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

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

Shale gas reservoir is an “artificial reservoir” with complex flow mechanism and many factors affecting well productivity. The key to develop the shale gas field in a scientific and efficient way is to determine the factors influencing gas well productivity and further establish productivity evaluation model. Based on the geological background and fracturing effect of shale wells in the Jiaoshiba Block, Fuling Gas Field, the factors influencing the productivity of multi-stage fractured horizontal shale gas wells are systematically analyzed. Then, the radar chart and fuzzy analytic hierarchy process （FAHP） are used to analyze the eight main factors affecting the productivity. Results show that there are obvious differences in terms of the degree various factors influencing on well productivity in different regions. Specifically, since the reservoir physical properties in the northern of the main area and western areas are favorable, the horizontal section parameters and fracturing scale are the main control factors of gas well productivity; the productivity of gas wells in the eastern area is highly related to the preservation conditions; due to the increase of buried depth in the south of the main area, the compressibility parameters and fracturing scale jointly determine the gas well productivity. In contrast, the compressibility parameters of gas wells in the southwest of the Jiaoshiba are the controlling factor. In this paper, fuzzy analytic hierarchy process （FAHP） is applied to determine the weight of various factors affecting productivity in different areas, and then a comprehensive productivity evaluation model suitable for shale gas wells is established. The results of numerical simulation and practical application show that the gas well productivity predicted by fuzzy comprehensive evaluation model is applicable to the infill wells in the Jiaoshiba Block, and the model is effective to analyze and predict the productivity and development effect of shale gas well.

By using the experimental test data such as the total organic carbon content（TOC） and porosity and the drilling and testing data of horizontal wells, the researches on the source-reservoir coupling relationship of marine shale reservoirs in Nanchuan district and the reasons for typical high and low field wells have been carried out. The researches show that the shale organic matter and storage space are closely connected and interdependent, forming a complex source-reservoir coupling relationship between each other. The TOC（the source） and the porosity（the reservoir） are the key parameters to characterize the source-reservoir configuration types. There are 12 categories, including high-carbon with high-porosity, medium-carbon with medium-porosity, and low-carbon with low-porosity, for the semi-quantitative evaluation. By introducing this new method of source-reservoir classification, the evaluation criteria of source-reservoir configuration for Ⅰ, Ⅱ and Ⅲ shale reservoirs of Wufeng-Longmaxi Formation in the study area are established. Combining the source-reservoir configuration evaluation and gas test production analysis of 8 horizontal wells with similar mining technology in the study area, it is shown that the larger the proportion of class Ⅰ source reservoir configuration in horizontal wells, the higher the fracturing gas test production. The new source-reservoir classification method is a practical tool for geological evaluation and post-compression productivity analysis of shale gas wells, and has the popularization significance.

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

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

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

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

In order to characterize the micro pore structure of Shahezi Formation shale in Songliao Basin, nine shale samples from the lower part of the Shahezi Formation in the Songliao Basin were selected to carry out NMR T₂ tests in saturated and dry conditions, and simultaneous petrophysical testing with field emission scanning electron microscope observation. The T₂ relaxation characteristics, pore types and distribution characteristics were systematically analyzed. And the difference of porosity measured by the NMR method and the gas method was compared. The results show that the NMR T₂ spectrum of the shale samples from the Shahezi Formation is dominated by a single peak type with shorter relaxation time, and the pore diameter is mainly distributed in the range of 10~1 000 nm. The pore types are mainly nano-scale inorganic pores, and the organic pores and microfracture generally underdeveloped. The NMR porosity calculated after deducting the base signal is 0.68 %~3.66 %, which has a good matching relationship with Helium porosity. The samples with smaller porosity are more likely to be affected by the background signal of rock matrix, resulting in the relative error of test results. In generally, the nuclear magnetic resonance technology can accurately analyze the porosity and pore size distribution of low porosity and low permeability shale samples, but attention should be paid to the NMR signal interference caused by organic matter and clay mineral bound water.

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

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

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

The vertical depth of Weirong deep shale gas reaches 3 800 m, and the formation collapse pressure coefficient is above 1.95. The ultra-long horizontal wells in the region are increasing year by year, and the ultra-long horizontal wells have become an important development means for stable production in the later stage of the gas field. Based on the research of rotary steerable drilling method, the hydraulic open-hole evaluation model and Landmark software are used to comprehensively analyze the influencing factors of geological parameters, trajectory profile, drill string mechanics, hydraulic parameters and surface equipment. The extension limits of the ultra-long horizontal section were different under different rig conditions and working conditions. The optimized profile type is beneficial to prevent collision between wells and safe running of pipe string. The stress intensity of the drill string in 3D trajectory profile is twice that of 2D trajectory profile, and both the density and viscosity of drilling fluid will affect the extension of ultra-long horizontal section. The evaluation results show that the theoretical limit of open hole horizontal section is 5 840 m without considering the drilling capacity, while the maximum horizontal section extension of 70 drilling rig is 3 500 m due to the drilling depth limit. The larger the pump displacement, the lower the drilling fluid density, and the longer the elongation capacity.

At present, the hydraulic fracturing is a key technology for shale oil and gas exploitation. The natural fractures will be encountered in the process of compression fracture propagation, and the propagation characteristics of compression fractures after the encounter of natural fractures have a significant impact on the formation of compression fracture network, thus affecting the final fracturing effect. Therefore, it is necessary to conduct the researches on the encounter of compression fractures with natural fractures. Based on the ABAQUS software, the intersecting process of two-dimensional hydraulic fracture and natural fracture under the condition of interlayer effect is simulated, by considering the fracture propagation form and tensile failure. Meanwhile, the influences of different stress differences, intersecting angles, stress differences of reservoir isolation and strength differences of reservoir on hydraulic fracture behavior are considered. The simulation results show that the fracture degree and opening effect are better under the interlayer effect, and the opening effect of natural fracture is worse with the increase of stress difference until the hydraulic fracture passes through the natural fracture. When the intersection angle is small, the interlayer effect has no effect on the fracture propagation path, and only the upper part of the natural fracture is opened, but the opening degree of the fracture is better. With the increase of the intersection angle, the opening effect of the natural fracture is better. When the intersection angle is 90°, the hydraulic fracture directly passes through the natural fracture. With the increase of interlayer stress difference, pore pressure at the intersection point increases, and the opening effect of natural fractures is better. When the interlayer stress difference exceeds a certain value, hydraulic fractures will pass through natural fractures. The larger the elastic modulus difference between reservoirs, and the stronger the formation resistance to disturbance, the larger the pore pressure at the intersection point will be, which determines the propagation behavior of fractures. When the elastic modulus difference between reservoirs is small or large, the opening effect of natural fractures is better.

At the early stage of production, deep shale gas wells in southern Sichuan have sufficient energy. Most of the wells use casing to discharge fluid quickly. When the wellhead pressure drops to the capacity of the pressurized operation or the gas well is difficult to carry fluid, tubing production is run. The tubing installation time typically depends on the wellhead pressure drawdown to the capability of the snubbing unit or the onset time of liquid loading. Tubing depth and diameter are commonly determined based on the production progress according to operators’ field experience. So far, the influence between the tubing installation time and gas well deliverability is still unclear. Based on the well performance monitoring data of 53 times of deep shale gas wells in Southern Sichuan at the casing production stage, the calculation model of wellbore pressure drop and the variation law of wellbore flow pattern are analyzed, besides, the bottom hole flow pressure and critical liquid carrying capacity is also determined the best running time of tubing. In this work, the variation of wellbore pressure drop under different tubing depth is analyzed, and a method to determine the optimal tubing running depth is proposed by aiming at minimizing wellbore pressure drop. Finally, the optimal string size is obtained, and field verification is carried out based on the sensitivity analysis of liquid carrying and pressure loss. The results suggested that the optimum tubing installation time is when wellhead pressure drops to 15~25 MPa. The proper tubing depth is at 70° to 85° of well deviation and the suitable tubing inner diameter is 62 mm. By running tubing in time, the pressure drop rate of the gas well is reduced by 50 %, and the unit pressure drop production is increased by twice times, which effectively guides the tubing design and implementation of deep shale gas horizontal wells in Southern Sichuan.

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