CO₂ flooding has the dual purpose of enhancing oil recovery（EOR） and carbon dioxide storage, and has a large development prospect. In particular, the need of carbon emission reduction gives a large space for the development of large-scale application of this technology. For Sinopec, the development history of CO₂ flooding can be divided into three stages: single well stimulation, pilot test and comprehensive application. After more than 50 years of development, CO₂ flooding mechanism and supporting technology have been relatively mature. According to the reservoir characteristics of Sinopec and three types of CO₂ flooding, which are miscible drive, near miscible drive and immiscible drive, the screening standard of CO₂ drive reservoir are established to clarify the mechanism of CO₂ flooding in low permeability reservoir, tight reservoir, medium and high permeability reservoir. Taking three reservoirs of Subei Basin, Fu-3 member of Caoshe Oilfield, Fu-3 member in Hua-26 fault block, and Duo-1 member of Zhoucheng Oilfield, and Gao-89-1 block of Zhengli Zhuanggao Block in Bohai Bay Basin as examples, the actual development effect of typical blocks are summarized, showing that CO₂ flooding is an important way to improve oil recovery efficiency. In order to solve the technical bottleneck of large-scale application of CO₂ flooding in low permeability reservoirs and medium-high permeability reservoirs, the researches on oil displacement mechanism and gas injection effect should be further strengthened to promote the development of CCUS. It is of great significance to achieve “carbon peak” and “carbon neutral” and ensure national energy security.

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.

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 %.

In order to effectively solve the problems of difficult gas injection in S358 high pour-point reservoir and low oil displacement efficiency caused by gas channeling due to high mobility ratio of gas flooding after fracturing, laboratory experiments of gas injection phase and long core displacement mechanism have been carried out. Through the PVT phase state experiment of the high pour-point oil injected by CO₂, dry gas, flue gas, and oxygen-reduced air（N₂ 90 %+O₂ 10 %）under the formation conditions, the characteristic mechanisms of the above four injection gas such as the solubilization expansion, viscosity reduction and tension reduction have been analyzed. CO₂ is preferred as the injection gas. Through five groups of high temperature and high pressure long core flooding experiments with different combination methods, the effect of CO₂ combination flooding on channeling prevention and extraction is evaluated. The experimental results show that the displacement effects of both CO₂+weak gel and CO₂+foam are the best two, and the final displacement efficiency is 70.101 % and 68.212 % respectively. The research results show that the injection of CO₂ combined flooding slug increases the displacement resistance and reduces the fracture conductivity, which plays a key role in improving the microscopic sweep volume. Among them, both the CO₂+weak gel and CO₂+foam displacement methods have the best extraction effects. The research results can provide an experimental basis for the efficient development of high pour point oil in this block.

Based on the interactions between CO₂ and crude oil, CO₂ and conglomerate, the enhanced oil recovery（EOR） mechanism of CO₂ huff-n-puff has been revealed in Huanmahu tight conglomerate reservoir. Meanwhile, a high temperature and high pressure nuclear magnetic system was applied to monitor the change of oil saturation during experimental processes at pore scale in cores of substrates. Core fracturing and displacement system were used to investigate the effects of fractures on EOR during CO₂ huff-n-puff. The experimental results indicated that CO₂ could effectively dissolve in crude oil to replenish formation energy, reduce oil viscosity and improve wettability. Moreover, the crude oil produced in depletion development was in large pores, while that in medium pores and small pores could be effectively activated by CO₂ huff-n-puff. After depletion development, three cycles of huff-n-puff could enhance oil recovery by 23.1 %, among which the first cycle contributed most with factor of 15.1 %. The existence of fractures could increase the contact area between crude oil and CO₂ and decrease the flow resistance of crude oil, and finally the EOR is up to 27.1 %. All the results reveal the feasibility of CO₂ huff-n-puff to improve oil recovery in tight conglomerate reservoirs from pore scale.

In order to clarify the influence of supercritical CO₂ immersion on the physical properties of glutenite reservoirs with different clay mineral content in Mahu under the conditions of Xinjiang Mahu glutenite reservoir. Several researches have been done. Firstly, the type and proportion of clay minerals in the reservoir were determined according to the results of X-ray diffraction （XRD）：kaolinite （1.52 %）, montmorillonite （0.42 %）, chlorite （0.73 %）, illite （0.68 %）. Secondly, the core which is close to the pore permeability of reservoir core is made manually. Finally, under the condition of reservoir temperature at 70 ℃ and pressure of 20 MPa, using supercritical CO₂ high-temperature and high-pressure reaction device, and the experimental study on the influence of supercritical CO₂ immersion on the permeability of sandy conglomerate reservoir with different clay mineral content was carried out. The results show that when the clay mineral content is 2.5 % ~ 6.0 %, the permeability of the reservoir increases after the injection CO₂, the lower the clay mineral content, the shorter the action time and the more obvious the permeability increase. When the clay mineral content in the reservoir is greater than 7.5 %, with the increase of the action time, the permeability gradually decreases, and the higher the clay mineral content is, the greater the decrease is. When the clay mineral content is 6.0 % ~ 7.0 %, CO₂ has the best effect on improving reservoir permeability.

In order to improve the oil recovery of tight sandy conglomerate reservoir, the tight oil in the tight glutenite core is extracted by the supercritical CO₂ based on the reservoir conditions of Mahu tight sandy conglomerate reservoir in Xinjiang. And then, four production parameters affecting tight oil extraction, which are the pressure（7~25 MPa）, the temperature（30~60 ℃）, the soaking time（30~180 min） and the cycle time（30~180 min）, have been optimized and analyzed by the single factor analysis method. The results show that the supercritical CO₂ can extract the crude oil from the tight glutenite with relatively good effects, and the extraction rate can reach up to 25.22 %. By the orthogonal design experiment L₉（3⁴） with four factors and three levels for the above four production parameters, it is found that the factors influencing the extraction effect of crude oil by supercritical CO₂ have primary and secondary order: pressure > immersion time > temperature > circulating time. The optimal parameter scheme is the pressure of 25 MPa, tht temperature of 50 ℃, the soaking time of 120 min, and the cyclic time of 150 min. The application of CO₂ to extract crude oil in tight glutenite reservoirs has good application prospects.

In order to further clarify the mechanism of steam flooding assisted by CO₂ in the heavy oil reservoir, its visualization experiments are carried out by the acrylic plate model and natural cores, and their synergy is analyzed. After the mechanism of synergistic displacement is clarified, the core flow experiments are carried out to further analyze the influence of the synergistic effect and the injection mode on the actual displacement efficiency. The results show that CO₂ assisted steam flooding has the effects of the synergistic viscosity reduction, the expansion of steam sweep efficiency, the availability of residual oil at the blind end, and the demulsification. Among them, the comprehensive viscosity reduction rate of the crude oil is 59.8 %, and the steam sweep area is increased by 37.44 %. Compared to the flooding by steam alone, after the assitant of CO₂, the recovery rate increased significantly. The alternate injection of steam and CO₂ can get a recovery rate of 65.7 %, 7.9 % more than that of mixed injection, and observe the stable foam oil flow at the outlet.

The geological sequestration of greenhouse gas, CO₂, is an important means to cope with carbon peaking and carbon neutralization. However, the depleted gas reservoirs are the significant targets for the storage of CO₂. Due to the different forms of CO₂ in gas reservoirs, the effective CO₂ storage calculation method of gas reservoirs is established based on the theoretical CO₂ storage calculation method, which can be used to estimate the CO₂ storage potential of the depleted gas reservoirs. Meanwhile, the model of low permeability gas reservoir is established for the CO₂ storage in the later stage of the development. Considering the dissolution of CO₂ in formation water and the mineralization reaction of CO₂ between water and rock, the error of supercritical buried stock, dissolved buried stock and mineralized buried stock is 2.81 %, 7.37 % and 6.25 %, respectively, and the error of effective buried stock is only 3.06 % by comparing the calculated results with the numerical and analog results.

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.

The porosity and permeability of Mahu sandy conglomerate tight reservoir in Xinjiang are extremely low. After fracturing and putting into production, the stable production effect of early development is good, and the decline is large in the later stage. In order to supply the formation energy and improve the crude oil recovery, the tests of CO₂ huff and puff for three horizontal wells have been carried out in Ma131 well area. The test results show that the mechanism of CO₂ huff and puff to improve crude oil recovery is mainly reflected in increasing reservoir energy, expanding crude oil volume, reducing crude oil viscosity, extracting light components, dissolving reservoir minerals and increasing fluid flow capacity. Reasonable injection parameters are more helpful to enhanced oil recovery. During the development of CO₂ huff and puff, the higher bottomhole injection pressure and the longer soaking time, as well as greater sweep diffusion, result in earlier continuous oil production and more obvious enhanced oil recovery effect. The oil increment of three horizontal wells, Well-X721, Well-X92 and Well-M1114, is 2 161 t, 1 768 t and 1 452 t, respectively. CO₂ huff and puff has good adaptability and popularization and application prospect in sandy conglomerate tight reservoir.

In order to improve the current situation of serious water channeling and the poor development effect during the water flooding development of B238 Block in Xiaermen Oilfield, and further to enhance the oil recovery efficiency, the numerical simulation method has been carried out to systematically study the parameters optimization of the multi-stage slug injection system after polymer flooding and the differential adjustment of polymer injection concentration based on laboratory experiments. It is found that the combined small slug with multiple rounds is more effective than the large slug with less rounds. The main slug which increases EOR most is composed of 0.08 PV (polymer)+0.02 PV(gel)+0.06 PV(polymer)+0.02 PV(gel)+0.06 PV(polymer)+0.02 PV(gel)+0.06 PV(polymer)+0.02 PV(gel)+0.06 PV(polymer) and the EOR value is 7.92 %. When the polymer concentration adjustment range of injection wells is 20 %, that is, the concentration is adjusted to 420 mg/L, EOR reaches the inflection point. And with the continuous increase of polymer concentration adjustment range, the increase of oil recovery shows a downward trend. It shows that the gel system and polymer alternating injection method have the potential to further develop remaining oil, and provide some technical reference for the development of similar reservoirs.

In order to improve the rheological properties of hydrophobically associating polymers（HAP） and the mobility control ability in porous media, a water-soluble cyclodextrin polymer, β-CDP. is synthesized by condensation of the cyclodextrin and epichlorohydrin, meanwhile, mixed with the HAP. The results showed that the host-guest interaction improves the thickening ability and viscoelasticity of the HAP solution. The host-guest inclusion system of β-CDP and HAP maintained shear thinning behavior. β-CDP/HAP demonstrated special viscosity-temperature curves and its activation energy changes with temperature, showing a strong ability of temperature resistance. The core flooding experiments showed that β-CDP/HAP formed multilayer adsorption in porous media and had stronger mobility control ability than HAP. By the host-guest interaction between the hydrophobesp and the cyclodextrin groups, the intermolecular interaction can be enhanced, and the comprehensive performance of HAP can be improved.

The gas reservoir in 2^nd member of Shaximiao Formation of Xinchang Gas Field is tight, and its natural productivity is low. As one of the effective development methods, the horizontal wells has unclear main controlling factors of recovery factor. By the numerical simulation software, ECLIPSE, this problem has been analyzed and its influence has been quantitatively evaluated, so as to provide a favorable theoretical basis for the further development by horizontal wells. The results show that: 1）The main controlling factors of tight sandstone gas reservoir changes with the different reserves. For the class Ⅰ, Ⅲ and Ⅳ, it is mainly controlled by the water saturation, while for the class Ⅱ, effective thickness contributes most. 2）The influence of main controlling factors on the recovery factor of horizontal wells are different, with a degree of 91.14 %, 54.33 %, 61.82 % and 45.18 % respectively for class Ⅰ~Ⅳ and multiple factors instead of single factor. 3）The physical properties of reservoir have great influence on the recovery factor of horizontal wells. For the class Ⅰ and Ⅱ reservoir with good properties, the influence degree is less than 1 %, while that of the class Ⅲ and Ⅳ reservoir with poor properties is up to 17 %. Therefore, effective development of horizontal wells depend on the classification of reservoir by different reserves. For the areas with good properties, the optimization of engineering design should be strengthened, like increasing the length of horizontal section and fine fracturing; on the contrary, for that of poor properties, the deployment location of horizontal wells should be chosen in the areas with low water saturation, large effective reservoir thickness and high permeability.

In shallow tight reservoirs, the hydraulic fracturing tends to produce horizontal fractures. For the horizontal wells, multi-stage fracturing is easy to generate only one large horizontal fracture, which leads to poor stimulation effect. However, the single well mode of “bow-shape horizontal well + multi-stage horizontal fractures” can not effectively explore this kind of reservoir. In order to further improve the production degree of shallow tight reservoir, the development mode of spatial-braided well pattern in shallow tight reservoir is proposed based on the feasibility of shallow reservoir drilling, and the numerical simulation is used to verify the effectiveness of spatial-braided well pattern. The numerical simulation results show that under the same number of wells and drilling footage, the oil production, cumulative oil production and reservoir recovery degree of spatial-braided well pattern are higher than those of the opposite well pattern and staggered well pattern. However, with the expansion of the fracture scale in horizontal fracturing, the gap with staggered well pattern decreases. At the same time, according to the simulation, the reverse 7-point pattern water injection not only replenishes the formation energy, but also changes the seepage state, so that the remaining oil in the regional edge and between wells can be effectively displaced, and the recovery rate is significantly improved. The researches provide efficient development method for the efficient development of shallow tight reservoir.

Normalized Pressure Integral（NPI） Production Analysis is a kind of modern production decline analysis method which defines new parameters by integral. It can not only reflect the pseudo-steady state flow stage influenced by outer boundary, but also can reflect the unsteady state flow stage. In order to study the NPI production decline analysis method of carbonate reservoir, we established triporate-uniphase parallel inter-porosity flow model. In this model, fracture is the main flow channel and inter-porosity flow happens from cave to fracture and matrix to fracture. The bottom hole pseudopressure solution with considering the effect of skin factor of this model was obtained by Laplace transform and Duhamel principle. The NPI method curves were plotted by using normalized pressure integral method and Stehfest numerical inversion. And the curves can reflect the production performance of this model accurately. The storage ratio, inter-porosity flow coefficient, and dimensionless outer boundary radius were chosen to be sensibility parameter for sensibility analysis. The result shows that the storage ratio mainly influences the depth of depression on derivative curve and the inter-porosity flow coefficient mainly influences the time when inter-porosity flow stages happen. The skin factor just influences the dimensionless pseudopressure and dimensionless pseudopressure integral curves, while the dimensionless outer boundary radius will also influence the unsteady state flow stage of derivative of dimensionless pseudopressure integral curve.

In the tight reservoir like mahu with strong heterogeneity, large differences in the productivity of oil wells and obvious differences in the decline characteristics, the production decline analysis and prediction have important guiding significance to the management of oil well production system and the preparation and optimization of oil field development plan, and are also an important part of reservoir performance analysis. However, the traditional empirical decline models used today, such as the Arps production decline model, power law exponential decline model, Valkó extended exponential decline model, and Duong decline model, have different applicability. When using these methods to fit the production data of the fractured horizontal wells in the Mahu tight reservoir, the accuracy of the fitted results is low. Therefore, a new method of combination that uses different models for fitting in stages based on the model fitting results of Mahu oil wells in different stages is explored, and the examples are applied to verify it in this block. The research results show that this new method has lower error rate and higher degree of agreement than the traditional ones. In addition, by using this method, the prediction results of Estimated Ultimate Recovery（EUR） for the tight oil wells in Mahu reservoir are more accurate, and the method is highly feasible, which can be used as a reference for the research on the production decline law and the productivity prediction of other similar tight oil reservoirs.