There are broad prospects of CO₂ flooding for enhancing oil recovery and greenhouse gas storage. In this paper, we reviewed the development history and brief situation of CO₂ flooding at home and abroad, analyzed the development status of CO₂ immiscible flooding and CO₂ huff and puff, and summarized the phase state of CO₂ flooding, oil displacement mechanism evaluation and optimization design technology of CO₂ flooding reservoir engineering. The design focused on improving oil displacement efficiency and sweep efficiency, controlling viscosity index and gas breakthrough, achieving miscible or near-miscible flooding, and optimizing well pattern and injection parameters in combination with reservoir characteristics. It was pointed out that CO₂ near-miscible flooding and increasing sweep volume were the development trends of CO₂ flooding. WAG, foam flooding, fracture sealing and local gravity flooding were important means to prevent gas channeling. On the basis of summarizing the current CO₂ flooding technology and field experience at home and abroad, the top-level design of combination of CO₂ flooding and CO₂ geological storage should be done according to different types of reservoir characteristics.

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.

Shale oil resources are rich around the world and have extraordinary exploitation prospects. However, drilling horizontal wells and huge amounts of hydraulic fracturing measures had sharply increased the cost. A large number of experiments and numerical simulations showed that the gas injection could significantly improve the shale oil recovery. Nevertheless, this technique had not been implemented to the practical exploitation of shale oil. Consequently, it was still controversial whether shale oil recovery could be optimized through gas injection or not. By the comparison of the gas displacement experiments of the shale cores, the numerical simulation of shale oil recovery by gas injection and the gas injection pilots in practical fields, it was found that the results from experimental conditions and numerical simulation models were different from those in field pilots. Li Chuanliang insisted that the shale reservoir was consisted of myriad micro-lithologic traps. It was concluded that only if the gas was injected after fracturing, or establishing an orthogonal horizontal well pattern to dense the well spacing, would the shale oil recovery be improved. It has essential guidance for the improvement of shale oil recovery in China or even in the world.

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.

The greenhouse effect caused by excessive CO₂ emissions has led to many adverse effects on human life. As an effective CO₂ disposal technology, CO₂ geological storage technology has aroused more and more attention. The solubility of CO₂ in simulated deep saline solution and its variation with burial depth（800~2 800 m）were studied. The results showed that, when the buried depth was in the range of 800~1 700 m, the solubility of CO₂ decreased with the increase of buried depth. When the buried depth was greater than 1 700 m, the solubility of CO₂ increased with the increase of saline depth. In addition, the change of CO₂ solubility with burial depth could be fitted by the equation. And based on this equation, the storage capacity of CO₂ in a certain area of storage site could be calculated.

CO₂ flooding is a promising way to improve the crude oil recovery ratio. CO₂ could not only dissolve in crude oil, but also replace some light hydrocarbons or intermediate hydrocarbons in crude oil. So the composition has great influence on the component mass transfer and minimum miscible pressure of the CO₂ miscible flooding. Therefore, the influence of the quantitative characterization of crude oil composition on the minimum miscible pressure of the CO₂ miscible flooding has engineering significance for the reservoir screening. Taking the original formation fluid of a certain oilfield in China as the research object, we analyzed the multistage contact miscibility mechanism. Meanwhile, we used the Winprop module in CMG to carried out the phase simulation of experimental data. The results show that the minimum miscible pressure between CO₂ and crude oil is proportional to the molar composition of N₂, C₁ and C₁₁₊, and inversely proportional to that of C₂~C₁₀. While the mixing of the CO₂ and reservoir fluids needs higher reservoir pressure than minimum miscible pressure. It requires that when screening reservoirs with CO₂ flooding, we should try to consider the reservoir with high mole content of C₂ ~ C₁₀ and low mole content of C₂₄. It has great guiding significance for miscible displacement design and miscible phase prediction.

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.

Normal pressure shale gas is one of the main types of shale gas exploration and development in China. It has great resource potential and broad prospects. In recent years, Sinopec East China Oil and Gas Company has continued to carry out normal pressure shale gas exploration and practice in Nanchuan-Wulong area of the basin-margin transition zone in southeastern Chongqing. Positive progress has been made in the following aspects such as basic geological theory research, low cost engineering technology research, green mine construction of normal pressure shale gas. The enrichment and high yield geological theory of “three factors controlling gas”, and the classification and evaluation standard and the target evaluation system of shale reservoirs are established. Six low cost engineering technologies of normal pressure shale gas are proposed, that is, low density 3D seismic exploration, well completion at the “second” section, “drop ball steering+continuous sand addition”, “three steps” fracturing sand addition, electric fracturing and high efficiency drainage gas production. The development technology strategy of normal pressure shale gas is preliminarily formed. The integrated green exploration and development mode is put forward. More breakthrough and efficient development of normal pressure shale gas exploration are realized. Normal pressure shale gas shows a good prospect of exploration and development. However, the exploration and development of normal pressure shale gas in China is still in its infancy and exploration stage. There are still many challenges in aspects such as theoretical innovation, technological breakthrough and benefit development. So that five countermeasures are proposed for the development of China’s normal pressure shale gas industry: ①deepen the research on the main controlling factors of shale gas enrichment and high-yield, and strengthen the target evaluation; ②speed up the research on the supporting technology of excellent drilling and completion for the further acceleration and efficiency increasing; ③strengthen the research on high-efficiency fracturing technology to increase production, reduce cost and increase efficiency; ④strengthen the research on the production rule of normal pressure shale gas, and formulate the technical strategy of benefit development; ⑤fully implement the integrated operation mode of shale gas geological engineering, improve the management quality and create benefit. These countermeasures are counted on accelerating the development of normal pressure shale gas industry in China.

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.

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

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.

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.

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.

The Chang 6₁ reservoir was the main oil-bearing beds in the study area of Ganguyi Oilfield in Ordos Basin. The exploration and development practice showed that the reservoir characteristics had strong heterogeneity in three-dimensional space, and the vertical and horizontal distribution of the reservoirs were complex, which directly restrictsed the subsequent rolling exploration and development. In the study, based on the core observations and logging data, and combined with analytical testing, the controlling effect of the reservoir macroscopic heterogeneity on the oil layer distribution was systematically and visually analyzed. The complexity of the Chang 6₁ reservoir in the study area was caused by a variety of factors. Among them, the distribution of the sedimentary microfacies and diagenetic facies directly controlled that of the high quality reservoirs. And the interlayer heterogeneity, especially the interlayer permeability, was easy to cause the selective filling of oil, while the interlayer heterogeneity directly caused the heterogeneous distribution of oil in composite sand body. Through this study, the distribution law of ultra-low permeability and ultra-low permeability reservoirs in Ordos Basin could be better understood intuitively, which provides guidance for finding favorable zones in the future.

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 %.

Based on several geological problems in the exploration and development of the normal pressure shale gas reservoir, its classification is explored. For that, the relation between the change of organic carbon content, the degree of thermal evolution and porosity in shale are analyzed. On this basis, the relation between gas content and these geological factors, and between the gas content and initial production are further studied. At the same time, compared with the typical shale gas reservoirs at home and abroad, the controlling effect of shale gas migration with different pressure gradients on the initial production of gas reservoirs is discussed. It is clearly pointed out that there are differences in the energy supply for shale gas migration between transitional normal pressure shale gas reservoir at the margin of （or in） the basin and residual normal pressure shale gas reservoir outside the basin. Although there exists loss, because of the large distribution area of shale in the basin and the sufficient migration and replenishment of shale gas, the transitional normal pressure gas reservoirs at the margin of （or in） the basin have higher initial production and better commercial benefit. While for the residual normal pressure gas reservoirs outside the basin, as they have limited shale distribution area and insufficient migration replenishment, they belong to low pressure reservoir and have low initial production. In order to realize the commercial development, it is necessary to make more breakthroughs in the technologies of increasing production and reducing cost.

Water generally exist in the gas well in west Sichuan gas field, which has a great influence on the steady production of gas wells. The timely grasp of the flow conditions of the gas wellbore can judge the fluid accumulation in gas well and guide the formulation of the drainage gas recovery measures. By using the pressure meter to judge the downhole conditions of the gas well had the disadvantages of poor timeliness and high cost, and the prediction of two phase flow theory often had deviations from the actual existence. So we used a large number of gas well production data and flow pressure test data to establish the prediction model of wellbore flow condition based on RBF neural network. The RBF network had the self adaptability and its output do not dependent on the initial weight. The coincidence rate between prediction results and actual results among 15 wells was 86.67 %, which indicated that the neural network model was reliable for predicting the wellbore flow conditions of gas well, and could be used to guide production.

The shale gas reservoirs in Longmaxi formation in Pengshui and its adjacent areas were overpressured in geological history, but nowadays they transformed into normal pressure. Through the simulation of formation pressure evolution in the uplifting process, it is revealed that Longmaxi shale was fractured under excessive pressure in this process, resulting in shale gas loss and therefore overpressure release. By overburden pressure permeability test, it is found that when the normal stress on the mudstone fracture surface of Longmaxi formation is more than 15 MPa, that is to say, when the buried depth is more than 1 000 m, the cracks will be closed, but the degree of fracture closure is affected by overconsolidation ratio（OCR） of shale. For the mudstone or shale under the brittle zones, OCR is relatively small, the closure degree of fracture is relatively high, the overpressure may not be completely released, and a certain degree of overpressure is still maintain. But for those above the brittle zones, the lager the OCR, the worse the fracture closure degree, and it is apt to cause the overpressure released completely, finally transit to normal pressure state. There is a significant correlation between OCR and the pressure coefficient of the formation fluid, that is, the higher the OCR ratio, the more normal the pressure will tend to be.

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.

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.

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.

In view of the technical difficulties of CO₂ flooding completion string, the research process and development situation of completion string of CO₂ flooding injection-production well were systematically expounded. It was concluded that the sealing performance of the completion string of injection well and anti corrosion and gas proof performance of production well were the key technologies for the normal production of CO₂ flooding injection-production well. The pilot test of CO₂ flooding in domestic oilfield showed that the continuous optimization of packer and the gas tightness detection of tubing contributed to improve sealing of injection wells, and the technologies like CO₂ corrosion inhibitor formulation, injection strengthening, tube controlling by gas lifting, downhole oil and gas separation were helpful to improve the pumping efficiency of the production wells. Meanwhile, in view of the technical problems faced by the injection and production wells on site, the further research direction of production by CO₂ flooding injection and production technology was pointed out.

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.

The improvement of experimental technologies of geological evaluation for shale gas is the key factor for the success of shale gas exploration and development in America. The progress in experimental technologies of geological evaluation of shale gas is summarized from three aspects including gas-bearing property, occurrence and fracability of shale. It mainly focuses on the ultramicroscopic organic petrology, formation porosity thermocompression simulation experiment of hydrocarbon generation and expulsion, and the characterization of pore network, which are developed for high thermal maturity marine shale of South China in recent years. The future trends of experimental technologies of geological evaluation for shale gas are discussed. It is proposed that the effectiveness and connectivity of multiscale pore structure, the characterization of organic and inorganic pore in diagenetic evolution, and dynamic evaluation for fracability are the key studying aspects in experimental technologies of geological evaluation of shale gas.

The property of low porosity and ultra-low permeability of shale gas reservoirs decide that only by the horizontal well fracturing can we obtain the economic productivity, and the forecast of the production after fracture have a great influence on optimal plan of treatments and economical estimation. On the basis of summarizing the previous researches, a novel model for production forecast in the unsteady early period was established based on the corrected Warren & Root model and considered about the desorption, slippage and stress sensitivity of micro fractures. Then the analytical solution for pseudo pressure was obtained by Laplace transformation and well-test method. Lastly, the practical production data was used to verify the accuracy of this model, and the factors affecting production were analyzed. The conclusion showed that the computed value and actual value of average daily production for single well in shale gas reservoir were similar to each other, demonstrating the validity of the model. Desorption and slippage had noticeable effects on the production and it also revealed that desorption played an important role in gas output. However, stress sensitivity could also affect the production in some extent, but the extent of the influence was less than that of desorption and slippage. The conclusions were meaningful for the study of output mechanism of shale gas and early production forecast.

With the increasing demand for energy, shale gas, as a new type of unconventional natural gas resource, has attracted more and more attention. At present, the commercial development of high pressure shale gas reservoir in China has been successfully realized, but the efficient development technology of shale in deep layer and normal pressure shale is still in the exploratory stage. The normal pressure shale reservoirs in China are mainly located in the residual syncline outside the basin. The deformation degree of structure is strong, the formation pressure coefficient is between 0.9 and 1.3, the buried depth is generally shallow, the formation energy is insufficient, and the daily production of single well after fracturing is （1~5）×10 ⁴m ³. All those problems result in the failure of commercial breakthrough so far. The fracturing technologies of high-pressure shale gas reservoirs have little effect in the process of normal-pressure shale reconstruction. Based on the difficult problems in the transformation of atmospheric shale gas wells, optimization has been carried out on many aspects such as the perforation mode, artificial fracture control and support technology, field construction technology and fracturing materials. The suitable network fracturing with high density is researched, and the multi-cluster fracture equilibrium extension and multi-scale artificial fracture network are preliminarily realized. The scheme has been tested in an normal pressure shale gas well of a certain shale gas block in southeast Chongqing, and good reconstruction effect has been obtained after fracturing.

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.

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.

With the continuous and further development in Sinopec shale oil exploitation, a series of characteristic technologies such as drilling, logging cementing and fracturing have been preliminarily formed. By the summary and analysis of the progress and achievements made by Sinopec in shale oil engineering technology during the "14th Five-Year Plan" period, the problems and challenges currently existing in shale oil development engineering technology are reviewed, and the technical countermeasures and development suggestions in the aspects of geological and drilling engineering integration, speed-up of drilling and completion, three-dimensional well development, and ultra-long horizontal wells are pointed out. Therefore, it promotes the development of shale oil engineering technology in China, realizes the low-cost, large-scale and cost-effective development of shale oil resources, and provides useful reference.

Although the traditional surface process of shale gas field can effectively solve the problem of hydrate blockage, there are still many other problems such as safety production and green economy development existing in gas fields. The downhole throttlingtechnology can simplify the ground flow, lower the cost of investment, reduce the risk of gas test on the ground, and ensure on-site safety. However, due to the influence of geological conditions and the production rule of gas and liquid, it has not been applied in shale gas fields at home and abroad. By analyzing the applicable conditions of downhole throttling technology in high-pressure shale gas wells in south block of Pingqiao area, and comparing changes of gas volume and pressure before and after the application of this technology for single well, and the downhole depth, aperture and downflow time of downhole throttling were clarified. The results proved that this technology could not only effectively avoid the formation of hydrates in the high-pressure shale gas wells in south block of Pingqiao area, but also significantly reduce the pressure of the wellhead and the ground pipeline, simplify the ground flow, and have significant economic value and good application prospects.

The proved reserves of natural gas in place in China is huge. However, realizing the long-term large scale stable production of natural gas faces a series of challenges such as enhanced gas recovery（EGR） of complex gas reservoirs, especially for those unconventional resources such as shale gas, coalbed methane and tight sand gas. Under the background of carbon neutralization, CCUS-EGR technology has broad application prospects due to owing the functions of increasing gas rate and carbon reduction. The main EGR mechanisms for CO₂ flooding are summarized into three types: substitution due to dominant adsorption of carbon dioxide, continuous convective displacement and gas reservoir energy supplement. Under the consideration that the classification of occurrence states of the adsorbed, free and dissolved natural gas are applicable to all types of the gas reservoirs. The prediction method of increased natural gas ultimate recovery factor by CO₂ flooding is further deduced. It is found that CO₂ flooding is expected to improve shale gas recovery of more than 20 percentage points by this method. In order to break through the technology of greatly improving natural gas recovery, it is suggested to evaluate the potential of CO₂ flooding to improve natural gas recovery for gas reservoirs with good geological sequestration conditions, assess the economic feasibility of CCUS-EGR technology applying in target gas reservoirs, and carry out major pilot tests of CO₂ flooding in various types of gas reservoirs. The synergistic displacement effect of flue gas components and the technology of expanding CO₂ sweeping volume should be focused especially.

The fracturing fluid leak-off in the reservoirs with developed natural fractures had a comparatively great influence on hydraulic fracture structure, proppant distribution and formation contamination. However, the current mathematical model for fracturing fluid leak-off considering natural fractures almost ignored or simplified the clustered distributed natural fractures, which limited the applications of these models. So firstly, by the multiplicative cascade method, we established a two-dimensional fractal discrete fracture networks model which reasonably showed the clustered distribution of natural fractures. Then, the established fracture networks were transformed into homogeneous anisotropic equivalent continuum media through subdividing the fractured porous domain into small elements. Ultimately, a mathematical model of fracturing fluid leak-off in fractured reservoir was established based on the permeability tensor. The results showed that the the strike of fracture rich zone determined the direction of fracturing fluid leak-off and pressure propagation. As the fracturing fluid tended to filtrate along long fractures, it was suggested to seal the natural fractures near hydraulic fractures before fracturing treatments. Moreover, fracturing fluid viscosity had certain influence on leak-off velocity.

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.

In shale gas reservoirs with natural fractures, the artificial fractures and natural fractures communicate with each other after fracturing. The traditional dual media model can not accurately reflect the impact of natural fractures on well production. In order to investigate the influence on shale gas well productivity caused by gas transport in nanometer-size pores, the mathematical model of multi-stage fractured horizontal well in shale gas reservoir is built, which considers the influence of the complex flow mechanism such as the viscous flow, Knudsen diffusion, surface diffusion, adsorption layerand gas desorption. Discrete fracture model（DFM） is used to simplify the fracture and finite element method is applied to solve the model. The numerical simulation results of Pingqiao shale gas reservoir indicate that the free gas in fracture system mainly contributes to shale gas production in the early stage, and the average recovery of adsorbed gas is only 10.1 %. The existence of unmodified reservoir makes the influence of bedrock permeability on cumulative production greater. The density and connectivity of fracture networks have dominant effects on gas production and its decline trend.

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 reasonable length of horizontal wells for lens-like thin-layered bottom-water reservoirs has been a question, and there were limited studies in the literature. Aiming at the study of a specific low amplitude, moderate-high permeability, thin lens-like sandstone reservoir with bottom-water in Hutubi river layer in Luliang oilfield of Xinjiang, by using a variety of methods in geology, drilling, reservoir engineering and numerical simulation, and combined with the effects of horizontal wells during the reservoir development, we demonstrated the relation respectively between various factors of horizontal well length and wellbore pressure loss, reservoir adaptability, and development of oil drilling rate effects of such reservoir. Then, we proposed the range of the reasonable length of horizontal wells considering both theoretically and practically. The results showed good reliability and applicability, providing technical reference for the research and application of horizontal wells in similar bottom-water reservoirs.

The productivity of gas wells in conventional gas reservoirs is mainly measured by open flow rate. The open flow rate is determined by gas test and production test data to evaluate the productivity of gas wells. Because of the particularity of geological characteristics and seepage mechanism, it is controversial to use which indexes to characterize the productivity of shale gas wells. Combined with the testing and production data of actual shale gas wells in China, it is proposed that the productivity of shale gas wells in different development stages can be characterized by three kinds of indexes—unhindered flow rate, recoverable reserves and gas production. When the productivity of shale gas wells is characterized by open flow, the empirical formula of “one point method” in Fuling main area is established, and the reservoir capacity（α） is 0.25. For the production capacity test of multiple work systems, the multi-flow method has better adaptability in Fuling. When the productivity of shale gas wells is characterized by recoverable reserves, before shale gas wells enter the decline stage, the unsteady productivity evaluation method of shale gas fractured horizontal wells is selected; while after entering the decline stage, the recoverable reserves of shale gas wells can be predicted by empirical decline method. For shale gas wells with fixed production, the gas test production of the same oil nozzle can be optimized to characterize the productivity of shale gas wells. The research results lay a foundation for the dynamic analysis of shale gas well production and the formulation of development technology policy.

The capillary bundle model is one of the most common physical models for the porous media. The most classic physical model is the straight capillary bundle model with same diameter. But the bendability of the porous media is neglected in this physical model. Therefore, based on the tight sandstone, combined with the mercury data, and by the introduction of the correction factor-tortuosity, we put forward a new approach to establish the capillary bundle model. This approach considers the bendability of the capillary bundle model and can accurately calculate the radius of capillary, capillary porosity and permeability, capillary volume of different radius and permeability contribution of capillary bundle model with different radius. This new approach has great significance for the study of the reservoir fluid imbibition of specific pressure and quantitatively characterizing the water invasion reservoir damage.

A low permeability reservoirs usually have threshold pressure gradient with extremely low permeability. The seepage mechanism of multi-stage fractured horizontal wells are complex and the productivity are affected by many factors. Based on the dual-porosity medium seepage differential equation, applying point source theory and superposition principle, a semi-analytical productivity model for the multi-stage fractured horizontal wells is established, considering the threshold pressure gradient and hydraulic fracture conductivity. Then the calculation of production and the numerical inversion are conducted, following by the analyses of the influence factors combining specific examples. The study results show that the threshold pressure gradient has great effect on productivity. The larger the threshold pressure gradient is, the lower the production will be. The angle between the hydraulic fracture and wellbore has a little influence on production, but not obvious, and the highest production appears when the angle is 90°. The conductivity of the hydraulic fracture has obvious effect on the initial production, but a little influence on that in the later period. The hydraulic fracture at both ends of the horizontal wells affect more than that in the middle, so the fractured horizontal well’s stages and the length of the fracture should be increased. The storage ratio and cross flow coefficient mainly affect the medium-term productivity. The larger the storage ratio is, the faster the production will decrease. And the larger the cross flow coefficient is, the higher the production will be. The results of this study not only contributes to the deep understanding of the multi-stage fractured horizontal well’s seepage laws in the low permeability reservoirs, but also provides some important guidance and advice for the optimization design of the multi-stage fractured horizontal wells.

Experiments for seepage flow patterns in thin and poor reservoirs could be carried out by the plate models made by artificial core designed based on the similarity theory. Pressure gradient distribution in fractured thin and poor reservoir by fine controlling was revealed based on the pressure data, and the sketch maps of seepage flow sections were drew to study on seepage flow patterns of fine controlled fractured thin and poor reservoir qualitatively and quantitatively. Experiment results showed that seepage flow patterns in thin and poor reservoirs were greatly influenced by permeability, heterogeneity and fine controlled fracturing cracks while the thin and poor reservoirs had low permeability and strong homogeneity. Fine controlled fracturing could reduce the negative influence of low permeability and strong heterogeneity. Thin and poor reservoirs could be divided into the non seepage flow section, the nonlinear seepage flow section and the quasi linear seepage flow section. The non seepage flow section was reduced by over 72 % after fine controlled fracturing, the area for fluid flowing through increased correspondingly, and the proportion of quasi linear percolation area which was more conducive to fluid flow raised by at least 86 %.

At present, the oil recovery in the CO₂ oil displacement area of the peripheral oilfields in Daqing is mainly predicted by numerical simulation with no empirical formulas. In order to solve this problem, firstly, an heterogeneous ideal model of miscible, near-miscible and immiscible by CO₂ flooding based on the basic physical properties and PVT parameters of the peripheral oil field in Daqing oilfield is established. Secondly, three kinds of characteristic curves of CO₂ flooding are defined, including carbon content-accumulation of oil, type A and type B. The feature curve is used to predict the recovery rate in the model, and the calculation method of characteristic curve suitable for CO₂ near-miscible flooding modes is optimized. On this basis, the carbon content and recovery degree chart suitable for S block is established, and compared with the actual performance of S block. A-type gas drive characteristic curve is selected for the further establishment of the CO₂ near-miscible drive chart, and this improved chart is applied to predict the recovery rate of S block. The results show that the recovery rate predicted by the CO₂ near-miscible flooding chart is close to that predicted by the field test of S block. This method can predict the recovery rate of CO₂ flooding simply and quickly, and has guiding significance for the next development and evaluation of S block and similar blocks.

The machine learning method is the main technical means of carbonate lithofacies log identification. Selecting the appropriate machine learning method according to the different geological conditions and data is one of the key factors for high-precision identification of lithofacies. However, there are few researches on the applicability of machine learning identification methods. In this paper, four most commonly used machine learning methods for identifying lithofacies are studied, including Self Organizing Maps（SOM）, Multi-Resolution Graph-based Clustering（MRGC）, K Nearest Neighbor（KNN）, and Artificial Neural Network（ANN）. By comparing the principle and practical application effects of these methods, the advantages, disadvantages and applicability of the four machine learning methods have been summarized. When there are few core samples, MRGC is preferred, while when there are more core data, KNN is preferred as well as MRGC. Their application of lithofacies identification in the Longwangmiao Formation in the MX area in Sichuan Basin shows that MRGC and KNN are the best, SOM is the second, and ANN is the worst. This study of the application effects of machine learning methods provides a guidance for the identification of carbonate rock facies in other layers and regions, and has strong practical value.

Shale gas resource evaluation includes resource calculation, favorable distribution area and economic effectiveness based on geological and exploration process analysis. Its core is evaluation method selection, parameter processing and result analysis in line with geological process evolution characteristics and data mastery degree. The intelligent evaluation of shale gas resources can overcome the limitations of real resource evaluation, and can realize the whole process simulation and evaluation from qualitative to quantitative. It has obvious characteristics of development stages. The main feature of resource evaluation at this stage is to use modern means such as machine learning and inference engine. Method selection, parameter quality and evaluation effect are the keys to shale gas resource evaluation. Knowledge base establishment based on geological characteristics and exploration level, data collection, parameter analysis, data mining, geological reasoning, method selection, intelligent calculation, and reliability of results analysis, spatial expression of results and continuous execution throughout the process are the basic ideas and methods for intelligent evaluation of shale gas resources. Intelligent evaluation with powerful functions and continuous implementation throughout the whole process is the basic direction of the development of shale gas resource evaluation, which requires continuous accumulation and practice on the basis of existing technologies to promote the development of shale gas resource evaluation methods and technologies in a wider range.

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.

Bohai oilfield has the characteristics of loose cementation, serious heterogeneity, high viscosity of crude oil, high average permeability and large amount of water injection in a single well. The breakthrough phenomenon of water injection development was serious, and the injection water erosion also caused damage to rock structure. Then we formed inefficient and ineffective circulation between injection and production wells, seriously affecting the effect of water flooding development, and bringing great risks to subsequent chemical flooding development. In order to satisty the heavy oil reservoir of high water shutoff technology needs, based on the physical chemistry, polymer materials and reservoir engineering theory, and taking the chemical analysis, detection equipment and physical simulation as an experimental method, we took the reservoir rock and fluid in SZ-361 field of Bohai oilfield as the research object to study the water plugging effect and mechanism of starch graft copolymer gel. The results showed that when the water plugging agent group was "starch（4 %）+ acrylamide（4 %） + crosslinking agent（0.036 %） + initiator（0.012 %） +anhydrous sodium sulfite（0.002 %）", the reasonable slug size of water plugging agent was between 0.025PV and 0.075PV. For the model of "edge water and vertical oil well", the oil recovery of water flooding decreases with the increase of crude oil viscosity. After water plugging in the oil well, the liquid production rate decreases when the water content drops. The higher the viscosity of crude oil is, the greater the decline of water content and the recovery rate will be, but the ultimate recovery is still lower. Compared with the model of "single water and vertical oil well", the model of "multilateral water and vertical oil well" had higher water flooding recovery, and the effect of water plugging and oil increasing was better. For the high water cut development period of reservoir, due to the impact of early water flooding and chemical flooding profile control and other measures, the remaining oil saturation near the water wells borehole area was low, but the residual oil saturation in low permeability reservoirs near the wellbore was higher. Therefore, the effect of water plugging measures on increasing oil and precipitation was much better than that of profile control measures.

Compared with the single well development mode of the conventional gas reservoirs, multi-well pad technology has several advantages such as great improvement of operating efficiency and reduction of project cost. Strong interference between the wells and between the fractures exist in small well spacing and network fracturing mode of multi-well pad for shale reservoir, which affect the overall development effect of the well group. Based on the unstructured PEBI grid technology, its simulator for fracturing horizontal wells is developed independently. According to the results of microseismic monitoring, the stimulated reservoir volume（SRV） area formed by the network fracturing of horizontal well groups are assumed to be ovals. Considering the adsorption, desorption, diffusion and nonlinear seepage mechanisms of shale gas, the numerical simulation model of the fracturing horizontal well group in the multi-well pad mode is established by the finite element method. The difference between the cumulative production of the single well and the well group is compared, and the influence of the layout mode of the fractures and the horizontal wells on the cumulative production in homogeneous shale gas reservoirs are discussed. The results show that the inter-well seepage interference makes the cumulative production of the well group lower than the sum of that of a single well. U-shape layout mode of the fractures for single well can reduce the interference to a certain extent, which make the cumulative production of the well group superior to that of the uniform mode and the inverted U-shape mode. The cumulative production of cross distribution of horizontal wells is better than that of parallel mode.

The study of proppant transport in fractures is of great significance for guiding fracturing design and evaluation. The current researches of proppant placement rules mainly focus on displacement, proppant type, fracturing fluid viscosity, etc. However, there are few studies on the effects of different proppant combinations on proppant transport rules. In this paper, the experimental schemes of the influence of different proppant combinations on proppant transport rules are designed. Then the self-designed visual parallel plate device is used to carry out these experiments. The results show that the distribution of the proppant with smaller particle size is more evenly in the fractures, but the proppant with larger particle size is easier to settle at the wellhead. When medium particle size and large particle size proppant are combined in different proportions, there are small differences in the equilibrium heights of the formed sand bank, but the differences between the non-uniformity of the sand bank height are large. Meanwhile, a large amount of proppant settles at the entrance end of the crack. The proppant filling amount in the deep crack is small, and the effective filling crack with sufficient length and diversion capacity is failure to be formed. When the medium and small particle sizes are combined in different proportions, the proppant can obtain a farther distance than that of the combination of medium particle size and large particle size. The height of the formed sandbank is ideal, and the difference in the non-uniformity of the height of the sand bank between different proportions is also greater.

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

The produced GOR is a key index for the development and design of gas flooding reservoirs. On the basis of confirming that there are five sources of gas production in the whole life cycle of gas flooding, the prediction formula of produced GOR in low permeability reservoirs matching with three development stages is proposed. From gas injection to pre-gas production, the produced GOR is mainly controlled by the initial dissolved GOR of the reservoir fluid, and method of determining the equivalent GOR of water-soluble gas is given. The produced GOR in the stage from pre-gas production to gas channeling is affected by the gas dissolved capacity of ″oil bank″. The method of describing the physical property of gas flooding″oil bank″ in low permeability reservoirs can be used for reference to determine dissolved GOR of gas flooding″oil bank″. The change of produced GOR after gas channeling is determined by the GOR formed by free gas, and its prediction based on the understanding that the pore space released by the produced liquids would be filled with the injected gas and water. It is calculated by oil and gas fractional flow equation, Corey's model and Stone's equation combined with concepts of gas flooding increasing multiple in low permeability reservoir, and slug size ratio of water-gas during water alternating gas injection. The reservoir engineering method of produced GOR prediction taking the form of ″three-stages″ has been verified by the field test of CO₂ miscible flooding. It can be used in gas injection development planning design, optimization of oil production process or gas injection storage potential evaluation.