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.

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.

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.

Nowadays, the CCUS industry is developing rapidly worldwide, of which the projects are gradually turning from single-section items to whole-industry ones. The target of capture has expanded from power plants and natural gas processing to steel, cement, kerosene, fertilizers and hydrogen production. At present, there are five major ways to drive the industry: government and public funds, national incentive policies, taxation, mandatory emission reduction policies and carbon trading. In China, the CO₂ emitting enterprises are mainly power plants, cement, steel and coal chemicals, accounting for 92 % of the total emissions. According to the concentration, the low concentration CO₂ emission sources are mainly from power plants, cement, steel and refining and chemical industries, that with high concentration are mainly from coal chemical industry, synthetic ammonia and calcium carbide, and that with medium concentration is mainly from the polyethylene industry. The first are the majority, while the latter two are relatively few. Costs of CO₂ sources are comprised of three main parts: capture cost, compression cost and transportation cost, all of which are affected by the scale of capture. Meanwhile, the cost of capture is also related to the concentration of emission source. For the type of high CO₂ concentration, the expense of compression takes the lead in accounting. And capture cost is for the low CO₂ concentration type. As the tolerance of CO₂ cost is lower than source cost for most oilfields, it is necessary to seek ways like technology, policies or markets to fill the gap and promote the sustainable development.

Deep shale gas（buried depth is larger than 3 500 m） is the potential resource for future exploration in Sichuan Basin. Although the industrial shale gas flows have been obtained at the depth of 3 500~4 000 m in Wufeng-Longmaxi Formation of Sichuan Basin, the commercial development hasn’t been put into practice due to the rapid decline and the low EUR（Estimated Ultimate Recovery）. Based on the analysis of the current status of shale gas exploration and development, the challenges in the deep shale gas development with high efficiency and large scale in Sichuan Basin have been summarized, mainly in the following aspects: the understanding of occurrence mechanism and enrichment law of deep shale gas needs to be deepened, engineering and technology of economical and effective fracturing treatment need to be established, and the organizational operations and management methods of deep shale gas development are difficult to meet the needs of the large-scale and high efficient development. Three countermeasures are proposed to realize the large-scale and highly efficient development of deep shale gas: ①deepening the understanding of deep shale gas enrichment laws, establishing the methods of area selection and evaluation, and forming the prediction and description technologies of “sweet spot” and “sweet window”; ②deepening the research on the geological conditions of deep shale gas, forming an advanced supporting technology of drilling and fracturing and an equipment system to fully release the reservoir capacity; ③promoting the geology-engineering integration, building a new system and mechanism, and greatly reducing the cost to maximize the development benefits of deep shale gas. The industrial gas flows have been obtained in several wells at the depth of more than 3 500 m of Wufeng-Longmaxi Formation in Sichuan Basin and the proven reserves have been submitted. It is the key and priority stratum of the deep shale gas development. By deepening the geological understanding, overcoming the key technical problems, and improving the management system, it can significantly accelerate the speed, reduce the cost, increase the efficiency and achieve a large-scale and highly efficient development in a relatively short period. The output is expected to be higher than that of the middle and shallow shale gas reservoir.

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.

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 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.

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 %.

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.

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.

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.

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.

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.

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.

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.

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.

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.

In order to study the influence of mineral interface action on the initiation and propagation of shale hydraulic fracturing fractures, a shale microstructure model was established. In the model, the zero-thickness cohesive element was embedded in the solid element. A numerical simulation of the effect of mineral boundary interface stiffness on hydraulic fracture propagation was carried out to reveal the law of shale hydraulic fracturing crack propagation under the influence of mineral interface action. The results show that the tensile destruction is the main form of fracture failure of shale hydraulic fracturing. The crack propagation path consists of two ways, one is to extend along the mineral boundary, and the other is to cross the mineral boundary and enter the mineral to expand. With the increase of the mineral boundary interface stiffness, the crack initiation pressure and pore pressure gradually increase, the length, number and area of the cracks gradually decrease, and the width of the cracks gradually increases, so that it is easy to form short and wide cracks. When carrying out shale hydraulic fracturing operations, the location where the stiffness of the mineral boundary interface is lower should be selected first. The research results help to reveal the action mechanism of the mineral interface action on the expansion of the shale hydraulic fracture, and provide a theoretical basis for the reasonable selection of the hydraulic fracturing layer position of the shale gas reservoir.

Generally there exist a large number of ineffective perforation clusters in multistage hydraulic fracturing of horizontal wells of shale gas reservoirs. So improving the effectiveness of perforation and maintaining the long-term conductivity of fractures are the main challenges to increase production and reduce costs for shale gas horizontal wells. Based on previous research results, the main reasons for low production of perforation clusters include: ① Fracture does not initiate or propagate effectively due to mechanical heterogeneity of shale reservoir, stress shadow between fractures, or difference of perforation erosion rate; ② The distribution of proppant is non-uniform between clusters and in fractures due to the difference of perforation displacement distribution within the stage, weak sand suspension ability of low viscosity fracturing fluid, and fracture bending, inclination and roughness; ③ The fracture conductivity is lost due to the breakage and embedding of proppant, diagenesis, formation and migration of formation particles. In order to solve the above problems, the optimization and technical solutions to facilitate the balanced initiation of fractures, the uniform distribution of proppants, and the improvement of fracture conductivity are proposed. They include new-type limited entry fracturing technique, degradable temporary plugging diversion, optimization of perforation parameters and sand-adding sequence, high-speed channel fracturing, high viscosity friction reducers and new-type proppants, etc., which are expected to provide benchmark for improving the effectiveness of perforation cluster fracturing of horizontal wells.

The availability of shale oil directly affects the degree of effective exploration and development, and the mobility of shale oil is closely related to its occurrence state. Therefore, studying the occurrence state of shale oil plays an important role in its development. The pore model is established by graphene and quartz, and the occurrence state of n-octane and its mixture in nanopores is studied by molecular simulation method. The effects of pore size, temperature, pressure, shale oil composition, wall wettability and wall composition on the occurrence state are analyzed. The results show that: ①shale oil is multi-layer adsorbed in the pores and symmetrical about the pore center, and the thickness of the adsorption layer is 0.4~0.5 nm; ②The larger the pore size of the reservoir, the higher the temperature, the lower the pressure, the lighter the molecular component, the weaker the polarity, and the higher the wall wettability are, the more unfavorable the adsorption of oil molecules on the wall is;③ In the combined wall, due to the influence of graphene wall, the adsorption amount of shale oil molecules increases with the increase of quartz wall wetting humidity. In addition, the adsorption transfer phenomenon of n-hexanoic acid and cyclohexane also occurs.

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.

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.

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.

The water cut of heavy oil reservoir in Dagang Oilfield increased rapidly in the middle and late period of water flooding, and the production effect became worse. CO₂ huff and puff technology is an effective method to develop heavy oil reservoirs. But the parameter optimization and field effect in the late stage of high water cut needed to be studied urgently. Therefore, the heavy oil reservoir in Dagang Oilfield was used to carry out the experiments of CO₂ injection for solubilization and swelling with viscosity reduction. Based on the experiments and well logging data, a single-well numerical simulation model was established to simulate the reservoir parameters and CO₂ injection parameters, and analyzed the CO₂ oil stimulation mechanism. Based on the results of theoretical researches, the in-site CO₂ huff and puff experiments were carried out in Banqiao and Liuguanzhuang. The research results show that the mechanism of water control and oil increase by CO₂ is mainly to expand the volume of crude oil and reduce the viscosity of crude oil, and the viscosity can be reduced by up to 98 %. The impact of injection volume, injection speed, and throughput cycle is relatively large on the CO₂ throughput effect. It is recommended that the CO₂ injection volume of a single well is 600~1 000 t（0.22~0.37HCPV）, the injection speed is 40~80 t/d, and the throughput runs 3~4 cycles. In Banqiao and Liuguanzhuang, CO₂ huff and puff have been carried out 12 times on wells, with an average increase of 3.4 times of oil production per well and a 52.2 % reduction of comprehensive water cut. Thus, CO₂ huff and puff technology is an effective water-control and oil-increasing technology, which has important reference significance for improving oil recovery in the later stage of water injection in similar heavy oil reservoirs.

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 physical and mechanical properties of bedding shales show strong anisotropy, which leads to the significant difference in the logging response of the same formation between the vertical wells and the horizontal wells, and bringing the difficulties in regional reservoir evaluation. Based on the numerical simulations, the influence of orientation and density of bedding on the anisotropy of longitudinal wave has been analyzed, and a correction model for longitudinal wave of shale in Longmaxi formation has been built. Then, combined with the indoor compression wave experiment, the rationality of this new model has been analyzed. The results show that, the longitudinal wave anisotropy of shales in Longmaxi formation is obvious, and the coefficient of longitudinal wave is around 1.088 ~ 1.109. The coefficient of longitudinal wave anisotropy has a quadratic polynomial relation with the sine of the bedding angle, and the anisotropic coefficient increases linearly with the increase of bedding density. Application examples show that this new model can reasonably correct the acoustic response of horizontal wells to that of vertical wells.

In order to solve the problem that the injection pressure of shale reservoir in Fuling area is too high in the early stage of hydraulic fracturing, researches on the resistance reduction based on proppant slug technology was carried out. By using the previous self-developed jet device and target, a set of physical simulation method for reducing fracture resistance in near well by grinding perforation with proppant slug was established and the orthogonal experiment was carried out. For the on-site needs, fore-tail pressure drop and average pressure drop rate are established to characterize the experimental results, and then analyzed accordingly. The results show that the influence of various factors on the resistance reduction effect from large to small is in the following orders: sand ratio, particle size, number of slugs（grinding time） and proppant type. The effect of reducing resistance of quartz sand is better than that of ceramsite. Drag reduction increases with the thickening of proppant particle size and the increase of sand ratio, and decreases at first and then increases with the prolongation of grinding time. Based on the results of orthogonal experiment, the optimal operating parameters of quartz sand with particle size of 40/70 mesh, sand ratio of 9 % and grinding time of 9 min are selected. On this condition, the optimal friction reduction effect of pressure drop rate of 0.439 MPa/min and head-tail pressure drop of 1.04 MPa are obtained. The experimental study provides a certain reference for the construction design of hydraulic fracturing of shale reservoir.

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 calculation of the bottom hole pressure(BHP) in the high temperature and high pressure the gas wells with should consider the temperature changes inside the wellbore. The coupling of the pressure and temperature need to be solved simultaneously. The current calculation methods considering the wellbore heat transfer, and the coupling of pressure and temperature mainly apply to the steady flow. However, they don’t apply to the transition flow during the shut-in period. Meanwhile, the wellbore heat transmission of the offshore gas well in high temperature and high pressure should consider the effects of sea water. Nevertheless, there are fewer examples of this research. According to the problems above and based on the basic equation, we established a new calculation model, which considers wellbore storage, and the heat transfer among the wellbore, adjacent formation and sea water. This method is successfully applied to the BHP calculation and well testing analysis for the well M1 during the shut-in period in M gas field of the western South China Sea, thus providing the basis for the temperature and pressure calculation and well testing optimization of high temperature and high pressure offshore gas well.

In order to improve the refracturing effects of the tight reservoirs and the economic benefits, we provided the optimization methods for the well and layer selection and fracturing design in the refracturing process of the tight wells: the multi-level fuzzy comprehensive evaluation method and artificial neural network method were applied to study the influence of the geological and engineering factors on the refracturing effect, so that the well and layer selection criteria of refracturing for the horizontal wells in tight reservoirs could be determined. The stress field variation and fracture extension rule were studied, and the fracturing material for tight reservoirs was provided. Based on the field production data, 3D fracturing simulation software was used to optimize the refracturing parameters of 3 target horizontal wells. The studying results can scientifically guide the application of refracturing technology in tight reservoir wells.

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

The 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 the case of the carbonate heavy oil reservoir with the well developed dissolution fracture, the percolation mechanism of dissolution fracture is different from that of fracture. The conventional well test models can not meet the needs of the well test analysis. In the heavy oil reservoir with quadruple media. According to the basic principle of the seepage flow mechanics, the quadruple-media well test mathematical model based on the fracture, dissolution fracture, dissolution pore and matrix is established in heavy oil treating as the power-law fluid. By means of the Laplace transformation and Stehfest numerical inversion, we obtained the real space solution, and drew the well test curves of three different boundary conditions. The results show that three concaves with different depths and widths occur in the pressure derivative curves of the quardrule-media reservoir and the slope of pressure derivative double-log curve is(1-n)/(3-n) in the stage of radial flow. The smaller the power-law index is, the greater the slope of pressure-derivative curve of radial flow will be. The smaller the storativity ratio is, the wider the concave will be, furthermore, the greater the interporosity flow coefficient is, the ealier the concaves will appear. Compared to the thriple-media, the change of the pressure-derivative curve affected by many parameters is more sensitive in the heavy oil reservoir with quadruple-media. The model is used to guide the interpretation and study of the well test data .

CO₂-EOR has been widely used in foreign countries, but rare in China because of technical and economic factors. Taking the CO₂ flooding project of the small fault block reservoir in Subei basin as an example, the development modes of huff-n-puff, synchronous gas injection, gas cap flooding, gas-water alternation, CO₂ combined flooding in medium and high permeability reservoirs are summarized, and economic benefits and influencing factors are analyzed. The practice in Subei basin shows that the economic benefits of CO₂ flooding projects are closely related to the injection cost and utilization of CO₂. The economic benefits of various development models are different but overall are good, which play a better performance in low permeability and low water cut oil reservoirs through gas cap flooding and gas-water alternate flooding.

Foam drainage-gas recovery technology is the most common nowadays and is the most effective application technique. However, due to the certain difference in production conditions of different gas fields, the mode, type, and foam drainage system of foaming agents are different. At present, southern Pingqiao adopts the method of 24 h continuous injection which is commonly used in other gas fields. It works in some wells, but for other wells, this technology dose not works well. In order to form a set of foam drainage model suitable for shale gas wells in southern Pingqiao, combined with laboratory evaluation, field test and economic evaluation, it is proved that the foam drainage process can effectively carry out the bottom hole liquid accumulation and achieve a certain degree of production increase. But in the later stage, it is more focused on reducing the production decline of shale gas wells and ensuring the stable production of gas wells. The XHY-4M type liquid foaming agent is optimized for foaming. When the concentration of defoamer is 0.3 %, the concentration of defoamer is 5 % ~ 20 %, the ratio of defoamer and foaming dose is 1.2∶1, the ratio of water to gas in the well is greater than 0.5, and the overall foam drainage effect is better. Meanwhile, the foam drainage system is constantly adjusted and optimized, and the intermittent foam drainage system of “less injection and multiple times” is adopted, which is more applicable and the effect of economic evaluation is optimal. The results of this study have certain reference for the stable production of similar shale gas wells.

Significant progress has been made in the exploration and development of shale gas in the Wufeng-Longmaxi Formation of Sichuan Basin, but shale gas content varies greatly among different well locations. Through the analysis of formation water salinity, geochemical index and formation water type in Well-PY1HF, Well-JY1HF, Well-NY1HF, Well-LY1 and other wells in Southeastern Chongqing, it is found that CaCl₂ water type reflects good shale gas preservation conditions, while the water types of NaHCO₃ and Na₂SO₄ reflect formation water and atmospheric water are interconnected to different extent, leading to a relatively poor preservation condition. Based on the characteristics of large-scale faults and residual syncline structures developing in Southeastern Chongqing and the formation water characteristics of Wufeng-Longmaxi Formation, the groundwater seepage mode can be divided into two types: the infiltration type in the large-scale fault development area and the centripetal flow type in the residual syncline area, corresponding to different shale gas preservation conditions. In the area with large-scale faults, the surface water infiltrates deeply along the faults, causing great damage to shale gas reservoir, most of them contain few gases. The formation water in the residual syncline is centripetal flow, and the deep part of the syncline is relatively well preserved. The surface water and the formation water form a free alternating zone at the syncline edge, and the preservation condition of shale gas reservoir is poor, thus the gas bearing property is poor. In the core part of the syncline, the closer to the core part, the weaker the influence of atmospheric water infiltration is, and the better the preservation condition will be.

In order to solve the problems of long perforation cycle, high cost and self-locking of long horizontal section of coiled tubing transmission, a key test for tractor perforation has been carried out. At present, the staged fracturing of horizontal shale gas wells mainly uses pumping bridge plug perforation. In the first part of the frac well, because of the lack of pumping channels, coiled tubing transmission perforation is used usually, which need longer operating cycle and higher cost, and is not beneficial to reduce cost and improve efficiency. Nanchuan Shale Gas Field has expanded the business scope of the roller tractor by introducing and improving some tools, and realized the tractor perforation of shale gas horizontal wells. The tractor perforation powered by a tractor transports the perforation gun to the position and ignites the gun. By on-site improvement and testing, Nanchuan Shale Gas Field has solved the problems of voltage isolation protection joints, shock absorption joints and adapters, mastered the performance of tractor perforation and applicable conditions, and provided experience for subsequent construction and basis. The test results show that the perforation of the tractor in the horizontal section of shale gas wells with a well deviation of less than 90° is reliable and feasible. The tractor perforation can meet the needs of shale gas horizontal wells under pressure perforating operation. Its operation process is greatly affected by well deviation and wellbore cleanliness. Compared with coiled tubing perforation, its speed-up and cost-reducing effect is obvious. The construction period can be saved by two days, up to 50 %.

CO₂ huff-n-puff after fracturing of horizontal wells can effectively improve the properties of crude oil and increase the oil recovery of ultra-low permeability reservoirs. Combined with the geology and fluid characteristics of a typical ultra-low permeability reservoir, Block H, the mechanism of multi-cycle CO₂ injection in horizontal wells and the variation of crude oil properties in ultra-low permeability reservoirs are studied by means of laboratory experiment and numerical simulation. The results show that after CO₂ injection, the saturated pressure of crude oil increases, the volume expands, the viscosity decreases, and the system becomes lighter. And the main action mechanism of different stages of CO₂ huff-n-puff are different: in the injection stage, the main mechanism is to supplement the formation energy, dissolve in crude oil, and reduce the crude oil viscosity; in the soaking and the initial stage of production, the main mechanism is to reduce the crude oil viscosity and expand the scope of CO₂; in the middle and late period of well opening production, the light hydrocarbons and a small amount of intermediate component hydrocarbons in the oil phase are extracted. The CO₂ content in oil phases at different distances in the reservoir is analyzed by the method of fixed time and fixed point, and it is deduced that the lateral sweep radius of CO₂ injection along the fracture in H block is 24~40 m. With the increase of the huff-n-puff cycle, the increase of molar content of CO₂ in the oil phase decreased from 451 times in the first cycle to 0.44 times in the third cycle. The dissolved amount of injected CO₂ in crude oil decreases relatively, and the effect on the properties of crude oil also gradually decreases. The above research provides a new analysis method for understanding the mechanism of CO₂ huff-n-puff, and provides some theoretical support for further popularizing the multi-cycle CO₂ huff-n-puff technology of horizontal wells in ultra-low permeability reservoirs.

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.

： Aiming at the problems of reservoir density, ultra-deep, high temperature and high closure stress of the exploration well S1 in new area, we designed the modification scheme of compound high diversion acid fracturing. It was based on the fluid with better performance. The sand adding existed in the whole stage of prepad fluid and acid liquor. The proppant placement in all fractures（near wells and far wells）was realized. Meanwhile, acid is used to etch the main fracture and communicate with the surrounding reservoirs. So that the complex flow channel of ceramsite and acid etching across the whole crack scope formed. The evaluation conductivity in the lab showed that the conductivity of the compound channel form by ceramsite and acid etching increased by 40 %. The average embedded depth of high strength ceramsite proppant was only 85 μm. By the indoor fluid analysis and evaluation technology, the fracturing fluid system with the heat resistance of 180 ℃ was selected as prepad fluid to realized the effective long hydraulic fractures. The ground cross-linked acid system with the heat resistance of 165 ℃ was developed, and the optimum HCL concentration was 15 %, which meet the requirements of sand carrying and deep penetration. Then we optimized the proppant type and adding method to realized the effective support for all fractures. Well S1 successfully completed the fracturing by the equipment with the pressure resistant of 140 MPa. The highest displacement was 5.1 m ³/min and the highest pressure was 108.5 MPa, the cumulative sand adding was 78.6 t, and the fractured daily liquid output reached 72.9 t/d. The long-term conductivity of composite fractures remains at a high level.

For the characteristics of condensate gas reservoirs, evaluation methods on just one side would lead to misjudgment on retrograde condensation of gas reservoir. Therefore, qualitative and quantitative comprehensive evaluation method of retrograde condensation damage was established. Firstly, the retrograde condensate phase evaluation and production dynamic analysis were used to judge whether the retrograde condensation of gas wells occurred or not. And then, methods such as the gas well productivity, pollution skin coefficient, numerical simulation and pressure build-up testing were comprehensively applied to quantitatively evaluate the degree and radius of the retrograde condensate damage. The established method was carried out in the case of the well-169 of Zanarol condensate gas reservoir in Kazakhstan. The results show that gas condensate has occurred in Zanarol condensate gas reservoir. Retrograde condensation has great influence on oil productivity, but a little on that of gas. And the damage degree is different for different gas wells. Generally, retrograde condensation damage was little and its influence rate was less than 16 %. Pollution radius was about 20 m. Thicker gas layer and carbonate reservoirs with developed fracture-vug were important reasons for less influence of retrograde condensation damage on gas well productivity in Zanarol. The established method can be used as a reference for the analysis of complex condensate gas reservoirs.

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 %.

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

Based on the analysis of the factors influencing the minimum miscibility pressure in CO₂ flooding and 36 groups of tubule experimental data, the correlation degree of each factor influencing the minimum miscibility pressure in CO₂ flooding of crude oil is calculated by the grey correlation method. The prediction model of minimum miscible pressure in CO₂ flooding for crude oil is fitted by the MATLAB （Matrix Laboratory） software, which is related to the reservoir temperature, relative molecular weight of C₅₊, volatile hydrocarbon component （N₂+CH₄） content and intermediate hydrocarbon component （CO₂+H₂S+C₂—C₄） content. The fitting correlation coefficient reaches 0.900 9. The data of the minimum miscible pressure test of three wells in an oilfield are used to verify the new prediction model. The average error of calculation is 3.57 %, which can be used to guide the field development of the reservoirs.

CCUS is an important technical means to achieve the carbon neutrality goal. At present, China is in the implementation stage of the “dual carbon” goal, and there is still a lack of mature technical system in the economic boundary assessment, source-sink optimization and safety monitoring of geological sequestration of CO₂. This paper summarizes the development process of China's CO₂ geological sequestration technique from three aspects, economic boundaries of sequestration technology, source-sink matching technology, and sequestration safety and monitoring, reviews the economic costs of CCUS technology in the capture, transportation, injection and burial period, and further summarizes the current technical and economic boundaries and influencing factors of each period. In addition, by summarizing the current development status of CCUS source-sink matching technology at home and abroad, the source-sink characteristics and distribution of China have been clarified, and further development directions for source sink matching optimization technology have been proposed. Finally, by summarizing the safety risk assessment and burial monitoring techniques for geological sequestration of CO₂, it is clear that economically efficient, effective, and quantitative monitoring methods are the focus of future research.

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.

In order to find out the complex situation of remaining oil distribution at the middle and high water-cut stage of Suizhong 36-1 Oilfield, and by the study of the flow field variation characteristics of nine-point well pattern for complex heterogeneous reservoirs by high temperature and high pressure experiments, the physical simulation experiments for the nine-point well pattern and the characteristics research for flow field of infilled row shape injection-production well pattern were designed and carried out based on the newly developed 3D large-scale core modeling technology and the stereoscopic acquisition system for oil-water saturation. For the injection and production patterns with complex rhythms, the distribution of remaining oil was also very complicated, but there were certain rules: under the condition of single positive rhythm, the subsidence of injected water was obvious even in the experiments, and the remaining oil was mainly distributed in the upper part of the positive rhythm; under the condition of inverse rhythm, the injected water could spread evenly to all permeability layers of the model, and the remaining oil was mainly accumulated in the weak hydrodynamic area; under the condition of complex compound rhythm, the distribution of remaining oil depended on the low permeability zone with weak water flooding in the complex structure, and it was not necessarily the area without streamline between corner wells. At the same time, based on the above characteristics, it was found that the water flooding degree of nine-point well pattern was high, most recoverable reserves could be produced. And when nine-point well pattern transformed into row injection-production well pattern, the recovery rate of heterogeneous reservoir could be improved by about 8 % ~ 10 %. Experimental studies suggest that no matter for the nine point injection production well pattern or the converted row shape injection-production well pattern, the maximum recovery rate of structure reservoirs with complex rhythmic was difficult to exceed 40 %.

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.

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.