in the region.

Drilling medium-deep geothermal wells is costly, but converting existing depleted oil and gas wells into geothermal wells can significantly reduce these costs. This study analyzed heat extraction performance based on the engineering parameters and test data of a geothermal well reconstructed from a depleted oil and gas well in the northern Shaanxi region. Long-term heat extraction performance was simulated numerically to explore the impact of inner pipe design parameters. The study found that improving the thermal insulation of the inner pipe had a more significant impact on geothermal well heat extraction power as depth increased and flow rate decreased. However, the diameter of the inner pipe had a minimal influence on heat extraction performance and was less sensitive to changes in depth and flow rate, resulting in a limited overall impact. Additionally, the study quantified the effect of inner pipe material selection on the system's economic performance throughout its life cycle. Results indicated that reducing the inner pipe's thermal conductivity from 0.2 W/（m·K） to 0.02 W/（m·K） under certain working conditions could increase the outlet water temperature by 0.66 °C during one heating season. However, it also raised the average heating cost by 0.035 RMB/（kW·h） and extended the payback period by 1.83 a. Therefore, considering the limited benefits of using high-insulation inner pipe materials, it is recommended to prioritize temperature and pressure resistance when designing inner pipes for geothermal wells reconstructed from depleted oil and gas wells.

With the growing global demand for clean energy, geothermal resources as a renewable energy source have attracted widespread attention. This study evaluated the geothermal resource development potential and application prospects in the Xiangfu District of Kaifeng City. The results showed that the vertical temperature field of the thermal reservoir in the Xiangfu District could be divided into varying temperature zones, constant temperature zones, and increasing temperature zones, with depth significantly influencing the temperature distribution. The geothermal gradient increased with depth above 500 m and gradually decreased below 500 m. Chemical analysis of geothermal fluids showed significant differences in the water chemistry types between thermal reservoirs at different depths, with no significant hydraulic connection between the reservoirs. Based on the maximum allowable depth reduction method and the extracted water volume method, the total exploitable geothermal fluid without reinjection was estimated to be 9,390×10⁴ m³. Under complete reinjection conditions, the total exploitable geothermal fluid was estimated to be 360.7×10⁸ m³, indicating substantial development potential. These research findings provide a scientific basis and guidance for the efficient development and utilization of geothermal resources in the Xiangfu District.

This study addresses the challenges presented by the reservoirs in He-8 member in SD block of Ordos Basin, characterized by low porosity, low permeability, strong heterogeneity, and conventional fracturing fracture shapes. Utilizing fracture mechanics, this research examines the interactions between temporarily blocked fractures and the initial fracture throughout their entire contact period. Key considerations include fluid pressure drop within the fracture and the rock mechanics parameters of the reservoirs in He-8 member. The study systematically analyzes the influence of various parameters such as fracture strike, well deviation angle, and azimuth angle on fracturing fracture parameters. Notable findings include: Fracturing pressure decreases with increasing well deviation angle and azimuth angle. The initiation angle diminishes as well inclination increases, reaching a nadir before decreasing further with azimuth angle adjustments. Using artificial cement samples and a large-scale experimental system with realistic triaxial physical models, the study simulates the initiation, turning, and propagation behaviors of new fractures in temporary plugging fracturing. The behaviors of initiation, steering and extension of newly formed fractures at different well inclination and azimuth angles were evaluated along with the parameters such as fracture initiation pressure and fracture stimulated area. The experimental results reveal: Both initial and secondary fracture pressures tend to decrease as well inclination increases, making fractures more prone to turning and significantly enlarging the modifiable area. With consistent trap inclination, fracture initiation pressure decreases and the fracture modification area expands as bore azimuth increases. Fractures resulting from azimuthal 90° spiral perforation exhibit greater complexity compared to those from azimuthal 0° spiral perforation. Additionally, fixed surface perforation techniques can regulate fracture pressure and the initial fracture positions in horizontal wells, recommending a perforation angle between 75° and 90°. These findings offer valuable insights for the design of temporary plugs and fracturing strategies in low-permeability tight sandstone oil and gas reservoirs.

The shale gas reserves in the Wufeng Formation-Longmaxi Formation of the Luzhou Block in southern Sichuan are substantial. Tectonic movements alter the ground stress, significantly impacting the exploration and development of shale gas. To optimize exploration areas for deep shale, methods such as seismic comprehensive data, ancient structural maps, and rock mechanics parameter testing have been employed. Additionally, neural network algorithms and geological mechanics modeling analysis have been used to invert the stress field of ancient geological structures across multiple stages within the study area and to predict the development of reservoir fractures influenced by stress. The research indicates that numerical simulation methods and neural network algorithms effectively invert the crustal stress field across multiple stages. Tectonic movements have altered the crustal stress, concentrating it in the stratigraphic anticline. Here, the core of the anticline, affected by strong tectonic activity, is fractured, gradually releasing stress. The ongoing multi-stage tectonic movements have facilitated changes in the stress of the reservoir rock, making the fracture zone conducive to fault formation with decreasing stress over time. Around the original faults, crack development is pronounced, leading to stress attenuation zones prone to numerous, short, small cracks. The current stress field, shaped by multiple tectonic periods, presents a complex distribution and irregular crack development, significantly influencing shale gas drilling and development. These findings offer valuable insights for the exploration and development of deep shale gas.

Most mature oilfields in eastern China, particularly medium and high permeability fault block reservoirs, have entered the high water-cut development stage. Enhancing oil recovery（EOR） in such reservoirs is crucial for stabilizing production and extending the economic development period of aging fields. The Chun-47 Block in the Dongying Sag of the Jiyang Depression is a medium and high permeability fault block reservoir. Adaptive well pattern design and differential adjustment strategies tailored to the reservoir characteristics during various development stages have enabled efficient exploitation, with a current recovery factor of 78.5% and an ultimate recovery factor of 84%. Analyzing the mechanisms underlying efficient development and identifying the field’s development patterns have academic and practical significance. This study examines the geological characteristics, reservoir macroscopic and microscopic features, fluid properties, and development strategies. Results highlight that favorable reservoir properties form the foundation for high recovery rates, while high waterflood displacement efficiency and comprehensive stage-specific development strategies serve as the key technical aids. The practical experience, strategies, and methods adopted for the efficient development of this block provide valuable insights for similar oilfields.

The intercalated shale oil within the first member of the Qingshankou Formation in the southern Songliao Basin exhibits significant exploration potential, primarily influenced by the quality of its intercalations, which impacts both oil content and productivity. The physical properties of these interlayers are notably heterogeneous, highlighting the necessity to characterize and describe interlayer reservoirs comprehensively and establish a suitable classification scheme. This study utilized advanced techniques such as field emission scanning electron microscopy, high-pressure mercury injection, and nuclear magnetic resonance to characterize the reservoir. Employing the fractal theory associated with mercury injection, a physical property classification standard tailored for sandstone interlayers was developed. This standard was combined with logging data to predict the physical property parameters of the reservoirs, facilitating the identification and mapping of high-quality interlayer reservoirs. The results delineate the first member of the Qingshankou Formation in the Daqingzijing area into regions of varying source rock maturity: low maturity areas with a vitrinite reflectance（R_o） of less than 1.0% and areas with middle to high maturity source rocks（R_o greater than 1.0%）. It was found that interlayer physical properties deteriorate as the maturity of the source rock increases. A grading standard for interlayer physical properties was established, categorizing the sandstone interlayers into Class Ⅰ to Ⅲ, and deeming some as invalid reservoirs. From Class Ⅰ to invalid reservoirs, there is a sequential decrease in the content of large and medium pores, with reservoir space transitioning from intergranular pores and intergranular solution pores to intragranular solution pores and intergranular pores. The mercury injection profiles evolve from weak platforms and slow straight lines to convex shapes, indicating a gradual degradation in oil content. High-quality interlayer reservoirs are predominantly situated along the main body of the estuary bar and the underwater distributary channels, with the thickness decreasing from southwest to northeast. The findings of this research provide crucial insights for targeting interbedded shale oil prospects within the first member of the Qingshankou Formation in the southern Songliao Basin, assisting in the strategic selection of exploration and development sites.

Geothermal energy, as a clean energy source, plays an important role in China's energy transition. Energy companies across the country are actively promoting geothermal development projects. PetroChina Jidong Oilfield Company is a leader in the large-scale development of geothermal resources and has established the largest geothermal heating demonstration base in China, the Caofeidian new town geothermal heating project. As a key project for public welfare, geothermal heating requires cost reduction, quality improvement, and efficiency enhancement for large-scale development. With long construction cycles and stringent requirements, Jidong Oilfield has achieved low-cost, high-efficiency geothermal well drilling through various technological measures, including integrated geological engineering profile design, optimization and simplification of wellbore structure, cementing design optimization, and rapid drilling technology improvements. This research combines practical case studies from the Jidong Oilfield geothermal heating project, analyzing the factors influencing cost and construction progress, identifying construction issues, and detailing countermeasures and implementation effects. This paper offers valuable solutions for optimizing geothermal well design and cost reduction in large-scale geothermal development projects.

The research and application of risk analysis and evaluation for underground gas storage facilities are critical due to their diverse equipment, complex process flows, and numerous risk factors. In particular, corrosion failure accidents in ground process pipelines at these facilities have become increasingly common in recent years. Effective and accurate analysis of the causes of these corrosion failures is essential for ensuring the safe operation of underground gas storage facilities. This article presents a risk assessment methodology that leverages data and knowledge fusion. The process begins with a statistical analysis of the corrosion failure data from ground process pipelines in underground gas storage facilities, from which a Bayesian corrosion prediction model is developed. This model serves as the foundation for analyzing the basic events that lead to corrosion failure in these pipelines. Subsequently, a knowledge model of corrosion failure is established, and a detailed analysis of corrosion causes is conducted using the fault tree specific to corrosion failure in ground process pipelines. The importance of each basic event within the fault tree is quantified through the structural importance coefficient assigned to each event. The analysis categorizes the influencing factors of corrosion failure into four main groups. A judgment matrix is then created to determine the relative weight values of these different influencing factors. This matrix is crucial for setting the weight factors in the fuzzy comprehensive evaluation, which ultimately determines the risk level of corrosion failure in ground process pipelines at underground gas storage facilities. By applying examples of corrosion risk assessments for ground process pipelines, this study provides a scientific basis for enhancing safety management and operational practices at underground gas storage facilities.

Continental shale oil horizontal wells have fast decreasing natural production and low recovery, for which single well water injection huff-n-puff can effectively replenish formation energy and improve recovery. Taking Ordos Chang7 shale oil as an example, numerical simulation method is used to carry out the optimisation study of water injection huff-n-puff in horizontal wells of continental shale oil. To enhance the accuracy of the numerical simulation model for shale reservoirs after volume fracturing, the Embedded Discrete Fracture Model（EDFM） is introduced. This model characterizes both natural and hydraulic fractures resulting from volume fracturing. Additionally, a conceptual model that considers imbibition and reservoir stress sensitivity is established. The timing, volume, and speed of injection, as well as the soaking period and huff-n-puff cycle, are optimized based on simulation results. These results indicate that a too-rapid injection rate causes water to flow along the fractures, decreasing the utilization rate of the injected water. As the huff-n-puff cycle increases, the oil increment per cycle tends to decrease. For the specific case of a shale reservoir in Ordos, the optimization of huff-n-puff parameters is as follows: Water injection should commence when the pressure coefficient drops to 0.706, with an optimal injection volume of 4 000 m³ at a rate of 300 m³/d. The recommended soak period is 15 days, with a total of six huff-n-puff rounds. This approach can increase the recovery rate by 4.95% and achieve a total oil-water replacement rate of 6.65%. This study provides valuable insights for water injection huff-n-puff strategies in shale reservoirs.

Energy storage volume fracturing is a pivotal early development technique for shale reservoirs, designed to supplement reservoir energy preemptively and significantly boost single well production. A method for predicting the maximum cumulative oil production during the development stage of energy storage fracturing is proposed, based on the mechanisms of imbibition and displacement coupled with the statistical analysis of actual production data. The results demonstrate that following a 30% flowback ratio, the cumulative oil production from energy storage fracturing exhibits a strong linear relationship with the logarithm of the flowback ratio. This relationship can predict the maximum cumulative oil production of a single well after fracturing. Validated by actual production data from other shale reservoirs, this method proves to be more accurate and universal than the decline curve analysis method. It encompasses a comprehensive evaluation of subjective and objective factors such as reservoir conditions, fracturing scale and technology, production system design, and drainage efficiency. Additionally, the method facilitates the determination of the liquid-to-oil ratio and the reasonable flowback rate. By controlling the average rate of discharge and production within the range of 6~8 m³/（d·km）, which aligns with the rates of oil drainage and imbibition, higher oil recovery and a lower liquid-to-oil ratio are achieved. This prediction method for maximum recoverable oil post-single well fracturing provides a basis for the economic benefit evaluation, production system optimization, and fracturing cost control of energy storage fracturing. It holds significant guiding importance for geological-engineering integration, well spacing optimization, and fracturing design.

The Subei Basin is characterized by a complex structure and well-developed faults. The shale in the second member of the Funing Formation has relatively low organic matter abundance, with a total organic carbon (TOC) generally below 1.5%. This shale exhibits diverse lithofacies types, complex pore structures, strong reservoir heterogeneity, and significant lateral variations in pressure coefficients. Using the shale oil reservoir in Block H of the second member of the Funing Formation in the Subei Basin as an example, this paper analyzed the characteristics of regional logging responses based on the results of rock physics experiments. By integrating conventional and specialized logging methods, a logging interpretation model was developed to evaluate the lithology, reservoir properties, oil content, mobility, and fracability of the shale oil reservoir. The model’s calculations aligned well with core analysis results. Building on this, sensitive parameters were optimized to establish evaluation and classification standards for the shale oil reservoirs in the block, and a comprehensive “sweet spot” evaluation of the reservoir was conducted. Exploration practices involving multiple wells have verified that this logging evaluation technology is regionally adaptable. It effectively classifies shale oil reservoir types, supports the optimal selection of “sweet spots”, and provides reliable technical support for the exploration and development of shale oil in the Subei Basin.