The block discrete element method has gradually become a widely studied and applied simulation approach for hydraulic fracture propagation due to its advantages in handling discontinuous media. To further advance the application of block discrete element method in fracture propagation modeling, this paper summarizes the current research and application status of fracture propagation simulation based on the block discrete element method, discusses existing problems and challenges, and identifies future research directions. The study shows that the block discrete element method can directly characterize the location, occurrence, and number of discontinuous structural surfaces, select different constitutive equations according to their different conditions in the formation, and assign the corresponding parameters, making the simulation results of hydraulic fracture propagation more consistent with the actual situation; when simulating hydraulic fracture propagation, initial hydraulic fractures and fracture surfaces need to be preset, and hydraulic fractures can only propagate along the preset fracture surfaces, which affects the accuracy of hydraulic fracture simulation to some extent; in the next step, when dealing with natural fracture problems, efforts shall be focused on developing new natural fracture models; when dealing with bedding problems, efforts shall be focused on using constitutive models that can characterize other reservoir characteristics for research; when dealing with fault slip and casing deformation problems, efforts shall be focused on developing new cross-scale models and conducting integrated research on fault slip-casing deformation. Research on the block discrete element method is conducive to the development of unconventional oil and gas reservoir stimulation technology and can provide theoretical and technical support for the efficient development of unconventional oil and gas resources.

Digital core technology is an important means for evaluating reservoir physical properties in oil and gas exploration and development, with wide applications in analyzing rock composition and distribution, pore structure, and microscopic seepage mechanisms. With the rapid development of observation methods and computing power, the introduction of artificial intelligence algorithms has broken through the limitations of traditional digital core technology. This paper summarizes the workflow, application areas, and development history of digital core technology, reviews the current application status of artificial intelligence-related algorithms in core reconstruction, image segmentation, parameter prediction, and their effectiveness in digital core analysis, and prospects the application potential of artificial intelligence in multimodal and multiscale aspects of digital cores. This research can provide guidance for the integrated development of emerging information technologies such as artificial intelligence and big data with oil and gas exploration and development technologies.

Exploration on both sides of the Mianyang-Changning Tensional Trough has achieved good results, but there are still controversies regarding the characteristics, genesis and control effects on hydrocarbon accumulation of the tensional trough, which restrict further exploration deployment. For this purpose, based on regional seismic lines and key exploratory well data, the study focuses on the sequence sedimentary filling and unconformity characteristics of the Lower Cambrian inside the Mianyang-Changning Tensional Trough. The results indicate that the Mianyang-Changning Tensional Trough extends nearly north-south and can be divided into inner, middle and outer zones horizontally. Vertically, the trough interior developed two stages of filling sedimentation, two stages of widespreadsedimentation and two stages of sedimentary onlap unconformities,the two stages of filling in the first member of the Maidiping Formation and the first and second members of the Qiongzhusi Formation are the direct causes of abnormally increased stratigraphic thickness in the trough. The two stages of sedimentary onlap unconformities developed at the bottom of the two stages of filling sedimentary bodies, indicating two stages of basement subsidence in the study area; the episodic activity of the Xingkai taphrogeny is the internal driving force for the two stages of basement subsidence and also the internal cause for the formation of the tensional trough. The development of the tensional trough can be divided into juvenile, mature, and senescent stages, with the early Qiongzhusi period being the mature stage; the tensional trough mainly controls the development of Lower Cambrian source rocks and the source-reservoir matching of the Dengying Formation. The steep slope zone on the eastern side has high-quality source rock development and good spatial source-reservoir matching, making it the enrichment zone for Dengying Formation oil and gas reservoirs and the main direction for future exploration. This understanding has certain guiding significance for the next step of exploration in the Dengying Formation of the Sichuan Basin.

In addressing the challenge of unclear understanding of the dynamic evolution history and enrichment patterns of shale gas in strongly reformed syncline-type structures in northern Guizhou, the burial history, hydrocarbon generation history, and dynamic accumulation process of the Wufeng-Longmaxi shale in the Anchang Syncline were reconstructed based on testing data, drilling data, and geophysical data. The results indicate that the Wufeng-Longmaxi shale in the Anchang Syncline generally exhibited the characteristics of "continuous hydrocarbon generation, overall gas enrichment, formation overpressure" before the Indosinian period, and experienced a process of "slow hydrocarbon generation, differential enrichment, uplift and pressure release" after the Indosinian period, with shale maturity ranging from 2.8% to 3.0%; the evolution of shale gas content shows a trend of stable increase during the Indosinian-Early Yanshanian period and gradual decrease during the Yanshanian-Himalayan period; the pressure system underwent an evolution process of "normal pressure - hydrocarbon generation pressurization - overpressure - pressure release", and is currently at normal formation pressure; the gas content structure indicates that adsorbed hydrocarbon was dominant in the early stage, free hydrocarbon gradually increased after the Hercynian period, and both adsorbed and free hydrocarbons generally decreased after the Yanshanian period. Currently, free hydrocarbon is dominant, with a free-to-adsorbed hydrocarbon ratio of 1.50-1.80. Shale gas enrichment in syncline structures shows good correlation with formation dip angle, burial depth, and distance to outcrop areas; Class I and II faults damage shale gas reservoirs, while shale gas is locally enriched near Class III and IV faults. The Anchang Syncline structure develops five shale gas enrichment patterns: core long-term gas accumulation type, gentle wing slow accumulation type, small fault lateral sealing type, steep wing-through-going fault type, and late-stage erosion dissipation type. Among them, the core long-term gas accumulation type is the most favorable shale gas enrichment pattern. The research results provide a typical case for shale gas resource evaluation in strongly reformed areas of northern Guizhou.

Abstract:Helium is an important carrier of information on crust-mantle material exchange and a strategic rare gas resource critical to national security and high-tech industries.Based on drilling,logging,and 2D seismic data,we analyzed the reservoir geological conditions in Y Region of the Gushi Sag,Weihe Basin,and characterized the helium accumulation conditions,aiming to deeply understand the geological structural features,reservoir properties,and helium occurrence state in this area,to predict helium-rich zones and provide a scientific basis for helium resource exploration,development,and sustainable utilization.The results showed that the main reservoir in Y Region-the Gaoling Group and the Lantian-Bahe Formation,had good physical and electrical properties.In the early stage,a fan delta developed;by the time of Zhangjiapo Formation deposition,the shore-shallow lacustrine deposition expanded,and the delta retreated landward,forming an excellent reservoir-caprock assemblage.The regional basement granite provided ample helium source,and circulating geothermal water served as a carrier for helium migration and accumulation.Deep,large faults provided pathways for helium migration and helped form various structural traps,while the Zhangjiapo Formation caprock effectively prevented helium from escaping,facilitating helium accumulation.In the Lantian-Bahe Formation,the gas-bearing water layer is 48-102 m thick with a favorable depositional environment,making it the main target interval for helium exploration in the Y Region.This research provides technical support for selecting key target areas for helium exploration in the Weihe Basin.

The Fengxi Area in the Qaidam Basin is characterized by lacustrine carbonate interbedded with thin terrigenous clastic rocks, belonging to complex mixed carbonate reservoirs. Due to the characteristics of thin interbedded deposition, variable lithology, strong heterogeneity and complex pore structure, evaluating effective reservoirs is challenging. For this purpose, using high-resolution resistivity imaging (FMI), lithoscopic logging (LS) and drilling core data, based on the identification of sedimentary structures and rock bedding, the rock structure was classified into five types: algal limestone, dark spotted, massive, weakly layered and strongly layered; using nuclear magnetic resonance logging (CMR) and mercury injection experiments, the pore structure was classified into four types; combining the rock structure classification and pore structure classification results, a set of logging identification methods suitable for effective mixed carbonate reservoirs in this area was developed. The study shows that the dominant reservoirs in the Fengxi Area are widely distributed and laterally continuous and stable, but the vertical thickness of dominant reservoirs varies among oil units. Among them, the dominant reservoirs of unit N₂¹Ⅳ₃ are mainly concentrated on the western flank of the main structure, with reservoir thickness gradually thinning eastward; the dominant reservoirs of unit N₂¹Ⅴ₅ are mainly concentrated in the central part of the main structure, with reservoir thickness gradually thinning toward both ends. The research results effectively support well placement and reserves submission studies in the Fengxi Area.

The Wuxia fault zone is an important reservoir-controlling fault in the northwestern margin of the Junggar Basin.Its oil and gas reservoirs occur in strata such as the Permian and Triassic and the crude oil properties are complex.Aiming at the significant compositional differences between Permian and Triassic crude oils,the characteristics of the two sets of crude oils were systematically evaluated and compared based on the analysis of physical properties,whole oil group composition,saturated hydrocarbons and biomarkers of the crude oils.Research findings indicate that both sets of crude oils belong to mature light oil and have similar physical properties,but exhibit significant differences in geochemical characteristics.Permian crude oil is rich in β-carotane and gammacerane,indicating algal organic matter originating from a strongly reducing,high-salinity lacustrine environment;biomarkers of Triassic crude oil show mixed organic matter dominated by algae with higher plants,formed in a weakly reducing-oxidizing lacustrine environment.Oil-source correlation confirmed that Permian oil reservoirs mainly received hydrocarbon supply from the Permian Fengcheng Formation,while Triassic oil reservoirs are a mixed-source product of the Fengcheng and Urho Formations.This understanding clarifies the genetic differences of oil reservoirs in different strata of the Wuxia fault zone and provides an important geochemical basis for subsequent oil-source tracing,refined exploration,and favorable target optimization in this area.

Currently, commercial development of shale gas has been achieved in the Second Member of the Permian Wujiaping Formation (referred to as Wu 2 Member) in the Hongxing Area within the Liangping-Kaijiang Trough in eastern Chongqing. However, research on shale gas accumulation conditions in the north-central part of the western Hubei Trough remains insufficient. Therefore, through detailed measurement and sample analysis of the Permian Wu 2 Member stratigraphic section in Longmenba, Fengjie County, eastern Chongqing, the characteristics of the Wu 2 Member shale reservoir were clarified and the shale gas exploration potential areas in western Hubei-eastern Chongqing were predicted. The results indicate that the thickness of organic-rich shale in the Wu 2 Member reaches 29.3 m and can be divided into five sub-layers. The organic-rich intervals are sub-layers 1, 3, 4 and 5, mainly composed of black argillaceous siliceous rocks interbedded with siliceous shale, with increasing calcareous content upward in the formation; sub-layers 1 and 3 are volcanic ash-dense intervals,with the first appearance of the conodont C.wangi near the top of bed 101 as the boundary between the Wujiapingian and Changxingian stages; the organic-rich intervals were deposited in a humid,semi-humid,semi-arid climate with anoxic bottom water and high productivity paleoenvironments. The average TOC is 6.34%, characterizing a carbon riched, silicon riched, low porosity, low permeability reservoir. Compared with the Hongxing Area and the Enshi Area, although the Wu 2 Member has a relatively shallow (mostly less than 2 000 m) burial depth, it has large thickness (about 30 m) and high TOC (greater than 4.00%), thus still possessing good shale gas accumulation potential. The research results can provide geological basis for the construction of a shale gas exploration and development demonstration area in western Hubei-eastem Chongqing.

The lithofacies of the Permian Fengcheng Formation in the Mahu Sag,Junggar Basin are complex,and the types of diagenesis are diverse.Its reservoir capacity is significantly affected by diagenesis.However,the differences in diagenesis among different lithofacies and their evolutionary sequences are unclear,and the controlling effects on reservoir capacity are not well understood,hindering an in-depth understanding of the reservoir formation mechanism of the Fengcheng Formation.In response to this issue,through image processing technology to analyze rock optical thin sections and scanning electron microscope (SEM) images,minerals and pore-fracture characteristics were quantitatively identified,the types of diagenesis and their evolutionary sequences were clarified,and the impact mechanisms of diagenesis on the reservoir capacity of shale oil reservoirs were systematically analyzed in combination with core descriptions,high-pressure mercury injection experiments,etc.The research results show that the lithofacies of the Fengcheng Formation shale oil reservoir can be divided into three types:Type Ⅰ siltstone facies has the highest porosity and permeability and the strongest reservoir capacity,Type Ⅱ carbonate rock facies comes second and Type Ⅲ mud shale facies has the lowest.The three lithofacies share similar diagenetic evolutionary sequences,but the dominant diagenetic processes differ. The Fengcheng Formation reservoir is in the middle diagenetic stage B. Its diagenetic evolutionary sequence includes early mechanical compaction,calcite and dolomite cementation,pyritization,early hydrocarbon charging,dissolution,fracturing,late hydrocarbon charging and dissolution.Compaction and carbonate cementation are the main factors for densification,while dissolution and fracturing are key to the diagenetic modification of tight reservoirs,contributing significantly to the formation and improvement of reservoir space.The research results have important guiding significance for deepening the understanding of shale oil reservoir formation mechanisms,improving the shale oil reservoir evaluation system,and "sweet spot" optimization.

Aiming at the insufficient understanding of the mechanism by which the time-varying phase behavior characteristics of formation fluids during hydrocarbon gas injection development affect oil displacement efficiency,making it difficult to conduct fine control and improve oil recovery,high-pressure PVT experiments on typical well fluids were conducted to clarify the time-varying phase behavior characteristics of formation fluids during hydrocarbon gas injection development.Based on the time-varying fluid phase behavior,reservoir numerical simulation studies on the impact of fluid phase behavior changes on oil displacement efficiency were carried out,and technical strategies for hydrocarbon gas injection development in typical well groups considering the time-varying phase behavior characteristics of the reservoir were formulated and optimized.The study shows that after hydrocarbon gas injection development,the crude oil at the gas displacement front in the reservoir becomes lighter,while the residual oil at the gas displacement rear becomes heavier.During hydrocarbon gas injection development,the fluid characteristics of light oil in the reservoir near production wells shift to volatile oil fluid characteristics.Compared with injecting lean hydrocarbon gas,injecting rich hydrocarbon gas can reduce the oil-gas interfacial tension at the gas displacement rear and enhance the degree of oil-gas miscibility,thereby improving oil recovery.This research can provide a basis for formulating technical strategies for hydrocarbon gas injection development in reservoirs and offers important reference significance for CO₂ flooding development in reservoirs and gas injection development in condensate gas reservoirs.

With the growth of global energy demand, horizontal well technology has become an important means for oil and gas field development. Based on the equivalent wellbore radius principle and pressure drop superposition theory, combined with the oil-water two-phase pseudopressure function, a horizontal well oil-water two-phase productivity prediction model considering the actual well trajectory was established. The study results show that the oil production distribution along the horizontal well is generally "U"-shaped, with fluctuations in flow rate due to the actual well trajectory; as the length of the horizontal well increases, the oil production slowly increases; the production of each section of the horizontal well is positively correlated with permeability, and passing through high-permeability formations helps enhance productivity. In addition, the shape of the relative permeability curve has a significant impact on oil and water production. The concave water phase at low water saturation has the best oil production performance, while the reservoir water saturation increases with the oil production of the well gradually decreases. This study provides a theoretical basis for optimizing horizontal well design and improving well productivity.

Aiming at the highly discrete and locally enriched distribution contradictions of oil and water in mid-deep high-water-cut reservoirs in the Jidong Oilfield,micron CT experiments and displacement experiments were integrated to systematically reveal the dynamic evolution laws and control mechanisms of residual oil at the pore scale.The results show that the relative sorting coefficient of pore radius in high-permeability and low-permeability reservoirs is significantly higher than that in medium-permeability reservoirs,resiindicating a "polarized" distribution characteristic of reservoir heterogeneity;residual oil can be divided into five forms:network,porous,narrow-throat,isolated droplet,and film-like;in the original reservoir,the proportion of network residual oil is positively correlated with reservoir permeability.During the water flooding stage,the oil displacement efficiency is positively correlated with the contribution rate of mega-pores and permeability.The increase in recovery factor by binary combination flooding shows a bimodal characteristic,i.e.,the increase in high-permadbility and low-permeability groups is significantly higher than that in the medium-permeability group,and it is strongly positively correlated with the pore radius sorting coefficient.Based on this,a staged differentiated development strategy is proposed:"staged development" in the water flooding stage,prioritizing the development of medium- and high-permeability layers,and "U-shaped" regulation in the chemical flooding stage,implementing selective plugging in medium-permeability reservoirs and collaborative development of binary combination flooding in high-permeability and low-permeability reservoirs.The research results provide theoretical support and engineering practice guidance for precise potential tapping of remaining oil.

To address the high CO₂ emissions during heavy oil development in Canada′s Surmont Block, this study establishes a multiphase compositional thermal coupling model and proposes a method for in-situ CO₂ utilization and storage in post-heavy-oil reservoir development. Numerical simulations were employed to systematically evaluate the production performance and storage potential of three technologies: SAGD, ES-SAGD, and VAPEX.The recovery rate of crude oil by ES-SAGD technology can reach 58%,carbon intensity is antrolled at 0.25, demonstrating dual advantages. VAPEX exhibits the lowest carbon intensity and the highest solvent recovery rate. This research establishes a synergistic pathway of "oil displacement - solvent recovery - carbon storage," providing theoretical and strategic support for constructing a low-carbon, high-efficiency, and sustainable development system in post-heavy-oil reservoir stages.

Tailwater reinjection is a necessary means to ensure the sustainable development of geothermal resource extraction. However, during tailwater reinjection, excessive injection pressure can damage the thermal reservoir, and tailwater quality may also impair the fluid flow capacity of the thermal reservoir. To ensure the safety and stability of thermal reservoir reinjection, taking the Guantao Formation thermal reservoir in the Xiong′an New Area as an example, a prediction model for the fracture pressure of the thermal reservoir was established to calculate and analyze the critical injection pressure for thermal reservoir reinjection; using numerical simulation methods, the effects of reinjection water temperature and injection pressure on reservoir porosity and permeability were studied; finally, a mathematical model for tailwater particle deposition was established to analyze the effects of suspended particle size, seepage velocity, and particle mass concentration on the permeability of the thermal reservoir. The study shows that under conditions below the fracture pressure of the thermal reservoir, the temperature and pressure of the reinjected tailwater do not have a significant impact on the porosity and permeability of the thermal reservoir. The changes in porosity and permeability are less than 2.00%, and thermal breakthrough will not occur within 100 years; tailwater quality can have a greater impact on the permeability of the thermal reservoir. During the tailwater reinjection process, attention must be paid to the impact of tailwater quality on the physical properties of the thermal reservoir. The research results can provide technical support for the safety and stability of tailwater reinjection operations in thermal reservoirs.

In response to the unclear production characteristics and synergistic mechanisms of static and dynamic imbibition on micro-pores,nuclear magnetic resonance (NMR) testing technology was employed to conduct static and dynamic core imbibition experiments.Based on the analysis of T₂ spectra before and after core imbibition,the production characteristics of the two imbibition methods on small pores and large pores were studied,the effects of imbibition time,interfacial tension,and permeability on imbibition efficiency were evaluated,and a new method of combined imbibition,static first followed by dynamic,was proposed.The experimental results show that in static imbibition,the recovery degree of small pores (pore diameter:0.002 7-0.368 0 μm) is higher than that of large pores (pore diameter:0.368 0-23.000 0 μm),accounting for more than 58.7% of the produced proportion.The recovery degree of small pores increases with increasing permeability and first increases then decreases with decreasing interfacial tension.In dynamic imbibition,the recovery degree of large pores is higher than that of small pores and is the main contributor to the total recovery factor.With decreasing interfacial tension,the recovery degree of large pores increases,while that of small pores and total pores first increases then decreases.The optimal interfacial tension for dynamic imbibition is lower than that for static imbibition.The combined imbibition method,static first followed by dynamic,can simultaneously and significantly improve the recovery degree of both small and large pores.Practice shows that after the first round of combined static-dynamic imbibition in the pilot test well group,the average daily oil production increase reached 336%,and the average water cut decrease reached 29%,demonstrating significant oil increase and water control effects.This research has strong guiding significance for improving tight oil recovery.

To address the insufficient understanding of the microscopic mechanism of enhanced oil recovery (EOR) by CO₂ flooding in high-temperature high-pressure and low-permeability reservoirs,a high-temperature high-pressure micro-visualization experiment was conducted.Using ImageJ threshold analysis,the microscopic oil displacement mechanisms of CO₂ miscible and immiscible flooding were studied,the residual oil of CO₂ miscible and immiscible flooding was classified and characterized,and the effects of CO₂ injection volume,injection rate,injection pressure,and reservoir heterogeneity on the final recovery degree were investigated.The study shows that the leap displacement and gas-oil-gas composite displacement occur,and CO₂ compression-release easily occur in narrow throats during CO₂ flooding.In both CO₂ miscible and immiscible flooding processes,as the CO₂ injection volume increases,the displacement efficiency rises significantly and then stabilizes.With increasing displacement velocity,displacement efficiency first increases and then decreases.When the displacement pressure exceeds the minimum miscibility pressure (MMP),the recovery of residual oil in low-permeability reservoirs can be enhanced.Compared with immiscible flooding,CO₂ miscible flooding yields better results and the final recovery degree is less affected by reservoir heterogeneity.This research provides an important theoretical basis and practical guidance for the design of CO₂ flooding development plans in low-permeability reservoirs.

Currently, old wells in the Hancheng Block face a gas production bottleneck, with the recovery rate of only 32.0%, failing to achieve long-term stable and high production. To enhance the coalbed methane (CBM) productivity of old wells in the Hancheng Block and displace adsorbed gas in desorption blind pores, a surfactant screening experiment was conducted. By comparing the effects of seven surfactants on reducing surface tension, contact angle, and enhancing CBM desorption, a new foam-free surfactant suitable for field operation conditions and capable of improving recovery was selected. The study shows that injecting the new foam-free surfactant into coal can effectively reduce surface tension and change the wettability of the coal surface; it eliminates excessive bubbles during operation, reduces the Jamin′s effect, decreases capillary pressure,weakens the water blocking effect, and makes CBM in blind pores easier to desorb. Field tests show that injecting a 0.30% solution of the new foam-free surfactant increased the cumulative gas production of the original low-production old well by 13 500 m³, achieving a relatively ideal stimulation effect. This research can provide a reference for stimulating similar old CBM wells.

To address the problem that the filter cake formed by synthetic-based drilling fluid in the near-wellbore zone is difficult to remove, thus causing damage to the reservoir, a filter cake removal fluid was developed based on the composition of the synthetic-based drilling fluid filter cake, and the fluid is formulated with retarded acid HWCP, corrosion inhibitor HWCI, cleaning penetrant JFC, and waterproof lock agent HSSJ. The filter cake removal ability and reservoir protection ability of the filter cake removal fluid system were evaluated. The study shows that the weight loss rate of the synthetic-based drilling fluid API filter cake reached 90.97% after being soaked at 90 ℃ for 3 hours. After injecting the filter cake removal fluid into cores contaminated by synthetic-based drilling fluid, the permeability recovery value was 96.98%. This system has good filter cake removal performance and reservoir protection ability, effectively reducing the damage degree of synthetic-based drilling fluid to the reservoir. Field applications have demonstrated that this system achieves effective well stimulation and enhanced production performance. This research can provide reference for protecting reservoirs in western South China Sea oilfields and improving the comprehensive economic benefits of similar oilfields.

To improve the positioning accuracy under unstable first arrival time conditions of microseismic events in hydraulic fracturing, a Dung Beetle Optimizer with Differential Evolution (DE-DBO) algorithm was established by combining the Dung Beetle Optimizer (DBO) and the Time Difference of Arrival (TDOA) velocity model. This algorithm initializes the initial positions of dung beetles through Bernoulli chaotic mapping on the basis of the standard DBO to improve population diversity, uses differential evolution algorithm to enhance the global search ability of DBO, and uses the Levy flight strategy to improve the diversity of group search and guide the search algorithm to jump out of local optima. The simulation results show that when the wave velocity fluctuates within the range of ±1%, ±3%, and ±5%, DE-DBO has smaller root mean square error and absolute error. Its positioning accuracy, convergence speed, and algorithm stability are better than those of the traditional standard DBO, particle swarm optimization, and genetic algorithm. The research results not only improve the accuracy and stability of microseismic positioning under uncertain velocity models but also have great significance for fracture dynamic monitoring and fracturing effect evaluation at hydraulic fracturing sites.

During CO₂ flooding and storage, influenced by mechanical factors, wellbore integrity may be compromised, leading to gas channeling and leakage. In response to this problem, a low-temperature (30-45 ℃) curable methyl methacrylate (MMA) resin wellbore repair system was developed using methyl methacrylate as the main agent, with the addition of redox initiators and cross-linking agents. Performance evaluation of the system was subsequently conducted. The study shows that at 40 ℃, the initial setting time of this resin repair system is 8.2 hours, and the curing time is 10.4 hours; the repair system has good injection performance and adhesion performance, with a surface tension of 27.1 mN/m, and contact angles with sandstone, N80 steel sheet, and oil well cement are all less than 30°. The bonding strength at the cement-steel pipe interface is increased by 13.15 times compared to before repair. The repair system has good CO₂ channeling sealing performance and CO₂ aging resistance. After repairing the cement-steel pipe interface, the CO₂ breakthrough pressure is 26.78 MPa; under CO₂ aging conditions, the compressive strength and CO₂ permeability of the quartz sand consolidated body change by less than 5.0% within 30 days; this resin repair system can enter micro-pores with sizes of 20-100 μm and tightly fill them after curing. This wellbore repair system has important application value for CO₂ flooding and storage in low-temperature reservoirs.