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.

In the process of CO₂ injection and storage of a single well in depleted gas reservoirs, the injected CO₂ causes the rebalance among gas, water and solid, and the accompanying CO₂ dissolution, water evaporation and salting out affect the physical properties of the formation near this well. Therefore, taking depleted gas reservoir in western Sichuan as an example, the SRK-HV equation and salting out model are used to analyze the three-phase change rule during the CO₂ injection process of the depleted gas reservoir. The researches show that during the CO₂ injection process in the constant volume system, with the increase of the number of mole of CO₂, the gas phase pressure increases, the CO₂ solubility gradually increases, and the mole fraction of H₂O in the gas phase gradually decreases, but the total number of mole of H₂O in the gas phase continuously increases, indicating that the total evaporation of water increases. In addition, the water phase volume reduction caused by water evaporation is smaller than the initial water phase volume, so the increase of formation water salinity is small. The dissolution of CO₂ accelerates the precipitation of CaCO₃, while inhibiting the precipitation of CaSO₄ and CaSO₄·2H₂O. In calcium chloride type formation water, CaCO₃ and CaSO₄ will be separated with the increase of salinity. The research results has certain reference significance for the study of water evaporation and salting out during CO₂ injection in depleted gas reservoirs.

In order to study the physicochemical reaction law of carbonate rock reservoirs under the condition of CO₂ geological storage, lab experiments on the reaction of carbonate rocks and supercritical CO₂ under reservoir conditions were carried out with the carbonate reservoir of the Sinian Dengying Formation reservoirs in the Sichuan Basin as the research object. The response characteristics of carbonate porosity, permeability, and pore structure to supercritical CO₂ environment were investigated by the pressure pulse attenuation method, scanning electron microscopy method, and nuclear magnetic resonance method. The test resulted in an increase both in the porosity and permeability of the carbonate rock. The maximum porosity change rate is 32.35 % and the permeability increases by eleven times. Additionally, micro-fractures appear after the test, and the proportion of the micro-fractures with the aperture of 20~50 μm increases. By using X-ray diffraction and contact angle techniques, the mineral makeup and wetability of carbonate rocks were examined. The average content of main minerals quartz increased by 12.6 %, the average content of calcite decreased by 22.3 %, and the hydrophilicity increased. Brazilian splitting technique was used to examine the mechanical characteristics of carbonate rocks both before and after supercritical CO₂ immersion. The tensile strength of carbonate rocks was discovered to have fallen by 18.28 %, causing damage to the rocks, and the compaction stage of the load-displacement curve was longer. This work examines the effects of supercritical CO₂ dissolution on the porosity, permeability, mineral composition, and rock mechanical characteristics of carbonate rocks, and provides theoretical evidence for the geological storage of CO₂ in carbonate reservoirs.

Under the situation of intensifying CO₂ emissions and increasingly serious environmental problems, carbon emission reduction is urgent. CO₂-EOR is the main means of geological storage of CO₂, but most of the researches on CO₂-EOR at home and abroad are to study the residual oil, and there are few studies on the form of CO₂ storage during oil flooding. In this paper, nuclear magnetic resonance is used to detect CO₂ displacement online combined with numerical simulation is used to study the CO₂ storage morphology and distribution characteristics of different core saturated oil after gas flooding. The results show that the NMR technology combined with the microscopic gas flooding oil numerical simulation method can effectively study the microscopic storage morphology of CO₂. When CO₂ in the core replaces crude oil, it first enters the large pore to drive oil, and after the pressure in the large pore reaches a certain level, the crude oil flows to the small hole throat with uneven distribution of capillary force around it, and the gas continues to drive the crude oil until the small pore pressure accumulates to a certain value in the small pore. Numerical simulations are performed using COMSOL Multiphysics software. Microscopic simulation results shows that CO₂ in large pores mainly exists in the form of continuous free gas, while CO₂ in small pores is first retained in dissolved form. There is no CO₂ completely stored in free gas or dissolved gas in both large and small pores.

CO₂ storage in abandoned oil and gas reservoirs can reduce the direct emissions of greenhouse gases in the atmosphere, which is one of the effective ways to mitigate the greenhouse effect. Improving the conventional gas-liquid phase equilibrium theory and applying the thermodynamic equation of state to study the CO₂-hydrocarbon-groundwater system are of great significance to reveal the dissolution mechanism of CO₂ buried in the subsurface. The research progress of thermodynamic equation of state in the phase equilibrium calculation of CO₂-hydrocarbon-formation water system at home and abroad is summarized.The shortcomings in its practical application are pointed out, and its development trend is analyzed, including: the equation of state and mixing rules suitable for non-ideal systems should be further studied to accurately predict the change law of thermodynamic properties of the system; the expansion of the difference of formation water ions in the research system to make it consistent with the real CO₂ storage conditions; the physical process of phase change in CO₂ is coupled with the chemical process of mineral dissolution and precipitation in formation water.

The stability of foam system is very important in the application of foam flooding and gas reservoir foam drainage agent. The influence of surfactant molecular structure and interface arrangement on the permeability and stability of foam liquid film is of great significance for the construction of highly stable CO₂ foam, but there is no systematic understanding at present. The betaine surfactant with four molecular structures is used as the research object, and the foam phase property evaluation is used as the research method. For the saturated adsorption capacity, foam liquid film permeability, foam stability and other phase properties, the surfactant molecular structure, interface arrangement, CO₂ foam liquid film permeability, foam stability and their correlation experiments are carried out. The results show that when the molecular head groups of surfactants are consistent, the hydrophobic carbon chain length increases, the hydrophobic effect increases, the molecules on the liquid film surface are arranged more closely, the permeability of foam liquid film decreases, and the stability of foam increases. When surfactant molecules have longer hydrophobic carbon chains, the enhanced hydrophobicity leads to a tighter arrangement of the liquid membrane and an increase in adsorption capacity, hindering the permeation behavior of CO₂ gas within the bubble and weakening the foaming ability of the foaming solution. Based on the regression analysis of the parameters obtained from four foaming systems, the correlation coefficient R² between foam life, foam liquid film molecular adsorption capacity and foaming capacity and foam liquid film permeability K is established. The fitting shows that R²>0.90. Therefore, the permeability of foam liquid film K can be used as one of the parameters to evaluate the stability of foam system and provide a reliable evaluation parameter for the screening of highly stable foam system.

Cap rock is the most important geological structure in CO₂ storage, and the characterization method of its sealing capacity is a hot research topic at present. Aiming at the problem of evaluating the sealing ability of caprock, based on the theory of coupling parallel capillary bundle and DLVO（microscopic force of charged surface passing through liquid medium）, considering slip effect and water film effect, the theoretical calculation method of caprock breakthrough pressure is established, and the accuracy is verified with experimental data. The variation of breakthrough pressure with slip length and effective capillary radius is studied by analyzing the influencing factors. The results show that the relative error between the calculated breakthrough pressure and the experimental data of six core samples is between 0.317 % and 10.800 %. The smaller the slip length and the larger the effective capillary radius, the smaller the breakthrough pressure.

With the continuous development of shale gas, the interference of adjacent wells is increasing during the fracturing of horizontal wells, which has a great impact on the production of gas fields, the safety of casings, and the string of gas wells. The influencing factors of the interference between fracturing wells and the countermeasures to reduce the interference need to be clarified.The field performance of fracturing interwell interference is confirmed by downhole pressure monitoring. Through production dynamic tracking analysis and microseismic monitoring results, it is basically clear that well spacing, fracturing transformation intensity, and natural fractures are the main factors affecting the interference between horizontal wells during fracturing. Three governance strategies have been proposed to reduce fracturing interference, including optimization of fracturing design source, on-site management of gas production wells, and production operation adjustment. These measures have achieved good improvement effects in on-site applications.

Accurate characterization of the flow characteristics of shale gas horizontal wells is the key basis for quantitative evaluation of production performance and further guidance of development program optimization design. In order to explore the gas-liquid two-phase flow law of shale gas horizontal wells at different inclination angles, a three-dimensional simulation wellbore model with the pipe diameter of 0.124 m, pipe length of 10 m and inclination angles of 0°, 5°, 10°, 15°, 20°, 30°, 45°, -5°, -10°, -15°, -20°, -30°, -45° respectively is constructed. The volume model is used to track the gas-liquid interface. The characteristics of gas-liquid two-phase flow in wellbore are dynamically monitored. The flow pattern, velocity and holdup distribution characteristics of wellbore with 300 m³/d liquid volume and 500 m³/d gas volume are obtained by simulation experiments under various well inclination angles, and the influence law of well inclination angle on gas-liquid two-phase flow characteristics of shale gas horizontal wells is deeply analyzed. The results show that the flow pattern of up-dip pipe（well angle is larger than 0°） is characterized by slug flow, and the average fluid velocity changes in a single-peak form with the increase of well angle, and the peak appears when the well angle is 15°. The flow velocity at the gas-liquid interface is the lowest, and the bottom water holdup is larger with lower well angle is than that with higher well angle, and reaches the maximum value when the well angle is 10°. The flow pattern of down-dip pipe（well angle is less than 0°） is characterized by stratified flow, and the average fluid velocity is linearly increasing with well inclination angle. The flow velocity at gas-liquid interface is between the top and bottom value, and the bottom water holdup decreases with the increase of well inclination angle.

In order to explore the characteristics of fracturing fractures of shale with weak plane development, a fracture propagation model of shale reservoirs taking the weak plane of bedding and natural fractures into account is established by the three dimension discrete element method to analyze characteristics of fracturing fractures under different injection rates, fracturing fluid viscosity, bedding tensile strength and natural fracture cohesion. The research results show that the high-displacement injection and high fracturing fluid viscosity can reduce the restriction of near-wellbore bedding on hydraulic fractures and increase the ability of hydraulic fractures to penetrate layers. The hydraulic fractures can continuously pass through six beddings when the fracturing fluid viscosity is increased to 10 mPa·s. The tensile strength of the bedding connected to the natural fracture is not the main factor affecting its own opening. The greater the natural fracture cohesion is, the greater the natural fracture shear strength and the lower the degree of opening of natural fracture will be. When bedding and natural fractures develop near the wellbore, the hydraulic fractures can be fully extended by increasing the injection rates and the fracturing fluid viscosity in the early stage. For shale which is easy to form simple double-wing fractures, pumping an appropriate amount of acid in the early stage can dissolve the natural fracture filler, so as to reduce the natural fracture cohesion, increase its opening degree, and improve the complexity of fractures.

The classification and identification of shale gas “sweet spot” involves a variety of different factors, which requires personal experience, and is usually time and resources consuming. In order to solve this problem, an efficient and effective classification and identification method for shale gas “sweet spot” based on the Random Forest method is proposed. Firstly, data from ten wells in Changning area are selected and eleven features are selected for “sweet spot” classification by the Kendall correlation. Then, the single decision tree and the Random Forest method are used for the “sweet spot” classification and identification. Finally, the results are verified and the Random Forest parameters are optimized. The experimental results show that although the prediction accuracy of a single decision tree can reach 97.7 %, it shows a trend of overfitting, and the fitting accuracy is greatly reduced by only 70.7 % after pruning. The Random Forest method avoids the disadvantage of the single decision tree method, and the prediction accuracy reaches 98 %. Moreover, the computational cost is low, which can effectively reduce the time loss and save the labor cost. As a result, the proposed Random Forest machine learning method with multi-source information is an effective shale gas “sweet spot” classification and identification method.

Palaeogeomorphology and palaeo-environment conditions are the main environmental factors affecting the sedimentation. Due to the frequent water change, complex terrain and high difficulty in seismic identification and tracking, the reconstruction research of palaeogeomorphology and palaeo-environment in the 3rd member of Funing Formation in Qintong Sag of Subei Basin is still insufficient, which affects the overall exploration evaluation of the study area. In order to clarify the palaeogeomorphology and palaeo-environmental conditions of the 3rd member of Funing Formation in Qintong Sag during the deposition period, the formation core, logging data and rock material data are comprehensively analyzed. The semi-quantitative reconstruction of the palaeogeomorphology of the 3rd member of Funing Formation is carried out by combining the palaeo-geologic map, impression method and residual thickness method, and the pyrolysis experiment data, TOC and trace element content data of 33 rock samples from two wells are selected to carry out the palaeo-environment reconstruction analysis. Accordingly, paleogeomorphology reconstruction in map form and the curves of palaeo-environment changes of the 3rd member of Funing Formation in Qintong Sag are drawn, which prove that the study area is a half-graben, lower in the South and higher in the North with the convergence across the east-west direction, the climate is warm and humid during the sedimentary period, the water body activity is frequent and recurrent, the water salinity is low, the multiple source is supplied intermittent, the material source input continues to increase, and the deposition rate is fast. Therefore, the corresponding relationship between stratigraphic physical parameters and paleogeomorphology, geochemical parameters and paleoenvironment in the study area are clarified, which provide reference for the further exploration and development.

At present, the researches on the heat transfer of the steam cavity edge in the SAGD production process mainly pay attention to the heat conduction between steam and the reservoir, while little attention has been paid to the convective heat transfer and changes of the reservoir physical properties affected by the temperature. However, the influence of both on the heat transfer effect and temperature field distribution cannot be ignored. By the comprehensive consideration of two heat transfer mechanisms of heat conduction and heat convection, as well as the influence of reservoir physical properties changes on heat transfer, a semi-analytical model is established through the conservation of mass, energy and mathematical coordinate transformation, and the temperature distribution at the edge of the steam chamber and the physical property distribution of the reservoir under the influence of temperature are obtained by differential solution. The results show that: ① the model proposed in this paper is more practical, with an accuracy improvement of 34 % and 11 % compared to the Butler's model and the Dong's models, respectively. ② By analyzing the relative relationship between convection and conduction under the change of reservoir physical properties, it is concluded that the proportion of the conduction heat transfer in the crude oil movable area is more than three times higher than that of the conduction heat transfer, the convection heat transfer accounts for the main proportion in the movable area of crude oil, but at the locations far away from the steam cavity, the conduction and convection work together, and it also gives relevant measures to improve heating efficiency.

The development of the natural gas hydrate reservoirs has the typical characteristics of high risk, high difficulty and high investment, so the correct evaluation of development quality is a prerequisite and the key to the issue. In order to solve the problems that the evaluation index has limitations and the evaluation results has ambiguity for the development of the natural gas hydrate reservoirs, the factor set is chosen based on the main controlling factors, and the scoring criteria of main controlling factors are defined. The weight set is established by the comprehensive weight calculated by analytic hierarchy process, and then fuzzy comprehensive evaluation of development quality of natural gas hydrate reservoir is further completed. This method is used to evaluate the development quality of Messoyakha and other typical natural gas hydrate reservoirs, and the applicability and feasibility of the method are verified, so as to provide theoretical basis and technical support for the efficient development of the natural gas hydrate reservoirs.

Offshore natural gas hydrate reservoirs are often accompanied by a large amount of free gas. However, the low permeability of the reservoir limits the flow of gas and water in different layers. Therefore, the fully exploitation of the hydrate-dissociation gas and free gas in the reservoir is the key to improve gas production efficiency. Based on the actual geological data in the Shenhu area of the South China Sea, the TOUGH+HYDRATE code is used to establish the numerical model of the combined exploitation of three different hydrate reservoirs with vertical wells. The spatial changes of gas production, water production, temperature, pressure field and hydrate saturation are analyzed, and then the optimized depressurization production strategy of natural gas hydrate is put forward. The results show that during the depressurization production, gas and water are continuously collected to the production well, and the temperature and pressure around the well drop rapidly. After continuous production for ten years, the water production rate continues to increase with the decrease of gas production rate. The cumulative gas production of three-layer combined mining method is up to 4.59×10⁶ m³, and the cumulative water production is 8.31×10⁵ m³. Hydrate dissociation is controlled by the depressurized gradient, hydrates around the well are preferentially dissociated, and the flow of underlying water will accelerate the dissociation of reservoir hydrates.