Gas Migration Research Articles

Mathematical Model of the Migration of the CO2-Multicomponent Gases in the Inorganic Nanopores of Shale

Nanopores in shale reservoirs refer to extremely small pores within the shale rock, categorised into inorganic and organic nanopores. Due to the differences in the hydrophilicity of the pore walls, the gas migration mechanisms vary significantly between inorganic and organic nanopores. By considering the impact of irreducible water and the variations in effective migration pathways caused by pore pressure and by superimposing the weights of different migration mechanisms, a mathematical model for the migration of CO2-multicomponent gases in inorganic nanopores of shale reservoirs has been established. The aim is to accurately clarify the migration laws of multi-component gases in shale inorganic nanopores. Additionally, this paper analyses the contributions of different migration mechanisms and studies the effects of various factors, such as pore pressure, pore size, component ratios, stress deformation, and water film thickness, on the apparent permeability of the multi-component gases in shale inorganic nanopores. The research results show that at high pressure and large pore size (pore pressure greater than 10 MPa, pore size greater than 4 nm), slippage flow dominates, while at low pressure and small pore size (pore pressure less than 10 MPa, pore size less than 4 nm), Knudsen diffusion dominates. With the increase of the stress deformation coefficient, the apparent permeability of gas gradually decreases. When the stress deformation coefficient is less than 0.05 MPa−1, the component ratio significantly impacts bulk apparent permeability. However, when the coefficient exceeds 0.05 MPa−1, this influence becomes negligible. The research results provide a theoretical basis and technical support for accurately predicting shale gas productivity, enhancing shale gas recovery, and improving CO2 storage efficiency.

Depositional environments of the northeastern Yenisey-Khatanga sedimentary cover in relation to assessment of hydrocarbon prospects

Background. Although the recent years have seen a significant increase in the amount of geological and geophysical data on the oil and gas potential of the Yenisei-Khatanga trough, no notable hydrocarbon discoveries have been made within its northeastern part. This is primarily related to a lack of understanding of the development of sedimentary basins, along with the processes of oil and gas generation, migration, and accumulation. This determines the need to generalize and analyze the accumulated geological, geophysical, and geochemical data within the framework of a comprehensive basin analysis and revision of the existing geological models.Aim. Elucidation of the evolution of sedimentary basins in the northeastern part of the Yenisei-Khatanga trough and the adjoining Anabar-Khatanga saddle; updating the geological model of the sedimentary cover for further assessment of hydrocarbon systems.Materials and methods. Development of a numerical geologic model of the Yenisei-Khatanga trough and the adjoining Anabar-Khatanga saddle based on available publications and engineering reports. A basin analysis and paleogeographic reconstructions for the main time steps of sedimentary cover evolution.Results. The evolution of the sedimentary basins under study has been reconstructed, and the main stratigraphic units in the development of hydrocarbon systems have been identified. Depositional environments supporting the development of the essential hydrocarbon system elements have been delineated for further hydrocarbon system modeling and geological risk assessment.

CH4 and CO2 Emissions From Different Tectonic Settings Along the Western Margin of the Ordos Block in China: Output and Correlation With the Regional Tectonics

AbstractThe investigation of tectonic controls on CH4 and CO2 emissions was conducted by measuring the fluxes of the gases in the different tectonic units along the northwestern margin of the Ordos Block in China, a region renowned for its intricate tectonic configuration. The mean fluxes of CH4 ranged from −1.5 to 1.1 mg m−2 d−1, while CO2 fluxes spanned from 2.0 to 29.2 g m−2 d−1. Notably, the Minqin, Ordos, and Haiyuan blocks primarily exhibited absorption characteristics for CH4. In contrast, within the Hetao and Yinchuan grabens, both degassing and absorption processes coexist. A striking observation was that blocks with high internal deformation exhibited significantly higher CH4 and CO2 fluxes compared to those in the stable blocks. Additionally, regions experiencing extensional deformation demonstrated greater gas emission than those undergoing compressional deformation. The spatial distribution of CH4 and CO2 fluxes at the study points exhibited a similar trend to faults in the Yinchuan Graben. Our findings revealed that CH4 and CO2 are mainly of biogenic origin, accompanied by abiotic emissions from underground. And the gas source, migration pathway, and tectonic stress were the primary factors influencing gas emission, with tectonic stress playing a pivotal role. This stress controlled the formation of tectonic structures, changed the degassing pathway, and served as the driving force for gas migration. The results of this study offer valuable insights into the mechanisms governing CH4 and CO2 emission in faulted regions. Furthermore, our results may contribute to future assessments aimed at quantifying the contribution of geological sources to greenhouse gas emissions.

Study of Gas Migration in the Fissures of Closed Goaf and CH4 Production Characteristics in Vertical Wells under Different Gas Injection Conditions

Study of Gas Migration in the Fissures of Closed Goaf and CH4 Production Characteristics in Vertical Wells under Different Gas Injection Conditions

Disaster-causing mechanisms of gas migration under loading and unloading conditions

Disaster-causing mechanisms of gas migration under loading and unloading conditions

Prediction of Oil Source Fault-Associated Traps Favorable for Hydrocarbon Migration and Accumulation: A Case Study of the Dazhangtuo Fault in the Northern Qikou Sag of the Bohai Bay Basin

In order to study the distribution pattern of oil and gas near the lower-source, upper-storage type of oil source faults in the hydrocarbon-bearing basins, a set of prediction methods favourable to oil and gas migration and accumulation were established by superimposing the parts of the oil source fault-associated traps, the contiguously distributed sand bodies and the lateral sealing position of faults. The trap associated with a fault can be determined by the fault’s convex part on the fault plane’s morphology map, the fault throw displacement curve and the intersection of faults on the structure map. The set of sand bodies can be determined by the sand-to-shale ration of the formation. The lateral sealing position of faults can be investigated by the shale content of the fault. This study is based on our case study of the Dazhangtuo Fault in the lower sub-member of the 1st member (Es1L) of the Shahejie formation in the northern Qikou Sag of Bohai Bay Basin. The results illustrate 4 fault nose traps formed by fault line deflection in the Es1L formation of the Dazhangtuo Fault, 2 each in the middle and eastern end. The Dazhangtuo Fault is favorable for oil and gas migration except at the eastern and western ends and the middle part of the fault. The fault-associated traps in the Es1L formation that are highly favorable for hydrocarbon migration and accumulation (overlapping site of associated traps and favorable location for oil and gas migration) are distributed in the eastern and central parts of the Dazhangtuo Fault. In contrast, those moderately favorable for hydrocarbon migration and accumulation (associated trap at a certain distance from the favorable location for oil and gas migration in the Dazhangtuo Fracture) are locally distributed in the east. Both traps are conducive to accumulating hydrocarbons from the underlying source rock in the Es3 formation. Such observations are consistent with the current confirmed hydrocarbon distribution, thus validating the feasibility and accuracy of predicting the distribution of traps related to oil source faults favorable for hydrocarbon migration and accumulation, it can be used to guide the exploration of the lower-source, upper-storage type of hydrocarbon accumulations in the hydrocarbon-bearing basins.

Characteristics and Genesis of Carbonate Weathering Crust Reservoirs: A Case from the Ma5Member of Ordovician in Gaoqiao Area, Ordos Basin, China.

The hydrocarbon reserves in carbonate rocks account for about half of the global hydrocarbon reserves and are an important reservoir type. The Ordovician Majiagou Formation in the central Ordos Basin is a representative weathering crust reservoir. The Caledonian movement uplifted the stratum as a whole, and subsequently, 120 million years of exposed weathering, denudation, and leaching created this unique karst paleomorphology. Dolomite reservoirs have developed dissolved pores and microfractures, which are the best reserved spaces for natural gas and good hydrocarbon migration channels. This paper takes the Ma5Member (hereinafter referred to as Ma51+2) carbonate reservoir in Gaoqiao Gas Field as the research target, based on the core, thin section, cathodoluminescence, logging data, etc., and systematically study the effect of karstification on the reservoir and the genesis of the dolomite reservoir. The results show that the depositional period of the Ordovician Majiagou strata is a regression cycle and the depositional environment is a limited evaporative tidal flat. The reservoir lithology of Ma51+2 is mainly gypsiferous dolomite and micrite dolomite. The reservoir space types consist of intergranular pores, gypsum mold pore, intragranular dissolution pores, intercrystalline pores, and microfractures. The porosity has values from 0.3 to 11.2% (mostly less than 5.0%) with an average of 3.3%, and the permeability ranges from 0.003 to 13.2 mD (mostly less than 1 mD) with an average of 0.36 mD. Karstification is divided into three periods, including syngenetic karst, eogenetic karst, and burial karst. The sedimentary microfacies determine the material basis of the reservoir, and multistage karstification finally modifies the physical properties. By deeply exploring the formation mechanism and influencing factors of the carbonate reservoir in the Ordovician Majiagou Formation, it provides an important theoretical basis and practical guidance for oil and gas exploration and development. At the same time, it also has important reference value for understanding and predicting the development law and distribution characteristics of carbonate reservoirs under similar geological background.

Validation of a methane oxidation biosystem design methodology using numerical modeling

Introduction: Methane oxidation biosystems (MOBs) are cost effective engineered systems capable of catalyzing the transformation of CH4 into CO2 biotically, thereby mitigating emissions from landfills.Method: In this study we validate how accurately one can predict the hydraulic behaviour of a MOB using numerical modeling. More precisely how one can identify the length of unrestricted gas migration (LUGM), a critical design criterion for effective methane abatement biosystems. Laboratory experiments were conducted to obtain the material properties for a compost mixed with plastic pellets, and sand. With the water retention curve and air permeability function, we predicted the hydraulic performance of a MOB using Hydrus-2D. We then designed and constructed a MOB and monitored several key parameters for 12 months. The validation of the design methodology was conducted using field measurements, while actual climatic data was used as input in numerical modeling.Results: The air permeability function was an appropriate activation function for determining LUGM. Accordingly, the predicted hydraulic behaviour matched the measured hydraulic behaviour reasonably well, validating the proposed procedure.

Upward migration of the shallow gas enhances the production behavior from the vertical heterogeneous hydrate-bearing marine sediments

Low gas production rates and insufficient gas yield hinder the large-scale production from natural gas hydrates; a joint production of gas hydrate and its underlying shallow gas is expected to address this limitation. This study focuses on the interaction between heterogeneous hydrate reservoirs and the upward migration of the shallow gas. The results indicated a 38.4 % increase in production efficiency with the assistance of the shallow gas. Specially, the melt water generated from extensive hydrate decomposition could potentially induce a lateral migration of the shallow gas at the interfacial zones of the heterogeneous reservoirs. Further investigation revealed that a lower production pressure would help the release of the shallow gas as well as the hydrate decomposition, thereby contributing to a 64.55 % shorter t90. A faster depressurization rate could facilitate the temperature recovery by intensifying the lateral movement of the shallow gas in the junction layer. Consequently, a proper control of the upward channeling of the shallow gas was suggested in the field test for a successive and secure gas production. Our results could be of help in elucidating the interlayer interference mechanisms and the selection of the depressurization strategy for a better recovery efficiency from the multi-gas source reservoirs.

Research on CO2-WAG in Thick Reservoirs: Geological Influencing Factors and Random Forest Importance Evaluation.

In the development process of thick reservoirs, the impact of various geological factors on the effectiveness of the CO2 water alternating gas (CO2-WAG) flooding technology remains unclear. This paper establishes multiple CO2-WAG flooding models for thick reservoirs to study the effects of sedimentary rhythm, dip angle, matrix permeability, high-permeability streaks (HPS), and barrier layers on the effectiveness of CO2-WAG flooding and then uses the random forest algorithm to rank the importance of these geological factors. The results show that different geological factors have varying degrees of impact on the distribution of water and gas migration and recovery rates during the CO2-WAG flooding process. The ranking of the importance of various factors obtained by reservoir numerical simulations and the random forest algorithm is HPS, sedimentary rhythm, dip angle, matrix permeability, and barrier layers. These research findings will provide effective guidance and a reference for the optimal selection of CO2-WAG flooding schemes for similar thick reservoirs under different geological conditions.

Gas migration at the granite–bentonite interface under semirigid boundary conditions in the context of high‐level radioactive waste disposal

AbstractThe corrosion of waste canisters in the deep geological disposal facilities (GDFs) for high‐level radioactive waste (HLRW) can generate gas, which escapes from the engineered barrier system through the interfaces between the bentonite buffer blocks and the host rock and those between the bentonite blocks. In this study, a series of water infiltration and gas breakthrough experiments were conducted on granite and on granite–bentonite specimens with smooth and grooved interfaces. On this basis, this study presents new insights and a quantitative assessment of the impact of the interface between clay and host rock on gas transport. As the results show, the water permeability values from water infiltration tests on granite and granite–bentonite samples (10−19–10−20 m2) are found to be slightly higher than that of bentonite. The gas permeability of the mock‐up samples with smooth interfaces is one order of magnitude larger than that of the mock‐up with grooved interfaces. The gas results of breakthrough pressures for the granite and the granite–bentonite mock‐up samples are significantly lower than that of bentonite. The results highlight the potential existence of preferential gas migration channels between the rock and bentonite buffer that require further considerations in safety assessment.

Geological genesis and identification of high-porosity and low-permeability sandstones in the Cretaceous Bashkirchik Formation, northern Tarim Basin

Abstract The genesis and prediction of high-porosity and low-permeability sandstone reservoirs are hot spots in oil and gas geology research worldwide. High-porosity and low-permeability sandstone reservoirs are developed in the Cretaceous Bashkirchik Formation of the Luntai Uplift in the northern Tarim Basin, China. In this article, we conducted a systematic study on the geological origin and logging identification of high-porosity and low-permeability tight sandstone based on core observation, thin section, logging index response, and mathematical discrimination methods. The results show that the K1bs sandstone segment in the study area generally contains calcium carbonate, which mainly comes from carbonate rock debris and calcite cement. Calcite cement mainly fills the pores between primary particles, and it is the main factor leading to the densification of the reservoir. The geological origin of the formation of low-permeability layer is mainly due to the early cementation of carbonate, and the development mode of the low-permeability layer is “high content of calcium debris → severe calcium cementation → poor petrophysical properties → formation of low-permeability layer.” The low-permeability layer has the characteristics of high gamma and high resistivity, and the multi-parameter discriminant method established based on the Fisher criterion has a good identification effect for the low-permeability layer. The low-permeability layer has a small thickness, poor stability and continuity, and strong longitudinal heterogeneity, thus it can form a low-permeability baffle inside the reservoir, which greatly reduces the oil and gas migration capacity.

Surprising concentrations of hydrogen and non-geological methane and carbon dioxide in the soil

Due to its potential use as a carbon-free energy resource with minimal environmental and climate impacts, natural hydrogen (H2) produced by subsurface geochemical processes is today the target of intensive research. In H2 exploration practices, bacteria are thought to swiftly consume H2 and, therefore, small near-surface concentrations of H2, even orders of 102 ppmv in soils, are considered a signal of active migration of geological gas, potentially revealing underground resources. Here, we document an extraordinary case of a widespread occurrence of H2 (up to 1 vol%), together with elevated concentrations of CH4 and CO2 (up to 51 and 27 vol%, respectively), in aerated meadow soils along Italian Alps valleys. Based on current literature, this finding would be classified as a discovery of pervasive and massive geological H2 seepage. Nevertheless, an ensemble of gas geochemical and soil microbiological analyses, including bulk and clumped CH4 isotopes, radiocarbon of CH4 and CO2, and DNA and mcrA gene quantitative polymerase chain reaction analyses, revealed that H2 was only coupled to modern microbial gas. The H2-CO2-CH4-H2S association, wet soil proximity, and the absence of other geogenic gases in soils and springs suggest that H2 derives from near-surface fermentation, rather than geological degassing. H2 concentrations up to 1 vol% in soils are not conclusive evidence of deep gas seepage. This study provides a new reference for the potential of microbial H2, CH4 and CO2 in soils, to be considered in H2 exploration guidelines and soil carbon and greenhouse-gas cycle research.

To necessity of gas migration control under well cementing

To necessity of gas migration control under well cementing

Dynamic Change Characteristics and Main Controlling Factors of Pore Gas and Water in Tight Reservoir of Yan’an Gas Field in Ordos Basin

Tight sandstone gas has become an important field of natural gas development in China. The tight sandstone gas resources of Yan’an gas field in Ordos Basin have made great progress. However, due to the complex gas–water relationship, its exploration and development have been seriously restricted. The occurrence state of water molecules in tight reservoirs, the dynamic change characteristics of gas–water two-phase seepage and its main controlling factors are still unclear. In this paper, the water-occurrence state, gas–water two-phase fluid distribution and dynamic change characteristics of different types of tight reservoir rock samples in Yan’an gas field were studied by means of water vapor isothermal adsorption experiment and nuclear magnetic resonance methane flooding experiment, and the main controlling factors were discussed. The results show that water molecules in different types of tight reservoirs mainly occur in clay minerals and their main participation is in the formation of fractured and parallel plate pores. The adsorption characteristics of water molecules conform to the Dent model; that is, the adsorption is divided into single-layer adsorption, multi-layer adsorption and capillary condensation. In mudstone, limestone and fine sandstone, water mainly occurs in small-sized pores with a diameter of 0.001 μm–0.1 μm. The dynamic change characteristics of gas and water are not obvious and no longer change under 7 MPa displacement pressure, and the gas saturation is low. The gas–water dynamic change characteristics of conglomerate and medium-coarse sandstone are obvious and no longer change under 9 MPa displacement pressure. The gas saturation is high, and the water molecules mainly exist in large-sized pores with a diameter of 0.1 μm–10 μm. The development of organic matter in tight reservoir mudstone is not conducive to the occurrence of water molecules. Clay minerals are the main reason for the high water saturation of different types of tight reservoir rocks. Tight rock reservoirs with large pore size and low clay mineral content are more conducive to natural gas migration and occurrence, which is conducive to tight sandstone gas accumulation.

Influence of tectonic stress field on oil and gas migration in the Tahe Oilfield carbonate reservoir: Identification of areas favorable for reservoir formation

An understanding of the tectonic stress field distribution in the carbonate reservoirs of the Tahe Oilfield is essential for oil and gas migration and reservoir reconstruction. This study adopts a geological genesis perspective and integrates the unique attributes of the carbonate reservoirs in the Tahe Oilfield to simulate three-dimensional stress fields using the finite element method and Petrel software. The simulation, which takes pore pressure and boundary constraints into consideration, aligns with the findings of acoustic emission tests conducted by previous researchers and validates the model by corroborating the maximum horizontal principal stress direction with imaging logging interpretations. With subsequent utilization of the generalized Coulomb-Mohr shear failure criterion and the Griffith generalized maximum tensile stress criterion, the simulated stress enables the prediction of the total fracture intensity. To complement this analysis, we integrate seismic data and fault formation mechanisms to characterize variations in fracture intensity within distinct regions of the study area. Three key findings emerge from this investigation. First, due to the Hercynian thermal event, X-shaped conjugate faults display a disproportionately high degree of development compared to other primary fractures. Analyzing the mechanisms of formation and development of these X-shaped strike-slip faults reveals discernible differences in deformation characteristics between NW-trending and NE-trending faults, with the former exhibiting a greater propensity for fracture rupture and efficient oil-gas migration. Second, fault intersections are critical and efficient conduits for fluid accumulation and thereby contribute to reservoir formation. Lastly, exclusive of X-shaped conjugate faults, NE-trending faults exhibit the greatest propensity for oil and gas accumulation and migration. Collectively, these findings facilitate the identification of areas favorable for oil and gas migration and provide a crucial mechanical analysis that can inform the exploration and development of the Tahe Oilfield.

Gas and water migration in cement slurries at different curing times

Gas and water migration in the hydrating cement slurry is a major cause of well completion failure. Gas and water migration may occur at different curing times due to varying well conditions and cement slurries. The current study has not been carried out to investigate the gas and water migration at different curing times. In this paper, theoretical calculations and migration experiments are used to investigate the gas and water migration in cement slurry at different curing times. The gas and water migration process can be divided into the formation rock to annular cement slurry (F-A) stage and the bottom to top (B-T) stage. At relatively short curing time, the cement slurry is more like a viscous fluid and there is clear interface between the gas and slurry. The pressure difference required for gas migration in F-A stage is very small. Maximum velocity of gas bubble migration in B-T stage is closely related to gas bubble size and cement viscosity. The smaller the size of gas bubble and the greater the viscosity of the cement slurry, the smaller the maximum velocity of the gas bubble will be. There is no clear interface between the water and slurry at relatively short curing time. The pressure difference of water migration is small. At relatively long curing time, the cement slurry has a certain of gel strength and there is also clear interface between the gas/water and slurry. The water migration is similar to gas migration. The pressure difference required for gas and water migration in F-A stage increases as the static gel strength increases. The size of the gas and water bubbles formed after invasion increases as the static gel strength increases. The critical radius at which gas and water bubbles can move is closely related to the static gel strength of the cement slurry. The greater the static gel strength, the larger the critical radius will be. The channeling path sizes of the gas and water migration are all small at relatively short curing times. The dimensions of the channel are gradually increasing from bottom to top. The pressure difference of gas migration and the dimension of channel increase as curing time increases. When the cement slurry cures for a long enough period, the gas cannot migrate in the cement slurry, but only along the weak cement slurry-wellbore interface.

Deep carbonate gas reservoir sweet spot identification with seismic data based on dual-factor control of sedimentary facies and fault system

Deep carbonate reservoirs are attractive targets for gas development. These reservoirs are deeply buried, and commonly possess strong heterogeneity and poor seismic data quality, making the identification of favorable production areas (“sweet spots”) challenging. Furthermore, sedimentary facies and fault systems markedly impact reservoir quality, and identifying these features in seismic data is also crucial for sweet spot identification. To solve these problems, we propose a dual-factor-controlled sweet spot identification method with two steps. First, sedimentary facies and faults are identified separately at different seismic scales using different attributes by the steerable pyramid (SP) method. The SP method decomposes the original seismic data into high-frequency and low-frequency data. The amplitude attributes from high-frequency data are used to identify sedimentary facies, and coherence attributes based on low-frequency data are used to characterize the fault systems. Second, after separately identifying the sedimentary facies and faults, the two attribute volumes are merged together to identify reservoir sweet spots. The results are verified by using well production data. The results of a field study in the Dengying Formation deep carbonate reservoir in the central Sichuan Basin, China, indicate that reservoir sweet spots are primarily developed in ideal sedimentary facies along strike-slip fault systems. Sedimentary facies generally control the type and distribution of reservoirs, whereas strike-slip fault systems control the migration and accumulation of gas. In addition, the fault systems serve as karst channels that further improve the reservoir properties. The proposed dual-factor method might help to maximize exploration potential in deep carbonate reservoirs with similar settings.

Enhancing carbon sequestration efficiency and safety through albumin-optimized CO2 hydrate distribution and geological layer stability: An innovative approach

The persistently high global CO2 emissions are exacerbating the greenhouse effect issue. Scientists have explored methods such as carbon sequestration via subsea hydrate formation in response to global warming. However, this method faces a series of challenges when injecting CO2 on a large scale, including the slow formation rate of CO2 hydrates and potential leakage risks. Specially, the direct injection of promoters could lead to excessively high concentrations of additives close to the injection wells. This would consequently accelerate the local hydrate conversion, potentially causing reservoir blockage problems. The current study proposes a novel strategy involving additives that exhibit varying effects with concentrations. The high-concentration areas close to the wellbore can maintain the permeability by inhibiting hydrate formation; while the reduced concentration further away upon gas migration facilitates the rapid formation of CO2 hydrates. We successfully demonstrate the spatial and temporal differences in hydrate formation when using such additives. This can also facilitate the rapid formation of a dense hydrate cap layer over the reservoir, potentially preventing the leakage of CO2 gas. A new type of additive based on egg albumin was developed, which possesses the dual function and exhibits good biocompatibility and specific reservoir stability.

Study on the mechanism of CO2 huff-n-puff enhanced oil recovery and storage in shale porous media considering heterogeneous structure

CO2 possesses several advantages, including strong solubility, effective viscosity reduction ability, and low miscible pressure, making it a promising candidate for enhanced oil recovery (EOR). Additionally, due to its adsorption capture mechanism, shale formations are considered ideal environments for CO2 storage. However, the influence of heterogeneity of shale multi-scale structure on CO2 migration mechanism, EOR, and storage mechanism is not clear. In this study, a heterogeneous shale structure model containing fractures and matrix was designed based on scanning electron microscope. The multiphase–multicomponent–multirelaxation model was used to study the fluid migration mechanism in the process of miscible CO2 huff-n-puff in shale reservoir. By analyzing density variations, velocity changes, and pressure distributions, the effects of diffusion coefficient, adsorption parameters, and fracture size were studied. Furthermore, by changing the matrix structure, the influence of heterogeneity on the law of oil and gas migration was explored. Additionally, a comparison between CO2 and water was performed. Finally, the influence of reservoir heterogeneity on fluid transport mechanism was studied. The results show that EOR and CO2 storage rate (CSR) are proportional to the diffusion coefficient. The main factor affecting the CSR is the adsorption capacity of rock to CO2. The larger CO2–oil contact area between the fracture and the matrix leads to a larger CSR, highlighting the importance of induced fractures. In addition, it was found that CO2 huff-n-puff was superior to water flooding, showing an EOR performance advantage of about 15%. This study is helpful for the practical application of CO2 huff-n-puff technology in the field of unconventional oil and gas development and CO2 storage.