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

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

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

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.

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.

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

The 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.

Due to the deep buried depth（3 500~4 200 m）, high ground stress, high ground stress discrepancy（7 to 17 MPa）, low reservoir brittle（< 0.5） and the undeveloped natural fracture, the hydraulic fracture of Weirong deep shale gas face the problems of high fracturing construction pressure, narrower pressure window, low sensitive sand concentration, high fracturing difficulty. Large-scale physical model experiments show that the morphology of Weirong shale fractures are composed of main fracture and branch fracture, within low fracture complexity and forming bedding seam more easily. On the basis of geology-engineering integration, the stratigraphic segmentation and clustering are optimized in combination with geological sweet spot. Through the study of the proppant transport, the placement mode and injection timing of the three-grade particle size proppant have been optimized, which increase the sand loading. The transverse complexity of fractures is improved by the combined temporary plugging steering fracturing technology. The net pressure and complexity of fractures are improved by the temporary plugging in the fractures and the optimization of construction discharge and liquid viscosity, thereby improving the fracturing volume and control reserves. The research results have been successfully applied in Weirong Gas Field. The sand loading has been increased to 1.95 t/m, the average open flow per well is 38.5×10⁴ m³/d, and the single well EUR is 90×10⁸ m³. All those shows a significantly improvement compared with the previous stage. Post-pressure evaluation shows that the fracturing effect is positively correlated with the sand adding strength. Therefore, how to improve the sand adding strength and control the strength of the liquid used in deep shale gas is the key to economic and effective fracturing.

CBM development in China focuses on the high-rank coal, which is brittle and, during drilling, fracturing and drainage, easily crushed into coal fine. During the production, coal fine flows owing to the water flashing effect. As the water production declines, the coal fine will sediment and block the flowing channels, leading to the great reduction of coal permeability. When the coal fine enter the wellbore, it may jam the pump, resulting in accidents in production such as pump stuck or buried pump, and leading to the stop of production for well repair. In order to solve this problems, the generation mechanism, migration rules and current major controlling approaches of coal fine are summarized. And then, the mechanics model, hydraulic model and migration model are investigated respectively. According to the former studies, the coal fine migration process can be summarized as four stages: denudation, detachment, suspension and sedimentation. However, the geology conditions of coal seam in China are extremely complex and the structure changes effect is dramatic on coal basins. These factors enhance the problems of production and migration. Nevertheless, the coal fine controlling approach method primarily learns from the sanding control technology in oil reservoir and is still undeveloped for the CBM reservoirs.

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

As a new field of unconventional natural gas exploration and development, deep coalbed methane（CBM） has great resource potential, but its benefit development faces great challenges. How to carry out efficient development is a problem needed to be solved at present. In order to achieve stable production and steadily promote the expansion of the gas field, focusing on how to realize the problem of “long fracture and far support” in reservoir reconstruction, Yanchuannan gas field has achieved good results through fracturing optimization and tackling key problems of deep coalbed methane geology-engineering integration. The research shows that: ①Deep CBM has great resource potential with a high gas content of 13~20 m ³/t, but it is difficult to develop and transform the reservoir and the daily production of single well is low, only of 0~500 m³/d; ②According to the underground observation, in the existing active hydraulic fracturing technology, the effective supporting seams mainly distributes within eight meters of the wellbore, and the main fracture extension is generally less than 30 m; ③Deep coal seam fracturing should take the large-scale artificial fracture with long-distance support and high conductivity as the main target to improve the sand adding strength with large displacement, and at the same time develope “low density and long migration” proppant. The average daily gas production of single well is 1 800 m ³. It provides a new idea for the deep CBM development.

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

Because of the importance of preservation conditions and shale pore evolution to shale gas exploration and development, it is of great scientific significance and academic value to study the relation between them. The pore structure characteristics and evolution of black shale with different preservation conditions have been studied by means such as argon ion polishing, scanning electron microscope and nitrogen adsorption, and it is found that the pore structure of black shale under different preservation conditions are significantly different. This difference is caused by the difference of preservation conditions in the late uplift process, which is manifested in the following aspects. First, inorganic pores in black shale with good or bad preservation conditions are both less developed, and most of the original intergranular pores are filled with generated hydrocarbons. The inorganic pore characteristics between them are basically similar. Second, the organic pores in black shale are of great difference under different preservation conditions. The diameter of shale organic pores is larger in good preservation conditions, which are in round or bubble shape. While the organic pores are relatively smaller in diameter or totally absent in poor preservation condition, which are in flat or irregular shape with the certain characteristics of flattening and deformation. Third, the pore volume and specific surface area of the black shale under good preservation conditions are better than that under poor conditions. Fourth, the porosity evolution of black shale is affected by preservation conditions. The original pore morphology and distribution are controlled by facies and diagenesis process, and so are the organic matter（oil） distribution form. Thermal evolution of organic matter（oil cracking） influences the existence of organic pores. Whereas, in the late uplifting process, the pore structures（shape, size, pore volume） are affected by the quality of the preservation condition. Therefore, the size, morphology and porosity of the shale organic pores reflect the preservation conditions of shale gas in some extent.

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.

Shale oil reservoir bears heterogeneous pore structure with multi-scale pore sizes. Nano-scale organic intra-granular pore, nano-micro scale inorganic inter-granular pore and micro-fracture coexist in shale oil reservoir. The ultra-low porosity and ultra-low permeability characteristics make the laboratory core flow experiment unavailable for shale oil core sample. As a consequence, shale oil flow parameters in different scale of porous medium can not be measured and it is difficult to accurately evaluate the shale oil flow ability in different scale of porous medium. To solve this problem, a calculation method for pore structure characterization and flow ability of shale oil reservoir is proposed based on digital cores. The nanopore shale oil flow model is first established considering nano-micro scale transport mechanisms and occurrence state, and the influences of shale pore surface physicochemical property and pore size on shale oil flow are analyzed. Then, the nanopore shale oil flow model is further extended to 3D porous media by establishing pore network shale oil flow model. The digital cores in different medium and its pore network are constructed based on the multi-scale shale core imaging data in shale oil reservoir. The multi scale pore structure characteristic and shale oil flow ability are studied in detail on this basis. The analysis results indicate that when the pore radii are less than 5 nm, the shale oil permeability is dependent on adsorbed phase permeability. Inter-granular pore dominates shale oil flow ability. The micro-scale effect on shale oil permeability is very small which can be neglected. The micro scale effect and oil slippage are more obvious in organic pores. However, the contribution of organic pore permeability on total shale oil permeability relies on the connectivity of organic pore structure.

Based on geological, logging and experimental analysis data, normal-pressure shale gas reservoir of Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Member in Pengshui area has been researched by the established quantitative characterization method, and it is found that the reserving space of high-quality shale in ①—⑤ layers is mainly composed of organic pores and bedding joints. The arithmetic average aperture measured by FIB nanotechnology with higher resolution ranges is from 20 to 50 nm, being mainly mesopores. However, the volume weighted average aperture is 100 nm, being macropore. In terms of the measured pore volume, macropore is the main contributor to total volume and porosity. Core-scale fractures lead to the abrupt decrease or increase of gas logging and the migration of shale gas at layer-level. The new method, Maps, show that the bedding joints in layer① of well-Longye-1 are open and continuous with an opening width of 4.69 μm, and the opening width of bedding shear joint is 1.1~2.67 μm. The sum of plane porosity for bedding and bedding shear joints is 1.39 %, which accounts for about 1/3 of the total porosity of the sample. It confirms the important contribution of bedding fracture and natural tectonic fracture for shale gas reservoir spaces. Comparing with the overpressure shale gas reservoirs, the porosity of shale reservoir in normal-pressure area is slightly low, and the high-angle seam and bedding joints are more developed. A new parameters and criteria method for evaluating normal-pressure shale gas reservoirs has been established. By this method, favorable reservoir area of type I reservoir is of 620.22 km² in layer ① to ⑤ of Wulong syncline.

Nanchuan Shale Gas Field is China's first commercially developed shale gas field dominated by normal pressure shale gas. In order to evaluate the exploration and development prospects of this type of shale gas, the exploration and development history of this area has been reviewed, the geological characteristics of the gas field are analyzed from the aspects such as structure, deposition, reservoir, preservation, in-situ stress, gas reservoir and production characteristics, and finally, the key technologies of exploration and development are summarized. The results show that: ①Nanchuan Shale Gas Field has experienced multi-stage tectonic movement. Its shale gas geological conditions are complex, and there are three structural belts: Pingqiao, Dongsheng and Yangchungou. The characteristics of deposition, reservoir, preservation and in-situ stress are quite different in different tectonic zones, but the shale gas reservoirs are generally with the type of elastic gas drive, mid-deep to deep layer, normal temperature, high pressure to normal pressure and dry gas. ②As for the production, its has the characteristics of high initial test output, high liquid volume, fast decline, medium elastic yield and relatively low single well's EUR. ③Six key technologies of exploration and development have been formed, which are, “sweet spot” target evaluation, reservoir characterization, in-situ stress field prediction, geology-engineering integration design of horizontal wells, development technology policy and low-cost engineering technology. ④The discovery of Nanchuan shale gas field brings four inspiration: firstly, firming exploration confidence is the foundation of exploration breakthrough; secondly, deepening basic geological research is the core of breakthrough; thirdly, innovative technological practice is the key to benefit development; fourthly, the implementation of the integration model is the guarantee of improving quality and efficiency.

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

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.

Staged fracturing for horizontal wells is one of the key technologies for shale gas development. As the shale gas development in China extends to normal pressure fields, it is urgent to enhance the speed and efficiency of fracturing technology. The existing plug and perf operation technology has many limitations, including long duration of pumping, easiness to stuck tools, limited number of fracturing stages for ball-actuated sliding sleeves, and limited fracturing scale for packers dragged by coiled tubing. For the new infinite stage and full-bore sliding sleeve fracturing technology, the structure principle of the sliding sleeve as well as its technological characteristics are explained, and a pilot test has been carried out in 16 fracturing stages of two wells in Nanchuan Shale Gas Field. This technology replaces perforation and coiled tubing drilling plugs by preset sliding sleeves. All the sliding sleeves are opened successfully. The number of fracturing stages is unlimited and the operation is continuous. The average time of single stage fracturing is 3.5 h and it can finish seven fracturing stages per day. As a fast, safe and efficient staged fracturing technology, it provides a new technical means for enhancing speed and efficiency of fracturing technology for shale gas wells in China.

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 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.

The efficient development of condensate gas reservoirs requires accurate fluid phase properties data, among which accurate prediction of dew point pressure is an important issue in the development of condensate gas reservoirs. In order to solve the problem of low accuracy of traditional prediction methods for dew point pressure of condensate gas reservoirs, based on optimization theory and applied statistical analysis, and by fitting measured data, a non-parametric regression model determined by alternating conditional expectation transformation（ACE） is proposed, and an explicit correlation of dew point pressure with statistical significance is obtained. Based on Pearson correlation analysis, the independent variables of the model are gas reservoir temperature, mole fraction of （C₁, C₂-C₆, C₇₊）, and molecular weight and relative density of C₇₊. The potential function relation between independent and dependent variables is analyzed by 27 sets of experimental data for published dew point pressure, and 9 groups of measured dew point pressure data of TLM oilfields are predicted. The results show that the model has high precision and good generalization ability. The average absolute relative deviation（AARD） of model regression is 2.16 %, and the predicted AARD is only 4.8 %. The maximum absolute relative deviation（ARD） is 9.21 % and the minimum is 0.34 %. This study provides a reference method for dew point pressure prediction of condensate gas reservoirs.

As one of the important economic indicators for the development of shale/tight reservoirs, the production performance and EUR calculation of shale/tight wells is an important subject in unconventional reservoir engineering. This has been challenging for the reservoir engineers from both China and other country for a dozen of years. Based on the understanding of the unique geological characteristics of shale/tight reservoirs, this paper describes in detail the production performance of those wells producing extremely tight reservoirs, from which the inapplicability of using traditional methods has been explained. Further, a new methodology and the workflow has been presented from SPEE recommendations, and one practical example has also been illustrated of implementing the workflow.

Southeastern Chongqing is the first area to realize commercial development of shale gas in China. According to the main development progress of drilling and completion technologies in this area, 10 key technologies are summarized, which are, casing program optimization, severe loss control in shallow layers, low-cost managed pressure drilling, well trajectory control based on geology-engineering integration, bit selection, oil-based drilling fluid with low oil-water ratio, ROP enhancement through drilling parameter optimization, cementing technology for leakage wells, completion technology for preventing trapped pressure in annulus, and factory-like drilling technology. In order to make up for the deficiency in drilling and completion technologies, six directions of further research are proposed, which are, drilling equipment automation, drilling parameter enhancement, water-based drilling fluid, complex situation treatment, small hole drilling and completion, and shale gas drilling with long horizontal section, which aim to improve the drilling and completion technologies and the exploration and development profits in southeastern Chongqing.

The low-yield and low-efficiency wells in the deep coal seam gas field of South Yanchuan are of high proportion and the reasons for low-yield are complex, so that it is difficult to achieve the expected development effect. In order to solve these problems, taking the low-yield and low-efficiency wells in South Yanchuan CBM Gas Field as the research object, the integrated research and analysis of geological engineering have been carried out. Combined with the practical experience of CBM development, it is found that the unreasonable drainage rate leads to the blockage of coal reservoir seepage channels, the inadequate reservoir transformation results in a small discharge area, and the lack of formation energy in the low-pressure area leads to the limitation of coal bed methane desorption. These three problems are the main reasons for the production of low-efficiency wells in South Yanchuan. For the reasons of inefficiency, production stimulation measures such as controllable strong pulse deblocking, volume fracturing to achieve fracture steering, nitrogen disturbance dredging and desorption have been carried out. The results of field application evaluation show that these measures can achieve different degrees of production increase, among which volume fracturing can achieve the purpose of effectively improving the physical properties of the reservoir. The daily production of a single well is increased by 1 000~4 000 m ³. The effect of production increase is remarkable. It is the most effective means of increasing production in South Yanchuan CBM Field currently.

The distributed optical fiber temperature monitoring technology is gradually being used to monitor the downhole production of fractured horizontal wells. However, it is still a huge problem to interpret the production profile of fractured horizontal wells quantitatively based on DTS data in low permeability gas reservoirs. In view of this, this study established the method, first, the temperature data preprocessing, and then, on the basis of the principle of conservation of mass and energy conservation of horizontal wells in low permeability gas reservoir fracturing coupling temperature forward model, finally using a variety of traffic data of mathematical methods of inversion layers, forming a set of monitoring based on distributed optical fiber temperature measurement technology of horizontal wells in low permeability gas reservoir fracturing of output profile processing and interpretation methods.The actual data processing of fractured horizontal well 5 was carried out by using the established method.The results show that the forward temperature fitting curve is basically consistent with the original temperature curve, which indicates the rationality and accuracy of the forward model.In addition, the calculated absolute errors of daily gas production of the five wells were between 100 m³ and 1 712 m³, and the absolute errors of daily water production are between 0.7 m³ and 1.8 m³. The errors are small and meet the production requirements. All these provided technical support for the development of low permeability gas reservoirs.

Due to the large natural fractures and the single extension of hydraulic fractures, gas channeling occurs easily during fracturing of multi-platform, as a result the instantaneous gas production of adjacent wells is reduced by at most 93 %, and the wellhead pressure is increased by at most 12 MPa, which seriously affects the fracturing development effect of shale gas. For this complex situation, a fracture control and channeling prevention technology for horizontal wells of shale gas is proposed, which mainly includes fracture-length control of multiple fracture and steering fracture. By the measures of increasing the number of hydraulic fractures to reduce the net pressure, or using temporary plugging materials to steer hydraulic fractures, the extension direction of hydraulic fractures has been controlled and the fracture complexity has been increased to reduce the interacting of adjacent wells, and finally make the shale gas effectively develops in the well controlled gas drainage area. The numerical simulation shows that after applying this technology, the effective fracture length is shortened by 11.9 %~24.8 % The field application effect is obvious, the fracture length monitored by real-time micro seismic is reduced by 24 %, and the real-time monitoring pressure of adjacent wells does not change. The fracture control and channeling prevention technology in horizontal wells of shale gas does not only provides theoretical support for field application, but also reduces the probability of complex situations and improves the production of single well.

With the rapid development of the shale gas industry in China, the shale gas geological evaluation experimental testing technology has been continuously improved. At present, a series of technology, mainly including core pretreatment, mineral composition, geochemistry, pore structure, physical properties, mechanical properties and gas content, has been formed in China. Compared with traditional sandstone, conglomerate, siltstone and other clastic reservoirs, shale reservoir, as a fine-grained deposit, has typical characteristics of low porosity and ultra-low permeability, and the natural fractures and micro nano pores develop. Therefore, it brings four challenges to the experimental technology of shale gas geological evaluation: the sedimentary microfacies are changeable, the diagenetic evolution is complex, the pore structure characterization is difficult and the fluid flow mechanism is diverse. In order to further speed up the progress of shale gas exploration and development in China and solve the bottleneck and problems in the actual production process, four directions are put forward for the experimental testing technology of shale gas geological evaluation, that is, ①the fine description of reservoir urgently needs to be developed from static characterization to dynamic evolution, ②the researches of reservoir pore and fluid occurrence mode in pore develop into simulation experiment under real geological conditions, ③the porosity characterization develops from single scale to macro-micro multi-scale integration, ④experimental data mining based on big data develops into capacity evaluation and prediction. All these are expected to provide reference for the development of the shale gas exploration and development technology and theory in China.

SD Oilfield’s progressive exploration and development is getting more and more difficult under low oil price. In order to tap its potential and extend the peripheral trap results, by the means such as: ①fine structural interpretation to identification of low sequence faults, ②strengthen the basic geological researches to deepen the understanding of the main control factors of oil and gas reservoir formation, ③deploy the development and evaluation of wells to improve utilization of single wells, ④combined dynamic and static analyses to rolling expand the oil-bearing area of old area, ⑤comprehensive evaluation of upper and lower layers to reduce the risk of the progressive exploration, two oil-bearing layers and six oil-bearing fault blocks have been added in SD Oilfield during the period from the 12th Five-Year Plan to the 13th Five-Year Plan and the newly added proved reserves are 1 011×10⁴ t, which strongly support the persistent increase of oil production in Sinopec East China Oil and Gas Company and establish the accumulation mode of SD Oilfield. It is clear that the key direction of the progressive exploration are the subsurface reservoir and igneous related reservoir of Daiyi Formation in the future.

The shale gas fields in Southern Sichuan are developed in an integration mode of testing, production and transmission, which has realized the development goals of cost reduction, emission reduction, fast production commissioning and early returns. However, a lot of empirical practices serve as reference of decision-making during implementation of integration practices. There is a lack of general guidance. In order to study the post-frac soaking, the flowback system and the drainage measures, the experiments of overpressured NMR imbibition, permeability stress sensitivity and gas-liquid two phase percolation are conducted, the flow regime and the distribution of pressure profile are simulated, and the discharge and production effect of more than 30 wells in Southern Sichuan shale gas field has been evaluated. The results show that the entry of fracturing fluids into reservoir through imbibition is beneficial to increasing the complexity of shale cracks, and the optimal shut-in time of Southern Sichuan shale gas field is 4~10 days. Meanwhile, a six-staged flowback system is formed, and a post-frac drainage guide chart is established. It is determined that tubing and manual lifting should be implemented when the flow regime changes and the tube should be installed at the well deviation of 70° ~ 85°. Besides, the drainage strategy is also proposed. In general, the research results are of great significance for guiding post-frac production control and drainage technology.

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

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.

In order to find out the formation mechanism and distribution of residual oil after water flooding and tap the potential of residual oil, a parallel pore micro model has been established based on N-S equation. Phase field method has been used to track the phase interface in the process of water flooding. The distribution characteristics of residual oil after water flooding under different wall wetting conditions have been studied. The residual oil after water flooding has been exploited by mobility ratio improved by polymer flooding, interfacial tension changed by surfactant or wettability inversion occurred. And the effects of different mobility ratio and interfacial tension on the micro flow of residual oil in parallel pores after water flooding have been studied. The results show that when the rock surface is water-wet, the residual oil mainly stays in the large pore channels in parallel pores after water flooding. The polymer flooding improving the mobility ratio can effectively displace the residual oil in the pore channels, entirely. When the rock surface is oil-wet, the residual oil after water flooding mainly stays in the wall of parallel pores and small channels. It is difficult to displace the residual oil in the small pore by improving the mobility ratio. However, after changing wettability by surfactant, the residual oil is stretched into oil droplets and congregated, and finally the residual oil saturation is reduced. The lower the mobility ratio or interfacial tension, the higher the oil displacement efficiency. This study reveals the distribution and displacement mechanism of residual oil in parallel pores after water flooding, and provides an important theoretical basis for the effective exploitation of reservoirs by water flooding.

The stimulation of offshore tight sandstone gas reservoirs is influenced by several factors. In order to promote the efficient development of offshore tight sandstone gas reservoirs, volumetric acid fracturing technology of offshore tight sandstone gas reservoirs is studied. And then, considering 3 problems of acid fracturing in sandstone reservoirs, 6 requirements for geology and engineering are put forward. Based on the analysis of reservoir lithological characteristics, brittleness index, stress characteristics and natural fracture development of the offshore gas field, the geological and engineering conditions of sandstone reservoir volume acid pressure are summarized. Aiming at the problems of abnormal high temperature, high breakdown pressure, water lock damage and serious water sensitivity damage, an acid liquid system is developed. The formula was 8 %HCl+5 %SA702+60 %NaBr+1 %WD-12+5 %SA601+1.5 %HJF+10 %ethanol+1 %SA1-1+1 %WD-5B+1.5 %SA1-7. Acid pretreatment can effectively reduce reservoir fracture pressure, and 9.5 MPa is reduced when applied. Volume acid fracturing is reformed by the interlayer temporary plugging steering technology using 1.5 % fibre with the length of 6 mm+0.8 % small particle+1.2 % large particle. The single well increased production ratio was 7.1, and the yield increasing effect was remarkable. This technology can provide theoretical basis and technical support for the development of tight sandstone gas reservoirs.

The lithology, physical property, gas bearing property and other characteristics of shale gas reservoir are obviously different from those of conventional oil and gas reservoir, so the traditional conventional logging technology and the method of log interpretation can not be fully applicable. According to the geological characteristics and logging technology series of Weirong Deep Shale Gas Field, and based on the research on the logging response characteristics and “six-property” relation of the Longmaxi Formation shale reservoir, using core calibration log technique and petrophysical optimization volume model and regression analysis to carry out the research on the logging calculation method of shale reservoir geological and engineering parameters, form the calculation method of shale gas reservoir key parameters and establish the logging identification standard of shale reservoirs. The application shows that the proposed logging evaluation method has achieved good results in the evaluation of Weirong Deep Shale 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.

Deep CBM resources with great potential is an important area of CBM exploration and development in China. After more than 10 years of research and exploration, Sinopec East China Oil & Gas Company has made positive progress in basic geological theory research and low-cost engineering technology research of deep CBM. The first deep coalbed methane field in South Yanchuan put into commercial development in China has been built, the geological theory of "five factors" for coordinated control of deep CBM enrichment and high production has been established, a refined drainage system for deep CBM has been formulated, the low-cost engineering technology of deep CBM has been integrated, many low-cost exploration and development technologies of deep CBM dynamic evaluation and zonal management have been established, the development technology strategy of deep coalbed methane has been basically formed, and an economical and effective mode of exploration and development has been explored. All these above contribute to the realization of the benefit development for deep CBM. However, the exploration and development of deep CBM in China is still in its infancy and exploration stage. In the practice of exploration and development, there are still many challenges, such as theoretical innovation, technological breakthrough, and benefit development. Specifically, ①Deep CBM has strong geological heterogeneity, and the development engineering technology is not fully suitable for the change of unique geological characteristics; ②Some gas wells have short stable production period, rapid decline, and long-term low production effective production; ③The vertical resources need to be further evaluated, and the gas field reserves are not fully utilized. In order to solve the above problems, three countermeasures are put forward: ①innovating and applying the effective scale fracturing technology research under the geological conditions of high stress and low permeability of deep coal seam to achieve the increase of production, cost reduction and efficiency; ②deepening the analysis of the main causes of low efficiency, and taking the removal of blocking and dredging as the direction of governance; ③strengthening the potential evaluation of deep CBM resources and the development technology of applicability so as to improve the development of reserves and maintain the vitality of the gas field.

CO₂ injection for enhanced oil recovery（EOR） has gone though 4 stages of technical improvements in North Jiangsu Basin. During the current low oil price period, three challenges are exiting: the high cost of CO₂ flooding makes it difficult to realize benefit development, the minimum miscible pressure（MMP） is too high to enhance oil recovery substantially, and the heterogeneity is too strong for expanding CO₂ swept volume. Therefore, three main countermeasures is put forward. Firstly, the optimization of scheme is the key. By full advantage of the old wells to reduce investment for new wells, optimization of injection mode to reduce injection volume, use of current equipment to reduce recycling cost, and overall plan for the pipe network to reduce gas cost, the cost of CO₂ flooding is reduced, thus, the equilibrium oil price of 60 % of the CO₂ flooding project will be kept below ＄60/bbl. Secondly, screening and evaluation of additives to reduce MMP are carried out. Meanwhile, the miscible condition was improved and the recovery rate of CO₂ flooding was increased by the injection in advance to increase the formation pressure. Tiredly, the swept volume of CO₂ is improved by means of injection at the high parts, water alternating gas injection（WAG）, and profile modification to mitigate gas channeling. The research and practice offer reference and examples for the beneficial development of CO₂ flooding in similar reservoirs under low oil price.

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.

3D seismic exploration technology with the mode of “Wide-azimuth, high-density and broadband” is widely used in the exploration of conventional and unconventional oil and gas. Technical effectiveness and economy are the two main factors restricting seismic exploration, especially unconventional oil and gas exploration（shale oil and gas, coalbed methane, etc.）, whose economy is the main influencing factor. Taking 3D seismic exploration for the shale gas with normal pressure in Wulong as an example, the successful 3D method of shale gas with low density and economy is introduced, and the purpose of reducing the exploration cost of 3D seismic data and improving the exploration effect is achieved. Combined with the similar conventional 3D seismic exploration examples in Taozidang area, the S/N ratio is evaluated and analyzed emphatically. It is pointed out that the application geological background with relatively simple structure, regional enrichment and strong reflective seismic interface, low density observation system with high cost performance, single shot record with high energy and SNR, and methods of improving S/N ratio and high-precision static correction for seismic exploration are the keys to the success of low density 3D shale gas. The application of deep well and large dosage saturation excitation to ensure the energy and S/N ratio of seismic acquisition data, improve the ratio of effective seismic record ratio, and the method and measure of field management are worthy of reference. Its successful experience has been widely used in 3D seismic exploration in Guihua and Yangchungou.

The adsorption capacity of shale gas is mainly influenced by the factors such as burial depth, mineral composition, temperature and pressure. The shale gas in South Sichuan has the characteristics of large buried depth, high temperature and high pressure. It has great significance to determine the adsorption and desorption characteristics of this kind of shale reservoir in supercritical state for the implementation of gas reservoir production. By the combination of indoor physical simulation experiments and molecular dynamics simulation, the composite characterization model of Illite and Kerogen is constructed and optimized, the multiple prediction model of whole area adsorption capacity of the deep shale gas in South Sichuan is developed, and the adsorption and desorption characteristics of the gas reservoir are clarified. The experimental results show that: with the increase of formation pressure, the adsorption capacity increases gradually, and when the pressure is higher than 15 MPa, the increase of adsorption capacity gradually slows down. Under the original conditions of gas reservoir, the adsorbed gas volume accounts for 20 % ~ 25 % of the total gas volume. When the formation pressure drops to 20 MPa, the recovery degree of free gas is about 70 % ~ 90 %, and the recovery degree of adsorbed gas is about 25 % ~ 40 %.

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

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.

Large scale hydraulic fracturing of horizontal wells is one of the key technologies to realize the effective development of shale gas. The progress of engineering technology provides better conditions for large-scale fracturing of shale gas wells. In recent years, large-scale shale gas horizontal well fracturing has been carried out in southern Pingqiao Block by Sinopec East China Oil and Gas Company, but the correlation between horizontal well engineering parameters and production is not clear. Based on the engineering parameters and gas well production of 31 fractured wells in southern Pingqiao, their sensitivity analysis are carried out by linear regression of the field data. The results show that the drilling encounter rate of long horizontal section and high-quality shale “sweet spot” is the basis for achieving high production of gas wells. With the decrease of fracturing cluster number and fluid strength and the increase of sand strength, the gas well production shows an increasing trend, but the increase of gas well production slows down when the fracturing operation parameters reach a certain extent. Based on the above understanding, the optimal fracturing scale parameters of southern Pingqiao Block are preliminarily defined, which provides the basis for the further parameter optimization and development plan adjustment, and lays the foundation for the effective fracturing and development of shale gas wells in the adjacent areas of southern Pingqiao Block.

Yongchuan deep mountain shale gas block is located in Huayingshan fold belt, which is a low anticline group with broom like spreading to the south. The structural folds are strong and the faults are developed. The target layer of Longmaxi Formation has the characteristics of great difference in burial depth, high ground pressure and ground temperature and large difference in horizontal stress, while the crossing layer has strong abrasiveness, easy instability of well wall and poor drillability. The lack of early geological knowledge leads to low drilling time, long construction period and frequent complex situations, and the fracturing effect of multiple wells is not ideal. In order to solve the main problems faced by Yongchuan work area, researches on the geomechanical parameters, such as drillability, hardness, abrasiveness laboratory experiments, drillability profile establishment, formation three pressure prediction, 3D in-situ stress finite element, simulation and fracture propagation simulation under different horizontal stress difference modes, and horizontal well geological engineering double sweet spot prediction, have been conducted respectively. The results show that the formation drillability level is high, the safe drilling fluid density window is narrow, the difference of in-situ stress direction is large, and the formation of hydraulic fracturing network is affected by high stress difference. Based on the research results of geomechanics, the engineering technology has been adjusted. The drilling speed and fracturing production increase effect are obvious, which has reference significance for the development of deep shale gas in South Sichuan.

Large difference in productivity and unbalanced development of OGIP（original gas in place） are common issues during CBM production. Based on the production history of south Yanchuan coalbed methane reservoir and A-PDA（advanced production data analysis） method, numerical simulation is employed to study the depressuring degree and the distribution of residual gas as well as the development potential considering the sorption and matrix shrinkage effects. The results show that the 300 m×350 m rectangular well pattern cannot effectively utilize the reserves of CBM, and there is a great difference in the recovery degree of OGIP horizontally. The recovery degree in the northwest is low, and the average drainage radius is only 78 m, which is lower than that in the southeast. Through the mathematical model analysis, the residual gas in place in the northwest parts with the area of 2.8 km ² reached 2.53×10 ⁸ m ³, but the recovery degree is only 4.2 %. From the perspective of influencing factors, the typical remaining gas in the study area are mainly undeveloped well control type and imperfect well pattern type. Infilling well pattern or repeated fracturing can be used for undeveloped well control type, the former can make a raise in recovery degree by 9.6 % according to the numerical model, while for the latter, the well pattern needs to be further improved to promote area pressure reduction. The research provides a guild-line for adjustment disposition and measures.

After years of exploration and development integration practice, some achievements have been made in Yongchuan Deep Shale Gas Field. However, there is a big difference in productivity of gas well tests in different structural areas, restricting the scale of reserve increment and benefit development. In order to realize a high-yield and enrichment zone in this area and make clear the direction of exploration and development, the key factors of shale gas enrichment in the deep layer of this area, including thick and stable high-quality shale reservoir, favorable structural style, small scale faults without crush, relatively developed natural fractures, relatively large buried depth and good sealing capacity of roof and floor, are summarized through detailed characterization of structural styles and fault distribution rules, detailed description of reservoir characteristics, and analysis of formation pressure characteristics and production rules. In general, this area has high gas abundance and good resource scale.

By the macro and micro comprehensive research methods of seismic-geological interpretation profile, integrated core, imaging log interpretation（FMI）, thin sections authentication, and argon ion polishing scanning electron microscope, the characteristics, main controlling factors of the properties of the shale of Wufeng Formation-Longmaxi Formation in the Yangchungou structural belt of southeast Chongqing and their influence on shale gas-bearing properties are analyzed. The study shows that there are many fractures such as shear fractures, bedding fractures, slip fractures, cleavage fractures, and shrinkage fractures developing in the shale of Wufeng Formation-Longmaxi Formation in the Yangchungou structural belt. The integrated analysis shows that shale fractures and interlayer sliding fractures there are vertical with middle-high-angle, whereas shear fractures are horizontal with low-angle. Most of the fractures are formed in multiple stages resulting in fracture nets, creases, micro faults and other phenomena. The development and distribution of these fractures are controlled by the tectonic activity, shale mineral composition and mechanical properties, and development of bentonite. Tectonic geology is the external cause of fracture development. The Yangchungou structural belt presents a fault-folding fold structure and is affected by multi-stage tectonic movements. Shear fractures, reticulate fractures, complex fracture network belts, and crumple belts are very developed. Shale mineral composition and mechanical properties are the internal causes of fracture development, controlling the development of micro-fractures and bedding fractures, such as cleavage fractures, intergranular fractures and shrinkage fractures. The Poisson ratio in 1st Longshan member of Yangchungou area is relatively small, the Young’s modulus is large, and the brittleness index is high. All those are good for the formation of various cracks. The more frequently the porphyry in the shale layer is, the closer it is to the main slip surface between the Wufeng Formation and the Linxiang Formation, the more obvious the slip phenomenon is, and the more developed the interlayer slip fractures are. Although the natural fractures in the Yangchungou structural belt are very developed, the preservation conditions have not suffered serious damage, so the shale gas exploration potential is still good in the study area. Drilling revealed that the total gas content of the shale is equivalent to that of the adjacent area, and the total hydrocarbon measured by gas is better than that of the adjacent area. The proportion of free gas is also higher than that of the adjacent area. It indicates that the formation of local structural fractures has expanded the storage space of free gas in shale gas, which is beneficial to the rock gas accumulation.

The normal pressure shale gas reservoir in Southeastern Chongqing is characterized by large horizontal stress difference and high angle fracture development, so that it is difficult to form the complex fracture network and further realize the economic development. In order to solve these problems, key technologies of fracturing in normal pressure shale gas reservoir is studied. Based on the analysis of the fracturing technology of normal pressure shale gas horizontal wells in the Pengshui block, and by drawing on the successful experience of foreign marine shale gas fracturing, the scale of fracturing transformation, continuous sanding process and interim period have been continuously explored and optimized to improve the complexity of fractures and increase the volume of single section reconstruction to form a large-scale complex fracture network. Good results have been achieved in the current application in well-LY2HF and well-JY10HF of daily gas production of 9.6×10⁴ m³ and 16.7×10⁴ m³ respectively, thus realizing the economic development of normal pressure shale gas.