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

In order to study the differences in the adsorption/desorption characteristics of methane between the gelification and fusinization in the bituminous coal, the 2# coal seam of the Haishiwan Coal Mine in Minhe Basin is collected as the research object. By using the Langmuir fitting and dual-site Langmuir fitting on the experimental data of isothermal adsorption/desorption respectively, the adsorption thermodynamic characteristics of different fugacity environments are analyzed by calculating the isosteric adsorption heat, and the influence of maceral difference on coalbed methane production is discussed. The results show that: ①The adsorption of methane on the gelification and fusinization in coal accords with the Langmuir function, and the fitting degree is higher than 0.99. The adsorption capacity of the gelification is much higher than that of the fusinization. ②At the same temperature point, there is desorption lag phenomenon in both granular coal and pillar coal, which is due to the difference of adsorption heat. The fitting results of granular coal experiment are larger than those of lump coal experiment. ③The equivalent adsorption heat increases with the increase of fugacity and decreases with the increase of temperature. The influence of adsorption phase density on the equivalent adsorption heat is greater than that of temperature, leading to the adsorption of methane molecules with greater kinetic energy on the coal surface. The equivalent adsorption heat decreases with the increase of temperature as a whole. ④The adsorption capacity of different components of coal is quite different, and areas with high vitrain content should be the first choice for CBM well location deployment.

The initial formation pressure of coalbed methane（CBM） reservoir is a key parameter used for the evaluation of CBM reserves and productivity, which plays a guiding role in CBM production. Therefore, it is of great significance to accurately calculate the initial reservoir pressure of CBM reservoir. Based on the pressure potential superposition principle of the seepage mechanics theory, the pressure potential model in the process of fracturing and shut in after fracturing is established, and a method for determining the initial reservoir pressure of CBM reservoir is proposed by using the wellhead pressure drop data in the shut-in stage of hydraulically fractured gas well under two conditions: ignoring or considering the fracture network permeability change in the process of fracturing and shut in after fracturing. And then, a field application is carried out. From the fitting results of the case study, it can be seen that the linear relationships for both methods are obvious, indicating that the established methods are effective. From the perspective of interpretation accuracy, the method of considering the fracture network permeability change after fracturing involves more data points in fitting, and the fracture network permeability change during fracturing and after fracturing is an indisputable fact, so the interpretation result by using the method considering the fracture network permeability change is more reliable. If the change process of fracture network permeability of coal formation during shut in after fracturing is ignored, the interpreted stable permeability of fracture network and initial reservoir pressure will be high. Since this method can not only be used to determine the initial reservoir pressure, but also to determine the stable permeability of fracture network after fracturing and evaluate the change trend of fracture network permeability, it provides a basis for the classification of CBM reservoir types, CBM reserve calculation, fracturing effect evaluation, and optimization design of drainage and production system.

In order to reveal the change law of apparent resistivity in the process of CH₄-coal adsorption/desorption of different macroscopic coal petrology compositions, the No.4 coal seam of the Jurassic Yan'an Formation in Dafosi coal mine is taken as the experimental object. By the proximate analysis and apparent resistivity measurement experiments of different coal samples （the durain, vitrain and mixed samples） with different water content （air dry basis sample, natural water absorption sample and samples dried at 378.15 K） of coal, the relationship between the apparent resistivity, methane adsorption and pressures is studied. The experimental results found that when compared to the vitrain, the durain has higher fixed carbon content, but lower ash content and moisture. The initial resistivity of the samples dried at 378.15 K of the durain is the largest. The influence of the adsorption of methane on the resistivity of the coal body is manifested in that with the adsorption of methane, the apparent resistivity of coal is significantly reduced. During the pressure increasing process that is the process of adsorption, the coal resistivity has a quadratic function relationship with the pressure and the amount of adsorption. The reason is that methane adsorption heat release, coal body expansion, and the spread of water on the inner wall of the pore throat causes the apparent resistivity to decrease. Due to methane adsorption, gas-water replacement occurs on the surface of the coal matrix, free water dissolves soluble minerals, and the ion concentration increases. In the process of adsorption, the apparent resistivity of coal decreases, but due to the limited soluble minerals and the hydrophobicity of coal, the resistivity of coal tends to be stable in the later stage of adsorption. During the depressurization process, that is the process of desorption, since the shrinkage of the coal matrix after expansion is irreversible （deformation）, the apparent resistivity of the coal body cannot be restored to its initial value. Compared to the durain, the pore connectivity of vitrain is poor, but the pore throat curvature is larger, when the number of charged particles in the double electric layer is high and aggregated in piles. This eventually leads to better electrical conductivity of vitrain than durain under the same conditions, i.e., the apparent resistivity of vitrain is smaller than that of durain.

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

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

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

Based on the theory of phase field method, a model of fracture propagation in porous elastic formation is established. In the proposed model, the fluid flow in the porous rock obeys Darcy’s seepage law, and the permeability of rock is anisotropic and a function of the maximum principal strain. The convergence of the model is verified by comparing the results of three different time steps cases. Meanwhile, based on the proposed model, the effects of the in-situ stress difference, intersection angle, injection rate, and fracturing fluid viscosity on the intersection behaviour of hydraulic and natural fractures are investigated. The results indicate that: ① The hydraulic fracturing can solely make one side of the natural fracture open; ② The smaller the intersection angle and in-situ stress difference, the easier the hydraulic fracture is to open the natural fracture; ③ Increasing injection rate is beneficial to completely open the natural fractures, therefore, in the process of fracturing construction, the construction displacement should be increased as much as possible under the conditions of wellhead equipment and underground string strength; ④ The injection pressure increases with the increase of injection rate and fluid viscosity. Finally, the reliability of this model is verified by comparing the simulation results of this model with those of previous laboratory experiments.

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

In the production process, part of the wells in southern Yanchuan CBM Field has the plugging characteristics of abnormal and rapid decline of gas production and liquid production. In order to analyze the causes of blockage, based on the changes of the production dynamic information of the liquid recovery, water quality and pump check of wells, the main cause of plugging is clarified, including scaling and pulverized coal. On the basis of analyzing the formation mechanism of scaling and pulverized coal blockage, the targeted prevention and treatment measures are carried out. For the scaling plugging wells, form a treatment measure combining the normal prevention by adding scale inhibitor and the plugging removal by multi-stage pulse shock wave. 16 wells implemented by multi-stage pulse shock wave have got a good production increase with an average production increase of 30.11×10⁴ m³ per well. For the pulverized coal plugging wells, coal-carrying process by self-circulation and hollow rod well washing, and nitrogen foam well-unblocking treatment measures are formed. Well washing for carrying pulverized coal effectively alleviate the pump check caused by pulverized coal blocking pump, the gas well repair free period extended by 60 %. Four wells applied the nitrogen foam for unblocking achieve significant production increase, with an average daily production increase of 1.25×10⁴ m³ per well. The results provide references for the cause analysis and treatment of blocked CBM wells.

The coal reservoir in Fukang mining area of Xinjiang has different characteristics of large inclination angle, large thickness, multiple coal seams and complex structure, and the development progress of coalbed methane（CBM） in the mining area is slow. It is urgent to find a suitable integrated development technology for CBM geology engineering conditions to provide strong guidance for the development of CBM in Xinjiang. The dual-tubing screen completion technology integrates the completion and stimulation, and has promoted and applied more than 400 CBM horizontal wells in the Qinshui Basin. The dual-tubing screen completion technology has increased the production of CBM horizontal wells from four aspects, such as hydraulic impact, carrying pulverized coal, chemical gel breaking of drilling fluid, and stress permeation, so as to help the efficient development of CBM in Fukang mining area. Based on the technical characteristics of dual-tubing screen completion, the applicability and mechanism of this technology for the development of CBM in Fukang mining area is discussed from four advantages: reservoir coal body structure, reservoir permeability recovery, reservoir pore fracture expansion, and reservoir structure, and has guiding and reference significance for the efficient development of CBM under similar reservoir geological conditions in Xinjiang.

Finding out the hydrogeological conditions and it’s controlling gas effects of CBM（coalbed methane） development area is important, which can provide a foundation for further development well location deployment. Taking the No.15 coal seam of Songta Block in Shouyang area as a research object, the conventional ion of the produced water in 11 coalbed methane wells has been tested, and the mineralization and ion distribution characteristics of the produced water are obtained. According to the Sulin classification, the types of produced water are divided. And according to the dynamic liquid level height at the initial stage of drainage of coalbed methane wells and combined with the elevation of coalbed floor, the equivalent water level of each coalbed methane well is calculated. On this basis, the hydrodynamic field in studying area are divided into stagnant area, weak runoff area and runoff area. Meanwhile, the controlling gas effects of hydrogeological parameters on gas content of No.15 coal seam are analyzed from the aspects of perspective of hydrochemistry and hydrodynamics. The results show that the main types of water quality in the studying area are NaHCO₃ and CaCl₂. The runoff area, weak runoff area and stagnant area are successively distributed from north to south. For some areas, when the sodium chloride coefficient is less than 1.04, the desulfation coefficient is less than 0.12, and the carbonate balance coefficient is less than 10.39, the gas content is more than 12 m³/t. These areas are beneficiation areas in coalbed methane. The hydrodynamic conditions of hydrodynamic sealing type and hydrodynamic plugging type are conducive to the enrichment of coalbed methane. The hydraulic escape type leads to the decrease of coalbed methane gas content. The research results provide a reference for the optimization, exploration and development of CBM enrichment areas in the study area.

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

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

In order to solve the difficulties in prediction of high-quality reservoirs in low-permeability V Oil Formation of Es₃ sub member in Block A, the residual velocity analysis, flattening and denoising of prestack gather data are carried out to improve the quality of data. Subsequently, well logging formation evaluation, petrophysical modeling and elastic curve forward modeling are carried out, lithology and physical property sensitive parameters are optimized, and it is clear that the combined application of two elastic parameters of speed ratio of P and S waves（V_p/V_s） and vertical wave impedance（C_PIMP） could identify high-quality reservoirs. Then, the prestack inversion data preparation, facies control scheme design, well free simulation constant variation and variable range optimization are carried out, and a set of comprehensive prediction method for high-quality reservoirs in low-permeability reservoirs based on facies controlled pre stack geostatistics inversion is established. The inversion results obtained by this method not only improve the accuracy of reservoir prediction, but also are more in line with the geological law. The prediction results can effectively reflect the distribution of high-quality reservoirs in low-permeability reservoirs. Two horizontal wells have been deployed and good application results have been achieved.

The progress of rheological testing methods has promoted the researchers' understanding of viscoelastic fluids in a wider testing range. The polymer solution used for oil displacement has the characteristics of “Three-stage” rheological curve （zero shear section, shear thinning section, and ultimate shear section）, so a more accurate description model and limiting conditions are extremely needed. Taking partially hydrolyzed polyacrylamide and hydrophobically associating polymer as the research objects, the rheological curves in a wide range （0.01 ~ 10 000 s^-1） have been analyzed, and the changes of viscoelastic modulus have been studied. The results show that under the experimental conditions, the rheological curves of the two polymers can be described by Carreau rheological model. The structural viscosity formed by hydrophobic association greatly enhances the elasticity of the solution, and makes the elastic modulus of the polymer P-P4 dominant. Considering the influence of elastic characteristics on the rheological curve, the relaxation time spectrum derived from the experimental data of small amplitude oscillation is used to limit the characteristic relaxation time（λ）. Finally, the experimental data are highly matched by the nonlinear regression fitting curve of Carreau rheological model. When studying the rheological constitutive equation of viscoelastic solution, it is necessary to fully consider the solution characteristics, establish the relationship between different test parameters, and establish reasonable limiting conditions, which are effective means to optimize and improve the rheological constitutive equation of viscoelastic fluid.

Shale oil in the fourth member of Shahejie Formation in Dongying Depression has advantages such as large resource, thick reservoir, high formation pressure coefficient, and developed natural fractures and micro-fractures. However, that it is affected by unfavorable factors such as burial depth, development of faults and high formation temperature leads to high fracturing cost, rapid decline and poor economic benefit. In order to overcome the problems such as the narrow pressure fracture width and the difficulties during sand addition in the fracturing of the continental shale oil reservoir by the conventional fracturing technology, and promote the production of shale oil in the fourth member of Shahejie Formation, the on-site tests are conducted in Well-G17-X10 of Niuzhuang Sag with the performance of the self-suspension and self-reducing resistance properties of the self-suspension proppant and combined with complex network fracturing technology. The results show that compared with the adjacent well, Well-GX26, Well-G17-X10 not only has lower fracturing difficulty, double sand ratio and less liquid reduced by 30 %, but also has 520 days of self-injection production period, which is 436 % of that of Well-GX26, and 2 482 t of oil production period, which is 344 % of 722 t of Well-GX26. This achievement verifies the unique advantages of self-suspension proppant in improving effective suspension of fractures and increasing seepage volume of oil wells. It not only successfully explores a new fracturing stimulation technology, but also broadens the technical idea of shale oil efficient production.

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

He-1 reservoir of Dongsheng Gas Field is a bottom water gas reservoir. Fractures are easy to communicate with the bottom water layer, resulting in rapid bottom water coning and there is no productivity after water flooding of gas wells. It is difficult to get effective production. Combined the research and development of water-consolidated proppant with the secondary sanding and high-pressure fracture control technology, the artificial shelter layer is formed at the bottom of the fracture, which effectively prevents the rise of gas-water interface while controlling the fracture height, improves the gas-water permeability ratio, reduces the flow resistance in the fracture, delays the water breakthrough cycle of gas wells, and realizes the economic and effective development of tight low permeability bottom water gas reservoirs. The water-contorl secondary sanding fracturing technology has been applied in ten wells of the bottom water gas reservoir in He-1 Member of Dongsheng Gas Field. The construction efficiency is 90 %. Compared with the adjacent wells fractured by the conventional means, the water production of the application wells is increased by 60 %, the liquid-gas ratio is decreased by 31.7 %, and the measured open flow capacity of Well-JP58-A is 20.4×10⁴ m³/d, which has achieved good water control effect while increase fracturing production.