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.

In order to evaluate the CBM exploration potential of Hongguo Block, the basic geological conditions for the enrichment of CBM reservoirs were analyzed from the aspects such as stratigraphic distribution, coal quality, physical characteristics, gas-bearing capacity and preservation conditions by the data of coal drilling and CBM wells. And then the resource potential of CBM was preliminarily accessed. Finally, the favorable gas-rich areas were further optimized. Results show that coal bed in Hongguo Block has the characteristics of moderate burial depth（500~1 200 m）, large accumulated thickness（10.3~25.8 m）, moderate thermal maturity（0.9 %~2.0 %） and high gas content（10.8~26.3 m ³/t）, with superior geological conditions of CBM accumulation. By the comprehensive evaluation, the favorable CBM area is about 260 km ² and the amount of resource is about 422×10 ⁸ m ³. The most favorable area type I₁ is located in the east of Panguan syncline, with high thermal evolution degree, developed cleavage and fissure, high pressure coefficient, and superior preservation conditions, which is the primary target area for the next CBM exploration.

In order to study the difference in adsorption/desorption characteristics and the desorption hysteresis of CH₄ in different coal ranks, low, medium, and high coal rank samples are collected for the experiments of micro-component determination, liquid nitrogen adsorption, and isothermal adsorption/desorption to systematically analyze the composition, pore structure, differences in adsorption/desorption characteristics and desorption hysteresis effects of different coal rank sample materials. Combined with the calculation results of methane adsorption heat, the mechanism of coalbed methane desorption hysteresis from the energy perspective is discussed. The results show that: ①The reflectance R_o,max of the vitrinite group of coal samples are 0.43 %, 1.26 %, and 3.27 %, respectively. Low-rank coal samples have low vitrinite group content, high inert matter group content, high volatile content and fixed carbon. Medium-rank and high-rank samples are reversed. The degree of coal metamorphism increases. Porosity, BET specific surface area, BJH total pore volume, and fractal dimension D₂ change in a “V” shape, and D₁ changes in an inverted “V” shape. ②Under isothermal condition, the residual adsorption amount becomes larger as the coal rank rises, and the desorption becomes more difficult. As the temperature rises, the residual adsorption capacity increases first and then decreases. With 40 ℃ as the inflection point, the temperature influences both the degree of activation of gas molecules and the pore structure of coal. ③When the pressure is the same, the higher the coal rank, the faster the methane adsorption rate at the low-pressure stage（p<4 MPa）, the adsorption capacity increases rapidly at the high-pressure stage（p>4 MPa）, and the adsorption capacity does not increase significantly. ④For the three coal samples, DFS4 ^#, SGZ11 ^#, and SH3 ^#, in the desorption process, their isosteric heat of adsorption are all greater than that in the adsorption process, indicating that the desorption process needs to continuously absorb heat from outside. Therefore, the methane in the adsorption state needs to absorb energy from the external environment, and the energy difference between the adsorption and desorption processes will cause desorption hysteresis. The methane in the free state enters into the micropores due to high pressure, resulting in the expansion and deformation of coal matrix, changes in pore structure, limit of methane desorption, and finally a desorption hysteresis effect.

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.

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.

In order to explore the influence of proppant settlement on the laying form of sand in coal seam cracks, the physical simulation is used to study the rules of proppant settlement and migration based on the previous researches. The visual physical simulation device of proppant transportation can directly and conveniently simulate the proppant placement in the fractures. Fully considering the in-site fracturing construction and the similarity of Reynolds number, the experiment for the influence of single factor change on the sand laying form of proppant is designed. The equilibrium height and time are used as the characterization parameters. In the early stage, the proppant settlement and migration rules of different pump injection displacement, sand ratio and proppant particle sizes are quantitatively analyzed by single crack. In the later stage, a branch crack is added to analyze the rules of proppant settlement and migration in the main crack and branch crack under the condition of different particle sizes of proppant. The results show that the smaller the pump displacement is, the higher the equilibrium height of sand dike will be if the sand ratio and particle size are larger and larger, and the longer the equilibrium time will be if the sand ratio and particle size are smaller and smaller; the distribution rule of branch crack is similar to that of main crack, the equilibrium height is lower than that of main fracture, and the equilibrium time is longer.

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

The difficulty of SEC reserve assessment of CBM is: ①the yield change of CBM is different from conventional oil and gas; ②there are differences in the development rules of CBM with different coal ranks. The research shows that deep high-rank and shallow low-rank CBM vary greatly in the evaluation parameters: the shallow low-rank CBM in the Powder River Basin shows the characteristics of quickly entering of high yield period, high peak yield and large production decline, while the high-rank coal seam gas in the deep parts of South Yanchuan are characterized by longer drainage time, low peak yield and low decline. The three types and four sub-classes of the “three-segment” yield forecasting model are summarized. For type I, a complete three-stage forecast is adopted. The yield time is 28 months, the stable production output is 850 m ³/d with the cycle for one year, and the decline rate is 25 %. For the IIa subcategory whose production has exceeded the capped production and is stable at present, or the IIb sub-class whose discharge time is long and the current production of which is stable, although the production hasn’t reached the capped production, two-stage forecast is adopted, the stable production period is half a year, and the decline rate is 25 %. For the IIIa subcategory whose production has exceeded the capped production and the production is declining at present, or the IIIb sub-category whose overall production is on the rise but goes down before the base date of assets evaluation, single-stage forecast is adopted, and the decline rate is 25 %. The error between the self-assessment result and the external assessment result by using this method and the assessment parameters is ±10 %, which proves that this method and the assessment parameters are suitable for the SEC reserve assessment of deep and high-order coalbed methane in south Yanchuan.

The damage of coal-rock reservoir completion fluid and the easy collapse of horizontal wells are the main factors limiting the output of coalbed methane horizontal wells in Qinshui area. In terms of the resulting problems of low horizontal well production and production reduction, the integrated technology of dual-tubing screen completion and production increasing is used to solve the problems of damage to coal seam caused by completion fluid of horizontal wells of coalbed methane and the instability of open hole wall of coal seam. Therefore, one-trip drilling of completion and flushing operation is realized, the output of single CBM well is improved, and the stable production cycle of a CBM well is extended. The dual tubing completion structure of a horizontal CBM well consists of an outer screen system and an inner flushing system. The outer screen system can realize the long time support of the shaft wall and prevent the collapse, while the inner flushing system can establish the completion fluid circulation channel, realize the function of hydraulic jet, pollution prevention, sand flushing and well cleaning, reduce the resistance encountered of screen pipe entering, and improve the success rate of screen pipe entering in just one-time. This process is the main method to develop horizontal wells in Qinshui CBM Block. A series of screen pipes and supporting tools with an outer diameter of 73 mm, 89 mm and 110 mm have been developed, and this technology has been popularized and applied in 331 horizontal CBM wells. Compared with the open-hole horizontal wells developed in the year before 2014, the stable production cycle of the screen completion horizontal wells is increased by more than 5 times, and the single well production of the horizontal wells of 15# coal seam has exceeded 1 000 m ³ to the fundamentally solve technical difficulties in development. A new efficient development mode suitable for the horizontal wells in the refreshing water coalbed methane block is formed.

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.

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.

In order to quantitatively evaluate the fracturing effect of hydraulic fracturing by voltage pulse on coal rocks, and determine that whether the technology is suitable for the voltage and water pressure loading in engineering practice or not, the voltage pulse hydraulic fracturing ultrasonic testing test is designed, the fracturing effect of this technique on coal rocks under different loading conditions is quantitatively characterized by the numerical calculation from damage variables and crack propagation width, and its advantages compared to the operation of hydrostatic fracturing merely is evaluated. The conclusions are as follows: ①Due to the fluctuation of load fluid electrical pressure, the damage degree around the borehole is the most serious, reducing with the decreases of the fluctuating pressure. ②The damage variables and crack width are positively correlated with the loading voltage, which increase with the increase of voltage. ③The fracturing effect of hydraulic fracturing by voltage pulse on coal is quantitatively analyzed from damage variable and crack width, which can provide reference for coalbed methane.

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.

At present, the clean quartz sand is used in the fracturing of southern Yanchuan CBM wells. According to the production effect in the early stage, the limited length of supporting seam generated by the clean quartz sand fracturing leads to the difficulty of adding sand in the construction, and the gas production effect in the later stage is not ideal. In order to solve this problem, laboratory experiments have been conducted to compare and evaluate the crushing and fracture conductivity of conventional quartz sand proppant and low-density nut shell proppant under different closing pressures. The experimental results show that the fracturing rates of both can meet the engineering requirements. Under high closure stress（35 MPa）, they have similar fracture conductivity. However, low-density nut shell proppant is cheaper than traditional quartz sand. Therefore, low-density nut shell proppant is more able to meet the current goal of cost reduction and production increase. The field test of this technology has obtained good results.

After years of development, some wells in South Yanchuan coalbed methane field have entered the decline period, and the daily liquid production of most wells has gradually decreased. Therefore, it is about to face the impact of intermittent pumping on productivity and production management. By studying the seepage mechanism of CBM, the non-destructive intelligent intermittent pumping technology is adopted for low-yield liquid wells with different well conditions. Considering such factors as downhole pressure gauge, peak and valley electricity price of municipal electricity, depth of downhole pocket, safety risk of remote pumping unit and so on, the implementation of unattended intermittent pumping without affecting the stable production of gas wells reduces the intensity of drainage and production well management, improves the efficiency of fine management, and has higher popularization value.

It is of great significance to clarify the formation mechanism of carbonate cementation and its influence on reservoir physical properties. By means of petrology and geochemistry, the occurrence characteristics and formation mechanism of carbonate cements in Cegai slope of Junggar Basin are analyzed. The results show that the distribution range of δ ¹³C_PDB value is -29.6 ‰~6.7 ‰, that of δ ¹⁸O_PDB value is -12.5 ‰~19.2 ‰, and it has a large span. All those indicate the material source of carbonate cementation and the complexity of water-rock interaction. δ ¹³C_PDB value has a positive offset with the typical marine or lacustrine phase of carbonate, while δ ¹⁸O_PDB value has the negative offset. The positive offset of δ ¹³C_PDB value is mainly affected by the carbon isotope fractionation of mixed hydrothermal fluid and the dissolution of a small amount of sedimentary carbonate. The negative deviation of δ ¹⁸O_PDB value may be caused by the mixing of various fluids—such as precipitation and deep hydrothermal—and the rise of diagenetic temperature. The material source of carbonate cements in Che-Guai slope is related to the CO₂ produced by the decarboxylation of organic acids, compaction and drainage of clay minerals, the dissolution of feldspar debris and the release of a large amount of plasma like Ca ²⁺, Fe ³⁺ and Mg ²⁺ by conversion among clay minerals. Under the microscope, it is found that the carbonate cements are metasomatic to detrital particles and accompanied by asphaltene appearance, and appear in the form of crystal powder to macrocrystalline grain among the closely arranged clastic particles, as a product of late diagenetic stage, which destroy the physical properties of reservoirs.

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.

In order to deeply analyze the thermal oxidation behavior of crude oil during air injection process in reservoir and further develop air injection enhance oil recovery technology, the TG/DTG-DTA analysis methods were used for study. Based on the classical Arrhenius kinetic model, the effects of oil chemical composition and reservoir rock on the oxidation activity of tested samples were quantitatively characterized. Crude oil undergoes three completely different chemical reactions during the whole heating process: low-temperature oxidation, fuel deposition and high-temperature oxidation. The oxidation of crude oil at low temperature shows a certain endothermic phenomena. Because of different hydrocarbon composition, crude oil with three samples added show different mass loss rates in each reaction area. Compared with that only contains crude oil, the addition of reservoir rocks reduces the activation energy of low temperature and high temperature oxidation. Researches show that: the higher the content of heavier components, the quicker the reaction of crude oil in LTO stage, the more fuel is deposited, and the higher the heat released from the combustion in HTO stage. The activation energy of crude oil in the high temperature stage is greater than that in the low temperature stage. High content of heavy components make the activation energy of oxidation reaction increase. The catalytic properties and specific surface area of reservoir rock reduce the activation energy of crude oil, playing an important role in the heterogeneous catalytic oxidation.

Bohai LD5-2 heavy oil reservoir has strong heterogeneity and low rock cementation strength. It has formed a dominant channel due to long-term water injection. At present, it is difficult to meet the requirements of greatly improving oil recovery by single profile control, flooding or oil displacement measures. The combined use of profile control, displacement and other measures has become a new way to solve this bottleneck. In order to meet the actual demands of LD5-2 reservoir, in-room experimental study of profile modification measure of “profile control+profile modify+oil displacement” is carried out by the longitudinal three-layer heterogeneous core and a new model of “injection and production separately” and the means of electrode measurement. The results show that, compared with the vertical well network, the hydraulic pressure difference of the mid-low permeability layer is larger after the horizontal well network profile adjustment, the effect of expanding the spreading volume is better, and the recovery rate increases by 28.50 %. For the heterogeneous cores, the remaining oil in the longitudinal direction is mainly distributed in the mid-low permeability layers. On the plane, the vertical well pattern is mainly distributed in the two wings away from the main stream line, while the horizontal well network oil-water interface is parallel to the well trajectory. The composite gel in the slug combination of “composite gel+microsphere/high efficiency oil displacing agent” has a strong retention effect in the high permeability layers. The liquid flow steering effect is better, which makes the synergistic effect in the subsequent “microsphere/high efficiency oil displacing agent” composite system better. It takes into account the technical requirements of expanding the volume and improving the washing efficiency, and the effect of increasing oil and precipitation is obvious, with the increase of recovery rate by 26.50 %. Profile modification is the key to increase oil recovery greatly.

In view of the low desulfurization efficiency of stripper, limitation of positive pressure stripping technology and great optimization space in Yuanba gas field, a new process of negative pressure stripper desulfurization is carried out, and the influencing factors of stripper efficiency are analyzed in depth. By parameter optimization, the optimal pH value is 4.0~5.0, the recommended stripper pressure is -30~-25 kPa, the optimal gas-liquid ratio is 8~12, and the liquid inlet volume is 7~9 m ³/h, which is conducive to improving the stripper efficiency. The field application shows that the efficiency of negative pressure stripping is 96.28 %, 19.68 % higher than that of positive pressure stripping. The annual cost saving is about 1 808 600 yuan, which has significant effect on cost reduction and benefits enhancement. The new process of negative pressure stripping desulfurization shows obvious technical advantages and good application prospects, and also provides certain reference for the field application of similar marine high sulfur gas fields.

Jinma-Yazihe area is located at the junction of Longmenshan fold-thrust belt and Sichuan basin. Based on the 3D seismic data, the characteristics of faults and the process of tectonic evolution are analyzed. The Bailuchang fault developed in the lower wall of Guankou fault can be regarded as its pre-existing fault, and the formed structural wedge causes local thickening of the lower wall. The shrinkage degree of the Guankou fault in the southeast direction is becoming smaller and smaller, which generally shows the vertical superimposed structural combination of stratified slip faults controlled by double slip layers. Pengxian fault is composed of several faults with a large fault distance in the middle part, which can be used as an indication of local tectonic stress transformation or concentration. The main faults in the Jinma-Yazihe area started in the early Indosinian period, continued to deform in the late Indosinian movement and strongly moved in the Yanshanian period. The Guankou and Pengxian faults thrusted strongly in the Yanshanian period, and continued to deform from the Himalayan to the neotectonic period, resulting in strike-slip and affecting the surface. Structural activities are closely related to hydrocarbon accumulation and contribute to the formation of structural traps, reservoir transformation, hydrocarbon migration and accumulation.