Since the 1970s, CO₂ flooding-EOR technology has formed multiple development modes in the concept of reservoir engineering, including continuous CO₂ injection, WAG injection with constant proportion, tapered/hybrid WAG injection and SWG/SSWG injection. The reason why CO₂ become the injection gas for tertiary oil recovery with great vitality benefits from its supercritical fluid characteristics and remarkable solvation capacity. Based on the analysis of the main oil displacement mechanism of CO₂ and the reservoir engineering concept and development mode of typical CO₂ flooding-EOR technology at home and abroad in recent years, and considering their development characteristics of different types of reservoirs, especially the successful application of horizontal well technology and low permeability reservoir volume fracturing technology, as well as the comprehensive utilization concept of CO₂ CCUS-EOR combined with CCUS concept, further suggestions are put forward for the development of reservoir engineering development mode by CO₂ flooding-EOR technology in China, so as to provide enlightenment for further promoting its large-scale development.

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.

In tight reservoirs with low permeability, the effect of porous media on fluid phase behavior can not be ignored. Therefore, the experiments of fluid phase behavior in PVT cylinder and porous media at different conditions of the dissolution gas and the permeability values are established based on full diameter core holder. The results show that the bubble point pressure of crude oil in porous media is lower than that in PVT cylinder. The difference between these two conditions become more evident as the dissolution gas volume becomes lower or the permeability becomes smaller. Based on the above results, the specific value of the diameter of hydrocarbon components and the average diameter of rock pore space is introduced into the function a（T）, modifying the classic SRK EOS equation and proposing the prediction model to calculate the parameters of crude oil in porous media. The simulation results are in good agreement with the experimental data. Furthermore, the EOS and characterized method are modified and established.

Serious retrograde condensation has occurred before the development of gas cap in South A condensate gas reservoir of Zanarol Oilfield, resulting in serious loss of condensate oil. It is particularly important to explore the method of improving the production of condensate oil for the further development of oilfield. Therefore, taking a typical well in South A gas reservoir as a example, the phase equilibrium theory and numerical simulation are applied to study the retrograde condensation rule of formation fluid and the distribution of condensate oil in formation. On this basis, the mechanism and effect of condensate oil enhancement by CO₂ huff-n-puff are researched. The results show that retrograde condensation in South A gas reservoir has two stages: constant composition expansion（CCE） and constant volume depletion（CVD）. Condensate oil distributes mainly within 30 m of wellbore, and its saturation ranges from 22.44 % to 29.51 %. The mechanism of CO₂ increasing condensate production is to change the retrograde condensation rule, reduce pressure condition of retrograde condensation, and evaporate condensate oil. However, if the injection volume of CO₂ is low, the volume of vaporized condensate oil will be small, which limits the effect of EOR. Therefore, the cumulative injection of CO₂ should be more than 500×10 ⁴ m ³ at a cycle to ensure the effect of CO₂ huff-n-puff. This study has guiding significance for condensate oil enhancement and plug removal in the middle and later stages of similar condensate gas reservoir development.

CO₂ is widely used as a displacement agent in oil displacement because of its unique physical properties and its chemical reaction with crude oil. But pure CO₂ gas flooding is prone to gas channeling. So the application of CO₂ in the foam flooding process make CO₂ can not only play its own role in oil displacement, but also realize fluidity control and reduce the possibility of gas channeling. In this study, the stability, particle size change and percolation characteristics of CO₂ foam with different particle sizes and the same chemical composition are experimentally studied, the change rule of the influence of particle size on foam performance is obtained, and the influence mode is analyzed and discussed. The results show that the smaller the bubble size, the better the stability of the foam system, the stronger the blocking ability, and the slower the particle size changes over time. Changing the preparation method to reduce the particle size of the foam system can effectively improve the foam’s stability and EOR capacity.

Xingbei block in North Jiangsu Oilfield is a complex fault block with heavy oil and bottom water reservoir. High viscosity and poor flowability of crude oil lead to low oil recovery. As it is difficult to realize the economical and effective development of this heavy oil reservoir by conventional technique, a method of combined stimulation of CO₂ and viscosity reducer is proposed for EOR in heavy oil reservoir with bottom water. Viscosity reducer plays an important role in this method. A new polymer surface active agent for viscosity reduction is synthesized by introducing the benzene ring structure into viscosity reducer. The performance evaluation of this new viscosity reducers is carried out from the aspects of concentration, temperature, salinity and pH value. It shows that the viscosity reducer has good temperature resistance and salt tolerance. When the viscosity reducing agent concentration is 0.5 %, the viscosity reducing rate of heavy oil reaches more than 90 %. It also has a stable viscosity reducing ability mixing with CO₂. Good effects of increasing oil production and reducing water cut have been achieved in the in-site implementation. There will be a promising prospect in the economic and effective development of North Jiangsu Oilfield and other similar domestic heavy oilfields with complicated fault block.

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.

CO₂ flooding is effective for enhancing the oil recovery in low permeability reservoir and reducing the greenhouse gas emissions. In order to solve the technical problems of difficult miscible phase, easy gas channelling and low sweep coefficient for CO₂ flooding in low permeability reservoir in Shengli Oilfield. By the combination of physical and numerical simulation, the development mechanism of the CO₂ injection miscible flooding long in advance is clarified, and the comprehensive techniques for extra low permeability reservoir is formed. After field application, the stimulation effect is obvious, the daily production of oil per well increase by 5 times. The principle and technical idea of reducing the miscibility pressure are put forward, and the system of reducing the miscible pressure system is developed, which can make the pressure decrease by up to 22 %. The challenge and countermeasure faced by scale application of CO₂ flooding in Shengli Oilfield are analyzed, and the development directions of CO₂ flooding are proposed, such as deepening the phase state theory of oil recovery enhanced by CO₂ flooding, developing CO₂ flooding technology with expanded sweep volume at low cost, developing incomplete CO₂ miscible flooding, and description and early warning of gas channeling. All these provide technical support for oil field to realize scale application of CO₂ flooding.

CO₂ injection for enhanced oil recovery（EOR） has gone though 4 stages of technical improvements in North Jiangsu Basin. During the current low oil price period, three challenges are exiting: the high cost of CO₂ flooding makes it difficult to realize benefit development, the minimum miscible pressure（MMP） is too high to enhance oil recovery substantially, and the heterogeneity is too strong for expanding CO₂ swept volume. Therefore, three main countermeasures is put forward. Firstly, the optimization of scheme is the key. By full advantage of the old wells to reduce investment for new wells, optimization of injection mode to reduce injection volume, use of current equipment to reduce recycling cost, and overall plan for the pipe network to reduce gas cost, the cost of CO₂ flooding is reduced, thus, the equilibrium oil price of 60 % of the CO₂ flooding project will be kept below ＄60/bbl. Secondly, screening and evaluation of additives to reduce MMP are carried out. Meanwhile, the miscible condition was improved and the recovery rate of CO₂ flooding was increased by the injection in advance to increase the formation pressure. Tiredly, the swept volume of CO₂ is improved by means of injection at the high parts, water alternating gas injection（WAG）, and profile modification to mitigate gas channeling. The research and practice offer reference and examples for the beneficial development of CO₂ flooding in similar reservoirs under low oil price.

CO₂ immiscible flooding is a very important technology for low permeability reservoirs with strong heterogeneity, high miscibility pressure of crude oil or severe reservoir voidage. Firstly, the expansion experiments and MMP test of CO₂ injection are carried out, and the IFT and mole content of oil and gas phase of each block are tested by numerical simulation. And then, the dominant mechanism of CO₂ injection to recover reservoir energy and improve oil displacement efficiency in low permeability reservoir are revealed. Therefore, taking M Block with low-permeability as the research object, and based on 3D fine geological modeling, the numerical simulation is applied to optimize reservoir pressure, gas injection volume, gas injection velocity, shut-in gas-oil ratio and other parameters, and the optimal technical policy is formulated. Preferable recovery performance is obtained through field application. The results show that for the CO₂ immiscible flooding technology in low permeability reservoirs, dissolving and expanding oil phase by gas injection are the dominant mechanism for both recovering reservoir energy and improving oil displacement efficiency, besides, the latter still need to reduce the IFT and evaporate and extract the light components. This study provides a reference for the formulation of CO₂ immiscible continuous flooding scheme in other reservoirs of the same type.

In order to further study the EOR effect of condensate gas reservoir in Zhongyuan Oilfield, the lower third member of Shahejie Formation of a block is taken as an example. Based on the theoretical support of material balance equation and state equation, laboratory experiments such as PVT phase state and physical simulation are carried out to reveal the development rule and deeply analyze the reasons of low production, even no production, of this gas reservoir, so as to recognizes the current situation. For the first time, a two-way EOR method by dry gas injection with pressure maintaining after plugging removing near wellbore area conforming to the geological characteristics of the condensate gas reservoir in this block is proposed. Physical simulation experiments of plugging removing by CO₂ flooding for natural cores at injection end and extraction end are conducted respectively. The corresponding permeability after plugging removing is 60.44 % and 63.15 %, showing that the effect of plugging removing by CO₂ injection is good. On this basis, experiment of core displacement with dry gas injection is conducted with the result that at the beginning, dry gas injection with pressure maintaining under the original formation pressure of 41.19 MPa for condensate gas reservoir can make the condensate oil recovery ratio up to 91.41 %; when the pressure decline to the plugging pressure of 21.14 MPa, using this method again, the recovery ratio can be 44.28 %. By the researches, the formation physical model of oil-water emulsification plugging, because that the near wellbore area pressure is lower than the dew point pressure in the development process, is further clarified, providing technical support for the benefit development of low permeability tight condensate gas reservoir in Zhongyuan Oilfield.

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.

In the CO₂ flooding environment, puncture occurs frequently in the gathering and transportation pipeline network composed of carbon steel pipelines. So it is of great significance to reduce corrosion and maintenance costs by using reinforced plastic non-metallic pipes instead of some metal pipes. Corrosion immersion experiments are conducted to study the changes of permeability, expansion and mechanical properties of swelling and mechanical properties of flexible composite pipes and aramid glass steel pipes under high salinity and CO₂ content with immersion periods. The results show that as the immersion periods increases, the permeability and expansion rate of the two non-metallic materials increase, but the tensile strength decreases. Among them, aramid glass steel pipe has higher permeability, relatively smaller expansion rate, and higher tensile strength. The flexible composite pipe has the smaller permeability, a relatively larger expansion rate, and the smaller tensile strength. After the strength check relay on the changed mechanical properties, both materials can meet the gathering and transportation pressure requirements of 3 MPa. Based on the experimental results, the maximum allowable pressure for different pipeline specifications is calculated.

In order to effectively solve the CO₂ flooding gas channeling in Caoshe Oilfield, two kinds of gas-soluble foaming agents, fluorine-containing foaming agent（agent A） and silicon-containing foaming agent（agent B）, are evaluated from three aspects: dissolution, foaming and plugging, and one of them is selected as the CO₂ flooding sealing system in Caoshe Oilfield. The optimal injection concentration is 1.5 %. According to the experimental results, the solubility of agent A and agent B in supercritical CO₂ under the assistance of the co-solvent, ethanol, reach 2.51 % and 1.93 % respectively, and both of them can form the dissolution conditions of stable foam. The comprehensive performance of foam produced by agent B is better than that of agent A. When the concentration of agent B reaches 1.5 %, the foaming performance is the best. Under the condition of high temperature（110 ℃） and high pressure（15 MPa）, the foaming volume reaches 261 mL, and the half-life period reaches 115 min. From the aspects of dissolution and foaming, agent B is optimized as the foam sealing system of CO₂ flooding in Caoshe Oilfield, and the evaluation experiments of CO₂ foam sealing ability under different injection modes are carried out. When CO₂ and foaming agent are injected alternately as the injection mode, the mixture is more uniform with more foam, and the resistance factor is high and can be more than 40, showing good foaming and plugging performance. The researches of sealing channeling system provide a new technical support for preventing gas channeling in CO₂ flooding of Caoshe Oilfield.

In recent years, the application scale of chemical flooding technology has been increased, but the results of some field tests are not ideal. There are many reasons for this situation, including the adaptability of profile control and displacement agent with reservoir pores. Aiming at the actual demand of field production and theory, the evaluation method and technical index of transport capacity of chemical profile control and flooding agent are studied. The results show that the transport capacity of profile control agent in porous media is a necessary condition for realizing the diversion of deep liquid flow. The transport capacity can be evaluated by the ratio of the pressure difference（β） between the front and the back of core at the end of injection of profile control agent. The recommended technical index ranges are as follows: ① β=1~3, good transport capacity; ② β =4~8, medium; ③ β=9~15, poor; ④ β>16, poor. The retention and transport ability of profile control and displacement agents are closely related to the molecular structure of materials, aggregate size and core permeability. Their purposes are contradictory and need to be taken into account reasonably in practical application. Viscosity is an index to evaluate the internal friction of fluids. The internal friction of polymer solution is related to polymer concentration, molecular aggregate morphology and salinity of solvent water. The size of polymer aggregates can be changed by intermolecular physical association and chemical cross-linking reaction, which can increase the friction force and viscosity of polymer solution, but this will also lead to poor transport capacity of polymer solution, and then weaken the deep retention and liquid flow diversion effect of polymer solution.

In Ordovician of Tahe Oilfield, the bottom hole temperature is high, the seam hole is developed, the leakage easily occurs, and the annular clearance of cementing is small. Therefore, the conventional low density cement slurry system cannot guarantee the sealing integrity of cement sheath and meet the requirements of exploration and development. Aiming at the above difficulties, the modified fly ash is optimized to enhance the early strength of cement, the high anti-extrusion microsphere is compounded to improve the comprehensive performance of cement slurry, the high temperature elastoplastic material is optimized to reduce the elastic modulus of cement, and the low density elastoplastic cement slurry system is evaluated combined with the matching cementing additives. The density is applicable in the range of 1.25~1.50 g/cm ³, API water loss is less than 50 mL, the rheological properties is good, the right-angle is thickening, the cement slurry settlement stability is good, and the system has good mechanical properties. Meanwhile, the elastic modulus can be as low as 7 GPa and the compressive strength is greater than 14 MPa. All these things enhance the sealing integrity of cement sheath under the action of alternating stress. The applications of this system in well-Zhongtan-1 and well-TP193 of Tahe Oilfield are successful and the cementing quality are well, which indicate that the system can meet the cementing technical requirements of small clearance liner in the leaky formation of Ordovician and has a good application prospect.

Taking the conglomerate reservoir of the Lower Karamay Formation in Qidong-1 area of Karamay Oilfield as the research object, the relation between physical properties, lithology and pore structure modes and the degree of recovery of polymer flooding is studied by laboratory experiments. And by means of nuclear magnetic resonance（NMR） technology, the experimental method of the study on the kinetics of polymer crude oil utilization is established and the kinetics of micro-porosity in the polymer flooding process of conglomerate reservoirs is analyzed. Through the micro-displacement experiments, the residuals after polymer flooding in conglomerate reservoirs are analyzed. The results show that the polymer flooding mainly displaces the cluster-like residual oil and the island-like residual oil. The polymer-driven residual oil accounts for the largest proportion of the total remaining oil. During the polymer flooding process, due to the complex pore structure of conglomerate and high viscosity of polymer solution, the large oil droplets are sheared into small oil droplets, and partially of which are dragged out of the pores by the polymer solution. The correlation between the degree of enhanced oil recovery by polymer flooding and core porosity and permeability is not obvious, however, it is related to the lithology and pore structure of the reservoir. The order of enhanced oil recovery with different lithologic polymer flooding from coarse to small is: boulder coarse sandstone>glutenite>unequal grain small conglomerate>fine conglomerate. There is a quadratic parabola relation between the degree of polymer recovery and dynamic oil saturation.

In order to further study the reasonable production allocation and drainage control method, and extend the high and stable production period of CBM wells, the reasonable production allocation is proposed by comparative researches on the isothermal adsorption of coal bed and production parameter of CBM wells in South Yanchuan CBM field. On the basis of the comparative analysis of the parameters and dynamic regulation of coalbed methane drainage on site, and taking coal reservoir pressure, critical desorption pressure, Langmuir pressure and stable production pressure as the key control nodes, the drainage process of CBM wells can be divided into five stages, and then the method of production parameter control during every drainage stage is studied. The result shows that the gas yield peak appears when the bottom hole flowing pressure is at about Langmuir pressure of coal bed in South Yanchuan CBM field. There is a good linear relation between the stable gas production and the peak gas production, as well as that between the stable flowing pressure and the Langmuir pressure. The fitting formula can be used to calculate the reasonable stable flowing pressure and stable yield of each well. The above five stages are fast drainage stage, slowly pressure drop drainage stage, gas yield rising stage, gas yield fluctuation stage, and stable yield stage. For the South Yanchuan CBM field, the reasonable bottom hole flowing pressure drop is about 0.1 MPa/d during the fast drainage stage. The drainage control at slowly pressure drop drainage stage, gas yield rising stage, and gas yield fluctuation stage are very important. The bottom hole flowing pressure drop should be about 0.003 MPa/d during the slowly pressure drop drainage stage, less than 0.005 MPa/d during the gas yield rising stage in Tanping structural belt, less than 0.01 MPa/d in Wanbaoshan structural belt, and about 0.003 MPa/d during the gas yield fluctuation stage.

In order to improve the accuracy of log interpretation and the applicability of interpretation model for zones, the suitable porosity and saturation models are established for analysis of the 3rd member of Funing Formation in the west slope of Qintong sag, North Jiangsu basin. After the statistics and analysis of the experimental porosity and well logs, it is found that interval transit time after shale correction and the porosity of the experimental analysis can satisfy the relation among acoustic formation factors. The interval transit time for the rock matrix in this area is determined to be 189.39 μs/m, the matrix lithology coefficient（x） is 1.472, and the interpretation model for the porosity in the zone is established. And then, the relation between formation factor（F） and porosity is analyzed. Meanwhile, the variation rule of cementation index（m） with core porosity is determined, that is, with the increase of porosity in mesoporous reservoirs, m is relatively stable, while with the increase of porosity in high-extra-high pore reservoirs, m tends to increase. Therefore, the variable cementation index（m） can be calculated from well logs, and then the oil saturation of reservoir can be calculated accurately. The interpretation results of the established porosity and saturation models in this area agree well with the experimental analysis.

By the macro and micro comprehensive research methods of seismic-geological interpretation profile, integrated core, imaging log interpretation（FMI）, thin sections authentication, and argon ion polishing scanning electron microscope, the characteristics, main controlling factors of the properties of the shale of Wufeng Formation-Longmaxi Formation in the Yangchungou structural belt of southeast Chongqing and their influence on shale gas-bearing properties are analyzed. The study shows that there are many fractures such as shear fractures, bedding fractures, slip fractures, cleavage fractures, and shrinkage fractures developing in the shale of Wufeng Formation-Longmaxi Formation in the Yangchungou structural belt. The integrated analysis shows that shale fractures and interlayer sliding fractures there are vertical with middle-high-angle, whereas shear fractures are horizontal with low-angle. Most of the fractures are formed in multiple stages resulting in fracture nets, creases, micro faults and other phenomena. The development and distribution of these fractures are controlled by the tectonic activity, shale mineral composition and mechanical properties, and development of bentonite. Tectonic geology is the external cause of fracture development. The Yangchungou structural belt presents a fault-folding fold structure and is affected by multi-stage tectonic movements. Shear fractures, reticulate fractures, complex fracture network belts, and crumple belts are very developed. Shale mineral composition and mechanical properties are the internal causes of fracture development, controlling the development of micro-fractures and bedding fractures, such as cleavage fractures, intergranular fractures and shrinkage fractures. The Poisson ratio in 1st Longshan member of Yangchungou area is relatively small, the Young’s modulus is large, and the brittleness index is high. All those are good for the formation of various cracks. The more frequently the porphyry in the shale layer is, the closer it is to the main slip surface between the Wufeng Formation and the Linxiang Formation, the more obvious the slip phenomenon is, and the more developed the interlayer slip fractures are. Although the natural fractures in the Yangchungou structural belt are very developed, the preservation conditions have not suffered serious damage, so the shale gas exploration potential is still good in the study area. Drilling revealed that the total gas content of the shale is equivalent to that of the adjacent area, and the total hydrocarbon measured by gas is better than that of the adjacent area. The proportion of free gas is also higher than that of the adjacent area. It indicates that the formation of local structural fractures has expanded the storage space of free gas in shale gas, which is beneficial to the rock gas accumulation.