In recent years, extensive attention has been paid to the decarbonization of petroleum and gas exploration and related technologies at home and broad. The structural transformation of the energy industry of the oil and gas is one of the inevitable ways for China to achieve the “carbon peak and neutrality” targets. Under the prerequisite of energy reform to accelerate the achievement of the targets, the energy reform direction and pathway for the oil and gas technology have been analyzed. Taking the project of the electricity substitution technology in the PetroChina Southwest Oil and Gasfield Company as an example, the changes in terms of environmental pollution and energy consumption before and after the implementation of the project are compared. Then, it focuses on the necessity of the drilling and completion electrification transformation and the advantages of the drilling and completion are emphasized. Based on the analyses and summary of the key and difficulties in the practice process, the key technologies that restrict the development of electricity substitution technology and the breakthrough points of the future researches are put forward, which provides reference for the application of “electricity substitution” technology in oil and gas exploration and development under the “dual-carbon” targets.

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.

The minimum miscible pressure （MMP） of CO₂ flooding is a crucial parameter to judge whether miscible flooding is attainable. In order to reduce the application threshold of miscible flooding, the MMP between CO₂ and crude oil needs to be reduced urgently. Adding miscible flooding assistants to oil reservoir is an effective means for minimum miscible pressure reduction. At present, according to the elements contained, the miscible flooding assistants can be divided into three categories including fluorocarbon, siloxane, and hydrocarbon （oxygenated）. In order to reduce the cost and improve the MMP reduction performance, the hydrocarbon structure should be added to the fluorocarbon assistants to make the assistants develop in the direction of mixing type. The hydrocarbon assistants have sound MMP reduction performances and room for improvement. The key is to find a suitable CO₂-phlic structure. Computer simulation is also a vital means to study micro mechanism and assist structure designing. Compared with fluorocarbon and siloxane, the cost of hydrocarbon （oxygenated） is lower, and it has the most application potential from the prospective of cost. At present, the main factor affecting the large-scale application of miscible assistants is the limitation of cost. The promotion and application in the future needs the close cooperation of petroleum and chemical practitioners. In this paper, the mechanisms of CO₂ miscible flooding assistants reducing MMP are introduced. The structures of existing miscible flooding assistants, MMP reduction effectiveness are summarized, and the influencing factors on MMP reduction efficiency are analyzed. The developing directions CO₂ miscible flooding assistants designing are prospected.

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.

CO₂ gas channeling time prediction is of great significance for CO₂ gas channeling prevention and enhanced oil recovery. Current studies rarely involve quantitative characterization of the gas channeling time. According to the parameters of the target block reservoir, the crude oil viscosity, reservoir permeability, gas injection rate and injection-production well spacing and other factors impact on the moving rule of the CO₂ drive front is analyzed by the numerical simulation method, then the characterization formula of gas flow time and gas flow influence coefficient considering multiple factors is established, and the accuracy of the formula is verified by comparing with the field practice. The results show that under the condition of constant pressure production, the sweep efficiency decreases with the increase of crude oil viscosity. When the crude oil viscosity is greater than 3 mPa·s, the increase of gas emergence time slows down. When the reservoir permeability increases, the seepage resistance decreases, the displacement front moves faster, and the oil well breaks out earlier. When the gas injection velocity increases, the leading edge movement speed increases and the gas appearance time advances. When the gas injection velocity is 2 500 m³/d, the sweep efficiency is the minimum. When the injection-production well spacing increases, the moving speed of gas front slows down, and the gas emergence time of oil well prolongs. When the injection-production well spacing is larger than 250 m, the well spacing continues to increase, and the sweep efficiency increases slightly.

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.

The leakage of fluid （CO₂, brine and freshwater） along fault is a crucial issue that cannot be ignored during CO₂ geological storage. For this reason, the equations to describe the fluid leakage rate along faults in different stages are derived. Then, these equations are combined with mass and energy conservation equations to establish the fluid leakage model in CO₂ storage processes by considering geologically activated faults. In such case, the crucial parameters （i.e., leakage time and leakage amount） for fluid leakage along a fault are obtained. The results of the effects of different parameters on leakage time and amount show the advanced initial time of CO₂ leakage, the extended duration and the increased leakage amount of CO₂, with CO₂ injection rate and reservoir permeability increasing. Meanwhile, the initial time and duration of CO₂ leakage are unchanged while the leakage amount of CO₂ is increased, when increasing the fault permeability. In addition, the fault permeability has the greatest impact on the leakage amount of brine and freshwater, compared to CO₂ injection rate and reservoir permeability. The numerical results show that brine starts to leak earliest, followed by CO₂, freshwater. Meanwhile, the duration of CO₂ leakage along a fault is the longest, while the duration of brine leakage is the shortest. Additionally, the leakage amount of CO₂ is the largest, followed by brine leakage amount and the freshwater leakage amount.

Currently, there are few works on the laws of front migration and gas channeling with laboratory experiments from the aspect of CO₂ sweep efficiency. Therefore, a visual physical simulation device is used to carry out the physical simulation experiment of CO₂ immiscible flooding of slab core. The influences of factors such as crude oil viscosity, reservoir permeability, reservoir heterogeneity and injection rate on the migration of CO₂ immiscible flooding front and gas channeling laws are analyzed. The study found that under the conditions of constant flow injection in injection wells and constant pressure production in production wells, the viscosity of crude oil decreases, the permeability decreases, the reservoir is homogeneous, and the injection speed increases, which will lead to an increase in the recovery degree of CO₂ immiscible flooding. Meanwhile, the decrease in the viscosity of crude oil, the lower the permeability, and the increase in the injection rate, also lead to the enhancement of the ability of the oil well to continue to expand sweep factor after gas breakthrough, that is, it can alleviate gas channeling. It is concluded that under the condition of constant flow injection in injection wells and constant pressure production in production wells, high injection rate development can alleviate gas channeling and obtain better development results. When the injection rate increased from 0.1 mL/min to 2 mL/min, the recovery increased from 15.4 % to 35.3 %, and the sweep factor difference increased from 8.3 % to 26.2 %. This research is of great significance for CO₂ immiscible flooding gas channeling suppression and enhanced oil recovery.

During the reaction between CO₂ and rocks, there is a synergistic/coupling effect among minerals because the rocks contain quartz, potassium feldspar, albite and other components, which promotes or inhibits the reaction process to a certain extent. The chlorite is an important clay mineral of sedimentary rocks. In order to clarify the chemical behavior and change process of the chlorite in the CO₂ aqueous solution, the state of chlorite reacting with CO₂ respectively for 7 and 30 days at 10 MPa and 60 ℃ are systematically evaluated by means of XRD（X-Ray Diffraction）, XRF（X-Ray Fluorescence）, ICP（Inductively Coupled Plasma）, and SEM（Scanning Electron Microscopy）, focusing on the comparison of the change of the solid elements, the crystal structure and the ion concentration in the reaction solution before and after chlorite powder reaction. Combined with the structural characteristics of chlorite, the mechanism of chlorite change is clarified. The results show that the concentrations of Ca²⁺, Mg²⁺ and Al³⁺ in the liquid phase firstly increase and then decrease after the reaction of the chlorite with CO₂. The concentration of Si⁴⁺ firstly increases and then is stabilized. The crystal planes corresponding to chlorite d（002） and d （004） peaks in the solid phase are destroyed after the reaction, and the mass ratio of Si and Al in the solid element increase from 4.82 to 5.39. Under the acidic conditions, hydroxyl groups in brucite flakes are easier to combine with H⁺ and release cations such as Fe²⁺, Mg²⁺, Al³⁺, etc. Because the brucite octahedron is more prone to ion exchange than silica tetrahedron and alumina octahedron, Mg, Al, Fe and other elements in brucite flakes are dissolved before Si and Al in silica tetrahedron and alumina octahedron.

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.

The implementation of CO₂ flooding in heavy oil reservoirs with low-permeability is currently the main comprehensive utilization technology for enhanced oil recovery. However, due to the low viscosity and high mobility of CO₂, CO₂ flooding in heavy oil reservoirs is prone to premature gas channeling. For this reason, the feasibility of low permeability heavy oil reservoirs with CO₂-viscosity reducer to reduce viscosity and improve mobility ratio has been explored, and the mechanism of the combined flooding of CO₂ and water-soluble viscosity reducer for low-permeability heavy oil reservoirs to EOR is obtained. The results show that the KD-45A water-soluble viscosity reducer can only emulsify the surface of crude oil to reduce the viscosity without external stirring. The viscosity reduction effect is poor, but the viscosity reducer slug can improve the mobility ratio caused by viscosity differences, which can effectively control the CO₂ rushing along the airflow channel. The O/W-shaped emulsion transition zone formed by the emulsification of the water-soluble viscosity reducer has a viscosity close to the water phase, which can prevent the fingering of the water-soluble viscosity reducer, so that the viscosity reducer slug has a more obvious control and displacement effect on CO₂, and the swept area of CO₂ is larger. The dissolution of CO₂ in the viscosity reducer will reduce the interfacial tension of the CO₂-viscosity reducer system, which can give full play to the synergy between the two displacement effect. The formation of carbonized water after CO₂ dissolves in the viscosity reducer can greatly reduce the influence of gravity and viscosity differences on the swept area, forming a relatively stable and continuous displacement interface. The displacement mechanisms of the combined flooding system are synergistic and superimposed, which can significantly improve the recovery rate of heavy oil.

In order to ensure that the best oil recovery and displacement method of the new target block of the oilfield could be selected in the process of tertiary oil recovery, based on the application of tertiary oil displacement method in typical blocks at home and abroad, 23 reservoir parameters have been studied as the key parameters that affect the displacement mode, and the fuzzy evaluation method are used in the process. And then, the correlation between the target area and the test area is calculated by the improved Deng’s correlation method, so as to predict the recovery ratio of the target area. The study of a new block of some oilfield in China verify that the best displacement mode is fire flooding. The proposed proposed method provides a calculation basis for the optimal displacement method of the new block.

In order to solve the problems that the effectual time and effective features of polymer flooding in horizontal wells of oilfields developed directly after natural energy development are quite different from those of polymer flooding in high water-cut periods, a more efficient and convenient way to determine the effectual time of polymer flooding is proposed by production dynamic analysis, that is the change features of production capacity, water cut and submergence depth. Based on the effectual time, the production period after polymer injecting is divided into the induced effective period, the dominant effective period and the subsequent effective period, and the relation between the injected pore volume and the stage is established. Then, a study has been conducted to characterize the changes in injection pressure, injection capacity, oil production capacity and integrated water content at different injection pore volumes, and the purpose and main content of the on-site measures at each stage have been clarified. According to the reservoir conditions in the polymer flooding well area and the outstanding problems exposed during the polymer flooding process, the influence of these factors on the development effect of the polymer flooding well group is evaluated and the main factors affecting the development effect of the current polymer flooding well group is clarified. This research provides a reliable basis for the efficient management of the oilfield polymer flooding well group on-site, and clarifies the target well areas of the subsequent conversion well group.

After multi-cycle steam stimulation in HJ Oilfield, the changes of reservoir physical properties are obvious and difficult to determine, which brings serious obstacles to the design and implementation of subsequent development measures. In order to solve this problem, the relationships among porosity, permeability, wettability and steam stimulation cycles are conducted by using one-dimensional physical simulation experimental setup after the design of sweep multiples based on two wells, Well-J151 and Well-J117 in HJ Oilfield. The results show that the physical property parameters of reservoir will change under the long-term sweep of high temperature steam. In the scope of steam sweep, both porosity and permeability all increase with the increase of the steam stimulation cycles. With the increase of steam stimulation cycles, the lipophilicity of reservoir rocks gradually weakened and the hydrophilicity gradually strengthened. Based on the experimental results, the relationship between sweep multiples and porosity growth rate, as well as the chart of the relationship between oil layer sweep multiples and permeability growth rate are established. The parameters of the porosity and permeability of reservoirs in different stages of steam stimulation development can be predicted by the above relationship and chart, and the relationship and chart can be also extended to other similar heavy oil reservoirs.

Natural gas hydrate are rich, which is one of the most potential new energy resources with abundant resources. However, gas hydrate has not been exploited commercially at present, and its micro-structure characteristics and gas storage mechanism need to be clarified urgently. Based on the framework and guest molecular information of SI, SII and SH type gas hydrates, the molecular models of three typical gas hydrates are constructed and optimized. The hydrogen bonds number, hydrogen bonds length, porosity, pore composition, pore size distribution and other structural characteristics of hydrates are determined by structural characterization, and the micro-structure differences of three typical hydrates are compared and analyzed. Based on the hydrate skeleton structure, the adsorption behavior of methane and carbon dioxide is studied by the grand Canonical Monte Carlo method. Combined with the adsorption capacity and adsorption heat, the gas storage characteristics and differences of the three hydrates are clarified. The results show that the hydrogen bonds in SII hydrate are the longest and the most abundant, but the pore connectivity is the worst. High pressure is conducive to increasing the gas storage capacity of hydrate, while low temperature can increase the stability of gas adsorption in hydrate. Although the amount of carbon dioxide storage is smaller than that of methane, the adsorption stability of carbon dioxide is stronger. The adsorption capacity of gas in SII type hydrate is the largest, and the adsorption heat in SI type hydrate is the largest.