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.

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.

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.

The study of the filling veins in deep reservoirs within the strike-slip fault zone in the north of Fuman Oilfield utilizes a range of methods including petrographic characteristics, analysis of rare earth elements andSr（strontium） isotopes, fluorescence spectra of oil inclusions, microscopic thermodynamics, and U-Pb isotopic dating of carbonate rocks. The findings reveal two stages of calcite vein formation in this area. These veins originate from the formation water of the middle and Lower Ordovician sources, with no evidence of oxidizing fluid intrusion, suggesting that the deep to ultra-deep oil and gas reserves have maintained good sealing properties in later stages. Furthermore, based on the burial history deduced from inclusions and low U-Pb isotope dates from carbonate rocks, it has been determined that there are three distinct stages of hydrocarbon charging in the deep Ordovician strata of the northern strike-slip fault zone in the Tarim Basin. These stages correspond to （459±7.2） Ma（middle Caledonian）, （348±18） Ma（early Hercynian）, and 268 Ma（late Hercynian）. It is noted that the early Hercynian period was the key phase for hydrocarbon accumulation in the deep and ultra-deep carbonate rocks in the north of Fuman Oilfield, with a significant correlation observed between oil and gas charging and fault activity.

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.

Acid fracturing is a critical stimulation technology for enhancing production in ultra-deep marine carbonate reservoirs. A significant challenge in this process is maintaining the conductivity of acid-etched fractures under ultra-high temperature and high closure stress conditions. To address this, conductivity experiments were conducted using various acid solutions and their combinations. The morphology of the acid-etched fractures was captured using a three-dimensional laser scanner. The degree of fracture closure was analyzed using the Airy stress function and the complex variable method, integrated with the local cubic law and an acid fracturing model to create a numerical calculation method for evaluating the conductivity of acid-etched fractures. The results show that under high closure stress（90 MPa）, the conductivity of acids and their combinations decreases by an order of magnitude compared to low closure stress（5 MPa）. As closure stress increases, different acids and combinations exhibit distinct patterns of conductivity reduction, with potential for two rapid decline phases. Furthermore, specific acid combinations have been identified that enhance the conductivity of fractures under extreme conditions of temperature and pressure. The average error between the conductivity values calculated by the model and those obtained from experimental results is relatively low, about 10.6%, indicating that the model can effectively characterize the distribution and magnitude of conductivity across different points within the fracture. In Sichuan Basin, under identical engineering parameters, the conductivity of acid-etched fractures in the 4th member of Dengying Formation is higher than that in the 2nd member. This research provides valuable theoretical guidance for optimizing the design of acid fracturing stimulation schemes in ultra-deep marine carbonate rocks in Sichuan Basin.

The geological structure and reservoir characteristics of low-permeability carbonate gas reservoirs are complex, and the high uncertainty in data acquisition and interpretation makes it challenging to identify optimal development areas. To address this, the study introduces an intuitionistic fuzzy Multi-Attributive Border Approximation area Comparison（MABAC） model, combined with the Best Worst Method（BWM） for weighting, to select the most suitable areas for developing these reservoirs. The approach begins by establishing a comprehensive evaluation index system that considers geological characteristics, hydrocarbon generation capacity, and gas storage capability of the low-permeability carbonate formations. This system not only integrates geological data but also considers the construction conditions relevant to these reservoirs. Using the BWM, weights for each key evaluation indicator are determined, taking into account the multifactorial impacts on various oil and gas fields and establishing the hierarchical relationships between these factors. An improved intuitionistic fuzzy multi-attribute decision-making model is then developed. This model uses intuitionistic fuzzy data instead of precise information, enhancing the selection process for favorable areas. The application of this model on ten candidate blocks indicated that Block C is the most favorable, outperforming others in terms of remaining dynamic reserves, effective reservoir thickness, and other crucial indicators. The blocks were ranked as follows based on the overall distance value: Block C > Block I > Block H > Block A > Block D > Block G > Block J > Block E > Block F > Block B. The effectiveness and rationality of the proposed intuitionistic fuzzy MABAC method were validated through comparisons with existing methods and analysis of numerical simulation results, confirming its utility in optimizing the development of low-permeability carbonate gas reservoirs.

The second member of Xujiahe Formation in Gaomiaozi Gas Field, located in Xinchang fault zone of western Sichuan Depression, Sichuan Basin, is a typical tight sandstone gas reservoir with multiple layers of superimposed sand bodies. The sand bodies exhibit clear transverse phase transitions, characterized as “overall sand rich, locally gas rich”. However, due to the impedance of the high-quality reservoir being similar to that of mudstone, traditional post-stack inversion methods struggle to accurately delineate the boundaries of the sand body and the distribution of high-quality reservoir zones.To address these challenges, the study initially focused on identifying and predicting the boundary of the favorable facies zones based on the geological characteristics of the second member of Xujiahe Formation. This was complemented by an analysis of sensitive petrophysical parameters. Subsequently, a pre-stack geostatistical inversion study was conducted under phase control constraints. This approach enabled the differentiation between effective reservoirs and mudstone, culminating in an accurate prediction of phase-controlled effective reservoirs. The results of this predictive technology not only enhanced the accuracy of identifying sand bodies but also improved the reliability of predicting effective reservoirs. The outcomes closely matched the actual drilling results. This prediction technology has significantly supported the reserve submission and the strategic deployment of exploration well locations in the Hexingchang gas field, yielding substantial oil and gas benefits.

Deep and ultra-deep oil and gas exploration and development are key strategic areas in China's energy sector, with ultra-deep directional drilling serving as a crucial technology for accessing these resources. However, the challenges of drilling and completing ultra-depe directional wells are substantial due to complex topography, diverse formation lithologies, varying pressure systems, reservoir fluid characteristics, and the engineering mechanics of deep formations. To address these challenges and enhance the safe and efficient development of deep oil and gas resources in China, this paper introduces the concept of a geology-drilling engineering-mechanics coupling mechanism for ultra-deep directional wells. The paper systematically reviews the progress and identifies existing problems in the geology-drilling engineering-mechanics coupling mechanism of ultra-deep oil and gas drilling. It also proposes directions for future research and development. It is emphasized that research on the coupling mechanism in China is still in its early stages and requires further integration of geology, mechanics, and engineering disciplines to develop efficient drilling technologies suitable for ultra-deep directional wells.

The rapid development of shale gas, a clean and low-carbon unconventional natural gas, plays a key role in supporting China’s goals for achieving a carbon peak and carbon neutrality. Over the past decade, China has made significant strides in the theoretical and technical aspects of shale gas fracturing, progressing from non-existence to existence and evolving from followers to partially leading the field. This paper discusses three critical aspects of the shale gas fracturing process: fracture layout, fracture creation, and support fracture, yielding several key insights: ① The primary objectives in optimizing the characteristics of the fracture network are to maximize reservoir modification volume and fracture complexity. This maximization is crucial for enhancing the shale gas production capacity. ② During the fracturing process, it is essential to ensure uniform fracture initiation across each cluster. However, due to the non-homogeneity of the ground stress field and the presence of structural weak surfaces such as natural fractures, inter-cluster collusion or overlap of fractured fractures often occurs. This results in the actual fracture seam spacing being unequal to the planned cluster spacing. ③ Under conditions of close cutting and strong sand addition, the applicability of limit flow restriction fracturing is limited. The scientific challenges related to temporary plugging at the fracture mouth, temporary plugging within the fracture, and sand placement in narrow bifurcation seams remain unresolved. These challenges involve complex liquid-solid two-phase flow dynamics. ④ For fractures containing proppant, it is necessary to determine the inflow capacity demand and distribution mode based on the reservoir’s capacity or production demands. Subsequently, optimizing the proppant parameters and the sand placement process is crucial. The paper concludes that ongoing enhancement in theoretical research and process technology related to the fracturing transformation of deep and ultra-deep shale reservoirs is essential. It is imperative to refine, accurately design, and differentially set the fracturing construction parameters, elucidate the transport mechanism and distribution mode of proppant in complex fracture networks, and optimize fracture conductivity comprehensively. The research findings presented here are of significant reference value for the development of deep to ultra-deep shale gas in China, aiming to achieve cost reduction, quality improvement, and efficiency enhancement.

China’s first long-term abandoned deepwater oil field has become a marginal oil field that is difficult to exploit due to complex technical difficulties and low economic benefits faced by secondary development. Through the research and practice of GGRP (geophysics-geology-reservoir-production) integrated technology, abandoned oil fields are revitalized to ensure high and stable production. In order to cope with the challenges of uncertainty in the distribution of remaining oil, structural complexity, reservoir heterogeneity and temperature limitations of underwater manifolds, we have overcome a series of cutting-edge technical problems. These innovative technologies include remaining oil prediction technology for long-term water flooding shut-in oil fields, geological guidance and fine description technology for complex oil reservoirs, and reservoir pipe flow coupling model flow assurance technology. They have successfully guided the secondary development of oil fields and significantly improved improve the development effect of oil fields. The results show that the initial production capacity of the oil field has jumped to the top three oil fields in the eastern South China Sea. The actual water content rising trend is basically consistent with the plan design, and the increase in recoverable reserves is expected to reach 259×10⁴ m³. This pioneering research provides valuable experience for the secondary development of long-term abandoned deepwater oil fields. This scientific and technological achievement has broad application prospects in the development of similar oil fields.

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.

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.

Under the framework of the national “double carbon” strategy, the efficient development and utilization of clean energy have become a focal point across various industries. Middle and deep hydrothermal geothermal resources, characterized by their abundant reserves and environmentally friendly attributes, represent a significant clean energy source. Recent trends have shown a shift from a distributed development model to a cluster development model for geothermal resources, offering advantages in terms of economy, stability, risk management, and scalability. However, the development mode, well patterns, and well spacing, key parameters in cluster development, are still under investigation due to their significant impact on the process. There is an urgent need to conduct research on these mechanisms and optimize the key parameters. In this study, the HTC geothermal field serves as the subject for our analysis. We employ numerical simulation technology to integrate the underground temperature field, pressure field, and water flow field into a comprehensive mathematical model. This model helps analyze the effects of various development modes and patterns, as well as the spacing of mining and irrigation wells, thereby identifying optimal parameters that can guide field production. Practice has demonstrated that this approach effectively ensures the stable operation of geothermal development projects and enhances their economic benefits.

The study explores the abundant oil and gas reserves in the Carboniferous of the southwestern Tarim Basin, with a specific focus on the source rocks of the Carboniferous Kalashayi Formation. By conducting kerogen identification, total organic carbon（TOC） testing, and thermal simulation, the research revealed that these mudstone source rocks primarily consist of Type Ⅲ kerogen. Their TOC ranged from 0.2% to 2.8%, averaging 1.0%. The thermal maturity of the rocks, indicated by a vitrinite reflectance（R_o） greater than 0.7%, varied across different areas. The hydrocarbon generation history of these source rocks was also examined. In the Magaiti slope, the rocks underwent two phases of hydrocarbon generation: one during the Late Hercynian period and another during the Himeyama period. In contrast, in the Bachu bulge, there was only one hydrocarbon generation phase, occurring during the Late Hercynian period. The source rocks in the Magaiti slope are considered mature and are still generating hydrocarbons, influenced by factors such as source rock thickness, TOC, maturity, and the history of hydrocarbon generation and excretion. Furthermore, the source rocks in the western piedmont zone were identified as having the best quality and the highest hydrocarbon generation intensity.

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.