Cluster deployment is the only way to realize the decarbonization industry development for the carbon capture, utilization and storage （CCUS） technology. The innovation and development for the engineered full flowsheet technology of CCUS is the key and urgent need to complete the scale deployment of CCUS decarbonization industry cluster, serving great significance to China’s energy security and carbon neutrality. In this study, the scientific connotations are clarified. The concept is proposed. The basic mode, application mode and key combination mode are firstly summarized, then the technologically scientific process is analyzed. The key techniques are summarized. The formation mechanisms are investigated. The representative project cases both at home and abroad are summarized. The current challenges and outlook are discussed and analyzed. Current works have shown that the efficient CO₂ capture technology, CO₂ chemical and bio-utilization, CO₂ mineralization, efficient CO₂ geological utilization and storage are the core connotation, with CCUS system optimization, source-sink matching and technology matching as the configuration mechanisms. The full flowsheet technology of CCUS is complex and diverse, with five main steps composing in its technical and scientific process. The framework of this technology has been established, and a lot of progress has been made in the field of scientific research and engineering applications. However, there is still a gap between China and developed countries in Europe and America in this field. The main direction of tackling challenges in China includes: accelerating the engineering demonstration of CCUS cluster scale deployment, strengthening the formation mechanism of the engineered full flowsheet technology of CCUS cluster scale deployment technology and scientific research, focusing on the breakthrough of CO₂ capture, geological storage, and other key technical links among the engineered full flowsheet CCUS technology.

With the continuous and further development in Sinopec shale oil exploitation, a series of characteristic technologies such as drilling, logging cementing and fracturing have been preliminarily formed. By the summary and analysis of the progress and achievements made by Sinopec in shale oil engineering technology during the "14th Five-Year Plan" period, the problems and challenges currently existing in shale oil development engineering technology are reviewed, and the technical countermeasures and development suggestions in the aspects of geological and drilling engineering integration, speed-up of drilling and completion, three-dimensional well development, and ultra-long horizontal wells are pointed out. Therefore, it promotes the development of shale oil engineering technology in China, realizes the low-cost, large-scale and cost-effective development of shale oil resources, and provides useful reference.

There are broad prospects of CO₂ flooding for enhancing oil recovery and greenhouse gas storage. In this paper, we reviewed the development history and brief situation of CO₂ flooding at home and abroad, analyzed the development status of CO₂ immiscible flooding and CO₂ huff and puff, and summarized the phase state of CO₂ flooding, oil displacement mechanism evaluation and optimization design technology of CO₂ flooding reservoir engineering. The design focused on improving oil displacement efficiency and sweep efficiency, controlling viscosity index and gas breakthrough, achieving miscible or near-miscible flooding, and optimizing well pattern and injection parameters in combination with reservoir characteristics. It was pointed out that CO₂ near-miscible flooding and increasing sweep volume were the development trends of CO₂ flooding. WAG, foam flooding, fracture sealing and local gravity flooding were important means to prevent gas channeling. On the basis of summarizing the current CO₂ flooding technology and field experience at home and abroad, the top-level design of combination of CO₂ flooding and CO₂ geological storage should be done according to different types of reservoir characteristics.

Adsorbed gas represents a primary mode of shale gas occurrence and is a major source of shale gas production in the later stages of development. It primarily resides within the organic kerogen and clay minerals of shale formations, with organic kerogen being the dominant host. Consequently, the study of organic kerogen characteristics and its adsorption mechanisms is crucial for understanding shale gas development. In this paper, the kerogen of Longmaxi Shale in the Sichuan Basin is taken as the research object. The microstructure of kerogen is expressed by combining methods through the solid-state NMR experiment, Fourier transform infrared spectroscopy experiment, X-ray photoelectron spectroscopy experiment, and the molecular structure model of kerogen is constructed. The adsorption mechanism and characteristics of CH₄ in kerogen of Longmaxi Shale are analyzed by magnetic levitation weight experiment, molecular simulation methods of the Grand Canonical Monte Carlo（GCMC）, and Molecular Dynamics（MD）. The results show that the molecular formula of the kerogen of shale experimental sample of Longmaxi Formation is C₂₃₇H₂₁₉O₂₁N₅S₄. The excess adsorption gas volume of CH₄ in kerogen increase first and then decreased with the increase of pressure. Under the same pore size and pressure, the excess adsorption gas volume and total gas volume of CH₄ decrease with the increase in temperature. The C and S atoms in kerogen are the main cause of CH₄ adsorption. The CH₄ near the kerogen pore wall presents an adsorption state, while the CH₄ far from the kerogen pore wall presents a free state. As the pore size increase, the distance between the two peaks of CH₄ density gradually increases, and the peak value decreases gradually.

With the research and application of the geology-engineering integration technologies, North America has won the victory of shale revolution, and the United States has realized energy independence, playing a dominant role in the global energy market. Its history and experience in shale revolution are the references of great value to the exploration and production of hydrocarbon resources in China. With abundant oil and gas in the exploration areas of Sinopec and various types of favorable targets, accelerating exploration and production is of great significance to improve China's energy structure and ensure national energy security. The application of geology-engineering integration has brought benefit development for the marine shale gas in the Sichuan Basin. In terms of realizing efficient exploration and production of the ultra-deep marine carbonate, tight sandstone and shale, five key studies are suggested to be strengthened: ①fine reservoir description and adaptive fracturing technology of exploration and production for complicated reservoirs, ②ultra-deep carbonate reservoir prediction and optimal drilling technology system, ③application of big data in realizing efficient adjustment and optimize completion program for tight sandstone gas reservoirs, ④development of multi-layer and three-dimensional production technology for marine shale oil and gas, ⑤research on the key problems in the deep, normal-pressure and continental shale oil and gas. To achieve high quality exploration and efficient production of oil and gas, Sinopec will keep strengthening the basic geological research and engineering technology innovation, upgrading technical equipment and following the idea of geology-engineering integration. And then, Sinopec will establish integrated operation coordination mechanism and emphasize integrated management of whole process in order to cut costs and increase efficiency.

The machine learning is not only an important tool for oil and gas big data analysis, but also a general data-driven analysis method. As an important field with a long history and a large data base, oil and gas exploration and development has a great potential for data mining. The use of big data analysis technology for oil and gas field can help decision makers to conduct investment analysis, risk assessment and production optimization, which brings significant economic benefits. The machine learning method has been tried by the researchers applying to the researches on oil and gas. Nowadays, many application scenarios have been proposed with the development of machine learning algorithms, but general solutions for specific scenario are still divided. So that, we introduces the procedure of a machine learning modeling upon the most basic principles, and summarizes the development history of the main three kinds of machine learning methods that can be applied to oil and gas big data analysis. And then based on the characteristics of oil and gas field big data, the core contents, goals and advantages of oil and gas field big data analysis and utilization are discussed, the main application scenarios of machine learning in oil and gas field are analyzed, and the existing problems and countermeasures in typical oil and gas production prediction are summarized.

Deep mountain shale gas play in Yichang, Hubei Province is located in the northern margin of Jianghan Basin in Mid-Yangtze area and has the characteristics of shale gas in Longmaxi formation such as large buried depth, complex geological condition, and large horizontal stress difference. The study of geomechanics is helpful to deepen the understanding of the influence of complex structure, fault and natural fracture system on in-situ stress field, providing basic data for wellbore stability analysis, drilling risk prediction, fracturing design optimization and post-fracturing evaluation of shale gas horizontal wells. The establishment of 3D geomechanical model depends on fine structural interpretation, shale gas geology and multi-scale natural fracture model. Therefore, one for the whole area and development platform is established. The platform scale model has more fine resolution. It can accurately depict the ground stress field around the wells and provides better service for the optimization design of drilling and fracturing. The results show that the stress mechanism in Yichang exploration area is mainly extrusion strike-slip type, the horizontal two-direction stress difference is larger than that in shale gas area of Sichuan Basin, and the risk of natural fracture activation is greater. Meanwhile, the safe window of drilling fluid is narrow and the stability of wellbore is poor. The graded fracturing of horizontal wells is affected by the large horizontal stress difference and the high risk of natural fracture activation, so the hydraulic fracture pattern is relatively simple. Based on the platform model, the 4D geomechanical simulation after fracturing is carried out, and the change of in-situ stress field after pressure is analyzed. It is showed that the minimum principal stress around the fracture net after fracturing increases significantly, the stress mechanism transitions to the reverse impulse type, and the influence range of stress shadow is 20 ~ 40 m. Making full use of geomechanical results plays an important role in improving the efficiency and development benefit of drilling engineering. This study is the first time in China to establish a fine 3D geomechanical model for the deep mountain shale gas in the complex structural area outside the Sichuan Basin. The research results have important demonstration guidance and reference significance for the large-scale development of shale gas in deep layer.

Nowadays, the CCUS industry is developing rapidly worldwide, of which the projects are gradually turning from single-section items to whole-industry ones. The target of capture has expanded from power plants and natural gas processing to steel, cement, kerosene, fertilizers and hydrogen production. At present, there are five major ways to drive the industry: government and public funds, national incentive policies, taxation, mandatory emission reduction policies and carbon trading. In China, the CO₂ emitting enterprises are mainly power plants, cement, steel and coal chemicals, accounting for 92 % of the total emissions. According to the concentration, the low concentration CO₂ emission sources are mainly from power plants, cement, steel and refining and chemical industries, that with high concentration are mainly from coal chemical industry, synthetic ammonia and calcium carbide, and that with medium concentration is mainly from the polyethylene industry. The first are the majority, while the latter two are relatively few. Costs of CO₂ sources are comprised of three main parts: capture cost, compression cost and transportation cost, all of which are affected by the scale of capture. Meanwhile, the cost of capture is also related to the concentration of emission source. For the type of high CO₂ concentration, the expense of compression takes the lead in accounting. And capture cost is for the low CO₂ concentration type. As the tolerance of CO₂ cost is lower than source cost for most oilfields, it is necessary to seek ways like technology, policies or markets to fill the gap and promote the sustainable development.

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

The physical properties of shale oil reservoir are extremely poor, so it is necessary to form a network fracture system through volume fracturing to realize economic and effective development. However, there are lower permeability interlayers both in the top and bottom of shale oil reservoirs, so to master the fracture propagation law of reservoir with interlayers is the key for the successful fracturing of shale oil. With the help of the numerical simulation software, RFPA, of the rock fracture damage analysis system, the influencing factors of fracture propagation in the reservoir interlayers are studied. On the premise of considering the heterogeneity of strata, and by the comprehensively consideration of the elastic modulus, Poisson's ratio, uniaxial compressive strength, tensile strength, horizontal stress difference and interlayer stress difference of the reservoir, the fracability of shale oil reservoir is evaluated by the analytic hierarchy process. The results show that the elastic modulus of the reservoir interlayer, the difference of horizontal in-situ stress and the uniaxial compressive strength of the reservoir are negatively correlated with the degree of crack propagation. As these parameters increase, the cracks are more difficult to expand. However, there is a positive correlation between the ratio of tension and compression of reservoir and the stress difference between layers of reservoir and the degree of fracture propagation, that is, the increase of tensile strength and interlayer stress difference will help to increase the scale of fracture propagation, and the larger interlayer stress difference will make the fractures pass through the interlayers and continue to develop in the interlayer. Meanwhile, the mathematical model of the fracability is established by the analytic hierarchy process in fuzzy mathematics, and applied to the fractured wells in the work area. The predicted results are consistent with the experimental microseismic monitoring results, and the research results can provide reference for shale oil fracturing reform.

The proved reserves of natural gas in place in China is huge. However, realizing the long-term large scale stable production of natural gas faces a series of challenges such as enhanced gas recovery（EGR） of complex gas reservoirs, especially for those unconventional resources such as shale gas, coalbed methane and tight sand gas. Under the background of carbon neutralization, CCUS-EGR technology has broad application prospects due to owing the functions of increasing gas rate and carbon reduction. The main EGR mechanisms for CO₂ flooding are summarized into three types: substitution due to dominant adsorption of carbon dioxide, continuous convective displacement and gas reservoir energy supplement. Under the consideration that the classification of occurrence states of the adsorbed, free and dissolved natural gas are applicable to all types of the gas reservoirs. The prediction method of increased natural gas ultimate recovery factor by CO₂ flooding is further deduced. It is found that CO₂ flooding is expected to improve shale gas recovery of more than 20 percentage points by this method. In order to break through the technology of greatly improving natural gas recovery, it is suggested to evaluate the potential of CO₂ flooding to improve natural gas recovery for gas reservoirs with good geological sequestration conditions, assess the economic feasibility of CCUS-EGR technology applying in target gas reservoirs, and carry out major pilot tests of CO₂ flooding in various types of gas reservoirs. The synergistic displacement effect of flue gas components and the technology of expanding CO₂ sweeping volume should be focused especially.

The greenhouse effect caused by excessive CO₂ emissions has led to many adverse effects on human life. As an effective CO₂ disposal technology, CO₂ geological storage technology has aroused more and more attention. The solubility of CO₂ in simulated deep saline solution and its variation with burial depth（800~2 800 m）were studied. The results showed that, when the buried depth was in the range of 800~1 700 m, the solubility of CO₂ decreased with the increase of buried depth. When the buried depth was greater than 1 700 m, the solubility of CO₂ increased with the increase of saline depth. In addition, the change of CO₂ solubility with burial depth could be fitted by the equation. And based on this equation, the storage capacity of CO₂ in a certain area of storage site could be calculated.

Real-time monitoring and evaluation of fractures is one of the core issues in the multi-stage fracturing process of horizontal wells, and has long been a focus of many scholars. During the fracturing construction, the pressure during pump shutdown includes water hammer pressure and seepage pressure. By installing a high-frequency pressure device at the wellhead, not only the pump shutdown pressure drop curve but also the water hammer waveform curve can be completely collected. In this paper, the simulated pressure data are obtained by numerically solving the governing equation of wellbore water hammer. The cepstrum analysis of the simulated water hammer pressure verifies that the pressure generated by the water hammer has convolution characteristics. According to the related theory of wave impedance and cepstrum analysis, the water hammer wave can be used to determine the number of fracture clusters and the depth in multi-cluster fracturing of horizontal wells. The field application in Sichuan shale gas well shows that this method can find five liquid inlet points, of which the inversion results of four liquid inlet points are close to four perforation positions, and the remaining four clusters of holes in the design correspond to the liquid inlet points It was not detected in the cepstrum analysis.

The wettability decides the fluid distribution in porous media, and the wet-phase fluid will primarily occupy the smaller pore. Based on this principle, the paradox between laboratory test of coal wettability and state of fluids distribution is analyzed. On the view of wettability, two possible coalbed methane（CBM） storage types are proposed. When the coal is gas-phase wettability, owing to capillary pressure, the free gas and adsorption gas can be trapped in matrix （smaller pore system） by the water in cleat （larger pore system）. In matrix system, the sorption of gas is in equilibrium state, but the storage of gas is in the undersaturated state. The critical desorption process results from the capability pressure of water and gas. When the coal is water-phase wettability, the matrix is saturated by water, and the coalbed methane can store in the matrix in liquid-phase sorption state. This study designs the experiment to validate the gas liquid-phase sorption. The results indicate that a mass of methane can be adsorbed in the matrix in the liquid-phase sorption mode.

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.

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.

With the increasing oil demand in China, it is very important to further tap the potential of oil and gas fields. Chemical flooding technology is one of the important technologies of EOR, and polymer flooding, as the most important method of EOR, has been widely used in the field and achieved good oil displacement effects. Therefore, by summarizing the basic principles of polymer flooding, the development status of various kinds of polymer for oil displacement and the field application effect of polymer flooding, the development direction of polymer flooding in harsh reservoir conditions, such as high temperature and high salt, has been prospected. Through the review, although functional polymers, such as temperature resistant and salt resistant copolymers, instant polymers and amphiphilic polymers, have been successfully developed, the types of polymers used in the field are still limited. How to apply the research and development achievements of new polymers to on-site EOR is the key development direction. With the development of different polymer types, further research on polymer flooding mechanism is needed.

The improvement of experimental technologies of geological evaluation for shale gas is the key factor for the success of shale gas exploration and development in America. The progress in experimental technologies of geological evaluation of shale gas is summarized from three aspects including gas-bearing property, occurrence and fracability of shale. It mainly focuses on the ultramicroscopic organic petrology, formation porosity thermocompression simulation experiment of hydrocarbon generation and expulsion, and the characterization of pore network, which are developed for high thermal maturity marine shale of South China in recent years. The future trends of experimental technologies of geological evaluation for shale gas are discussed. It is proposed that the effectiveness and connectivity of multiscale pore structure, the characterization of organic and inorganic pore in diagenetic evolution, and dynamic evaluation for fracability are the key studying aspects in experimental technologies of geological evaluation of shale gas.

Deep shale gas（buried depth is larger than 3 500 m） is the potential resource for future exploration in Sichuan Basin. Although the industrial shale gas flows have been obtained at the depth of 3 500~4 000 m in Wufeng-Longmaxi Formation of Sichuan Basin, the commercial development hasn’t been put into practice due to the rapid decline and the low EUR（Estimated Ultimate Recovery）. Based on the analysis of the current status of shale gas exploration and development, the challenges in the deep shale gas development with high efficiency and large scale in Sichuan Basin have been summarized, mainly in the following aspects: the understanding of occurrence mechanism and enrichment law of deep shale gas needs to be deepened, engineering and technology of economical and effective fracturing treatment need to be established, and the organizational operations and management methods of deep shale gas development are difficult to meet the needs of the large-scale and high efficient development. Three countermeasures are proposed to realize the large-scale and highly efficient development of deep shale gas: ①deepening the understanding of deep shale gas enrichment laws, establishing the methods of area selection and evaluation, and forming the prediction and description technologies of “sweet spot” and “sweet window”; ②deepening the research on the geological conditions of deep shale gas, forming an advanced supporting technology of drilling and fracturing and an equipment system to fully release the reservoir capacity; ③promoting the geology-engineering integration, building a new system and mechanism, and greatly reducing the cost to maximize the development benefits of deep shale gas. The industrial gas flows have been obtained in several wells at the depth of more than 3 500 m of Wufeng-Longmaxi Formation in Sichuan Basin and the proven reserves have been submitted. It is the key and priority stratum of the deep shale gas development. By deepening the geological understanding, overcoming the key technical problems, and improving the management system, it can significantly accelerate the speed, reduce the cost, increase the efficiency and achieve a large-scale and highly efficient development in a relatively short period. The output is expected to be higher than that of the middle and shallow shale gas reservoir.

Based on the summary of deep shale gas breakthrough wells in recent years, four geological characteristics of deep shale gas are put forward. First, the basic evaluation parameters of deep and shallow shale are similar, but gas content and porosity of deep shale are generally higher than those of medium-deep shale. Second, the horizontal stress difference of deep shale is much greater than that of medium-deep shale. Third, deep shale gas in the basin is generally overpressured, and the pressure coefficient is generally between 1.9 and 2.1, while the complex structure area at the edge of the basin is normally pressured. Fourth, the positive structure is still the main factor for high yield of deep shale gas. Based on the analysis of the decline characteristics of single well production curve in Haynesville and Barnett shale gas fields and the geological characteristics of deep shale gas in Sichuan Basin, three main problems of deep shale gas, namely theoretical understanding innovation, engineering process applicability as well as cost and benefit development. The corresponding countermeasures are also pointed out.

Shale gas resource evaluation includes resource calculation, favorable distribution area and economic effectiveness based on geological and exploration process analysis. Its core is evaluation method selection, parameter processing and result analysis in line with geological process evolution characteristics and data mastery degree. The intelligent evaluation of shale gas resources can overcome the limitations of real resource evaluation, and can realize the whole process simulation and evaluation from qualitative to quantitative. It has obvious characteristics of development stages. The main feature of resource evaluation at this stage is to use modern means such as machine learning and inference engine. Method selection, parameter quality and evaluation effect are the keys to shale gas resource evaluation. Knowledge base establishment based on geological characteristics and exploration level, data collection, parameter analysis, data mining, geological reasoning, method selection, intelligent calculation, and reliability of results analysis, spatial expression of results and continuous execution throughout the process are the basic ideas and methods for intelligent evaluation of shale gas resources. Intelligent evaluation with powerful functions and continuous implementation throughout the whole process is the basic direction of the development of shale gas resource evaluation, which requires continuous accumulation and practice on the basis of existing technologies to promote the development of shale gas resource evaluation methods and technologies in a wider range.

CO₂ flooding is a promising way to improve the crude oil recovery ratio. CO₂ could not only dissolve in crude oil, but also replace some light hydrocarbons or intermediate hydrocarbons in crude oil. So the composition has great influence on the component mass transfer and minimum miscible pressure of the CO₂ miscible flooding. Therefore, the influence of the quantitative characterization of crude oil composition on the minimum miscible pressure of the CO₂ miscible flooding has engineering significance for the reservoir screening. Taking the original formation fluid of a certain oilfield in China as the research object, we analyzed the multistage contact miscibility mechanism. Meanwhile, we used the Winprop module in CMG to carried out the phase simulation of experimental data. The results show that the minimum miscible pressure between CO₂ and crude oil is proportional to the molar composition of N₂, C₁ and C₁₁₊, and inversely proportional to that of C₂~C₁₀. While the mixing of the CO₂ and reservoir fluids needs higher reservoir pressure than minimum miscible pressure. It requires that when screening reservoirs with CO₂ flooding, we should try to consider the reservoir with high mole content of C₂ ~ C₁₀ and low mole content of C₂₄. It has great guiding significance for miscible displacement design and miscible phase prediction.

In order to study the evaluation standard of deep shale reservoirs, their micro pore characteristics have been studied. Based on the ideas of micro pore structure research with “high precision and cross scale”, and by using nitrogen adsorption, high pressure mercury injection, scanning electron microscope and mineral analysis electron microscope experiments, a series of quantitative characterization techniques of reservoir micro pore structure with full pore size range are formed, and the evaluation standard of deep shale gas reservoir is established. The research results show that: ①The pore types include organic pore, intergranular pore, intragranular pore and microfracture, which are of great difference with each other. The organic pores are dominant with the surface porosity more than 50 %, the pore morphology is complex with the distribution of elliptic, irregular or flat, the shape coefficient is 0.50~0.90, and the fractal dimension（D） is 2.72~2.92. ②Based on the full pore size characterization technology and fractal theory, the pore structure can be divided into four types. The organic pores of type Ⅰ pore structure are developed （organic pore ratio Is greater than or equal to 50 %）, well sorted （sorting coefficient Is greater than or equal to 0.7）, large coefficient of variation （variation coefficient Is greater than or equal to 1.1）, and multi-modal distribution of pore size. ③According to the classification of pore structure and reservoir parameters, shale reservoirs are divided into four types. The key parameters make up the structure of type Ⅰ are TOC≥4 %, total gas content Is greater than or equal to 6 m³/t, porosity Is greater than or equal to 6 %, brittle mineral content Is greater than or equal to 50 %, Young’s modulus Is greater than or equal to 36 GPa, Poisson’s ratio Is less than or equal to 0.225, and type Ⅰ pore structure. This kind of reservoir is mainly distributed in 2—3¹ layers, which is the optimal target window position.

Based on the concept of geology-engineering integration, a systematic research, including theoretical study and field investigation, has been performed on design optimization, implement control and post-frac management of the whole lifecycle of volumetric fracturing technology in unconventional reservoir. The key technologies include: ①the series of pre-frac evaluation technologies regarding geology-engineering double “sweet spots”, double sweetness and comprehensive fracability; ②big data and AI algorithm based “well pattern-fracture-fracturing technique” multi-parameter collaborative optimization technology; ③fracturing control technology based on formation geological properties obtained from inversion study of on-site fracturing operation data; optimization on fracturing fluid flowback scenarios with consideration of imbibition effect; ④comprehensive post-frac evaluation technology; ⑤progressive production management optimization and adjustment technology in effective period of fracturing treatment. Field applications demonstrate that the geology-engineering integration volumetric fracturing technology with consideration of whole lifecycle development can maximize the potential to increase production, stabilize production and improve single well EUR, which has enormous guidance and reference significance towards the achievement of the “Four Improvements” and “Cost Reducing” goals in unconventional reservoir development.

The machine learning method is the main technical means of carbonate lithofacies log identification. Selecting the appropriate machine learning method according to the different geological conditions and data is one of the key factors for high-precision identification of lithofacies. However, there are few researches on the applicability of machine learning identification methods. In this paper, four most commonly used machine learning methods for identifying lithofacies are studied, including Self Organizing Maps（SOM）, Multi-Resolution Graph-based Clustering（MRGC）, K Nearest Neighbor（KNN）, and Artificial Neural Network（ANN）. By comparing the principle and practical application effects of these methods, the advantages, disadvantages and applicability of the four machine learning methods have been summarized. When there are few core samples, MRGC is preferred, while when there are more core data, KNN is preferred as well as MRGC. Their application of lithofacies identification in the Longwangmiao Formation in the MX area in Sichuan Basin shows that MRGC and KNN are the best, SOM is the second, and ANN is the worst. This study of the application effects of machine learning methods provides a guidance for the identification of carbonate rock facies in other layers and regions, and has strong practical value.

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.

In view of the technical difficulties of CO₂ flooding completion string, the research process and development situation of completion string of CO₂ flooding injection-production well were systematically expounded. It was concluded that the sealing performance of the completion string of injection well and anti corrosion and gas proof performance of production well were the key technologies for the normal production of CO₂ flooding injection-production well. The pilot test of CO₂ flooding in domestic oilfield showed that the continuous optimization of packer and the gas tightness detection of tubing contributed to improve sealing of injection wells, and the technologies like CO₂ corrosion inhibitor formulation, injection strengthening, tube controlling by gas lifting, downhole oil and gas separation were helpful to improve the pumping efficiency of the production wells. Meanwhile, in view of the technical problems faced by the injection and production wells on site, the further research direction of production by CO₂ flooding injection and production technology was pointed out.

In order to solve the problems of long perforation cycle, high cost and self-locking of long horizontal section of coiled tubing transmission, a key test for tractor perforation has been carried out. At present, the staged fracturing of horizontal shale gas wells mainly uses pumping bridge plug perforation. In the first part of the frac well, because of the lack of pumping channels, coiled tubing transmission perforation is used usually, which need longer operating cycle and higher cost, and is not beneficial to reduce cost and improve efficiency. Nanchuan Shale Gas Field has expanded the business scope of the roller tractor by introducing and improving some tools, and realized the tractor perforation of shale gas horizontal wells. The tractor perforation powered by a tractor transports the perforation gun to the position and ignites the gun. By on-site improvement and testing, Nanchuan Shale Gas Field has solved the problems of voltage isolation protection joints, shock absorption joints and adapters, mastered the performance of tractor perforation and applicable conditions, and provided experience for subsequent construction and basis. The test results show that the perforation of the tractor in the horizontal section of shale gas wells with a well deviation of less than 90° is reliable and feasible. The tractor perforation can meet the needs of shale gas horizontal wells under pressure perforating operation. Its operation process is greatly affected by well deviation and wellbore cleanliness. Compared with coiled tubing perforation, its speed-up and cost-reducing effect is obvious. The construction period can be saved by two days, up to 50 %.

With the expansion of domestic shale gas development demand and production capacity, the all-electric fracturing equipment and technology has become the recommended application technology for normal pressure shale gas fracturing engineering due to the low efficiency of conventional fracturing equipment, large environmental pollution and insufficient water power guarantee in the domestic market. This paper focuses on analyzing the demonstration application effect of all-electric fracturing technology in atmospheric shale gas resource block, demonstrating its advantages in shale gas benefit development and green and low-carbon development. Results show that the all-electric fracturing all-electric case can achieve stable high load, high reliable and continuous construction of the large displacement, high construction efficiency, The comprehensive costs of construction equipment, power, labor and maintenance, etc., fell by more than 40 %, pollution emissions by 70 %, the effective control of noise at boundary of atmospheric pressure shale gas can effectively help realize benefit the development and construction of green mining enterprises of the forehead.

CO₂ flooding is effective for enhancing the oil recovery in low permeability reservoir and reducing the greenhouse gas emissions. In order to solve the technical problems of difficult miscible phase, easy gas channelling and low sweep coefficient for CO₂ flooding in low permeability reservoir in Shengli Oilfield. By the combination of physical and numerical simulation, the development mechanism of the CO₂ injection miscible flooding long in advance is clarified, and the comprehensive techniques for extra low permeability reservoir is formed. After field application, the stimulation effect is obvious, the daily production of oil per well increase by 5 times. The principle and technical idea of reducing the miscibility pressure are put forward, and the system of reducing the miscible pressure system is developed, which can make the pressure decrease by up to 22 %. The challenge and countermeasure faced by scale application of CO₂ flooding in Shengli Oilfield are analyzed, and the development directions of CO₂ flooding are proposed, such as deepening the phase state theory of oil recovery enhanced by CO₂ flooding, developing CO₂ flooding technology with expanded sweep volume at low cost, developing incomplete CO₂ miscible flooding, and description and early warning of gas channeling. All these provide technical support for oil field to realize scale application of CO₂ flooding.

Shale oil resources are rich around the world and have extraordinary exploitation prospects. However, drilling horizontal wells and huge amounts of hydraulic fracturing measures had sharply increased the cost. A large number of experiments and numerical simulations showed that the gas injection could significantly improve the shale oil recovery. Nevertheless, this technique had not been implemented to the practical exploitation of shale oil. Consequently, it was still controversial whether shale oil recovery could be optimized through gas injection or not. By the comparison of the gas displacement experiments of the shale cores, the numerical simulation of shale oil recovery by gas injection and the gas injection pilots in practical fields, it was found that the results from experimental conditions and numerical simulation models were different from those in field pilots. Li Chuanliang insisted that the shale reservoir was consisted of myriad micro-lithologic traps. It was concluded that only if the gas was injected after fracturing, or establishing an orthogonal horizontal well pattern to dense the well spacing, would the shale oil recovery be improved. It has essential guidance for the improvement of shale oil recovery in China or even in the world.

In order to solve the problem that water flooding is difficult to effectively develop low-ultra-low permeability reservoirs, Sinopec has carried out more than 30 field tests of CO₂ flooding, and achieves preliminary results and understanding. In this paper, firstly, the field test progress of CO₂ flooding and typical reservoir effects of SINOPEC are systematically described. Then, the change characteristics of technical policies and key indicators are analyzed. Finally, the problems faced by the development of CO₂ flooding in Sinopec are pointed out, and the development suggestions are put forward. The analysis reveals that the CO₂ flooding is an effective method to supplement energy for the low and ultra-low permeability reservoir. In order to produce more oil, WAG （water alternating gas） flooding are performed after continuous gas flooding. The oil well take effects about 6 months after the program is implemented. The average oil production by single well is increased by more than one-time and the oil change rate is 0.15~0.40 t/t. But the economic benefit through CO₂ flooding is limited by two problems. The first one is that the minimum miscible pressure for CO₂ is usually higher than 25 MPa in the low and ultra-low permeability reservoir and it is difficult to achieve fully miscible condition. The second one is that the lack of low-cost gas sources limits the economic benefits of CO₂. In order to improve the oil displacement efficiency and achieve high economic benefit, not only the national subsidy policy is required, but also the optimization for CCUS is needed. The CO₂ flooding can also be performed with chemical agents, flue gas or nitrogen to improve oil displacement effect and enhance economic benefit.

Currently, the problem of intra-well frac hit is serious in shale gas, which disturbs the production of nearby wells. Taking the Weiyuan national shale gas demonstration area as the research object, and according to the production characteristics of parent wells, quantitative evaluation index of intra-well frac hit influence based on the recovery rate of parent well production has been put forward. Then ten key geological and engineering parameters affecting intra-well frac hit influence have been analyzed by grey correlation method. The result shows that the grey correlations of intra-well distance, parent well producing time, average fluid volume of single cluster and natural fracture are higher. On this basis, the influence of intra-well position, parent well production time and average fluid volume to intra-well frac hit extent has been evaluated to obtain the following results. Firstly, the main intra-well position of frac hit is parallel, while the secondary is the position of opposite and malposition. Secondly, as the producing time of parent wells increase, the impact of frac hit significantly increases. The suggested optimal operation time of child wells is within 300 produce days of parent wells. Thirdly, as the average fluid volume of single cluster of child wells increases, the impact of frac hit increases too, so that it is suggested to optimize the liquid scale of single cluster according to the production time of parent wells and intra-well position. Lastly, the fluids volume, perforations and slurry rate should be strictly optimized in the section with cut-through natural fracture in order to reduce frac hit risk. Field tests show that the result can provide a reference to reduce the impact of intra-well frac hit of shale gas.

In recent years, the exploration of Longmaxi Formation in Sichuan Basin has been successful, but the shale gas of the complex structural belt’s Longmaxi Formation are still the next areas for exploration. Therefore, it is necessary to carry out systematic researches on the Sanbaiti section in Mount Huaying of high-steep structural belt in Sichuan Basin, so as to provide ideas for the further exploration breakthrough. The section’s lithology, paleontology, mineral composition, geochemical characteristics, pore type and structure are studied, and compared with the drilling wells of adjacent areas. The findings are as follows. ①The outcrop in Mount Huaying section is well exposed. The shale strata from Wufeng Formation to the bottom of Longmaxi Formation are complete and continuous. Wufeng Formation is divided into two sections, and the Longmaxi Formation（no top） is divided into three sections. The WF2-LM9 graptolite biozone is well developed. From the bottom to the top, the sedimentary environment changed from reduction to oxidation, and the biogenic siliceous environment has been destroyed. The injection amount of terrigenous debris increases, and the abundance of organic matter shows a downward trend. The organic matter in Long-1 member of Wufeng Formation is relatively rich, and the content of brittle minerals is high. The reservoir space is dominated by organic pores, followed by inorganic pores and microfractures. The pore structure is dominated by ink bottles, and a small amount of slit pores. ②For the Hirnantian-Rhuddanian, although the Sanbaiti section of Mount Huaying is located in the deep-water shelf zone in southern Sichuan, the underwater highland micro-paleogeomorphology is locally developed. Due to the influence of undercurrent and other factors, the deposition thickness of organic-rich shale is thin. So that, the micro-paleogeomorphology has an important influence on the material basis of shale gas formation, which can provide ideas for the further evaluation of Longmaxi Formation. ③The formation of organic-rich shale reservoirs in Long-1 member of Wufeng Formation is mainly controlled by the combined action of volcanism, source supply and reduction environment.

Based on the analysis of the coal-forming environment of the Carboniferous Taiyuan Formation in Xunyi exploration area, southern Ordos Basin, and combined with paleogeomorphological analysis and sedimentary facies research, the coal accumulation characteristics of Taiyuan Formation were identified. By using experimental analysis methods such as industrial analysis, scanning electron microscopy, and isothermal adsorption, along with well-logging modeling evaluation, the characteristics of coal petrology and coal quality, reservoir physical properties, and gas content were investigated. The key controlling factors for deep coalbed methane accumulation and reservoir formation characteristics were analyzed and summarized, identifying favorable zones for further exploration. Integrated with coalbed methane exploration practice, it was confirmed that deep coalbed methane had promising exploration potential. Research showed that: (1) the development of coal seams in the Carboniferous Taiyuan Formation in the Xunyi exploration area was influenced by two coal-forming environments: tidal flat peat bogs and lagoon peat bogs. Due to the influence of coal-forming environments and sedimentary paleogeomorphology, the coal seam distribution exhibited a “thin in the west and thick in the east” coal accumulation pattern. (2) The coal lithotypes were primarily bright coal and semi-bright coal, with the coal body structures mainly characterized by primary and fractured types. The types of reservoir space included plant cell lumen pores, intercrystalline pores of pyrite and clay minerals, and cleat fractures. (3) The gas content of coal seams ranged from 15.8 to 25.6 m³/t, indicating moderate to good gas-bearing properties. The enrichment of coalbed methane was controlled by factors such as the coal-forming environment, tectonic evolution, and preservation conditions. (4) The northwest slope area was characterized by underdeveloped faults, normal formation pressure, weak formation hydrodynamics, and large coal seam burial depth, making it a favorable zone for deep normal-pressure coalbed methane exploration. The southeast fault slope area had relatively developed faults, low formation pressure, strong formation hydrodynamics, and moderate coal seam burial depth, making it a favorable zone for medium-to-deep low-pressure coalbed methane exploration. The PZ1 well, located in the southeast fault slope area, produced a low gas flow during coal seam fracturing tests, demonstrating the promising exploration potential of deep coalbed methane in the structurally complex margin of the Ordos Basin.

The starting pressure gradient and pressure sensitivity effect proposed by Bear（1972） and Fatt（1952） respectively have practical significance for the development of low permeability oil and gas reservoirs. The so-called starting pressure gradient refers to the critical pressure gradient that causes the oil and gas formations to start flowing. The so-called pressure-sensitive effect includes the phenomenon that the formation permeability decreases as the formation pressure drops. Due to the theoretical needs of tight and low-permeability reservoir development analysis in the Ordos Basin, relevant experts and scholars in China have paid attention to the starting pressure gradient and pressure sensitivity effect for nearly 20 years, but their understanding is still in the initial perceptual stage. The reason is the lack of basic derivation. The derivation in this paper shows that the pressure gradient and starting pressure gradient of Darcy linear flow are constant, but the pressure gradient and starting pressure gradient of Darcy plane radial flow both are functions of radial radius. It is incorrect to directly apply the constant starting pressure gradient of linear flow to the plane radial flow equation. Although the pressure sensitivity effect of permeability exists, it can never be used in the flow equation of Darcy’s law. Because constant permeability is the basis for the establishment of Darcy’s law. Otherwise, it will shake the theoretical foundations of Ground Fluid Dynamics, Petroleum Reservoir Engineering and Reservoir Numerical Simulation.

Climate change centering on carbon dioxide（CO₂） emissions and energy security centering on the shortage of oil resources are two major problems restricting the sustainable development of China's social economy. In order to solve the bottleneck of both the CO₂ capture and the great improvement of recovery factor of low permeability reservoir, the related technology researches have been carried out in Shengli Oilfield, forming the supporting technologies such as CO₂ capture, safe long-distance transmission, reservoir engineering optimization design, the injection-production process design, design of surface gathering and oil displacement and environmental monitoring, and building an industrial-scale demonstration project for flue gas CO₂ capture, oil displacement and underground storage of coal-fired power plants. The industrial tests show that the cost of the new MSA technology is 35 % lower than that of the traditional MEA technology. Over 31×10⁴ t of CO₂ have successfully been injected into the reservoir, with the cumulative oil increment of 8.6×10⁴ t, and 28×10⁴ t of CO₂ storaged in G89-1 block. The central well area has increased the recovery rate by 9.5 %, and the recovery rate is expected to reach 17.2 %.

CO₂ huff-n-puff after fracturing of horizontal wells can effectively improve the properties of crude oil and increase the oil recovery of ultra-low permeability reservoirs. Combined with the geology and fluid characteristics of a typical ultra-low permeability reservoir, Block H, the mechanism of multi-cycle CO₂ injection in horizontal wells and the variation of crude oil properties in ultra-low permeability reservoirs are studied by means of laboratory experiment and numerical simulation. The results show that after CO₂ injection, the saturated pressure of crude oil increases, the volume expands, the viscosity decreases, and the system becomes lighter. And the main action mechanism of different stages of CO₂ huff-n-puff are different: in the injection stage, the main mechanism is to supplement the formation energy, dissolve in crude oil, and reduce the crude oil viscosity; in the soaking and the initial stage of production, the main mechanism is to reduce the crude oil viscosity and expand the scope of CO₂; in the middle and late period of well opening production, the light hydrocarbons and a small amount of intermediate component hydrocarbons in the oil phase are extracted. The CO₂ content in oil phases at different distances in the reservoir is analyzed by the method of fixed time and fixed point, and it is deduced that the lateral sweep radius of CO₂ injection along the fracture in H block is 24~40 m. With the increase of the huff-n-puff cycle, the increase of molar content of CO₂ in the oil phase decreased from 451 times in the first cycle to 0.44 times in the third cycle. The dissolved amount of injected CO₂ in crude oil decreases relatively, and the effect on the properties of crude oil also gradually decreases. The above research provides a new analysis method for understanding the mechanism of CO₂ huff-n-puff, and provides some theoretical support for further popularizing the multi-cycle CO₂ huff-n-puff technology of horizontal wells in ultra-low permeability reservoirs.

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.

In order to clarify the main principal factors that affect the initial productivity during the development of shale oil reservoirs, a comprehensive data analysis method involved both the hierarchical cluster analysis and the principal component analysis in data statistics is presented; and then the deta of the static formation parameters, fracturing operation parameters and the oil productivity of 51 wells in Block Li-151 are analyzed quantitatively. At first, the wells in the block are divided automatically into two types, Type A and Type B, by the hierarchical cluster analysis method. Then, a principal component analysis method is used to analyze the principal productivity factors for different types of wells. Analysis results show that, when the well shut-in time is less than 125 days, the oil production decline rate can be reduced effectively by the well shut-in measures; however, when it is greater than 125 days, the effect of well shut-in measures on oil production decline rate becomes negative. The production decline rate of Type A wells is highly negative with the amount of injected fracturing water; the main principal factors for the production decline rate of Type B wells are the moving liquid level and the porosity of shale matrix. The principal factors for the production rate of Type B wells are the number of fracturing sections. All in all, for the production optimization of shale oil development in Block Li-151, the differences of principal production factors between Type A wells and Type B wells should be considered and the different analysis results of the principal factors that affect the initial shale oil productivity under different well types should be fully utilized. Some guidance can be provided specifically for the formulation of a reasonable shale oil efficient development plan.

Normal pressure shale gas is one of the main types of shale gas exploration and development in China. It has great resource potential and broad prospects. In recent years, Sinopec East China Oil and Gas Company has continued to carry out normal pressure shale gas exploration and practice in Nanchuan-Wulong area of the basin-margin transition zone in southeastern Chongqing. Positive progress has been made in the following aspects such as basic geological theory research, low cost engineering technology research, green mine construction of normal pressure shale gas. The enrichment and high yield geological theory of “three factors controlling gas”, and the classification and evaluation standard and the target evaluation system of shale reservoirs are established. Six low cost engineering technologies of normal pressure shale gas are proposed, that is, low density 3D seismic exploration, well completion at the “second” section, “drop ball steering+continuous sand addition”, “three steps” fracturing sand addition, electric fracturing and high efficiency drainage gas production. The development technology strategy of normal pressure shale gas is preliminarily formed. The integrated green exploration and development mode is put forward. More breakthrough and efficient development of normal pressure shale gas exploration are realized. Normal pressure shale gas shows a good prospect of exploration and development. However, the exploration and development of normal pressure shale gas in China is still in its infancy and exploration stage. There are still many challenges in aspects such as theoretical innovation, technological breakthrough and benefit development. So that five countermeasures are proposed for the development of China’s normal pressure shale gas industry: ①deepen the research on the main controlling factors of shale gas enrichment and high-yield, and strengthen the target evaluation; ②speed up the research on the supporting technology of excellent drilling and completion for the further acceleration and efficiency increasing; ③strengthen the research on high-efficiency fracturing technology to increase production, reduce cost and increase efficiency; ④strengthen the research on the production rule of normal pressure shale gas, and formulate the technical strategy of benefit development; ⑤fully implement the integrated operation mode of shale gas geological engineering, improve the management quality and create benefit. These countermeasures are counted on accelerating the development of normal pressure shale gas industry in China.

Recently, positive progress has been made in the exploration and development for shale gas of the Wufeng-Longmaxi formation in the area with complex structure of the southeast area of Chongqing. In order to further deepen the understanding of shale gas accumulation in this area, based on the previous research results, by using the data such as experimental analysis, geophysical exploration, drilling, fracturing and gas testing, and starting from the key factors of controlling shale gas enrichment and high yield, typical target anatomy and mechanism analyses are carried out to summarize the rules of shale gas enrichment and high yield. Meanwhile, it is found that the enrichment and high yield of shale gas are controlled by three factors: sedimentary facies, preservation conditions and in-situ stress field, concretely speaking, deep-water shelf facies controls the scale of resources; preservation conditions control the degree of shale gas enrichment; in-situ stress field influences the effect of fracturing transformation and controls the yield of single well. To optimize shale gas sweet spot targets and well location deployment in complex structural areas, firstly, the resource basis for controlling shale gas enrichment should be evaluated, that is, the development degree and indicators of high-quality shale in deep-water shelf facies. Secondly, the intensity of tectonic movements is evaluated to determine the preservation conditions and enrichment degree of shale gas. Finally, it is preferred to deploy a shale gas well with a medium-curvature zone of moderate in-situ stress to facilitate high and stable yield. The research results have important guidance and reference significance for the exploration and development of shale gas in complex structural areas.

Carbon capture, utilization and storage (CCUS) is a key technology for achieving carbon neutrality, providing the dual benefits of enhanced energy production and reduced CO₂ emissions through CO₂-enhanced oil and gas recovery (EOR/EGR) and geological storage. However, the large-scale application of CCUS technology faces technical challenges such as engineering design and risk assessment. Traditional approaches, which rely on empirical formulas, experimental verification, and physical models, suffer from low computational efficiency, limited model accuracy, and difficulties in handling multi-dimensional coupling when addressing complex systems. Machine learning (ML), with its powerful data-driven analytical capabilities and adaptive optimization features, can establish high-precision prediction models, optimize operating parameters, predict reservoir fluid behavior, and assess leakage risks. This enables real-time monitoring and intelligent decision-making for complex systems, enhancing the safety and economic efficiency of CCUS technology. This study systematically reviews the applications of ML in CO₂-enhanced oil and gas recovery and geological storage. In terms of CO₂-enhanced oil and gas recovery, the applications cover percolation mechanism modeling, well pattern design optimization, production prediction and evaluation, multi-objective optimization, minimum miscibility pressure prediction, gas adsorption curve prediction, and CO₂-CH₄ diffusion assessment. For CO₂ geological storage, the applications include reservoir selection, research on CO₂ dissolution and diffusion mechanisms, geological storage performance prediction, and risk assessment. ML demonstrates significant advantages in improving prediction accuracy, optimizing operating parameters, and enhancing computational efficiency. It has made important progress in key fields such as reservoir selection, gas adsorption prediction, and storage performance prediction. However, challenges remain in terms of adaptability to complex geological scenarios, model universality, dynamic data processing capabilities, and physical interpretability.

The productivity of gas wells in conventional gas reservoirs is mainly measured by open flow rate. The open flow rate is determined by gas test and production test data to evaluate the productivity of gas wells. Because of the particularity of geological characteristics and seepage mechanism, it is controversial to use which indexes to characterize the productivity of shale gas wells. Combined with the testing and production data of actual shale gas wells in China, it is proposed that the productivity of shale gas wells in different development stages can be characterized by three kinds of indexes—unhindered flow rate, recoverable reserves and gas production. When the productivity of shale gas wells is characterized by open flow, the empirical formula of “one point method” in Fuling main area is established, and the reservoir capacity（α） is 0.25. For the production capacity test of multiple work systems, the multi-flow method has better adaptability in Fuling. When the productivity of shale gas wells is characterized by recoverable reserves, before shale gas wells enter the decline stage, the unsteady productivity evaluation method of shale gas fractured horizontal wells is selected; while after entering the decline stage, the recoverable reserves of shale gas wells can be predicted by empirical decline method. For shale gas wells with fixed production, the gas test production of the same oil nozzle can be optimized to characterize the productivity of shale gas wells. The research results lay a foundation for the dynamic analysis of shale gas well production and the formulation of development technology policy.

There are several methods of the production decline analysis during the shale gas reservoir development, such as the Arps model, the SEPD model, the Duong model and their composition models. Among them, the Arps model is the main method. There are two main choices of the appropriate decline methods. One is to transform the data into the linear relationship and the method with high correlation coefficient can be deemed as the better model. The other is to use the non-linear regression by the combination of the above models and choose the analysis method with high correlation coefficient. Then we proposed a new method to choose the production decline analysis model, and obtained the relation degree by comparing the linear combination of the different decline analysis models with the practical production data, furthermore, according to the degree of correlation in order, selected the production decline analysis method. This method is validated by the high fitting precision between the calculated results and the production data, which provides a reliable and reasonable way to choose the production decline models.

There are some problems of drilling composite bridge plug by coiled tubing in staged fracturing of shale gas horizontal wells, such as easy to get stuck, high frequency of strong magnetic fishing and long working hours. In order to solve these problems, deep analyses were carried out on the structure and dissolution principle of soluble bridge plug. And according to the key factors affecting the fracturing and dissolution performance of soluble bridge plug, field tests of soluble bridge plugs with different temperature resistance were carried out in Nanchuan shale gas field. The test results showed that the soluble bridge plugs could bear the differential pressure of 70 MPa under the temperature of 112 ℃. The soluble bridge plugs with heat resistance of 93 ℃ could be completely dissolved, while those with heat resistance of 120 ℃ could be partly dissolved. Compared with traditional composite bridge plug, the cost of a single well was reduced by 1.087 million Yuan. The main factors that affecting the fracturing and dissolution performance of soluble bridge plug were temperature, mineralization degree of solution and dissolution time. The higher the mineralization degree and the temperature were, the faster the dissolution rate of the soluble bridge plug would be. In particular, the well temperature was of great importance to the dissolution effect of soluble bridge plug. The feasibility and economy of soluble bridge plug in staged fracturing of shale gas wells were verified either, which was proved to have application value for cost reducing and efficiency increasing in fracturing of shale gas wells.

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.

Traditionally, laboratory testing and measurement are considered to be the most reliable characterization methods. However, in many cases, due to the unclear understanding of the sensitivity to the range of reservoir properties and local changes of heterogeneous reservoir properties, and based on the oversimplified assumptions, the feature prediction obtained by this deterministic strategy is highly uncertain. In recent years, molecular dynamics （MD） simulation has received extensive attention in the study of reservoir rock, fluid properties and their interactions, as well as at the atomic level. In MD simulation, interesting properties are extracted from the time evolution analysis of atomic position and velocity through the numerical solution of Newton's equations for all atomic motions in the system. This technology can help to carry out the computer experiments which can be used to do the experiments that may not be able to complete, with high cost or very dangerous. In this paper, we review the MD simulation technology and its application in the study of oil displacement mechanism and properties of oil displacement agent, and expounds the theoretical concept and program of MD, especially in the analysis of polymer flooding. It will provide useful guidelines to characterize reservoir rocks and fluids and their behaviors in various reservoirs, help to better optimize the operation of design and production plan, and provide a theoretical basis for the development of polymer flooding technology in oilfields.

The water cut of heavy oil reservoir in Dagang Oilfield increased rapidly in the middle and late period of water flooding, and the production effect became worse. CO₂ huff and puff technology is an effective method to develop heavy oil reservoirs. But the parameter optimization and field effect in the late stage of high water cut needed to be studied urgently. Therefore, the heavy oil reservoir in Dagang Oilfield was used to carry out the experiments of CO₂ injection for solubilization and swelling with viscosity reduction. Based on the experiments and well logging data, a single-well numerical simulation model was established to simulate the reservoir parameters and CO₂ injection parameters, and analyzed the CO₂ oil stimulation mechanism. Based on the results of theoretical researches, the in-site CO₂ huff and puff experiments were carried out in Banqiao and Liuguanzhuang. The research results show that the mechanism of water control and oil increase by CO₂ is mainly to expand the volume of crude oil and reduce the viscosity of crude oil, and the viscosity can be reduced by up to 98 %. The impact of injection volume, injection speed, and throughput cycle is relatively large on the CO₂ throughput effect. It is recommended that the CO₂ injection volume of a single well is 600~1 000 t（0.22~0.37HCPV）, the injection speed is 40~80 t/d, and the throughput runs 3~4 cycles. In Banqiao and Liuguanzhuang, CO₂ huff and puff have been carried out 12 times on wells, with an average increase of 3.4 times of oil production per well and a 52.2 % reduction of comprehensive water cut. Thus, CO₂ huff and puff technology is an effective water-control and oil-increasing technology, which has important reference significance for improving oil recovery in the later stage of water injection in similar heavy oil reservoirs.

At present, there is no particularly effective method to predict the degree of production at the end of the stable production period of gas reservoirs with active edge water. The production often declines rapidly without warning. Based on the physical model of long core of gas reservoirs by water flooding in Yakela area, the characteristics of gas-water two-phase seepage during water invasion are simulated by the experiment of gas recovery by water flooding. Taking the material balance equation of water flooding as the theoretical method, the concept of water invasion coefficient is introduced to describe the water invasion characteristics of gas reservoirs. As the hydrocarbon pore volume（HPV） of the injected water is consistent with the concept of water invasion coefficient, it is feasible to simulate the effect of water invasion on gas reservoir by water flooding experiments. The experimental results show that when the injected water reached 0.3 ~ 0.45 times of HPV, the waterflood front breaks through, and the gas production enters the rapid decline period from the stable production period. The production history shows that when the water invasion coefficients of the middle-lower gas reservoir reach 0.33 ~ 0.36, the gas production decreases rapidly, and the experiment is basically consistent with the production practice. By calculating the water invasion coefficient of upper gas reservoir, when the water invasion coefficients reach 0.33 ~ 0.36 from August 2019 to February 2020, the end of stable production period will come. It is basically consistent with the results of numerical simulation and necessary to adjust the high risk wells in time.