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.

In recent years, extensive attention has been paid to the decarbonization of petroleum and gas exploration and related technologies at home and broad. The structural transformation of the energy industry of the oil and gas is one of the inevitable ways for China to achieve the “carbon peak and neutrality” targets. Under the prerequisite of energy reform to accelerate the achievement of the targets, the energy reform direction and pathway for the oil and gas technology have been analyzed. Taking the project of the electricity substitution technology in the PetroChina Southwest Oil and Gasfield Company as an example, the changes in terms of environmental pollution and energy consumption before and after the implementation of the project are compared. Then, it focuses on the necessity of the drilling and completion electrification transformation and the advantages of the drilling and completion are emphasized. Based on the analyses and summary of the key and difficulties in the practice process, the key technologies that restrict the development of electricity substitution technology and the breakthrough points of the future researches are put forward, which provides reference for the application of “electricity substitution” technology in oil and gas exploration and development under the “dual-carbon” targets.

Qintong Sag of Subei Basin has high abundance of oil and gas resources and great exploration potential, but the geological target has the complex characteristics of “thin, broken, small, scattered and hidden”. Since 1989, there is a series of seismic technical breakthroughs in this area. From conventional 3D to high-precision 3D for secondary acquisition, the acquisition method of “single point broadband receiving with digital geophone, medium surface element grid and high coverage times” is established, a series of processing technologies have been formed, such as sequential processing, improved SNR processing, improved resolution processing, structural-constrained mesh tomographic velocity modeling and reverse-time prestack depth migration imaging, etc., as well as the thin-bedded sandstone prediction technology with the waveform indication inversion of SP sensitive curves. Technological progress has promoted the transformation from simple structural reservoir to complex small fault block reservoir, and then to complex structure-lithology subtle reservoir exploration in Qintong Sag. The analysis shows that the high SNR, high resolution and amplitude-preserving processing effect are limited by the large difference of multi-phase data collection, narrow frequency band of original data and low sampling density of wave field. In order to solve the further problems of the complex subtle reservoir seismic exploration, wireless single-point receiving, single-point broadband excitation, small surface element, high coverage density, wide azimuth seismic acquisition, amplitude quantization quality control, broadband omni-directional processing and five-dimensional interpretation should be explored.

Normal pressure shale gas plays such as the Ohio Formation Shale and Marcellus Formation Shale in the Appalachian Basin in the U.S. have been developed commercially. Although Wufeng-Longmaxi Shale in southeast Sichuan Basin in China has been initially developed, its production efficiency is not obvious and its cost is high due to the large burial depth and poor reservoir properties physical properties. In the normal pressure shale gas formation, the absolute pressure changes at different depths, which influences the gas occurrence state, and then has a significant influence on gas content and mobility. Therefore, it is urgent to carry out quantitative research on the differences of normal pressure shale gas reservoir conditions, gas occurrence state, gas content and mobility between China and the US. In this study, the Wufeng-Longmaxi shales of Well-LY1 in Pengshui of China and the Marcellus shale and Ohio Shale of Appalachian Basin in the United States are selected as the research objects under normal pressure. Based on the volume method, and with the considering of the influence of the temperature, pressure, maturity, water and oil on the adsorption capability and maximum adsorption capacity, and the temperature and pressure, porosity and water saturation on the determination of free gas volume, the gas content of three groups of shale reservoirs is evaluated. The reservoir pressures are considered as the initial pressures and the simulation are conducted based on a pressure drop of 5 MPa. On the basis of clarifying the desorption process of adsorption and free gas in the depressurized production respectively, the fundamental cause of the difference in normal pressure shale gas production between China and the U.S. is revealed. Compared to the Marcellus Shale in Appalachian Basin, the lower adsorption capacity, porosity and free gas of the Wufeng-Longmaxi shales result in low production of adsorbed gas and free gas. However, compared to the shale of the Ohio Formation, the deeper burial, higher temperature and higher pressure in the Wufeng-Longmaxi shales result in the extremely low recovery rate of adsorbed gas. Its lower porosity also contributes to the lower free gas production.

At present, China has encountered many problems and challenges in the exploration and development of continental shale oil. The mobility of shale oil is greatly affected by complex pore structure and poor seepage capacity, and restricts the efficient development of continental shale oil. Therefore, In order to solve such prominent problem, the present situation, existing problems and future development trend of the research methods and technical means of shale oil reservoir pore structure and shale oil seepage law are briefly introduced. The results show that the characterization withe multi-scale, fine and continuous is the key to characterize the pore structure of continental shale oil reservoir. The establishment of the uniform pore structure characterization technology and the classification evaluation criteria is the geological basis for the effective development of continental shale oil. The combination of multi-physical model and experimental method is the basis of the seepage characterization of continental shale oil. Strengthening the combination of numerical simulation, physical simulation and laboratory experiments is the main direction of the study on the seepage mechanism of continental shale oil. It provides an important guideline for breaking the bottleneck of continental shale oil development and is of great significance to realize the efficient development of continental shale oil reservoirs.

Considering of the “Multi-Complex” geological characteristics of the surface and underground in the Nanchuan District, a set of relatively complete ideas and technical processes for shale gas geophysics exploration have been explored through technical research on seismic data acquisition, processing and interpretation. And it has been successfully applied in shale gas exploration and development in Nanchuan District, including three aspects: ①In terms of acquisition, the quality of seismic data in limestone outcrops, karst caves and mined-out areas can be improved through real-time optimization of excitation points; ②In terms of processing, in order to improve the imaging effect, high-precision static correction technique in complex mountainous areas, the targeted processing technique in karst cave and goaf, and the Anisotropic Pre-Stack Migration Imaging technique are adopted; ③In terms of interpretation, on the basis of fine structure interpretation, the “sweet spot” prediction of shale reservoir is carried out from three dimensions: the enrichment of shale gas, the remodelling of reservoir and the driving of reservoir., and in the process of developing shale gas, horizontal well drilling is guided by prediction technology of dynamic target buried depth and formation dip prediction technique for horizontal wells.

CCUS is an important technical means to achieve the carbon neutrality goal. At present, China is in the implementation stage of the “dual carbon” goal, and there is still a lack of mature technical system in the economic boundary assessment, source-sink optimization and safety monitoring of geological sequestration of CO₂. This paper summarizes the development process of China's CO₂ geological sequestration technique from three aspects, economic boundaries of sequestration technology, source-sink matching technology, and sequestration safety and monitoring, reviews the economic costs of CCUS technology in the capture, transportation, injection and burial period, and further summarizes the current technical and economic boundaries and influencing factors of each period. In addition, by summarizing the current development status of CCUS source-sink matching technology at home and abroad, the source-sink characteristics and distribution of China have been clarified, and further development directions for source sink matching optimization technology have been proposed. Finally, by summarizing the safety risk assessment and burial monitoring techniques for geological sequestration of CO₂, it is clear that economically efficient, effective, and quantitative monitoring methods are the focus of future research.

Generally there exist a large number of ineffective perforation clusters in multistage hydraulic fracturing of horizontal wells of shale gas reservoirs. So improving the effectiveness of perforation and maintaining the long-term conductivity of fractures are the main challenges to increase production and reduce costs for shale gas horizontal wells. Based on previous research results, the main reasons for low production of perforation clusters include: ① Fracture does not initiate or propagate effectively due to mechanical heterogeneity of shale reservoir, stress shadow between fractures, or difference of perforation erosion rate; ② The distribution of proppant is non-uniform between clusters and in fractures due to the difference of perforation displacement distribution within the stage, weak sand suspension ability of low viscosity fracturing fluid, and fracture bending, inclination and roughness; ③ The fracture conductivity is lost due to the breakage and embedding of proppant, diagenesis, formation and migration of formation particles. In order to solve the above problems, the optimization and technical solutions to facilitate the balanced initiation of fractures, the uniform distribution of proppants, and the improvement of fracture conductivity are proposed. They include new-type limited entry fracturing technique, degradable temporary plugging diversion, optimization of perforation parameters and sand-adding sequence, high-speed channel fracturing, high viscosity friction reducers and new-type proppants, etc., which are expected to provide benchmark for improving the effectiveness of perforation cluster fracturing of horizontal wells.

CO₂ gas channeling time prediction is of great significance for CO₂ gas channeling prevention and enhanced oil recovery. Current studies rarely involve quantitative characterization of the gas channeling time. According to the parameters of the target block reservoir, the crude oil viscosity, reservoir permeability, gas injection rate and injection-production well spacing and other factors impact on the moving rule of the CO₂ drive front is analyzed by the numerical simulation method, then the characterization formula of gas flow time and gas flow influence coefficient considering multiple factors is established, and the accuracy of the formula is verified by comparing with the field practice. The results show that under the condition of constant pressure production, the sweep efficiency decreases with the increase of crude oil viscosity. When the crude oil viscosity is greater than 3 mPa·s, the increase of gas emergence time slows down. When the reservoir permeability increases, the seepage resistance decreases, the displacement front moves faster, and the oil well breaks out earlier. When the gas injection velocity increases, the leading edge movement speed increases and the gas appearance time advances. When the gas injection velocity is 2 500 m³/d, the sweep efficiency is the minimum. When the injection-production well spacing increases, the moving speed of gas front slows down, and the gas emergence time of oil well prolongs. When the injection-production well spacing is larger than 250 m, the well spacing continues to increase, and the sweep efficiency increases slightly.

Deep coalbed methane（CBM） development in East China is of great significance to ensure regional energy demand, optimize regional energy structure and realize the dual carbon goal. Based on the systematic investigation and previous works, the current situations of CBM extraction in East China were summarized, and the gas-bearing attributes and resources potential of deep CBM were analyzed. Then, the applicability of existing deep CBM exploration and development technologies in East China was discussed, and the potential favorable areas of deep CBM exploration and development in East China were discussed and predicted. Finally, the advantages and challenges of deep CBM exploration and development in East China are put forward. Previous results show that: East China has a good CBM development accumulation on the tectonically deformed coal and in the coal mine area, such as “Huainan CBM extraction model” and horizontal well staged fracturing in the roof of the tectonically deformed coal. Deep coal in East China has a high gas content（greater than10 cm³/g） and gas-bearing saturation（greater than 80 %）. The predicted geological resources of deep CBM are 8 984.69×10⁸ m³ in the Huannan-Huanbei mining area, suggesting that Huainan and Huaibei coal field has an attractive deep CBM resources potential. Horizontal well development and hydraulic fracturing techniques for deep CBM have great application prospects in East China. Panxie mine area in Huainan coal field is expected to be a pilot area for deep CBM exploration and development in these areas. However, the overall exploration and development degree of deep CBM is low, so it is necessary to carry out the more detailed resource evaluation and analysis of deep CBM geological accumulation in the type area, like deep Panxie coal mine in Huainan coal field.

Natural gas hydrate are rich, which is one of the most potential new energy resources with abundant resources. However, gas hydrate has not been exploited commercially at present, and its micro-structure characteristics and gas storage mechanism need to be clarified urgently. Based on the framework and guest molecular information of SI, SII and SH type gas hydrates, the molecular models of three typical gas hydrates are constructed and optimized. The hydrogen bonds number, hydrogen bonds length, porosity, pore composition, pore size distribution and other structural characteristics of hydrates are determined by structural characterization, and the micro-structure differences of three typical hydrates are compared and analyzed. Based on the hydrate skeleton structure, the adsorption behavior of methane and carbon dioxide is studied by the grand Canonical Monte Carlo method. Combined with the adsorption capacity and adsorption heat, the gas storage characteristics and differences of the three hydrates are clarified. The results show that the hydrogen bonds in SII hydrate are the longest and the most abundant, but the pore connectivity is the worst. High pressure is conducive to increasing the gas storage capacity of hydrate, while low temperature can increase the stability of gas adsorption in hydrate. Although the amount of carbon dioxide storage is smaller than that of methane, the adsorption stability of carbon dioxide is stronger. The adsorption capacity of gas in SII type hydrate is the largest, and the adsorption heat in SI type hydrate is the largest.

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.

During the reaction between CO₂ and rocks, there is a synergistic/coupling effect among minerals because the rocks contain quartz, potassium feldspar, albite and other components, which promotes or inhibits the reaction process to a certain extent. The chlorite is an important clay mineral of sedimentary rocks. In order to clarify the chemical behavior and change process of the chlorite in the CO₂ aqueous solution, the state of chlorite reacting with CO₂ respectively for 7 and 30 days at 10 MPa and 60 ℃ are systematically evaluated by means of XRD（X-Ray Diffraction）, XRF（X-Ray Fluorescence）, ICP（Inductively Coupled Plasma）, and SEM（Scanning Electron Microscopy）, focusing on the comparison of the change of the solid elements, the crystal structure and the ion concentration in the reaction solution before and after chlorite powder reaction. Combined with the structural characteristics of chlorite, the mechanism of chlorite change is clarified. The results show that the concentrations of Ca²⁺, Mg²⁺ and Al³⁺ in the liquid phase firstly increase and then decrease after the reaction of the chlorite with CO₂. The concentration of Si⁴⁺ firstly increases and then is stabilized. The crystal planes corresponding to chlorite d（002） and d （004） peaks in the solid phase are destroyed after the reaction, and the mass ratio of Si and Al in the solid element increase from 4.82 to 5.39. Under the acidic conditions, hydroxyl groups in brucite flakes are easier to combine with H⁺ and release cations such as Fe²⁺, Mg²⁺, Al³⁺, etc. Because the brucite octahedron is more prone to ion exchange than silica tetrahedron and alumina octahedron, Mg, Al, Fe and other elements in brucite flakes are dissolved before Si and Al in silica tetrahedron and alumina octahedron.

The gas test breakthrough of mudstone shale of Taiyuan Formation in Well-MY1 and Well-ZDY2 has proved that the Upper Paleozoic marine-continental transitional shale gas in the South of North China Basin has potential for further tapping resources. Based on the latest data of Well-TX3 and Well-TX4, this paper comprehensively analyzes the shale geochemistry, petrology, reservoir space, physical properties and gas bearing properties of the Taiyuan Formation and Shanxi Formation of the Upper Paleozoic in Tongxu area in the South of North China Basin, the results show that: ① The organic matter of the mud shales of the Taiyuan and Shanxi Formations comes from the vascular plant and belongs to type Ⅲ Kerogen; TOC value is 1.0 %~4.5 % and belongs to good source rock; R_o value is 2.4 %~3.4 % and is in the over mature stage. The mud shale reservoir has higher brittle mineral content, which is favorable for the later fracturing reconstruction. ②The reservoir space is dominated by fractures and micro-fractures, followed by inorganic pores, less developed organic pores and isolated distribution. ③Based on the comparison of the gas test results and shale gas evaluation parameters, the shale gas resource potential of Taiyuan Formation is obviously better than that of Shanxi Formation.

The availability of shale oil directly affects the degree of effective exploration and development, and the mobility of shale oil is closely related to its occurrence state. Therefore, studying the occurrence state of shale oil plays an important role in its development. The pore model is established by graphene and quartz, and the occurrence state of n-octane and its mixture in nanopores is studied by molecular simulation method. The effects of pore size, temperature, pressure, shale oil composition, wall wettability and wall composition on the occurrence state are analyzed. The results show that: ①shale oil is multi-layer adsorbed in the pores and symmetrical about the pore center, and the thickness of the adsorption layer is 0.4~0.5 nm; ②The larger the pore size of the reservoir, the higher the temperature, the lower the pressure, the lighter the molecular component, the weaker the polarity, and the higher the wall wettability are, the more unfavorable the adsorption of oil molecules on the wall is;③ In the combined wall, due to the influence of graphene wall, the adsorption amount of shale oil molecules increases with the increase of quartz wall wetting humidity. In addition, the adsorption transfer phenomenon of n-hexanoic acid and cyclohexane also occurs.

The logging response characteristics of different productivity shale gas wells are obviously different. By comparing and analyzing the logging response characteristics of shale gas well with different productivity, the logging response characteristics of high production shale gas reservoir are summarized. Then, by the analyses of the differences of lithology, electrical properties, physical properties, in-situ stress and pore pressure in shale gas wells with different productivity, and the geophysics logging information such as resistivity logging, radioactive logging and acoustic scanning, etc., a set of high-quality and high-yield shale reservoir identification methods based on integrated logging response characteristics is developed by considering the key parameters of organic quality and formation pressure to reflect shale gas productivity. The results show that the electrical characteristics of high-quality and high-yield shale reservoirs are high gamma-ray, low density, low neutron, high acoustic time difference and medium-high resistivity. This set of analysis method can accurately identify the exploration and development potential of shale reservoirs. The comparison between the field gas test results of different types of shale gas reservoirs in different shale gas blocks in southeastern Sichuan and the results of comprehensive well logging analysis shows that the method has a high coincidence rate. It can provide scientific basis for later completion plan decision of shale gas well.

The normal pressure shale gas reservoir within the complex structural belt of Nanchuan has been subject to the influences of multiple tectonic movements. The geological conditions in this region exhibit a high degree of complexity, thereby amplifying the challenges associated with efficient resource extraction. In response, an integrated geological engineering approach, tailored to the unique geological attributes of normal pressure shale gas in the intricate structural belt of Nanchuan, has been devised. This approach is aimed at mitigating challenges such as low rates of drilling in “sweet spots”, reduced mechanical drilling speeds, and suboptimal outcomes in fracturing transformations stemming from the intricacies of geological reservoir structures. In pursuit of optimizing the development of normal shale gas resources, a comprehensive investigation was undertaken, leveraging interdisciplinary knowledge spanning geophysical exploration, geology, drilling and completion, and fracturing techniques. An integrated process was established, fostering collaborative problem-solving and the mutual enrichment of geological and engineering insights. At its core, this approach emphasizes the synergy between geophysical exploration, geology, and engineering, thereby forming a pivotal development technology tailored for normal pressure shale gas reservoirs within complex structural zones. Through practical field applications, notable enhancements have been achieved. Mechanical drilling speeds and the rate of target window drilling in complex structural areas have witnessed significant improvements. Concurrently, the costs associated with fracturing operations have been consistently reduced, yielding improved gas well fracturing outcomes and enhanced productivity. These advancements collectively culminate in the efficient development of the Nanchuan normal shale gas field. Furthermore, they offer invaluable technological insights and experiential wisdom for the efficient extraction of normal shale gas reservoirs in the intricate regions of southeastern Chongqing.

Thermal injection stimulation technology, which is suitable for coal seams with low water content and difficult pressure reduction and desorption, is an effective method to increase coalbed methane production besides hydraulic fracturing. Based on the literature research at home and abroad, the stimulation mechanism of coalbed methane heat injection is expounded, the influences of heat injection and temperature rise on adsorption and desorption and permeability of coal seam are analyzed, and the thermal-hydraulic-mechanical coupling relationship in the process of thermal coalbed methane production are summarized. Then, four methods, which are thermal steam injection, thermal CO₂ injection, microwave thermal injection and coal seam burning, are introduced, and their technical principles, characteristics and research progress at home and abroad are summarized. The study shows that the method of heat injection can promote the desorption of coalbed methane, increase the content of free coalbed methane and achieve the purpose of increasing the coalbed methane production. Meanwhile, thermal cracking and coal pyrolysis caused by heat injection can improve the pore structure of coal seam, and communicate and increase the fracture network of coal seam, which are beneficial to the diffusion and seepage of coalbed methane. The thermal injection stimulation technology of coalbed methane can effectively solve the problems of low water content, difficult depressurization and desorption, and strong water sensitivity of coalbed methane, which is another potential stimulation method to replace hydraulic fracturing.

Fractured-cavity reservoirs have diverse storage spaces, strong heterogeneity, large differences in oil-water properties, high mobility ratio of immiscible nitrogen flooding in water flooding, serious water and gas channeling, limited sweeping range, and primary and secondary oil recovery stages. Oil recovery is much lower than that of clastic sandstone reservoirs. Taking the S91 fracture-cavity unit in Tahe Oilfield as the object, on the basis of geological modeling, history matching, remaining oil characterization and phase state experimental fitting, a numerical simulation study on enhanced oil recovery by hydrocarbon injection in fractured-cavity reservoirs is carried out, so as the evaluation of the hydrocarbon-gas miscibility conditions in fractured-cavity reservoirs, and the optimization of EOR parameters of hydrocarbon injection. The results show that the minimum miscibility pressure of injected hydrocarbon gas and formation crude oil in S91 unit is 42.5 MPa, which can be miscible under the current formation pressure. The mechanism of miscibility is vaporization gas flooding. As the content of heavy hydrocarbon components in the injected gas increases, the recovery factor increases. The gas injection method is gas injection in fractured reservoirs, and liquid recovery in caved reservoirs. The gas injection parameters are preferably 168×10⁴ m³, gas injection rate of 4×10⁴ m³/d, and injection-production ratio of 1∶0.9.

Shale gas is unconventional natural gas, mainly CH_4, occurring in organic shale. The adsorbed gas is the main source for later production of shale gas. Therefore, studying the adsorption mechanism of shale plays an important role in shale gas development. By using type Ⅱ kerogen molecules, a type Ⅱ kerogen model is established. Then, Monte Carlo method and molecular simulation method are used to study the micro adsorption behavior and mechanism of CH₄ in type Ⅱ kerogen. Experimental data are used to verify this model, and the effects of pore size, temperature and pressure on the adsorption behavior are investigated. The findings are as follows: ① The higher the pore size, the greater the excess adsorption capacity of CH₄. The higher the temperature, the lower the excess adsorption capacity of CH₄. With the increase of pressure, the absolute adsorption amount of CH₄ increases rapidly at first and then gently, and the excess adsorption amount of CH₄ increases first and then decreases. ② The adsorption heat of CH₄ decreases with the increase of pore size. The adsorption of CH₄ in kerogen is physical adsorption. ③ When the pore size is smaller than 1 nm, CH₄ is the adsorption phase in kerogen; when the pore size is larger than one nanometer（1 nm）, CH₄ is the coexistence of adsorption phase and free phase in kerogen.

In order to investigate the physical meaning of critical desorption pressure in undersaturated CBM（coalbed methane） reservoirs, the traditional critical desorption pressure calculation method and the liquid phase adsorption theory commonly used in field are introduced based on the status of the reserves of CBM, and the origin of the “undersaturated” phenomenon under the premise of gas phase wet is discussed. On the basis of the modified gas phase adsorption, the relationship between the critical desorption pressure and the capillary pressure in matrix pores is explained, and a new calculation method of critical desorption pressure is obtained. By comparing the advantages and disadvantages of the four methods in error analysis, theoretical completeness and operability, it is considered that the new calculation method proposed is relatively complete in theory, has strong operability and is easy to calculate, and obtains a reasonable result in an example. It can be concluded that CBM adsorption equilibrium and critical desorption phenomenon can be interpreted as the result of the interaction between reservoir pressure and capillary pressure under the premise of coalbed gas phase wetting. The improved gas phase adsorption theory and the new calculation method of critical desorption pressure are worth the further study.

For volumetric closed gas reservoirs, when the gas well produces with stable production rate, it can be divided into unsteady state stage, transient stage and pseudo steady state stage according to the variation behaviours of flowing bottom hole pressure and producing time. The unsteady state stage is called the elastic one-phase stage, and the pseudo steady state stage is called the elastic two-phase stage. The latter is a dynamic method to evaluate the Original Gas in Place（OGIP） controlled by gas wells. The elastic two-phase method proposed by CHEN Yuanqian in 1991 in the pseudo steady state stage has been repeatedly listed in the National Oil and Gas Industry Standards, and has been widely valued and applied in China. Based on the diffusion equation considering the elastic expansions of natural gas, rock and irreducible water in a gas well with stable production in the finite closed gas reservoir boundary, a new elastic two-phase method for the pseudo steady state stage represented by flowing bottom hole pressure and cumulative production rate is derived, which can be used to evaluate the original gas in place（OGIP）controlled by a gas well. The new formula of elastic two-phase method is superior to the old formula which based on the relationship between flowing bottom hole pressure and production time, and the new can overcome the influence of production fluctuation on the evaluation results. The application shows that the new formula of elastic two-phase method is practical and effective.

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 minimum miscible pressure （MMP） of CO₂ flooding is a crucial parameter to judge whether miscible flooding is attainable. In order to reduce the application threshold of miscible flooding, the MMP between CO₂ and crude oil needs to be reduced urgently. Adding miscible flooding assistants to oil reservoir is an effective means for minimum miscible pressure reduction. At present, according to the elements contained, the miscible flooding assistants can be divided into three categories including fluorocarbon, siloxane, and hydrocarbon （oxygenated）. In order to reduce the cost and improve the MMP reduction performance, the hydrocarbon structure should be added to the fluorocarbon assistants to make the assistants develop in the direction of mixing type. The hydrocarbon assistants have sound MMP reduction performances and room for improvement. The key is to find a suitable CO₂-phlic structure. Computer simulation is also a vital means to study micro mechanism and assist structure designing. Compared with fluorocarbon and siloxane, the cost of hydrocarbon （oxygenated） is lower, and it has the most application potential from the prospective of cost. At present, the main factor affecting the large-scale application of miscible assistants is the limitation of cost. The promotion and application in the future needs the close cooperation of petroleum and chemical practitioners. In this paper, the mechanisms of CO₂ miscible flooding assistants reducing MMP are introduced. The structures of existing miscible flooding assistants, MMP reduction effectiveness are summarized, and the influencing factors on MMP reduction efficiency are analyzed. The developing directions CO₂ miscible flooding assistants designing are prospected.

In order to realize the efficient development of lacustrine organic-rich shale oil reservoir in the lower sub-member of the third member of the Eocene Shahejie Formation and the upper sub-member of the fourth member of the Eocene Shahejie Formation in the Boxing Sag, Dongying depression, the geological data, such as thin sections, X-ray diffraction and the content of major and trace elements are analyzed. After the data analysis, the types of lithofacies and the evolution stage of sedimentary paleoenvironment are determined, and eight lithofacies assemblages are also divided based on the relationship between lithofacies and sedimentary environments. Then, the favorable lithofacies for shale oil exploration and development are determined based on the comparison of geological and engineering “sweet spot” parameters of different lithofacies assemblages. The results indicate that: ① Six lithofacies types of organic-rich laminated argillaceous limestone and limestone mudstone, organic-rich layered argillaceous limestone and limestone mudstone, organic-poor massive argillaceous limestone and calcareous mudstone are mainly developed in the study area; ② The sedimentary paleoenvironment with the characteristics of paleoclimate from arid to humid, little change in paleoredox, paleosalinity from high to low, and paleo-provenance from less to more exhibited eight evolutionary stages, corresponding to eight lithofacies assemblage types; ③ Lithofacies assemblage D and F, with high shale oil productivity, are the favorable in the Es^3L and Es^4U, respectively, and are in good agreement with the production practices. On the plane, the former is mainly distributed in the F159-F156-F160 well areas, and the latter is mainly distributed in FYP1-F116-F119 and F156-F159-F161 well area, which is a shale oil enrichment and high yield area in Boxing sag.

Natural fractures are well developed in shale gas reservoirs, which have great influence on reservoir reconstruction and later fracturing effect. Therefore, the fracture prediction is carried out by ant tracking technology based on the combination of logging and seismic. Firstly, the curves for the fracture development density of the wells are obtained by the calculation of the natural fractures by well logging. Then, by the comparison of various simulation methods, the Gaussian random method is selected, which can reflect the heterogeneity of fracture development in shale reservoir and establish the natural fracture model between wells. Finally, the Co-Kriging interpolation method is used to reflect the properties of inter-well fracture development, and ant attributes are input for the quality control in order to establish the prediction model of natural fractures in Nanchuan area. According to the prediction results, the fractures in Nanchuan area develop along the NE direction. The fractures in the east wing of Pingqiao anticline are more developed than those in the core, and the fracture network are easy to form. The prediction results are highly consistent with the actual drilling wells. This fracture prediction technology can guide the exploration and development of this area.

The geological conditions of the complex fault block reservoir in the Paleogene of Jidong Oilfield, Nanpu Sag, northern Huanghua Depression, Bohai Bay Basin are complex. There are many faults, small fault blocks, the main reservoir is deeply buried, and it is shielded by the widely developed volcanic rocks. Therefore, the quality of seismic data is poor, the stratigraphic correlation and fine structural interpretation are difficult, the basin area is small, the source is close, the deposition rate is fast, and the sand body superposition relationship is complex. In order to effectively identify the distribution and connectivity of inter-well sand bodies and finely characterize the structural morphology, fine description and research on the complexity geological conditions in Jidong Oilfield have continuously carried out in recent years. Six key technologies have been gradually formed, including small layer division and fine correlation of complex fault block reservoirs, low-order fault identification, comprehensive characterization of delta reservoirs, formation and main controlling factors of dominant permeability channels in the process of water injection development, three-dimensional geological modeling of complex fault block reservoirs, and quantitative characterization and distribution of remaining oil, which are applied to five typical blocks, including two types of reservoir genesis of fan delta and braided river delta, and two types of physical properties of medium permeability and low permeability. In the development stages of medium water cut and high water cut, normal water injection development and overall fracturing water injection development are the theoretical basis for the rational development of complex fault block reservoirs in Jidong Oilfield.

It is an effective way to realize efficient production of shale gas to adopt corresponding production mode in different production stages. The southern area of Pingqiao anticline in Nanchuan Block is a normal pressure shale gas reservoir with relatively low production and wellhead pressure, so the production mode needs to be further optimized. By analyzing the production characteristics of 30 wells in different stages in the southern area of Pingqiao, the reasonable production mode is summarized. The results show that the shale gas well can be divided into five production stages: pressure control, production increase and liquid carrying, intermittent production, pressurized production and low pressure and low production. In the stage of pressure control production, the principle of “keeping pressure + discharging liquid” is adopted to run downhole choke to improve the production cycle. The downhole choke is taken out to prevent the gas well from accumulating liquid in the stage of increasing production and carrying liquid. Measures such as gas lift, foam drainage are adopted in the intermittent production stage. Compressor is used to reduce the influence of pipeline gas transmission pressure in the pressurization stage. Low cost drainage technology such as jet pump is adopted in the stage of low pressure and low production. The mode has achieved good application effect in the south area of Pingqiao, which can provide reference for the development of normal pressure shale gas reservoir in the complex structural area of basin margin.

The leakage of fluid （CO₂, brine and freshwater） along fault is a crucial issue that cannot be ignored during CO₂ geological storage. For this reason, the equations to describe the fluid leakage rate along faults in different stages are derived. Then, these equations are combined with mass and energy conservation equations to establish the fluid leakage model in CO₂ storage processes by considering geologically activated faults. In such case, the crucial parameters （i.e., leakage time and leakage amount） for fluid leakage along a fault are obtained. The results of the effects of different parameters on leakage time and amount show the advanced initial time of CO₂ leakage, the extended duration and the increased leakage amount of CO₂, with CO₂ injection rate and reservoir permeability increasing. Meanwhile, the initial time and duration of CO₂ leakage are unchanged while the leakage amount of CO₂ is increased, when increasing the fault permeability. In addition, the fault permeability has the greatest impact on the leakage amount of brine and freshwater, compared to CO₂ injection rate and reservoir permeability. The numerical results show that brine starts to leak earliest, followed by CO₂, freshwater. Meanwhile, the duration of CO₂ leakage along a fault is the longest, while the duration of brine leakage is the shortest. Additionally, the leakage amount of CO₂ is the largest, followed by brine leakage amount and the freshwater leakage amount.

The shale oil development in Sinopec Jiangsu Oilfield is facing the problems of high investment and low production. After 45 years of development, there are a lot of abandoned old wells. Developing shale oil by old borehole side drilling can reduce drilling costs. In 2022, the sidetracking slimhole horizontal drilling in old wells is carried out in Huangzhuang. The slimhole drilling tools have the problems of large flexibility, difficult track control, slow drilling speed, small clearance, large air pressure consumption, poor cementing quality and high well control risk. In order to solve these problems, a system of efficient sidetracking slimhole horizontal drilling technology system is formed by the applications of large casing windowing, well track optimizations, high-efficiency drill bit+screw+LWD geosteering drilling, foam cementing, oil-based drilling fluid plugging, narrow gap well controlling, small hole coring, etc. A test application in H2CHF well shows that the actual drilling speed is up to 5.0 m/h, which is equivalent to the conventional drilling speed in adjacent wells, and the total drilling cost is reduced by 50 %, saved by 15 million. The new development and test would provide important ideas and reference for future development of shale oil in Jiangsu Oilfield.

Shale gas reservoirs, which develope micro-nano pore throats and fractures, have high clay mineral content, and strong heterogeneity of porosity. Therefore, large-scale hydraulic fracturing is usually needed to realize the effective exploitation. In the process of hydraulic fracturing, the spontaneous imbibition of the water phase will trigger a series of physical and chemical effects on the shale gas reservoir, changing the pore structures, physical and chemical properties of shale gas reservoirs, thereby affecting the production of shale gas. In order to further clarify the influence mechanism of water phase imbibition in shale gas reservoirs, multiple repetitive imbibition experiments were carried out. Based on the changes in rock sample quality caused by mineral dissolution, the visual characteristics of samples from scanning electron microscope, the observation of nuclear magnetic resonance pore structures, and the change of physical properties, the impact of imbibition on the microscopic pore structure, permeability and porosity of shale are revealed. The results show that: ① Water imbibition causes fractures in shale, thus changing the pore structure; ② The proportion of macropores increases in shale samples with significantly improved porosity, which indicates that water imbibition will increase the pore space in shale; ③ The imbibition capacity is positively correlated with the porosity and permeability of shale, and the physical properties of shale are significantly improved after imbibition. In addition, the time index is found to be able to quantitatively characterize the influence of imbibition on the pore-throat connectivity of shale.

The heat exchange technology of the medium-deep buried pipes of the abandoned oil and gas wells is one of the methods of oilfield geothermal development, which is helpful for low-carbon heating in oilfields and reduces the cost of geothermal development. In order to improve the heat transfer of a single well and better guide the reconstruction work, it is necessary to analyze the influencing factors of the heat transfer performance of the geothermal well after reconstruction. In this paper, numerical simulation method is used to analyze the influencing factors of the heat transfer performance of the geothermal well after reconstruction, and the parameters such as geology, well and working conditions are analyzed respectively. The main analysis conclusions are: ① The geothermal gradient and the thermal conductivity of the rock formation in the geological parameters have a great influence on the heat transfer of a single well, and the geological parameters should be the primary consideration factors in the selection of the stimulation target well. ② Well depth, casing outer diameter, and thermal conductivity of central heat exchange tube in the well parameters have certain influence on the heat exchange of a single well, which should be considered when selecting target well and formulating the reconstruction plan. ③ The water temperature and flow rate entering the well in the working condition parameters have an influence on the heat exchange of a single well, and the influence of the working condition parameters should be considered in the design of the surface heat exchange system. The research in this paper has reference significance for the selection of stimulation target wells, the formulation of stimulation plans, and the optimization of operating conditions parameters using the same heat exchange method.

During the drainage and gas production process of coalbed methane development, due to the pressure drop, the pulverized coal is prone to appear and brought into fracturing sand. At present, the pulverized coal and the deposition of fracturing sand have become the key factors restricting the continuous and stable drainage and production of coalbed methane. As the proportion of pulverized coal pump blockage in southern Yanchuan CBM Field is high, in order to effectively reduce the occurrence of this kind of operation, prolong the maintenance free period of gas wells, ensure the continuity of the production of the gas wells and cut the operation cost, a circulating well flushing device is developed and the supporting process is formulated. After the field tests, it is clear that the automatic circulation well flushing process can effectively reduce the pump inspection times of the gas well, the hollow rod automatic circulation well flushing process can effectively prolong the maintenance-free operating period of the gas well, and the pump down well flushing process can effectively improve the pump efficiency and increase the daily liquid production of the gas wells. The application results show that the CBM circulating well flushing device and supporting process are well applied in the mine, which can effectively improve the liquid flow velocity in the oil pipe, carry the sand and pulverized coal in the oil pipe to the ground, solve the pump sticking, pump plugging and pump leakage, and provide a new idea for on-site control of pulverized coal.

The bilayer or multilayer co-drainage is an important approach to improve the single well production. In order to improve the drainage efficiency of bilayer drainage wells in Zhengzhuang Block of southern Qinshui Basin, the drainage data and co-drainage trial data from the southwest of Zhengzhuang Block are analyzed and the method is put forward to judge the gas production capacity of No.15 coal seam in real time by the change trend of coal production after the hydrodynamic level drops below No.15 coal seam. Two methods predicting the gas production capacity of each layer by key parameters of both geology and engineering or by early desorption drainage parameters are proposed. A new drainage method is put forth and the trial is carried out in the southeast of Qinshui Basin, that is the “variable rate drainage, gas released at certain casing pressure, high-production-rate and certain stable production kept at high pressure”. The results show that if the production continues to rise after the fluid level drops below the No.15 coal seam, the gas production capacity of No.15 coal seam is high. On the contrary, it indicates that gas production of No.15 coal seam is low. When the resistivity of No.15 coal seam is less than 1 000 Ω·m or the construction pressure is low, the gas production capacity is relatively low. The data of bottom-hole flowing pressure and casing pressure of No.15 coal seam after casing pressure come out in coalbed methane well can be used effectively to predict the gas production capacity of each layer, with high prediction accuracy. The application of the new drainage method, proposed by this paper, results in 22.2 % shorter of the production-increasing cycle decreasing from 180 d to 140 d and more than 20 % increase of the average single-layer production from 1 000 m³ to 1 200 m³, compared with the old drainage method. The great difference in the development performance among the 20 wells is affected mainly by the gas production capacity of each well. The wells with higher gas production capacity have higher stable gas production and longer stable gas production time. The productivity prediction method and the co-drainage method of bilayer vertical coalbed methane wells have great reference significance to the productivity releasing of co-drainage bilayer vertical coalbed methane wells.

The deep underground place in China is rich in coalbed methane resources, so that it is an important field of further exploration and development of coalbed methane. However, the geological conditions of deep coalbed methane resources are more complex, and it is different to deploy supporting technologies for engineering, so there is great challenge to realize efficient development. Overcoming the technical bottle-neck of efficient development of deep coalbed methane is of great significance to promote the efficient utilization of deep coalbed methane resources. Taking the development practice of deep coalbed methane in southern Yanchuan CBM Field as an example, five challenges faced in the process of early productivity construction are systematically analyzed: ① The reservoir heterogeneity is strong, and the main controlling factors for enrichment and high yield are unknown; ② The vertical resources need to be further evaluated, and the reserve utilization degree is low; ③ The deployment mode of well pattern is single, and the control area of single well in high stress and low permeability area is small; ④ The modification of the deep coalbed methane reservoir is poor, so it is difficult to achieve long-distance effective support by conventional hydraulic fracturing in the early stage; ⑤ The traditional drainage system has a long production cycle which is resulted in poor economic benefits. On this basis, through repeated exploration and practice, a new concept and key technology for efficient development of deep coalbed methane resources have been formed by “five transformations”: ① The overall productivity construction will change to accurate delineation of favorable areas; ② The development layer system changes from single layer to composite layer; ③ The well pattern deployment has converted from single vertical wells to the mixing well pattern of “vertical well + horizontal well”; ④ Reservoir reconstruction has changed from conventional fracturing to effective support fracturing; ⑤ The drainage system has changed from “slow and long-term” to “efficient increase of production”. Based on the “five transformations”, the production and construction benefits of new wells have been significantly improved, the daily output of vertical wells has increased from 1 800 m³/d to 10 000 m³/d, and that of horizontal wells increased from 10 000 m³/d to 20 000~50 000 m³/d. Good development results have been achieved, and the breakthrough of adjustment countermeasures for efficient development of southern Yanchuan CBM Field has important demonstration and driving significance for the benefit development of deep coalbed methane.

Based on the analysis of the factors influencing the minimum miscibility pressure in CO₂ flooding and 36 groups of tubule experimental data, the correlation degree of each factor influencing the minimum miscibility pressure in CO₂ flooding of crude oil is calculated by the grey correlation method. The prediction model of minimum miscible pressure in CO₂ flooding for crude oil is fitted by the MATLAB （Matrix Laboratory） software, which is related to the reservoir temperature, relative molecular weight of C₅₊, volatile hydrocarbon component （N₂+CH₄） content and intermediate hydrocarbon component （CO₂+H₂S+C₂—C₄） content. The fitting correlation coefficient reaches 0.900 9. The data of the minimum miscible pressure test of three wells in an oilfield are used to verify the new prediction model. The average error of calculation is 3.57 %, which can be used to guide the field development of the reservoirs.

In order to analyze the ground temperature response and thermal effect radius of the heat transfer of the deep buried pipe, a full-scale numerical model of buried pipe heat transfer is established based on the well logging temperature, ground lithology interpretation, and field heat transfer experiments of an actual deep-buried pipe heating project in Xi’an. By the numerical analysis of the heat transfer of the buried pipes in five years, namely five heating periods and four recovery periods, the variation of ground temperature fluctuation （ΔT） around the buried pipe at different depths with running time is summarized. On this basis, by considering the theoretical research and engineering application, three different ΔT limits are selected to determine the thermal effect radius, and the factors affecting the thermal effect radius are analyzed. The results show that when ΔT limit is small enough to close to zero, the thermal effect radius is mainly affected by the geotechnical parameters around the buried pipe, and when ΔT limit increases, the thermal effect radius is mainly affected by ΔT limit.

In order to promote the development and utilization of dry hot rock resources in China, we take Kenya OLKARIA block as an example, and introduce the exploration, evaluation, development and utilization process of high temperature geothermal resources in Kenya in detail. At the same time, eight key drilling technologies formed during the development and utilization of high-temperature geothermal resources of the CNPC Great Wall Drilling Company are summarized and detailed engineering examples are listed. At last, the difficulties and challenges encountered in the development and utilization of Kenya's geothermal resources and China's dry hot rock resources are summarized and compared, the similarities and difference between countries are sorted out, and the solutions are put forward. With the establishment of a test base as the core, and with the developing and verifying new technologies and new equipment and forming new technical standards as the research direction, to point out that with the goal of realizing economical, profitable and large-scale development of dry hot rock, to strength basic scientific research work as a means, by the research idea of relying on the support of national policies and strengthen personnel training as the driving force, to provide theoretical and practical guidance for the efficient and economical development of dry hot rock resources in China.

Inter-well interference seriously affects the production of shale gas wells. The evaluation and prediction of well interference degree is of great significance to the efficient development of shale gas. But the existing research mainly focuses on the interference phenomenon between shale gas wells, production performance, and parameter optimization through numerical simulation. There are few studies on the quantitative evaluation and prediction of the interference degree between shale gas wells, and the selected parameters is incomplete, which makes it difficult to objectively evaluate the well interference between shale gas wells. Therefore, the machine learning method is used to comprehensively consider the geological parameters and fracturing parameters to evaluate and predict the degree of interference between wells in the shale gas reservoir. Firstly, the initial data are processed to improve the data quality. Then, based on the processed data, cluster analysis and random forest algorithm are used to evaluate and predict the interference degree of shale gas wells. The results show that the proportions of the wells with low, medium and high well interference in the shale gas reservoirs are 25.93 %, 37.03 % and 37.04 %, respectively. The fracturing factors show significant influence on the well interference degree in the shale gas reservoirs. After parameters optimization, the prediction results of well interference degree reaches 92.07 %, indicating that the developed prediction model can be applied to forecast the well interference degree in shale gas reservoirs.

Drilling fluid loss is an important engineering and technical problem that restricts deep and ultra-deep drilling, and the well loss in reservoir interval is the most serious reservoir damage mode in drilling and completion stage. It is the main way to control lost circulation to use the bridging plugging material to block the fracture leakage channel. However, the design of bridge plugging formula often adopts the empirical or semi-empirical method, leading to low plugging success rate and poor plugging effect. By the CFD-DEM simulation, it is clear that the bridge retention, accumulation filling and pressurized plugging are three key links in the formation process of fracture sealing layer. Considering the efficient bridging and compact filling of the plugging material, and based on the concept of “absolute bridge addition” and the theory of tight packing, a new experimental formula design method for pressurized plugging is proposed. “Absolute bridging amount” is used as a optimization parameter to determine the bridging material amount in the formula. The traditional compact packing theory is improved by the “complementation method”, which overcomes its defects of poor adaptability to the filling materials with discontinuous or overlapping particle size distribution, and determines the filling material addition in the plugging formula. The results of laboratory and field experiments show that the proposed method can realize the rapid and efficient design of the formula for deep naturally fractured reservoir, effectively ensure the sealing effect of the formula for deep naturally fractured reservoir and reduce the total amount of materials in the formula and save the material cost. The proposed method provides a new idea and theoretical basis for the design of plugging formula for deep naturally fractured reservoir.

Zigong Block, which is located in the southern side of Weiyuan Slope in Sichuan Basin, is a monocline in NW-SE direction. O₃w-S₁l^1-1 is the target layer of that block, which develops black shale with rich organic matters in deep-water continental shelf, while the longitudinal heterogeneity of the reservoir is strong. Different penetration degrees in the sweet spot of horizontal shale well lead to different testing results. In order to determine the longitudinal distribution of the optimal shale target and guide the tracking and adjustment of horizontal well drilling trajectory, based on stratigraphic subdivision, fine evaluation of reservoir is carried out by the comprehensive data of drilling, logging, well testing and laboratory analysis. Meanwhile, the gas production profile data are used to evaluate the impact of the target on shale gas productivity of the horizontal wells. The research results show that: ①Under the influence of both sedimentation and tectonics, the lower part of S₁l^1-1-1 are the optimal “sweet spots” for both geology and engineering among target layers; ②The production well logging data indicate that, the lower part of S₁l^1-1-1shows highest gas production contribution of per unit length, which is the optimal target position of the research area; ③The effective fracking length of shale reservoir in the lower part of S₁l^1-1-1 for horizontal well is the key factor for gas well productivity in Zigong Block. Based on the above results, which supports the productivity evaluation of shale gas effectively, and sets the foundation for realizing large-scale and cost-efficient development of shale gas in that block, the longitudinal distribution thickness of the optimal target in Zigong Block is accurate from 2~5 m to 1~2 m.

The upper Paleozoic Marine shale in middle Guangxi Depression, namely Guizhong Depression, has experienced complex tectonic evolution and thermal evolution. As the main production layer of shale gas, the microscopic pore structure characterization and reservoir pore evaluation of the shale in lower Carboniferous need to be studied urgently. Focus on the Lower Carboniferous Luzhai Formation shale reservoir in the northern Guizhong Depression, the material composition and reservoir pores of the shale are characterized and evaluated in detail by rock thin section, scanning electron microscope, Xray diffraction, porosity and isothermal adsorption tests on samples both from fields and cores. The results show that the TOC in the shale of Luzhai Formation is 0.4 % ~ 6.6 %. The organic matter is in the stage of high mature to over-mature thermal evolution. The content of brittle minerals such as quartz is high, with a good fracturing ability. The shale in Luzhai Formation, with an average porosity of 2.91 % and an average permeability of 0.007 9 ×10^-3μm², is a kind of low porosity, ultra-low permeability and good breakthrough pressure shale gas reservoir. There are five types of pores in the shale reservoir: the residual intergranular pore, intergranular pore, intragranular dissolved pore, clay minerals interlayer pore and organic pore. The main contributors are the clay minerals interlayer pores, the organic pores and the pyrite intergranular pores. The aperture rangs from 17 nm to 65 nm, most of which are microporous or mesoporous with the scale less than 50 nm. The connectivity between the pores is poor and there is a certain connectivity inside the pores.

After multi-cycle steam stimulation in HJ Oilfield, the changes of reservoir physical properties are obvious and difficult to determine, which brings serious obstacles to the design and implementation of subsequent development measures. In order to solve this problem, the relationships among porosity, permeability, wettability and steam stimulation cycles are conducted by using one-dimensional physical simulation experimental setup after the design of sweep multiples based on two wells, Well-J151 and Well-J117 in HJ Oilfield. The results show that the physical property parameters of reservoir will change under the long-term sweep of high temperature steam. In the scope of steam sweep, both porosity and permeability all increase with the increase of the steam stimulation cycles. With the increase of steam stimulation cycles, the lipophilicity of reservoir rocks gradually weakened and the hydrophilicity gradually strengthened. Based on the experimental results, the relationship between sweep multiples and porosity growth rate, as well as the chart of the relationship between oil layer sweep multiples and permeability growth rate are established. The parameters of the porosity and permeability of reservoirs in different stages of steam stimulation development can be predicted by the above relationship and chart, and the relationship and chart can be also extended to other similar heavy oil reservoirs.

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.

In order to ensure that the best oil recovery and displacement method of the new target block of the oilfield could be selected in the process of tertiary oil recovery, based on the application of tertiary oil displacement method in typical blocks at home and abroad, 23 reservoir parameters have been studied as the key parameters that affect the displacement mode, and the fuzzy evaluation method are used in the process. And then, the correlation between the target area and the test area is calculated by the improved Deng’s correlation method, so as to predict the recovery ratio of the target area. The study of a new block of some oilfield in China verify that the best displacement mode is fire flooding. The proposed proposed method provides a calculation basis for the optimal displacement method of the new block.

In order to explore the beneficial development path of fault-block shale oil in Qintong Sag, a development mode for the fracturing of directional wells combined with pseudo-horizontal wells has been proposed based on the study on the geological characteristics of shale oil in the second member of Funing Formation, and two wells are successfully implemented. The results show that the east and west wings of the deep sag belt of Qitong Sag in Subei Basin are structural complex areas with fault-block shale reservoirs, which are with large thick, developed natural fracture network, high pressure coefficient, and good mobility and transformability. The geological conditions here is not suitable for the development of long horizontal wells but for the directional wells. For the multi-layer development of thick shale oil, the rectangular directional well pattern is conducive to the CO₂ huff and puff, while the diamond reverse nine-spot well pattern is reasonable for the CO₂ flooding. Therefore, with the fracturing technology system based on “large-scale liquid injection energy storage & flow limiting perforation promotion and equalization & flow adjustment and fracture-stabilizing network & three-stage support and maintenance filling & continuous construction with all electric pumps”, the fracturing of the directional wells took as the “pseudo-horizontal well” can achieve the transformation effect of the horizontal wells, and the transformation volume of the single stage is 28.6 % larger than that of horizontal wells. This new develop mode of shale oil has high initial productivity, early oil breakthrough time, low flowback rate, fast water cut decline, and long stable production time. The single stage has high elastic productivity, high recovery degree, and good economic benefits, realizing beneficial development of shale oil in advance. The beneficial development shows a good prospect for the evaluation of shale oil in complex structural areas by the directional wells.

The classification and identification of shale gas “sweet spot” involves a variety of different factors, which requires personal experience, and is usually time and resources consuming. In order to solve this problem, an efficient and effective classification and identification method for shale gas “sweet spot” based on the Random Forest method is proposed. Firstly, data from ten wells in Changning area are selected and eleven features are selected for “sweet spot” classification by the Kendall correlation. Then, the single decision tree and the Random Forest method are used for the “sweet spot” classification and identification. Finally, the results are verified and the Random Forest parameters are optimized. The experimental results show that although the prediction accuracy of a single decision tree can reach 97.7 %, it shows a trend of overfitting, and the fitting accuracy is greatly reduced by only 70.7 % after pruning. The Random Forest method avoids the disadvantage of the single decision tree method, and the prediction accuracy reaches 98 %. Moreover, the computational cost is low, which can effectively reduce the time loss and save the labor cost. As a result, the proposed Random Forest machine learning method with multi-source information is an effective shale gas “sweet spot” classification and identification method.

Cap rock is the most important geological structure in CO₂ storage, and the characterization method of its sealing capacity is a hot research topic at present. Aiming at the problem of evaluating the sealing ability of caprock, based on the theory of coupling parallel capillary bundle and DLVO（microscopic force of charged surface passing through liquid medium）, considering slip effect and water film effect, the theoretical calculation method of caprock breakthrough pressure is established, and the accuracy is verified with experimental data. The variation of breakthrough pressure with slip length and effective capillary radius is studied by analyzing the influencing factors. The results show that the relative error between the calculated breakthrough pressure and the experimental data of six core samples is between 0.317 % and 10.800 %. The smaller the slip length and the larger the effective capillary radius, the smaller the breakthrough pressure.