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

FETKOVICH proposed the water influx rate equation in finite aquifer and the type curve with constant pressure in 1971 and 1980 respectively, which have been widely recognized and cited by experts both domestically and internationally. His methodology allows for the determination of a well's drainage radius and area by fitting actual production data to his type curve, a technique that has gained popularity among field experts. The derivation of this paper shows that the equation for water influx rate equation in finite aquifer of FETKOVICH is an is characterized by an exponential decline, a model he directly applied to analyze production declines in wells with volumetrically closed boundaries. He derived a dimensionless time for the type curve based on the relationship with the initial decline rate and used the inverse of dimensionless pressure as a proxy for dimensionless production to develop the type curve's dimensionless production profile. However, it's important to note that FETKOVICH's model does not establish a direct functional relationship between dimensionless time and dimensionless production in the type curve model, which means that a comprehensive dimensionless type curve cannot be formulated directly from his equations. This article deduces the water influx rate equation in finite aquifer and the dimensionless time and dimensionless production of the type curve, and questioned and commented on the existing problems.

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

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

The global consensus on achieving carbon neutrality is driven by the urgent need to address climate change caused by excessive CO₂ emissions. Carbon Capture, Utilization, and Storage（CCUS） stands out as a critical solution, receiving significant attention from the researchers. Sinopec Nanjing Research Institute of Chemical Industry Co., Ltd. has been committed to the research and development and application of CO₂ capture and utilization technology for a long time. The institute has perfected three advanced carbon capture methods: low partial pressure flue gas carbon capture technology, NCMA（Nanjing chemical mixed amine） decarburization technology and catalytic hot potassium alkali decarburization technology, which have been successfully applied in many industrial projects. Furthermore, the institute is pushing boundaries in new carbon capture and CO₂ utilization technologies, achieving notable advancements that align with both domestic and international standards.

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

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

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

In the past two decades, Sinopec Northeast Oil & Gas Company has made significant strides in exploring the southern Songliao Basin, revealing that the basin's volcanic rocks present a new and promising avenue for hydrocarbon exploration. According to the exploration practice of the basin, the company has developed a comprehensive four-component coupling reservoir control model specific to fault depressions. This model emphasizes the interconnected evolution of key elements such as hydrocarbon generating foci, reservoir formation periods, paleostructure, fault cap preservation, and effective reservoirs, with a particular focus on the main accumulation period. This strategic approach led to the significant discovery of a large-scale volcanic gas reservoir within the Huoshiling Formation in the Changling fault depression, located in the Songnan area. Consequently, the exploration focus has broadened from the Yingcheng Formation to the Huoshiling Formation, diversifying the exploration targets from acidic volcanic rocks to intermediate-basic volcanic rocks, and extending from subaerial to submarine eruptions. By using the technique of fine gas reservoir description, the integration of modeling, numerical modeling and geological engineering, the productivity breakthrough has been achieved in several wells in Songnan fault depression, and the efficient development and large-scale production of volcanic gas reservoir has been realized.

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

Under the background of “carbon peak and carbon neutrality”, traditional chemical enterprises are encountering challenges due to CO₂ emission limitations. CCUS（Carbon Capture, Utilization and Storage） technology emerges as a crucial strategy for addressing CO₂ emissions. To mitigate emissions at the source, chemical companies are turning to CO₂ flue gas capture and recovery technologies, while also exploring ways to integrate these efforts into a cost-effective CCUS industrial chain. To overcome the drawbacks of traditional CO₂ flue gas recovery units, such as large land use, high construction costs, inflexibility, and lengthy construction times, the modular skid-mounted CO₂ recovery technology has been introduced. This innovative approach minimizes upfront investment and accelerates project timelines by modularizing the recovery process, allowing for 100% factory prefabrication and streamlined on-site assembly. The skid-mounted design efficiently organizes pipelines and valves, integrating equipment within each module onto skids, resulting in a fully modular skid-mounted CO₂ recovery unit. Field applications demonstrate significant advantages of the modular skid-mounted approach over conventional methods. For example, a 5×10⁴ tons per year coal-to-hydrogen CO₂ flue gas recovery unit saw a 74.0% reduction in construction costs, a 75.2% decrease in required space, and a 50.0% shorter construction timeline, effectively meeting the objectives of cost reduction and expedited project completion.

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

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

Numerous oil displacing mechanisms of CO₂ have been widely recognized, but due to reservoir factors, the effectiveness of CO₂ flooding varies significantly under different reservoir conditions. It is necessary to further deepen the research on the micro-interaction mechanisms between CO₂ and crude oil, clarify the CO₂ flooding mode under different reservoir conditions, and maximize the potential of CO₂ flooding. Molecular dynamics simulation methods have been used to study the effects of components, temperature, and pressure on the interaction between oil droplets and CO₂. The kinetic parameters were obtained to quantitatively characterize the oil droplets-CO₂ interaction, clarifying the micro-interaction patterns under different conditions. The simulation results show that the dispersion force is the the main driving force of the interaction between CO₂ and alkane molecules, which mainly includes two aspects: one is the dissolution and diffusion of CO₂ molecules into the oil droplets by overcoming the steric hindrance between alkane molecules, and the other is the extraction attraction of CO₂ molecules to the outer layer molecules of the oil droplets. As the chain length of alkane molecules decreases, the temperature decreases and the pressure increases, the solubility parameter of the oil droplets and the coordination number of CO₂ increase, the curvature of the molecules in the outer layer of the oil droplets decreases, and the interaction between the two is enhanced. It is concluded that CO₂ miscible and near-miscible flooding should be realised as much as possible in light and medium-light reservoirs with lower temperatures and higher pressures, while in medium and heavy reservoirs with higher temperatures and lower pressures, the advantages of CO₂ non-miscible flooding in terms of dissolution viscosity reduction, crude oil volume expansion and energy replenishment should be fully exploited. The study results can provide theoretical guidance for laboratorial research and field application of CO₂ flooding.

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.

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

The BZ oilfield in Bohai, known for its buried hill carbonate reservoir, is currently in the middle to late stages of development. The reservoir is characterized by strong heterogeneity and a complex distribution of fractures and vugs, leading to challenges such as complicated production behavior, rapidly declining output, and significant discrepancies in the estimation of dynamic and static reserves. To address these issues, a comprehensive set of criteria for identifying different types of carbonate reservoirs in the oilfield was developed. This was based on conventional well log data, thin section analyses, limited core data, and information from well tests and production characteristics. The reservoirs were categorized into three main types: fracture, fracture-vuggy, and porous. A detailed three-dimensional numerical well-testing model was created to accurately predict high-quality reservoir zones. This model took into account the reservoir's horizontal and vertical heterogeneity, allowing for precise delineation and assessment of the reservoir boundaries and connectivity in complex wells. It also facilitated a more accurate evaluation of the dynamic reserves and confirmed the oil and gas potential in the submerged mountains at the boundary of the Archaean group. This comprehensive approach laid the groundwork for devising strategic adjustments during the latter stages of the oilfield's development. It guided field modifications aimed at maximizing the reservoir's potential, ultimately leading to validated high production outcomes.

Geothermal energy, as a stable and sustainable clean energy source, is set to play a crucial role in China's energy structure transformation and the realization of the “double carbon” goal in the future. The Ordos Basin, noted for its abundant geothermal resources, still holds much untapped potential due to incomplete understanding of its reserves and distribution characteristics, and the relatively low level of exploration and development. Focusing on the Changqing Oilfield and its surrounding areas, the study delves into the geothermal geological characteristics using well data. It employs the unit volume method to estimate the geothermal resource reserves and conducts zoning based on the development and utilization potential of these resources. The study reveals that the formation structure in the area is relatively straightforward, with a general geothermal gradient of 2.2~3.0 ℃/hm. The primary thermal reservoir consists of conductive Mesozoic sandstone, while other thermal reservoirs, except for Luohe Formation, exhibit poor water yield. The geothermal resources in the region are distributed with higher concentrations in the western areas and lower in the east, with a total amount of 79.91 × 10¹⁷ kJ. Among this a recoverable capacity of 6.39 × 10¹⁷ kJ, and a geothermal fluid reserve of 2.47 × 10¹² m³ have been identified Blocks such as Hongliugou-Dashuikeng-Jicun-Shancheng block, Zhanggoumen-Liuquzhen-Sanchazhen block and the block near Qingyang exhibit significant potential for geothermal resource development. Therefore, the study recommends prioritizing the redevelopment of abandoned oil and gas wells, alongside the construction of medium and deep casing heat exchange systems. This approach would facilitate the effective development and utilization of geothermal resources in these areas.

CO₂ flooding and sequestration technology can significantly improve crude oil recovery rates while enge. However, the oil displaceabling large-scale CO₂ flooding and sequestration process is accompanied by various CO₂ leakage risks. In response to the lack of previous CO₂ leakage risk management systems, especially the absence of systems based on online monitoring that support dynamic risk management, research has been conducted on the construction of a CO₂ flooding and sequestration leakage risk management system. Based on the construction of CO₂ flooding and storage leakage risk management system, a dynamic CO₂ leakage risk management system integrating multi-environment real-time risk identification and assessment, multi-space risk prediction, multi-level risk early warning and whole process risk control was developed and applied to the CO₂ flooding and storage demonstration project of Yanchang Petroleum in Ordos Basin. Case studies demonstrate that the developed CO₂ leakage risk management system can dynamically identify various leakage risks throughout the CO₂ flooding and sequestration process across all spaces, effectively supporting the dynamic management of leakage risks. This provides comprehensive and timely safety assurance for CO₂ flooding and sequestration projects, ensuring that potential risks are managed and mitigated effectively to maintain the integrity and success of these projects.

The BZ19-6 condensate gas field, characterized by large reserves, small surface pressure differential, high temperature and pressure reservoir conditions, and low porosity and permeability, is highly susceptible to retrograde condensation contamination during production operations. Evaluating the degree of retrograde condensation contamination and adopting appropriate contamination remediation measures are crucial for improving the situation in the BZ19-6 condensate gas field. The long core failure experiment was carried out using the mixed condensate gas to simulate the reverse condensate pollution, test the gas permeability corresponding to different exhaustion pressure points and evaluate the degree of reverse condensate pollution. Additionally, experiments on remediation of retrograde condensation contamination were carried out using three different approaches: injection of surfactant（TC281）, injection of methanol, and injection of a combination of methanol and surfactant. Furthermore, an experiment was conducted using a combination of methanol and surfactant to address both retrograde condensation and water blockage, a comprehensive liquid phase contamination. The experimental results indicate that all three schemes of injecting active agent（TC281）, injecting methanol and injecting methanol + active agent have certain effects on removing retrograde condensation pollution. The group of injecting methanol + active agent 1 has the best effect on removing retrograde condensation and removing retrograde condensation pollution, and the permeability recovery rate is 84%. The permeability recovery rate of methanol injection to remove retrograde condensation pollution is 81%. The recovery rate of retrograde condensate permeability in the surfactant injection group 1 was 54%. The injection of methanol + active agent 1 relieved the comprehensive liquid phase pollution of reverse condensation + water lock, and the permeability recovery rate reached 80%. These experiments provide guidance for remediation strategies to address retrograde condensation contamination in the BZ19-6 condensate gas field.

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.

With the convergence of global carbon neutrality goals, the CCUS industry has ushered in new opportunities after a century of development. Developed countries in Europe and America have vigorously supported the research and development of CCUS technologies and the promotion of engineering demonstrations through measures such as carbon markets, carbon taxation systems, carbon subsidies or rebates, and carbon border adjustment mechanisms. The embryonic form of CCUS industrialization has emerged, with broad market prospects. Compared to foreign countries, China's CCUS-related policies and regulations are mainly guiding in nature, with the scale of the carbon market and carbon price levels still at relatively low levels, urgently requiring strengthened research on CCUS policy and regulatory formulation and supporting measures. Therefore, we define the input-output framework of CCUS projects, sort out the economic benefits and fiscal taxation policy environment of typical CCUS projects in the world, and put forward suggestions on the development of CCUS industrial benefits in China. The analysis shows that foreign projects generally receive direct subsidies from the government, with capture costs accounting for 70% to 80% of operating costs. Environmental costs mainly include environmental risks after CO₂ leakage and additional emissions generated after installing CCUS. Output benefits include direct and indirect benefits, and under conditions where gas prices exceed 200 RMB per ton, CO₂ enhanced oil recovery projects are difficult to achieve economic benefits. In conjunction with a comparative analysis of the current status of CCUS policies and regulations at home and abroad, suggestions for the development of CCUS industrialization are proposed, such as accelerating the pace of technological research and development iterations, increasing the construction of CCUS cluster hub centers, and promptly issuing progressive and combined CCUS policies and regulations..

The gas-water relative permeability curve reflects the comprehensive physical properties of the reservoir. Clarifying the relationship between the gas-water relative permeability behavior of tight sandstone and the production performance of gas wells is conducive to the efficient development of tight gas reservoirs. Taking the typical tight sandstone gas reservoirs in the eastern margin of Ordos Basin as the research object, the reservoirs are divided into three types and gas-water relative permeability experiments are carried out. Combined with core analysis methods such as X-ray diffraction, scanning electron microscopy and nuclear magnetic resonance, the relationship between gas-water relative permeability and gas well production performance curve is revealed. The results show that: ① The two-phase transition zone of relative permeability curve I is wide, the pore type of which is mainly intergranular pores. The two-phase transition zone of relative permeability curve Ⅱ is narrow, the pore types of which are mainly intergranular pores and intergranular pores. The two-phase transition zone of relative permeability curve Ⅲ is extremely narrow, and the pore type is mainly dominated by intergranular pores; ② The clay mineral content is high. kaolinite and chlorite are conducive to gas-water phase flow. Illite is not conducive to gas-water phase flow; ③ The pore and throat of in the reservoir have large differences and can be roughly divided into three categories: large pores（greater than 1.0 μm）, mesopores（0.1~1.0 μm） and small pores（less than 0.1 μm）. The large pores in the reservoir of class I, Ⅱ and Ⅲ account for about 40%, 10%, and 4%, respectively; ④ The gas wells can be divided into three types, the production performance of which are consistent with the predicted results of the relative permeability curves. The main production layer of the well of class I responds to the reservoir of class I. The effective layer thickness is about 7 m. The average daily production is about 2×10⁴ m³ with a long stable production period. The main production layer of the well of class Ⅱ responds to the reservoir of class Ⅱ. The effective layer thickness is about 5 m. The average daily production is about 1×10⁴ m³. The main production layer of the well of class Ⅲ responds to the reservoir of class Ⅲ. The effective layer thickness is about 6 m. The average daily production is about 0.5×10⁴ m³ with a very short stable production period. By analyzing the gas-water relative permeability characteristics to predict gas well production dynamics, the impact of pore structure and clay minerals on gas-water flow behavior is revealed. This can provide theoretical support for developing measures to reduce resistance and enhance efficiency in the development process of low-pressure, high-water-content tight gas fields.

In the development of water-flooded oil fields entering the high water-cut stage, the remaining oil often accumulates at the top of structural high positions or thick oil layers, areas not effectively covered by the existing well network. Utilizing the intrinsic characteristics of the reservoir to inject CO₂ and form a gas cap drive can effectively improve development outcomes and achieve CO₂ sequestration. However, the suitability of specific reservoirs for gas cap drive development requires further study. This study delves into the effectiveness of CO₂ gas cap drive in high water-cut reservoirs by examining the movement of the oil-gas interface during the gas cap drive process, using both numerical and physical simulations. Key evaluation metrics include enhanced oil recovery rate, oil displacement efficiency, time to reach the critical gas-oil ratio, and gas retention rate. The research assesses how various reservoir characteristics, such as formation dip angle, crude oil density, viscosity, reservoir confinement, permeability, and the strength of water drive, influence the efficiency of CO₂ gas cap drive for both oil displacement and sequestration. Focusing on these main evaluation criteria, the study identifies that the suitability of CO₂ gas cap drive in reservoirs during the high water-cut phase is significantly influenced by factors such as reservoir confinement, formation dip angle, crude oil viscosity, permeability, and reservoir thickness. These findings aim to provide a foundation for broadening the application of CO₂ flooding techniques. crude oil viscosity, reservoir permeability, and thickness, to provide a basis for expanding the application range of CO₂ flooding.

The utilization of hydrate-based capture and storage of CO₂ presents a promising avenue for substantial emissions reduction, contributing significantly to achieving carbon neutrality goals and addressing climate change. This paper delves into the foundational aspects of gas hydrates, including their properties, formation mechanisms, and models, as well as hydrate synthesis within porous media and the use of molecular dynamics simulations for understanding hydrate formation. Key challenges identified in the synthesis process of gas hydrates include the limited solubility of CO₂ in porous media, which poses a significant hurdle in precisely determining the storage capacity of CO₂ hydrates. Additionally, the local structural mechanisms, particularly nucleation processes involved in gas hydrate formation, are highlighted as complex areas that warrant further investigation. The paper also evaluates the potential of coal-bearing strata, especially in high-latitude and permafrost regions, as viable underground repositories for CO₂ storage via hydrate formation. This approach not only offers a method for reducing atmospheric CO₂ levels but also leverages the unique geological characteristics of these regions to enhance the efficiency and stability of CO₂ storage. In summary, while hydrate-based CO₂ capture and storage technologies hold considerable promise for climate change mitigation, addressing the scientific and technical challenges identified in this review is crucial for advancing the field and optimizing the efficacy of this storage method.

Addressing the challenges of moderate to strong velocity sensitivity damage and strong to extremely strong water sensitivity damage in the medium and deep heavy oil reservoirs of Xinjiang oilfields, which lead to suboptimal waterflooding outcomes, a study was conducted leveraging the unique physical and chemical properties of CO₂. Utilizing high-temperature, high-pressure PVT apparatus and long core displacement equipment, the feasibility of enhancing oil recovery through CO₂ flooding/huff and puff was explored by determining the high-pressure physical properties of CO₂-crude oil and analyzing the composition and viscosity changes of the produced oil with gas chromatography and high-temperature, high-pressure rheometry. The experimental results show that 57.345% mole fraction of CO₂ can increase the dissolved gas-oil ratio（GOR） from 32 m³/m³ to 149.3 m³/m³, the bubble point pressure（p_b） from 6.8 MPa to 15.7 MPa, the volume coefficient of crude oil from 1.06 to 1.27, the density of crude oil from 0.896 5 g/cm³ to 0.854 8 g/cm³, and the viscosity of crude oil from 419.3 mPa·s to 253.4 mPa·s. Therefore, CO₂ can effectively supplement the formation energy, increase the elastic energy of crude oil and reduce the seepage resistance. The first round of 0.95 PV（pore volume） CO₂ flooding has a crude oil recovery of 32.8%, and the fluid in the porous medium is redistributed after 24 hours of shut-in. The second round of 0.5 PV CO₂ flooding can increase the crude oil recovery by 17.9%. The crude oil recovery of five rounds of CO₂ huff and puff is 63.5%. The viscosity of the produced oil tends to decrease, mainly due to the deposition of asphaltenes in crude oil in porous media. The experimental results have confirmed the feasibility of CO₂ flooding/huff and puff in the recovery of heavy oil in the middle and deep layers of Xinjiang Oilfield.

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

Dainan Formation in Majiazui Oilfield is characterized by developed fractures and is primarily composed of structural-lithologic reservoirs. The reservoirs exhibit thin vertical thickness and rapid lateral distribution changes, demanding high precision in reservoir prediction, which conventional seismic inversion methods struggle to meet. To address this challenge, the waveform indication simulation method was employed for thin reservoir prediction in the study area. This method, guided by waveform coherency, uses changes in seismic waveforms laterally instead of variogram functions to simulate target parameters, yielding high-precision inversion results that better conform to sedimentary and geological laws. Taking advantage of the dense and numerous development wells in the study area, and integrating geological, seismic, and well logging data, the spontaneous potential curve, which is sensitive to the reservoir, was selected for waveform indication simulation. This approach was used to predict the distribution of the main oil-bearing sand groups. The inversion results were analyzed in conjunction with the computation wells, check wells, and cross-fault wells, indicating that the waveform indication simulation has high vertical and lateral resolution. It can finely reflect the spatial variation of the reservoir. The main oil-bearing sand group's planar distribution was extracted and found to be consistent with the sedimentary patterns of the study area. Combined with the oil layer distribution map, the target oil-bearing sand group's distribution was re-evaluated, suggesting potential for rolling extension to the west beneath the Ma3 fault. This insight could guide further exploration and development strategies in the Majiazui Oilfield.

Reinjection plays a crucial role in maintaining the pressure of geothermal reservoirs, extending the lifespan of geothermal fields and preserving the environment. In the Hancheng area, located at the southeastern margin of the Ordos Basin in Shaanxi province, there is an abundance of karst geothermal resources. Despite this, the level of development and utilization of these resources in the region remains relatively limited. To further evaluate the development potential of Karst geothermal resources in the region, we implemented a karst geothermal heating project and conducting a tracer test, employing NH₄SCN as the tracer. The goal was to establish an hydraulic connection between the production well and the reinjection well. Utilizing the thermal breakthrough model, predictions were made regarding the changes in the temperature of the production well as a consequence of long-term reinjection. The findings suggest that there is a primary direct pathway for the flow of water, and possibly a secondary path that may contribute to groundwater storage. The temperature of production well's water is projected to decline by 8.31 ℃ over 100 years due to the reinjection process. However, this decline is not expected to cause a severe temperature drop in the geothermal reservoir within this dual-well system.

Represented by the integrated oilfield of the continental sandstone reservoir in Shengli Oil Zone, the main unit of which has entered the late stage of ultra-high water cut（>95%）. This stage has led to significant challenges, including extreme water consumption in certain areas, a sharp increase in the water-to-oil ratio, a marked decline in the utilization rate of injected water, rising operating costs per ton of oil, and diminishing economic returns. Despite these issues, approximately 60% of the remaining geological reserves are still present in the reservoir, making the widespread drilling of new wells economically unfeasible. The primary obstacles to profitable development at this stage include the preferential flow of injected water through zones of extreme water consumption and limited dynamic sweep efficiency. Addressing the identification, description, and management of these extreme water consumption zones is crucial for achieving profitable development in maturing oilfields with ultra-high water cuts. This paper suggests a comprehensive approach to tackle these challenges. It involves understanding the formation and control mechanisms of extreme water consumption zones, characterizing reservoir heterogeneity based on configuration and lithology, quantitatively describing the distribution of these zones, and devising strategies to regulate their expansion using variable streamlines in existing wells. The goal is to develop a suite of profitable development technologies that enable precise reservoir characterization and effective management of extreme water consumption zones in the late ultra-high water cut stage. Traditionally, a reservoir with a 98% water cut is considered nearly depleted. However, by applying key technologies for flow field regulation and benefit enhancement to a demonstration unit within such a reservoir, its economic lifespan can be extended by over a decade. This approach can stabilize annual oil production, reduce water cut, lower operating costs per ton of oil, and facilitate low-cost development in maturing oilfields at the late ultra-high water cut stage, thereby addressing the economic and operational challenges inherent in this phase of development.

The interlayer and intralayer interference, which is commonly existing in the process of oilfield development, especially for the offshore strongly heterogeneous huge thick sandstone and conglomerate reservoirs that are not completely separated vertically, is the basis and internal cause of reservoir subdivision. In practice, interference data are primarily obtained from production logging, which shows that the interference coefficient changes with the development stage and over time. Since production logging is typically a point test, it does not capture the full cycle interference coefficient, highlighting the need for laboratory studies on interlayer and intralayer interference. The theoretical study of interference coefficient involves numerous parameters and the interference coefficient changes with time. This theory can explain the phenomenon that the overall oil production capacity of multi-layer combined production wells is lower than the cumulative amount of multi-layer production, but it fails to solve the theoretical root cause of its formation. So a one-dimensional core displacement experimental device was used for the study of the interlayer and intralayer interference. The experiment shows that for the interlayer interference, the interference coefficient gradually increases with time as water cut rises, but decreases in high water cut period. This is due to the difference in the displacement pressure gradient of each core during single flooding and combined flooding. While for the intralayer interference, the interference coefficient of oil production index is large in the early stage, and gradually decreases with the increase of water cut. The essence of the interference is that the change of seepage resistance of different reservoirs with time results in the change of reservoir flow distribution.

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

Industrial oil and gas have been found in the volcaniclastic rocks of the Huoshiling Formation erupted underwater in the continental lacustrine basin of the Changling fault depression in the Songliao Basin, which has broad exploration prospects. The study focuses on the reservoir space characteristics, physical properties and pore structure differences of the underwater eruption pyroclastic rock reservoirs in the Huoshiling Formation, and analyzes the reasons for the differences in physical properties of different types of reservoirs and their formation and evolution processes. There are mainly the following four aspects: ① Tuff, with its high volcanic glass content, predominantly features devitrification and dissolution pores as its main reservoir spaces. Coarser particle sizes in tuff correlate with improved physical properties, including larger and more abundant pores. Sedimentary tuff, rich in clay minerals, exhibits mainly interstitial spaces between these minerals and poorer physical properties. Tuffaceous sandstone, with high levels of soluble components like feldspar, debris, and laumontite, is characterized by dissolution pores. ② The average porosity is 2.43%, and the average permeability is 0.076×10^-3 μm². Coarse-grained tuff exhibits the highest porosity, followed by tuffaceous sandstone and fine-grained tuff, with sedimentary tuff displaying the poorest physical properties. ③ Devitrification significantly contributes to the high porosity yet ultra-low permeability observed in tuff reservoirs. Organic acid dissolution during the middle diagenesis stage, resulting from two separate oil and gas fillings, further enhances porosity. Additionally, fractures serve as conduits for organic acids and deep hydrothermal fluids, promoting further dissolution that connects dispersed dissolution pores and enhances reservoir space effectiveness. ④The coarse-grained tuff reservoir in the near-source facies gas-carrying subaqueous pyroclastic flow subfacies is a favorable target for oil and gas exploration.

The production of BG shale oil Block of Jinhu Sag of Subei Basin declines rapidly after fracturing, showing poor development efficiency. Enhancing the estimated ultimate reserves（EUR） of individual wells during later depletion stages is crucial for profitable development. While CO₂ huff-n-puff is a common stimulation technique, its high costs and variable effectiveness have limited its widespread adoption. Based on the geological characteristics of BG block, we carried out research on the mechanism of shale oil stimulation by water huff-n-puff by using core NMR, SEM, well test analysis and other methods, and clarified that water huff-n-puff can greatly develop the oil in 1~100 nm pores in imbibition process and improve the porosity and permeability conditions. Given the Subei Basin shale oil's notable hydrophilicity, rich oil content, and extensive fracture network, water huff-n-puff technology was proposed and field-tested. Up to now, the cumulative oil increase of the two test wells is more than 7 600 tons, which shows good application prospects and economic benefits. And it has guiding significance for the low-cost and efficient production stimulation in the shale oil development in Subei Basin.

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

The structural and mechanical characteristics of carbonate rock under the action of chemistry and mechanics is an important research topic for the evaluation of the effectiveness of acid fracturing technology in this kind of reservoir. This research focused on the impact of 20% HCI gelled acid on the structural and mechanical properties of carbonate rocks, categorized into four types based on their mineral composition: limestone, dolomite-bearing limestone, limestone-bearing dolomite, and dolomite. The experiments revealed distinct reactions of these rock types to acid exposure. Limestone exhibited uniform etching, while dolomite-bearing limestone showed selective etching, creating wormhole-like grooves. Limestone-bearing dolomite and dolomite predominantly experienced point etching and erosion along structural planes. Initially, the shear failure of carbonate rocks was primarily governed by matrix strength. However, acid treatment altered their internal structure, making them more susceptible to tensile stress damage, leading to potential splitting or destruction along structural planes. Notably, the reduction in the macroscopic strength of the carbonate rocks post-acid treatment was significantly greater than the decrease in matrix strength alone. The invasion of acid liquid into the rocks introduced additional microscopic defects, evidenced by a reduced proportion of elastic energy and an increased proportion of dissipated energy at peak stress levels. This suggests that the macroscopic mechanical property deterioration results from both matrix strength weakening and internal structural changes. These findings offer valuable insights for field acid fracturing operations in carbonate rock reservoirs and aid in the planning of subsequent production strategies

The binomial productivity equation is a pivotal tool for analyzing data in gas reservoir development, typically resolved using well test data. However, in tight volcanic gas reservoirs, the pressure remains stable and changes slowly, which can lead to challenges during productivity well tests. Specifically, the indication curve generated from measured data may have an intercept less than 0, rendering the equation unsolvable in its standard form, thereby necessitating a correction to the formula. Taking the Well-C2 of tight volcanic gas reservoir as an example, the reason of abnormal indication curve is analyzed. By reviewing and adapting existing equation correction methods, the bottom hole flowing pressure data from the productivity test well is adjusted, leading to the derivation of a new corrected binomial productivity equation. It is applied to the tight volcanic gas well, and the result is more stable than the result of single-point method. It can fully leverage the well test data and provide the basis for the calculation of open flow capacity and the formulation of subsequent development and production plan.

Anisotropic parameter inversion based on pre-stack azimuth gather seismic data is one of the primary methods for fracture prediction, among which two algorithms, RüGER approximate equation and Fourier series expansion, are more widely used. Both the anisotropic gradient in the RüGER approximate equation and the second-order term in the Fourier series expansion can characterize the crack intensity. In the experiment, the applicability of applying this two equations was compared in the single-layer interface and the fracture layer of the actual drilled wells, respectively, and the fracture spatial prediction results were compared in the actual volcanic rock development zone. There are dimensional differences in the prediction of fracture strength between the two equations of single interface model. The range of fracture strength of RüGER approximation equation is larger than that of Fourier series expansion. Multiple results exist for the calculation of fracture orientation using the RüGER approximation equation, which may result in an orientation perpendicular to the fracture. However, when applied to the fractured layers observed in wells, both methods yielded broadly consistent results regarding fracture orientation and strength. In the application to the volcanic rock formation of the LFS area in the southern Songliao Basin, the Fourier series' second-order term slightly outperformed the RüGER equation in aligning with the fracture strength interpretations derived from electrical imaging logging. Additionally, the predicted fracture orientations from both methods matched those interpreted from imaging logging. It is concluded that the Fourier series equation for predicting fractures is more suitable for popularization and application in the field of volcanic rocks.

Currently, the most widely used pre-stack simultaneous inversion algorithm is based on the Zoeppritz equation approximation of isotropic horizontal media. This method, however, encounters challenges in medium-basic volcanic reservoirs characterized by rapid lateral lithological changes and vertical multi-period stacking. In such environments, tuffs and sedimentary tuffs exhibit similar logging and geophysical responses, complicating the distinction of lithology and physical properties of volcanic rocks through pre-stack simultaneous inversion. To address these challenges, qualitative analyses were conducted on the seismic response characteristics of volcanic reservoirs using convolutional model forward modeling. Additionally, well rock physics was employed for physical analyses of lithology and sensitive parameters pertinent to volcanic reservoirs. Comparative analyses of six binomial and trinomial pre-stack inverse algorithms, aimed at approximating the Zoeppritz equation in the specific area, were conducted through model calculations and actual data assessments. Based on these comprehensive analyses, the approximate algorithms developed by SMITH & GIDLOW and FATTI were identified as preferable choices. These algorithms use the reflection coefficients of P-wave impedance, S-wave impedance, and density as inputs for pre-stack inversion. The inversion results for P-wave impedance were utilized to predict the presence of local tuff, while the inversion outcomes for density were employed to ascertain the effective reservoir physical properties. The efficacy of this approach was validated through the deployment of an evaluation well and a horizontal well, which yielded predicted compliance rates of 76.0% and 84.6%, respectively.

Facing the challenges of extremely high water cut, developed preferential channels, highly dispersed remaining oil, and strong heterogeneity in nearly abandoned reservoirs, the study focuses on the 4-5 layer series of the North Block II（Oil Group No. 2） in the Shuanghe Oilfield. By employing detailed reservoir geological modeling, numerical simulation methods, and microscopic displacement experiments, the distribution characteristics of remaining oil after polymer flooding were characterized. Post-polymer flooding, the remaining oil saturation is higher in areas away from the main streamlines on the macro scale, including non-mainstream areas, weak zones along main streamlines, and peripheral areas with larger injector-producer distances. Vertically, remaining oil tends to accumulate at the top of positive rhythm sequences. Microscopically, the remaining oil is primarily in the form of semi-bound state. Based on the characteristics of remaining oil distribution, a technical concept of heterogeneous composite driving and streamline well pattern densification adjustment was proposed. By adjusting the well pattern to alter streamlines, creating a staggered row and column well pattern with a change in streamline direction of over 30° and a streamline deflection rate of 80%, the effective mobilization of remaining oil is promoted. Numerical simulation predicts that this technique could increase the recovery factor by 10.96%, add 706.1 thousand tons of recoverable reserves, and extend the life cycle by 15 years. This offers a new technical approach for significantly enhancing the recovery factor of reservoirs after polymer flooding.

The single-tubing layered testing and adjustment injection process for offshore oilfields cannot meet the conditions of wells with inclinations greater than 60°. At the same time, steel wire operation is required during logging, and a single well takes six hours on average. The logging efficiency is low, and it cannot truly achieve the real-time monitoring of downhole temperature, pressure, flow rate, and injection volume adjustment. On the basis of introducing the principle, applicability, and characteristics of intelligent polymer injection technology with cable control in offshore oil fields, key supporting tools such as cable control intelligent polymer injection pipe, high viscosity maintaining channel under large flow rate, and ground controller have been developed. Experiments have shown that the pipe has better performance with a differential throttle pressure of less than 4 MPa and a viscosity retention rate of more than 85%. Field applications demonstrated that the cable-controlled smart polymer injection technology can provide real-time feedback on flow rate, pressure, temperature, and other monitoring data during the layered polymer injection debugging process in high-inclination wells. This improves the efficiency of polymer injection well testing and adjustment and the standardization rate of reservoir allocation, offering effective technical support for enhancing the recovery factor in offshore oilfield polymer flooding operations.

In the Chaganhua Gas Field within the Songnan Fault Depression, the Huoshiling Formation's volcanic reservoirs exhibit an average porosity of 4.5% and a permeability of 0.08×10^-3 μm, indicating a dense and highly heterogeneous nature. Due to this complexity, a comprehensive approach, testing a broad set of reservoirs, is required to establish effective classification criteria. This study used physical property data, high-pressure mercury injection, nuclear magnetic resonance, and other experiments to analyze the microstructure of volcanic reservoirs. Through multi parameter comparison, a microscopic classification standard was established. Nuclear magnetic logging served as a bridge between microscopic and macroscopic parameters, facilitating the creation of a comprehensive evaluation framework for classifying volcanic reservoirs. This framework encompasses microscopic structural features such as pore throat radius, displacement pressure, mercury saturation, alongside macroscopic parameters obtained from nuclear magnetic logging and other experiments, such as the T2 spectrum distribution, centrifugal saturation, porosity, permeability, saturation, acoustic time difference, lithology density, and resistivity. Reservoirs are categorized from high to low quality into classes A, B, and C based on this comprehensive set of criteria. This method has strong operability and provides a reliable basis for the testing plan of new drilling and the optimization of sweet spots in exploration and development of horizontal wells. The research methods and understanding have certain reference significance for the classification research of volcanic reservoirs.

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.

Addressing issues such as poor water injection capacity, substandard water quality and wax deposition of high pour point crude oil in low permeability reservoirs of Shuanghe Oilfield in Henan, an independently designed water-CO₂ reservoir injection capability evaluation device was utilized to conduct flowability experiments and CO₂ displacement tests. Combined with core scanning electron microscopy and other testing methods, the main mechanism of poor water injection capacity of Shuanghe low permeability reservoirs was clarified, and the main mechanism of CO₂ improving the injection capacity of low permeability reservoirs was explored. The results show that the deposition of suspended particles in the produced water and wax crystals in the oil can lead to pore blockage, thereby reducing the water injection capacity of the reservoir. CO₂ has a significant dissolving effect on inorganic suspended particles in produced water and on alkaline minerals and carbonate minerals in rocks, which is the main mechanism for significantly enhancing the reservoir's water injection capacity. CO₂ can dissolve paraffin deposits on the rock surface, effectively improving the reservoir's water injection capability. At the same time, the effect of CO₂ flooding is obvious, the recovery rate is increased by 13.01% ~ 21.51%, and the subsequent water flooding is further increased by 5.40% ~ 6.04%. This study shows that CO₂ injection can significantly improve the injection capacity of low permeability reservoirs in Shuanghe Oilfield, and provides theoretical support for the field application of CO₂ injection and oil displacement technology.

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