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.

As a new parameter of the rock mechanics evaluation, the brittleness index （BI） has an important influence on the later fracturing and reconstruction of the reservoirs. The traditional calculation methods of the BI applied to the geosteering drilling of the shale gas horizontal wells have many limitations. Aiming at the calculation of the BI in real time by the LWD curves, we started with the experimental study on the BI and porosity to provide an experimental basis for calculating the BI by the porosity log information. Then, we used the regression method to analyze the relevance of the AC, DEN, CNL, GR logging values and BI, calculated the BI by using single LWD curves, and through the contribution of different logging curves to the BI, established a BI calculation method by logging while drilling of the shale reservoirs. Finally, we analyzed the feasibility of the model by the examples. The research result shows that the model is effective and adaptable, which provides a reliable basis for the geosteering drilling of the horizontal wells of the shale gas by the BI.

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.

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.

The geological conditions of fault block reservoirs are complex, whose small faults are developed, and reservoir heterogeneity is serious. When the reservoir enters the development stage with ultra-high water cut, the remaining oil is highly dispersed, the streamline between injection and production wells is fixed, the benefit of water drive becomes worse, and the spread of water flooding is difficult to further expand. Streamline adjustment and development have become the main direction of cost reduction and efficiency enhancement for fault block reservoirs when the price of oil is low. Conventional dynamic analysis is not suitable for the adjustment of high water cut fault block reservoirs. In this paper, streamline simulation method is used to analyze the influence of each factor on the streamline of water flooding, and grey relational method is used to calculate the influence degree of each factor. It is found that vertically heterogeneity, areal heterogeneity and injection-production well pattern have significant influences on streamline, while injection-production well spacing and injection-production pressure difference have relatively small influences. The streamline distribution model is divided into three categories: dense area, sparse area and blank area, on this basis, the optimal adjustment technology is formed. In several fault block reservoirs in Subei Basin, the adjustments of vector allocation, adding new waterline, reducing the number of wells in the well pattern, and reorganization after subdivision have been carried out. Remarkable effect of increasing oil production and efficiency has been achieved. It has certain guiding significance for the adjustment of the same type of reservoirs.

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.

In order to solve the problems that the effectual time and effective features of polymer flooding in horizontal wells of oilfields developed directly after natural energy development are quite different from those of polymer flooding in high water-cut periods, a more efficient and convenient way to determine the effectual time of polymer flooding is proposed by production dynamic analysis, that is the change features of production capacity, water cut and submergence depth. Based on the effectual time, the production period after polymer injecting is divided into the induced effective period, the dominant effective period and the subsequent effective period, and the relation between the injected pore volume and the stage is established. Then, a study has been conducted to characterize the changes in injection pressure, injection capacity, oil production capacity and integrated water content at different injection pore volumes, and the purpose and main content of the on-site measures at each stage have been clarified. According to the reservoir conditions in the polymer flooding well area and the outstanding problems exposed during the polymer flooding process, the influence of these factors on the development effect of the polymer flooding well group is evaluated and the main factors affecting the development effect of the current polymer flooding well group is clarified. This research provides a reliable basis for the efficient management of the oilfield polymer flooding well group on-site, and clarifies the target well areas of the subsequent conversion well group.

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.

The heterogeneous composite flooding has been proved to be an effective development technology to greatly improve oil recovery after polymer flooding, and the reasonable well pattern adjustment is the main method to improve the performance of heterogeneous composite flooding. By numerical simulation, the well pattern form, well spacing and flow line transformation angle of well pattern adjustment in Ⅳ1-3 reservoir of Shuanghe Oilfield have been systematically studied, and the comprehensive comparison and demonstration have been carried out from technical and economic aspects. The results show that the viscosity ratio of injection system to crude oil and the heterogeneity of formation have a decisive influence on the adjustment effect of well pattern flow line. For Ⅳ1-3 reservoir of Shuanghe Oilfield, on the premise of making full use of the old wells, the adoption of five points well pattern and well spacing of 150 ~ 300 m, and the great adjustment of the flow line angle can further improve the performance of heterogeneous composite flooding in decreasing water cut and increasing oil production.

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.

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.

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.

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.

Casing deformation occurs frequently during the development of the Weirong Shale Gas Field in the Sichuan Basin. In order to solve this problem, analysis on load and deformation degree of three casing deformation has been carried out by finite element method to discuss the deformation type. Meanwhile, by means of theoretical analysis, finite element simulation and equivalent test evaluation, the quantitative analysis is carried out on the parameters such as the overall angle change rate, cementing quality, wellbore temperature-pressure change and instantaneous stop pump. The influence of different engineering factors on casing strength weakening shows that the engineering factors are not the main factors of casing deformation. According to the analysis of comprehensive factors in the transformation process such as formation anisotropy, wellbore temperature-pressure coupling and reservoir lithologic interface, it is considered that the casing strength decreases under engineering conditions, while in the process of fracturing, the slip of weak strata or the non-uniform compression load of reservoir on casing leads to casing stress concentration and deformation. The relevant understanding provides a reference for the formulation of casing deformation prevention and control measures of Weirong Shale Gas Field.

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.

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

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

In order to illustrate the influences of the in-situ stress heterogeneity and cleat angle on wellbore stability of coal seam, the following researches have been done. The basic physical properties, mechanical parameters, macro and micro structure of cleats and in-situ stress states of coal and rock in an area have been acquired. Based on the discrete element numerical simulation method, comprehensive evaluation and analysis of the in-situ stress heterogeneity and cleat angles on wellbore stability in coal seam has been conducted by two kinds of evaluation method i.e. the maximal displacement and normalized the plastic area radius. The results of the numerical simulation show that under the condition of isotropic in-situ stress, cleat angle has little influence on the borehole stability. With the increases of the heterogeneity of in-situ stress, the influence of cleat angle on borehole stability is becoming more and more obvious. The maximum displacement around the well increases first and then decreases with the increase of the cleat angle from 0° to 90°. Meanwhile, with the increase of in-situ stress heterogeneity, the anisotropy of the radius of the circumferential plastic area caused by the change of cleat angle becomes more obvious. Therefore, the influence of cleat angle on wellbore stability should not be ignored in coal and rock strata with great difference in in-situ stress. The research results can provide reference for the drilling plan design of vertical and horizontal wells of coal seam in the study area.

The effect of CBM wells fracturing is controlled by multiple factors including geological characteristics of coal reservoir and data of hydraulic fracturing technology, therefore, it’s important to analyze the significance of each factor and determine the main controlling factors affecting the fracturing effect of CBM wells. With reference to the fracturing data from a CBM gas field in China, Apriori association analysis is employed to track the main controlling factors, and in combination of grey correlation method, a new set of identification methods of these factors for the effect of fracturing measures has been put forward. Meanwhile, it is figured out that eight main controlling factors affecting the fracturing effects are in the order as follows: maximum operation displacement of fracturing>average sand ratio>gas saturation>gas content>total proppant volume>total fracturing fluid volume>sand carrying fluid volume>prepad fracturing volume. Based on this method, different main control factors can be adjusted preferentially with reference to the degree of correlation in fracturing design to control fracturing effect, so as to provide theoretical basis for field application.

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.

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.

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.

Sidetracking horizontal wells can be used to control reserves, digging potentials and longitudinal residual oil and gas reservoirs. The researches at home and broad show that both restart production of long-time shutdown wells and increasing oil and gas production in low production wells need to imply sidetracking horizontal wells. The Sulige Gas Field, located in the Ordos Basin, is a giant gas field with reserves exceeded trillion, and in there an annual production capacity of 249×10⁸ m³ has been built. However, its single well yield is low, the rate of decline is fast, and the number of wells with daily production less than 3 000 m³ accounts for 50 %. To explore side drilling horizontal wells and to improve gas recovery are the technical directions to achieve the steady production, cost reduction and efficiency increase in development of Sulige Gas Field. In view of the difficulties of sidetracking horizontal wells with small holes in the research block, the researches are carried out on safe drilling, completion technology and economic benefit. Twelve sidetracking horizontal wells are tested in site, with an average horizontal segment length of 672 m and an average drilling cycle of 49 d. The initial average daily gas production of a single well after sidetracking was 2.7×10⁴ m³. The practice shows that it is technically feasible for the casing sidetracking horizontal well to improve gas recovery of low production and low efficiency wells in Sulige Gas Field.

In order to study the influence of mineral interface action on the initiation and propagation of shale hydraulic fracturing fractures, a shale microstructure model was established. In the model, the zero-thickness cohesive element was embedded in the solid element. A numerical simulation of the effect of mineral boundary interface stiffness on hydraulic fracture propagation was carried out to reveal the law of shale hydraulic fracturing crack propagation under the influence of mineral interface action. The results show that the tensile destruction is the main form of fracture failure of shale hydraulic fracturing. The crack propagation path consists of two ways, one is to extend along the mineral boundary, and the other is to cross the mineral boundary and enter the mineral to expand. With the increase of the mineral boundary interface stiffness, the crack initiation pressure and pore pressure gradually increase, the length, number and area of the cracks gradually decrease, and the width of the cracks gradually increases, so that it is easy to form short and wide cracks. When carrying out shale hydraulic fracturing operations, the location where the stiffness of the mineral boundary interface is lower should be selected first. The research results help to reveal the action mechanism of the mineral interface action on the expansion of the shale hydraulic fracture, and provide a theoretical basis for the reasonable selection of the hydraulic fracturing layer position of the shale gas reservoir.

In the case of the carbonate heavy oil reservoir with the well developed dissolution fracture, the percolation mechanism of dissolution fracture is different from that of fracture. The conventional well test models can not meet the needs of the well test analysis. In the heavy oil reservoir with quadruple media. According to the basic principle of the seepage flow mechanics, the quadruple-media well test mathematical model based on the fracture, dissolution fracture, dissolution pore and matrix is established in heavy oil treating as the power-law fluid. By means of the Laplace transformation and Stehfest numerical inversion, we obtained the real space solution, and drew the well test curves of three different boundary conditions. The results show that three concaves with different depths and widths occur in the pressure derivative curves of the quardrule-media reservoir and the slope of pressure derivative double-log curve is(1-n)/(3-n) in the stage of radial flow. The smaller the power-law index is, the greater the slope of pressure-derivative curve of radial flow will be. The smaller the storativity ratio is, the wider the concave will be, furthermore, the greater the interporosity flow coefficient is, the ealier the concaves will appear. Compared to the thriple-media, the change of the pressure-derivative curve affected by many parameters is more sensitive in the heavy oil reservoir with quadruple-media. The model is used to guide the interpretation and study of the well test data .

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.

In order to find out the complex situation of remaining oil distribution at the middle and high water-cut stage of Suizhong 36-1 Oilfield, and by the study of the flow field variation characteristics of nine-point well pattern for complex heterogeneous reservoirs by high temperature and high pressure experiments, the physical simulation experiments for the nine-point well pattern and the characteristics research for flow field of infilled row shape injection-production well pattern were designed and carried out based on the newly developed 3D large-scale core modeling technology and the stereoscopic acquisition system for oil-water saturation. For the injection and production patterns with complex rhythms, the distribution of remaining oil was also very complicated, but there were certain rules: under the condition of single positive rhythm, the subsidence of injected water was obvious even in the experiments, and the remaining oil was mainly distributed in the upper part of the positive rhythm; under the condition of inverse rhythm, the injected water could spread evenly to all permeability layers of the model, and the remaining oil was mainly accumulated in the weak hydrodynamic area; under the condition of complex compound rhythm, the distribution of remaining oil depended on the low permeability zone with weak water flooding in the complex structure, and it was not necessarily the area without streamline between corner wells. At the same time, based on the above characteristics, it was found that the water flooding degree of nine-point well pattern was high, most recoverable reserves could be produced. And when nine-point well pattern transformed into row injection-production well pattern, the recovery rate of heterogeneous reservoir could be improved by about 8 % ~ 10 %. Experimental studies suggest that no matter for the nine point injection production well pattern or the converted row shape injection-production well pattern, the maximum recovery rate of structure reservoirs with complex rhythmic was difficult to exceed 40 %.

In order to solve the problem that the injection pressure of shale reservoir in Fuling area is too high in the early stage of hydraulic fracturing, researches on the resistance reduction based on proppant slug technology was carried out. By using the previous self-developed jet device and target, a set of physical simulation method for reducing fracture resistance in near well by grinding perforation with proppant slug was established and the orthogonal experiment was carried out. For the on-site needs, fore-tail pressure drop and average pressure drop rate are established to characterize the experimental results, and then analyzed accordingly. The results show that the influence of various factors on the resistance reduction effect from large to small is in the following orders: sand ratio, particle size, number of slugs（grinding time） and proppant type. The effect of reducing resistance of quartz sand is better than that of ceramsite. Drag reduction increases with the thickening of proppant particle size and the increase of sand ratio, and decreases at first and then increases with the prolongation of grinding time. Based on the results of orthogonal experiment, the optimal operating parameters of quartz sand with particle size of 40/70 mesh, sand ratio of 9 % and grinding time of 9 min are selected. On this condition, the optimal friction reduction effect of pressure drop rate of 0.439 MPa/min and head-tail pressure drop of 1.04 MPa are obtained. The experimental study provides a certain reference for the construction design of hydraulic fracturing of shale reservoir.

At present, the leakage of shale gas drilling is quite common in China, and there are few plugging methods suitable for oil-based drilling fluid. The total loss of drilling fluid is still a difficult problem for technicians in the industry. Taking the field operation of Well-WY-1HF as an example, during the drilling of its horizontal well interval by using oil-based drilling fluid, the conventional plugging technology of bridge plug and cement plugging technology of oil well can not work efficiently. Based on the analysis of the characteristics of the loss zones, the effect of different plugging material of oil-base drilling fluid performance have been studied to determine the formula for successful plugging, that is high density （1.89 g/cm³） cement solidified plugging combined with low density （1.17 g/cm³） inorganic gel curing plugging, cooperating with the use of bridge plug with high concentration and large particle. It ensures the subsequent drifting, well logging, the casing and cementing operation smoothly. The successful implementation of this method provides certain reference for the application of shale gas plugging technology in the same area.

Reservoir permeability is an important factor affecting reservoir productivity. In order to solve the problem of poor prediction accuracy of conventional permeability logging models in low-permeability sandstone reservoirs with poor pore connectivity, a scheme combined with deep belief network（DBN） algorithm is proposed. First, the gray correlation method is used for the correlation analysis of logging curve, and according to the correlation ranking, the characteristic sensitive curves is sorted. Then, the optimization by supervised learning is combined with the contrastive divergence for the data mining to establish the prediction model of permeability. Compared to the previous BP neural network, DBN model improves the local optimization, and enhances the training efficiency and prediction accuracy. The average relative error of the prediction model is 9.1 %, which is about 20 % lower than that of the conventional permeability model. Based on the actual data processing applications and the error analysis, it is found that this method can effectively improve the prediction accuracy of permeability for the low permeability reservoirs.

Currently, there are few works on the laws of front migration and gas channeling with laboratory experiments from the aspect of CO₂ sweep efficiency. Therefore, a visual physical simulation device is used to carry out the physical simulation experiment of CO₂ immiscible flooding of slab core. The influences of factors such as crude oil viscosity, reservoir permeability, reservoir heterogeneity and injection rate on the migration of CO₂ immiscible flooding front and gas channeling laws are analyzed. The study found that under the conditions of constant flow injection in injection wells and constant pressure production in production wells, the viscosity of crude oil decreases, the permeability decreases, the reservoir is homogeneous, and the injection speed increases, which will lead to an increase in the recovery degree of CO₂ immiscible flooding. Meanwhile, the decrease in the viscosity of crude oil, the lower the permeability, and the increase in the injection rate, also lead to the enhancement of the ability of the oil well to continue to expand sweep factor after gas breakthrough, that is, it can alleviate gas channeling. It is concluded that under the condition of constant flow injection in injection wells and constant pressure production in production wells, high injection rate development can alleviate gas channeling and obtain better development results. When the injection rate increased from 0.1 mL/min to 2 mL/min, the recovery increased from 15.4 % to 35.3 %, and the sweep factor difference increased from 8.3 % to 26.2 %. This research is of great significance for CO₂ immiscible flooding gas channeling suppression and enhanced oil recovery.

Due to the own application conditions of the electric submersible pump and other drainage and gas recovery technologies, they cannot adapt to different drainage and gas recovery periods of shale gas wells in the south block of Pingqiao. In order to solve these problems, the technical adaptability analysis and countermeasures of shale gas drainage and recovery technology were carried out. Based on the analysis of the problems of electric submersible pump, jet pump and gas lift drainage and recovery process, the composite drainage and recovery process string combined by electric submersible pump and gas lift is designed according to the formation pressure characteristics of different drainage and recovery periods of shale gas wells of the south block in Pingqiao. The composite drainage and recovery process string consiste of ? 73 mm oil pipe, gas lift valve, intelligent switch and electric submersible pump. In the early production stage of shale gas wells, when the formation liquid supply capacity is sufficient, the electric pump drainage lifting process string is adopted. In the later drainage and recovery stage, when the submergence of submersible pump decreases to 100~200 m, the gas lift drainage and recovery process is adopted. This composite string overcomes the deficiency of electric submersible pump, jet pump and gas lift single drainage and recovery process, making one production string adapts to different drainage and recovery periods of shale gas wells possible, and finally realizing the continuous drainage and recovery of shale gas drainage and recovery wells.

The potential impact of shale gas development on regional environmental quality include the risk of groundwater pollution during hydraulic fracturing, the risk of surface water pollution due to the backflow drainage, and the influences of methane leakage on regional atmospheric environmental quality. The way of tracking, monitoring and evaluating the environmental quality of shale gas production areas is effective to confirm the effects of pollution prevention measures and understand the long-term cumulative environmental impact. The pollution prevention measures in Nanchuan shale gas production area have been summarized. The groundwater environment, surface water environment, atmospheric environment, acoustic environment, and soil environment in the production area have been monitored. According to the most unfavorable principle, the single factor indexes with the largest monitoring value have been used to evaluate the current environmental quality, and the inter-annual changes of the environmental quality of each element has been assessd. The results show that the monitoring factors of surface water environmental quality, groundwater environmental quality, atmospheric environmental quality, acoustic environmental quality, and soil environmental quality in Nanchuan shale gas production area meet the environmental quality standards of the corresponding functional area. There is no significant inter-annual changes in the evaluation indexes of each monitoring factor, especially the characteristic pollution factor of shale gas development such as chloride. The regional shale gas development has not caused pollution of various environmental elements and significant adverse changes in environmental quality. Although the current pollution prevention measures are effective, the continuous and cumulative environmental impacts still require longer-term follow-up monitoring and evaluation.

The exploration and development practice in Shunbei area of Tarim Basin shows that oil and gas resource there is rich. However, the reservoir is deeply buried, the degree of oil and gas enrichment varies greatly, the reservoir type is very complex, and the overlying strata has the engineering problems such as easy leakage and collapse. All these problems above bring great challenges to the efficient development in this region. In order to expand the scale of oil and gas and realize the efficient development, the exploration in organizational management and work model has been carried out. The main practices and corresponding technologies of key links such as management mode, well position demonstration, well type design, safe drilling and effective well completion have been initially formed. The research will give reference for development of the ultra-deep fault- karst reservoirs in this area and similar reservoirs.

Influenced by the underwater paleouplift and multi-stage structural extrusion of Leshan-Longnyusi, Yuxi Block gradually deepens from north to south, and has the characteristics of large thickness change of type I reservoir and low porosity（less than 4.5 %）, it is very important to study the pore structure of high quality shale. Traditional shale pore analysis technology has weak identification ability for different types and sizes of micro nano pores. Through an optimized analysis method based on maps image, it can reduce the space-time complexity of the algorithm and improve the applicability on the premise of effectively identifying and statistics the organic and inorganic pore fractures of shale. Characterization of organic pore fractures in Longmaxi formation is about 300 μm, inorganic pore seam with a visual field of view length of 500 μm. The diameter or opening range of organic pore gap detected by maps image is mostly between 0~100 nm. The organic matter content and organic matter porosity are different, and the abundance of organic matter is not the only control factor for the development of organic matter pores.

In order to effectively solve the problems of difficult gas injection in S358 high pour-point reservoir and low oil displacement efficiency caused by gas channeling due to high mobility ratio of gas flooding after fracturing, laboratory experiments of gas injection phase and long core displacement mechanism have been carried out. Through the PVT phase state experiment of the high pour-point oil injected by CO₂, dry gas, flue gas, and oxygen-reduced air（N₂ 90 %+O₂ 10 %）under the formation conditions, the characteristic mechanisms of the above four injection gas such as the solubilization expansion, viscosity reduction and tension reduction have been analyzed. CO₂ is preferred as the injection gas. Through five groups of high temperature and high pressure long core flooding experiments with different combination methods, the effect of CO₂ combination flooding on channeling prevention and extraction is evaluated. The experimental results show that the displacement effects of both CO₂+weak gel and CO₂+foam are the best two, and the final displacement efficiency is 70.101 % and 68.212 % respectively. The research results show that the injection of CO₂ combined flooding slug increases the displacement resistance and reduces the fracture conductivity, which plays a key role in improving the microscopic sweep volume. Among them, both the CO₂+weak gel and CO₂+foam displacement methods have the best extraction effects. The research results can provide an experimental basis for the efficient development of high pour point oil in this block.

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

The minimum miscibility pressure（MMP） of CO₂ flooding is affected by crude oil components and reservoir temperature. And its influence rule has great significance to screen and evaluate gas injection reservoirs. The tie-line analysis is a method to calculate MMP analytical approach which is faster, more accurate, and easier to operate. In this paper, a calculation process of simulating CO₂ flooding by tie-line analysis was proposed, and the influence law of components（C₄, C₁₀, C₁₄, C₂₀） and temperature on MMP was studied. The results showed that the simulation results of the tie-line analysis were similar to those of the slim tube numerical simulation. The MMP increased with the increase of temperature, and the sensitivity of MMP for each component was more obvious in higher temperature. The MMP decreased with the increase of C₄, C₁₀ and C₁₄ components, but increased with the increase of C₂₀ component. The study proposed a new method with simple process and accurate calculation for calculating MMP and evaluating influencing factors.

The development of high-quality shale in Wufeng-Longmaxi formation in Wulong area is characterized by wide distribution, large thickness, moderate burial depth, high organic matter abundance and moderate thermal evolution. It is a favorable shale gas exploration area. Due to the typical southern China’s mountainous landform in Wulong and the influence of large obstacles such as Wujiang river and nearby towns, the explosive source is limited, resulting in the emergence of the so-called “data skylight”. The advantages of seismic wave generated by the spark source, such as the rich high-frequency information, good waveform repeatability, good time consistency, safe and free from contamination, meet the source requirements for seismic exploration in the Wulong area. After the application of spark source, the coverage fold of large obstacle area increases and the section gap decreases. The energy of the spark source is 200 ~ 800 kJ, which is equivalent to the energy of the 2 ~ 4 kg well gun（14 kg, 21 m）. A high quality reflection signal can be seen above 2 s of the single shot record, and the effective frequency band is up to 80 Hz. The spark source can effectively make up for the “data skylight” in Wulong and Tukan town, and meet the requirements of 3D geological exploration.

Significant advances has been made in the exploration and development of deep gas reservoirs in the southeastern Chongqing, especially the deep shale gas. While the shallow gas exploration is on the contrary, especially the shallow fracture-matrix limestone gas reservoir, Maokou Formation, with low porosity, low permeability, low fracture development, low reservoir temperature, low pressure coefficient, and mediocre fracture development. During the acid fracturing process, as the gel is hard to break by acid and the flow back is difficult, then the effect is poor, and it is difficult to make breakthrough. Taking the characteristics of carbonate reservoir, Maokou Formation in well-Dashi-1HF, as the example, the difficulties in reservoir acid fracturing have been analyzed, the self-degradation gelling acid has been synthesized, the mechanism of degradation has been introduced, and the optimization of the acid-liquid system has been carried out. The horizontal well acid fracturing pipe string has been optimized to form acid fracturing technology of self-degradation gelling acid and multilevel packer, at the same time, the segmented acid fracturing parameters have been optimized. 4 stages acid fracturing of well-Dashi-1HF has been completed, and the total acid dosage is 2 129.2 m³. The test gas production after acid fracturing is 22.6×10⁴ m³/d. The results show that this new technology has a good effect in the shallow limestone of southeastern Chongqing, and provides useful reference for the acid fracturing of similar layers in the future.

The casing damage of horizontal wells for shale gas, especially for deep shale gas, has always been a problem that troubles the staged fracturing development of shale gas. The conventional methods, such as casing patching and chemical plugging, cannot simultaneously meet the demands of high pressure, high flow rate and small bridge plug passing during fracturing, resulting in the difficult implementation of the staged fracturing technology through pumping of bridge plugs. Besides, the staged fracturing technology with multi-packer is difficult to meet the requirements of pumping rate and scale due to the limited number of segments and limited displacement, resulting from the limited range of the ball-drop sliding sleeve. Taking Well-WY9-2HF as an example, by conducting the researches such as risk demonstration, pipe string mechanical analysis and structural optimization, tool development and improvement, and wellbore simulation test, the following conclusions are drawn: the string with suspension packer is suitable for isolating the casing-damaged sections; the combination of the upper casing and the lower tubing for injection can raise the pump rate; the full bore infinite sliding sleeve can increase the number of segments and the pump rate; together with multi-packer, well control safety measures and high-rate segmented fracturing technique, the full bore infinite sliding sleeve is used to realize a large-scale and high-rate fracturing with 31 stages in Well-WY9-2HF, which achieves the expected targets and obtains a commissioning production of 8.75×10⁴ m³/d. This technology can be used as a reference for the fracturing and commissioning of such wells.

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.

In order to further clarify the mechanism of steam flooding assisted by CO₂ in the heavy oil reservoir, its visualization experiments are carried out by the acrylic plate model and natural cores, and their synergy is analyzed. After the mechanism of synergistic displacement is clarified, the core flow experiments are carried out to further analyze the influence of the synergistic effect and the injection mode on the actual displacement efficiency. The results show that CO₂ assisted steam flooding has the effects of the synergistic viscosity reduction, the expansion of steam sweep efficiency, the availability of residual oil at the blind end, and the demulsification. Among them, the comprehensive viscosity reduction rate of the crude oil is 59.8 %, and the steam sweep area is increased by 37.44 %. Compared to the flooding by steam alone, after the assitant of CO₂, the recovery rate increased significantly. The alternate injection of steam and CO₂ can get a recovery rate of 65.7 %, 7.9 % more than that of mixed injection, and observe the stable foam oil flow at the outlet.

In China, low-rank coal and coalbed methane resources are abundant, meanwhile, as a kind of clean energy, the development and utilization of coalbed methane（CBM） can effectively alleviate the shortage of natural gas resources, but the commercial scale development is slightly insufficient, and systematic research is urgently needed. The premise of efficient CBM development is the selection of favorable areas, but the current CBM development evaluation involves certain subjective human factors, which will indirectly affect or interfere with the prediction effect. Taking the low-rank coal in the Dafosi minefield in the Binchang mining area of Huanglong Coal Field as the research object, based on the actual production data, the random forest algorithm in machine learning is used to predict the favorable area of coalbed methane in the area. The results show that: ① Pearson correlation analysis shows that the gas content, ash content, net thickness of coal seam, structural position, roof thickness, permeability, reservoir pressure and burial depth are eight mutually independent CBM output-related parameters and can be used for model establishment; ② The Random Forest algorithm divides the CBM development area into five types of areas with different degrees, of which type Ⅰ（extremely high） to Ⅱ（highly favorable） areas account for 13.88 % of the entire study area, mainly distributed in the middle of the well field. The southeast is not suitable for subsequent deployment of well locations, and there is a distribution of highly favorable areas in the west, so the well locations for subsequent development and deployment should also be considered. ③ It can be obtained from the receiver operating characteristic（ROC） curve, and the area under the ROC curve （AUC） is 0.961, indicating that the Random Forest model has high prediction accuracy and reliable results. Using machine learning algorithms for comprehensive prediction of CBM favorable areas can avoid human subjective factors in traditional algorithms, and can provide a certain theoretical reference for subsequent unconventional oil and gas development and selection.

The minor principal stress of Sulige gas field was between 43 ~ 48 MPa, while the proppant always used in fracturing was 20/40 mesh ceramic with moderate strength. In order to evaluate the feasibility of replacing the ceramsite with the quartz sand, we analyzed the demand and current situation of fracture conductivity by numerical modeling and well testing data. On this basis, we studied the selection of quartz sand and the mixed mode of quartz sand and ceramsite by indoor experiments, thus proposing the corresponding plan and carrying out the field tests. The results showed that, firstly, the present fracture conductivity was about 130 μm ²·cm, which was higher than the demand of the reservoir in class I（94 μm ²·cm）, the reservoir in class Ⅱ（65 μm ²·cm） and the reservoir in class Ⅲ（25 μm ²·cm）. The quartz sand was available for fracturing. Secondly, the uniform mixing of the 20/40 mesh quartz sand and ceramsite was a good combination way of proppant. When the closing pressure was between 40 ~ 50 MPa and the proppant placement concentration was 10 kg/m ², the conductivity of these who in the proportion of 1∶0, 7∶3, 1∶1, 3∶7 respectively were 20 % ~ 46.7 %, 23.9 % ~ 56.7 %, 46 % ~ 74.6 %, 73 % ~ 89.7 % of that of ceramsite. Thirdly, the optimal mixed proportion of quartz sand and ceramsite for the reservoir in class I should be below 1∶1. The optimal mixed proportion for the reservoir in class Ⅱ should be below 7∶3. The quartz sand could be used throughout for reservoir in class Ⅲ.

In order to solve the problems such as coal blockage and low gas production of coalbed methane wells in the Southern Yanchuan block, an application test of controlled shock wave plugging removal and permeability improvement technology is carried out. Therefore, four typical wells are selected to analyze the geological and engineering parameters in the construction process, as well as comparative analysis of the gas and water production before and after the implementation. The results show that the application of controllable shock wave plugging removal and permeability improvement technology in coalbed methane wells can improve liquid fluidity, promote gas desorption and diffusion, and remove plugging in coal reservoirs. The well selection criteria of this technology are low coalbed fracture pressure, good fracturing effect, including dirt band, high gas-bearing capacity of coalbed, relatively high formation pressure coefficient, etc. This technology has the effect of creating fractures and removing plugs, which can improve the fluidity of formation fluids and remove formation pollution. It has a good implementation effect and application prospect in the near-well zone of south Yanchuan coalbed methane wells to plugging removal and increase gas production, and is expected to be a new stimulation technology for low yield and efficiency wells.

Foam drainage-gas recovery technology is the most common nowadays and is the most effective application technique. However, due to the certain difference in production conditions of different gas fields, the mode, type, and foam drainage system of foaming agents are different. At present, southern Pingqiao adopts the method of 24 h continuous injection which is commonly used in other gas fields. It works in some wells, but for other wells, this technology dose not works well. In order to form a set of foam drainage model suitable for shale gas wells in southern Pingqiao, combined with laboratory evaluation, field test and economic evaluation, it is proved that the foam drainage process can effectively carry out the bottom hole liquid accumulation and achieve a certain degree of production increase. But in the later stage, it is more focused on reducing the production decline of shale gas wells and ensuring the stable production of gas wells. The XHY-4M type liquid foaming agent is optimized for foaming. When the concentration of defoamer is 0.3 %, the concentration of defoamer is 5 % ~ 20 %, the ratio of defoamer and foaming dose is 1.2∶1, the ratio of water to gas in the well is greater than 0.5, and the overall foam drainage effect is better. Meanwhile, the foam drainage system is constantly adjusted and optimized, and the intermittent foam drainage system of “less injection and multiple times” is adopted, which is more applicable and the effect of economic evaluation is optimal. The results of this study have certain reference for the stable production of similar shale gas wells.

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.

Middle Permian Qixia-Maokou Formation is one of the most important series of strata to explore and develop natural gas in Sichuan Basin. Nanchuan area is located in the southeast of Sichuan Basin. The pilot exploration indicates that there is a great development potential for natural gas in Qixia-Maokou Formation. In order to know its reservoir spaces of carbonate rocks, the test methods, such as thin section identification, SEM and phase analysis of X-ray diffraction, have been taken based on the samples of Well-JY205-2. The reservoir spaces are classified into two categories: pores and fractures. Pores include organic pores and inorganic pores, while fractures include stress fractures, grain edge fractures and shrinkage cracks. The types of reservoir spaces are obviously controlled by lithology. In Qixia-Maokou Formation, the dominant reservoir space types of carbonate reservoirs are the intragranular dissolution pores and the dissolution fractures distributed along the particle edge. These dissolution fractures can connect the pores with the fractures better, and are beneficial to improve the permeability of the reservoir. There are abundant intercrystalline pores of clay minerals in the layers with higher argillaceous content. The surface porosity of intragranular dissolution pores and intercrystalline pores of clay minerals in the layer-① of Mao-1 Member are the highest and in good agreement with the higher porosity and permeability in this layer, which indicates that the layer-① of Mao-1 Member is favorable to natural gas exploration.