Oil Shale Research Articles

Influence of Rock Fabric on Physical Properties of Shale Oil Reservoir Under Effective Pressure Conditions

Influence of Rock Fabric on Physical Properties of Shale Oil Reservoir Under Effective Pressure Conditions

Identification of Milankovitch sedimentary cycle in Fengcheng Formation, Mahu depression: a case study of well Maye 1

The sedimentary cycle of Fengcheng Formation in Junggar Basin changes rapidly and is difficult to identify. The low classification accuracy of high-frequency fine-grained sedimentary cycles restricts the exploration of unconventional shale oil and gas. Full-interval coring of well Maye 1 provides a solid foundation for small-layer research. In this paper, the high-frequency sedimentary cycle of Milan kovitch in Fengcheng Formation is studied by means of spectral analysis and wavelet transform, and the shale sweet spot is identified. The long period of eccentricity of 405ka, short period of eccentricity of 100ka and long period of axis slope of 42736a can be used as semi-quantitative basis for the classification of the fourth, fifth and sixth sequences. The Fengcheng Formation can be divided into 2 quaternary sequence cycles, 9 quaternary sequence cycles and 16 quaternary sequence cycles. A long period of eccentricity of 405ka can identify large-scale lake recessional and recessional, and there is a maximum lake flooding surface in the middle of the second Fengcheng Formation, which corresponds to high abundance of organic matter and high hydrocarbon generation potential. The 100ka short period eccentricity can identify the sweet spot layer, and there are 8 sweet spots in the well Maye 1, which is consistent with the results of nuclear magnetic interpretation. The research results provide a semi-quantitative basis for the classification of high-frequency sedimentary cycles and the identification of sweet spots of Fengcheng Formation in Mahu Sag, Junggar Basin.

A review of the flow characteristics of shale oil and the microscopic mechanism of CO2 flooding by molecular dynamics simulation

Shale oil is stored in nanoscale shale reservoirs. To explore enhanced recovery, it is essential to characterize the flow of hydrocarbons in nanopores. Molecular dynamics simulation is required for high-precision and high-cost experiments related to nanoscale pores. This technology is crucial for studying the kinetic characteristics of substances at the micro- and nanoscale and has become an important research method in the field of micro-mechanism research of shale oil extraction. This paper presents the principles and methods of molecular dynamics simulation technology, summarizes common molecular models and applicable force fields for simulating shale oil flow and enhanced recovery studies, and analyzes relevant physical parameters characterizing the distribution and kinetic properties of shale oil in nanopores. The physical parameters analyzed include interaction energy, density distribution, radial distribution function, mean-square displacement, and diffusion coefficient. This text describes how molecular dynamics simulation explains the mechanism of oil driving in CO2 injection technology and the factors that influence it. It also summarizes the advantages and disadvantages of molecular dynamics simulation in CO2 injection for enhanced recovery of shale oil. Furthermore, it presents the development trend of molecular dynamics simulation in shale reservoirs. The aim is to provide theoretical support for the development of unconventional oil and gas.

Review of Shale Oil and Gas Refracturing: Techniques and Field Applications

Shale oil and gas wells usually experience a rapid decline in production due to their extremely low permeability and strong heterogeneity. As a crucial technique to harness potential and elevate extraction rates in aged wells (formations), refracturing is increasingly employed within oil and gas reservoirs globally. At present, the selection processes for refracturing, both of wells and layers, are somewhat subjective and necessitate considerable field data. However, the status of fracturing technology is difficult to control precisely, and the difference in construction effects is large. In this paper, well selection, formation selection, and the fracturing technology of shale oil and gas refracturing are deeply analyzed, and the technological status and main technical direction of refracturing technology at home and abroad are analyzed and summarized. The applicability, application potential, and main technical challenges of existing technology for different wells are discussed, combined with the field production dynamics. The results show that well and layer selection is the key to the successful application of refracturing technology, and the geological engineering parameters closely related to the remaining reservoir reserves and formation energy should be considered as the screening parameters. General temporary plugging refracturing technology has a low cost and a simple process, but it is difficult to accurately control the location of temporary plugging, and the construction effect is very different. Mechanical isolation refracturing technology permits the exact refurbishment of regions untouched by the initial fracturing. However, it is costly and complex in terms of construction. Consequently, cutting the costs of mechanical isolation refracturing technology stands as a pivotal research direction.

Lithofacies Evaluation of Paleogene Yingxiongling Shale Oil, Qaidam Basin

Lithofacies Evaluation of Paleogene Yingxiongling Shale Oil, Qaidam Basin

Study on physical and mechanical properties of oil shale ash–based green mining filling materials

Study on physical and mechanical properties of oil shale ash–based green mining filling materials

Catalytic Conversion of Oil Shale over Fe or Ni Catalysts under Sub-Critical Water

Sub-critical water is an environment-friendly solvent. It is widely used for the extraction of various organic compounds. It can be used to dissolve and transport organic matter in oil shale. In this study, the conversion of oil shale was synergistically catalyzed by the addition of Fe or Ni to the Fe inherent in samples under sub-critical water conditions. Oil shale can be converted to gas, oil and residues of oil. Thermogravimetric (TG) analysis results presented that the weight loss of raw oil shale was up to 15.85%. After sub-critical water extraction, the weight loss rate of the residues was reduced to 8.41%. With the application of a metal catalyst, Fe or Ni, the weight loss of residues was further reduced to 7.43% and 6.57%, respectively. According to DTG curves, it was found that there were two weight-loss rate peaks. The decomposition process of kerogen in oil shale could be divided into two cracking processes. One is decomposed at a high velocity at around 420 °C, and another is decomposed at a low velocity at around 515 °C. Gas chromatography (GC) results of gas products indicated that Fe or Ni could contribute to producing normal alkanes, such as methane, ethane, propane, etc., which are produced by the hydrogenation of alkenes via hydrogen transfer during the conversion process of kerogen. Gas chromatography-mass spectrometry (GC–MS) was conducted to analyze the components of the liquid products. The results showed that n-alkanes, iso-alkane, oxygenated hydrocarbons and aromatic compounds were the major components of the kerogen cracking products. When Ni was introduced as a catalyst, the contents of aromatic compounds and oxygenated hydrocarbons in the liquid products were increased from 19.55% and 6.87% to 22.38% and 13.77%, respectively. This is due to the synergistic effect of the addition of Ni with the inherent Fe in oil shale under sub-critical water which ensures kerogen is more easily cracked to produce aromatic compounds and oxygenated hydrocarbons.

Volcanically Driven Terrestrial Environmental Perturbations during the Carnian Pluvial Episode in the Eastern Tethys

AbstractThe Carnian Pluvial Episode (CPE) fingerprints global environmental perturbations and biological extinction on land and oceans and is potentially linked to the Wrangellia Large Igneous Province (LIP). However, the correlation between terrestrial environmental changes and Wrangellia volcanism in the Ordos Basin during the CPE remains poorly understood. Records of negative carbon isotopic excursions (NCIEs), mercury (Hg), Hg/TOC, and Hg enrichment factor (HgEF) from oil shales in a large‐scale terrestrial Ordos Basin in the Eastern Tethys were correlated with marine and other terrestrial successions. The three significant NCIEs in the study section were consistently correlated with those in the CPE successions of Europe, the UK, and South and North China. The U‐Pb geochronology indicates a Ladinian–Carnian age for the Chang 7 Member. A comprehensive overview of the geochronology, NCIE correlation, and previous bio‐ and chronostratigraphic frameworks shows that the Ladinian–Carnian boundary is located in the lower part of Chang 7 in the Yishicun section. HgEF may be a more reliable proxy for tracing volcanic eruptions than the Hg/TOC ratio because the accumulation rates of TOC content largely vary in terrestrial and marine successions. The records of Hg, Hg/TOC, HgEF, and NCIEs in the Ordos Basin aligned with Carnian successions worldwide and were marked by similar anomalies, indicating a global response to the Wrangellia LIP during the CPE. Anoxia, a warm‐humid climate, enhancement of detrital input, and NCIEs are synchronous with the CPE interval in the Ordos Basin, which suggests that the CPE combined with the regional Qinling Orogeny should dominate the enhanced rate of terrigenous input and paleoenvironmental evolution in the Ordos Basin.

Preparation and Application of CO2-Resistant Latex in Shale Reservoir Cementing

With the application of CO2 fracturing, CO2 huff and puff, CO2 flooding, and other stimulation technologies in shale reservoirs, a large amount of CO2 remained in the formation, which also lead to the serious corrosion problem of CO2 in shale reservoirs. In order to solve the harm caused by CO2 corrosion, it is necessary to curb CO2 corrosion from the cementing cement ring to ensure the long-term stable exploitation of shale oil. Therefore, a new latex was created using liquid polybutadiene, styrene, 2-acrylamide-2-methylpropanesulfonic acid, and maleic anhydride to increase the cement ring’s resistance to CO2 corrosion. The latex’s structure and characteristics were then confirmed using infrared, particle size analyzer, thermogravimetric analysis, and transmission electron microscopy. The major size distribution of latex is between 160 and 220 nm, with a solid content of 32.2% and an apparent viscosity of 36.8 mPa·s. And it had good physical properties and stability. Latex can effectively improve the properties of cement slurry and cement composite. When the amount of latex was 8%, the fluidity index of cement slurry was 0.76, the consistency index was 0.5363, the free liquid content was only 0.1%, and the water loss was reduced to 108 mL. At the same time, latex has a certain retarding ability. With 8% latex, the cement slurry has a specific retarding ability, is 0.76 and 0.5363, has a free liquid content of just 0.1%, and reduces water loss to 108 mL. Moreover, latex had certain retarding properties. The compressive strength and flexural strength of the latex cement composite were increased by 13.47% and 33.64% compared with the blank cement composite. A long-term CO2 corrosion experiment also showed that latex significantly increased the cement composite’s resilience to corrosion, lowering the blank cement composite’s growth rate of permeability from 46.88% to 19.41% and its compressive strength drop rate from 27.39% to 11.74%. Through the use of XRD and SEM, the latex’s anti-corrosion mechanism, hydration products, and microstructure were examined. In addition to forming a continuous network structure with the hydrated calcium silicate and other gels, the latex can form a latex film to attach and fill the hydration products. This slows down the rate of CO2 corrosion of the hydration products, enhancing the cement composite’s resistance to corrosion. CO2-resistant toughened latex can effectively solve the CO2 corrosion problem of the cementing cement ring in shale reservoirs.

Activation energy and organic matter structure characteristics of shale kerogen and their significance for the in-situ conversion process of shale oil

Shale oil is a significant alternative energy, and in-situ conversion technology can achieve large-scale yield. The objective is to investigate the activation energy characteristics of kerogen at different maturities and total organic carbon contents. The study compared the activation energy of shale, kerogen and retained oil. The correlation between organic matter structure and in-situ conversion mechanism were also studied. In order to achieve the above objectives, the Chang 7 Formation in the Ordos Basin was used as an example. The methods include open and semi-open hydrocarbon generation thermal simulation experiment, Fourier transform infrared spectroscopy, solid-state nuclear magnetic resonance and other tests. The results indicate that the hydrocarbon generation in natural and artificially simulated kerogen samples are similar at low maturity. The proportions of low and main activation energy groups decrease with maturity, while those of high activation energy groups increase. TOC has an impact on activation energy but is not the primary factor. The proportion of low activation energy groups at different maturity stages is greater in shale than in kerogen. The activation energy of retained oil is smaller than that of shale. The activation energy increases sequentially for retained oil, shale and kerogen. The area of aliphatic carbon is significantly greater than that of aromatic carbon at low maturity. With increasing maturity, the areas of both gradually converge, and aromatic carbon surpasses aliphatic carbon by Ro around 1.1 %. Aromatic carbon and hydroxy/carboxylic carbon are mainly derived from the consumption and transformation of aliphatic carbon. The aliphatic carbon structure is mainly composed of methylene carbon, and aromatic structure coexists as single and multiple rings. There is no significant aromatic ring condensation in the maturity Ro = 0.5 ∼ 1.1 %. Different maturities affect the structure of kerogen, with TOC having a small impact. As the thermal maturity increases, the increase in the aromatic component leads to a gradual increase in the proportion of average and high activation energy groups. HI, H/C and fali exhibit a decreasing trend with maturity, indicating a reduction in the hydrocarbon generation potential. The study conducted novel experiments, which can provide a scientific basis for the in-situ conversion process of shale.

Organic geochemical study of Aleksinac oil shale

Organic geochemical study of Aleksinac oil shale

STUDY OF MICROSCALE PORE STRUCTURE AND FRACTURING ON THE EXAMPLE OF CHINA SHALE FIELD

Accurate characterization of pores and fractures in shale reservoirs is the theoretical basis for effective exploration and development of shale oil and gas. Currently, the scientific community has developed methods for determining the characteristics of the pore and fracture structure of shales with different resolutions, and also discussed the mechanisms of the influence of the characteristics of pores and cracks on the filtration of shale oil and gas. In this work, firstly, a three-dimensional model of a variable-scale pore-fracture structure was created. Secondly, on the basis of data obtained using computed tomography, the characteristics of the development of pores and cracks at different geometric sizes (25 and 2 mm) were statistically analyzed. Third, pore and fracture structures of mixed, felsitic and laminated felsitic shale have been relatively studied. The results show that: (a) the fractured porosity of group I felsite shale is 0.36–0.89 %; mixed shale of group I is 0.34–0.47 %; mixed shale of group III is 0.12–0.86 %; mixed shale of group III is 0.13–0.15 %. (b) Compared to mixed shale of group I, fracturing in felsite shale of the same group is more developed. In addition, the average fractured porosity of felsite shale is 0.28 % greater than that of mixed shale. After analyzing group III, it was noticed that the cracks of the mixed dolomite shale are less developed compared to the mixed shale of the same group, while the average porosity of the cracked shale is 0.33 % less than that of the cracks of the mixed shale (c). Various components of shale samples are distinguished on a gray scale. High density components are bright white (e.g. pyrite); medium density components — light gray (for example, quartz, carbonate and clay minerals); low-density components — dark gray (for example, organic matter); cracks — black (d). The volume of matrix components is relatively high and constitutes the bulk of the total volume of shale samples. The distribution of high-density minerals has a certain randomness. High-density ellipsoidal or irregular minerals (mainly pyrite) range in diameter from a few microns to hundreds of microns, and their volume is relatively small (e). Three types of microscale fractures are mainly developed in shale: microscale fractures within mineral particles (intragranular fractures), microscale fractures between mineral particles (intergranular fractures), and shrinkage fractures. Intragranular cracks are mainly microscale cracks formed by rigid particles that collapse in a certain direction under stress.

Application of Machine Learning for Shale Oil and Gas “Sweet Spots” Prediction

With the continuous improvement of shale oil and gas recovery technologies and achievements, a large amount of geological information and data have been accumulated for the description of shale reservoirs, and it has become possible to use machine learning methods for “sweet spots” prediction in shale oil and gas areas. Taking the Duvernay shale oil and gas field in Canada as an example, this paper attempts to build recoverable shale oil and gas reserve prediction models using machine learning methods and geological and development big data, to predict the distribution of recoverable shale oil and gas reserves and provide a basis for well location deployment and engineering modifications. The research results of the machine learning model in this study are as follows: ① Three machine learning methods were applied to build a prediction model and random forest showed the best performance. The R2 values of the built recoverable shale oil and gas reserves prediction models are 0.7894 and 0.8210, respectively, with an accuracy that meets the requirements of production applications; ② The geological main controlling factors for recoverable shale oil and gas reserves in this area are organic matter maturity and total organic carbon (TOC), followed by porosity and effective thickness; the main controlling factor for engineering modifications is the total proppant volume, followed by total stages and horizontal lateral length; ③ The abundance of recoverable shale oil and gas reserves in the central part of the study area is predicted to be relatively high, which makes it a favorable area for future well location deployment.

Characteristics of inclusions in chang 7 member and shale oil accumulation stages in Zhijing-Ansai area, Ordos Basin.

In order to further clarify the shale oil accumulation period of the Chang 7 member of the Mesozoic Triassic Yanchang Formation in the Zhijing-Ansai area of the central Ordos Basin, Using fluid inclusion petrography analysis, microscopic temperature measurement, salinity analysis and fluorescence spectrum analysis methods, combined with the burial history-thermal history recovery in the area, the oil and gas accumulation period of the Chang 7 member of the Yanchang Formation in the Zhijing-Ansai area was comprehensively analyzed. Sixteen shale oil reservoir samples of the Mesozoic Triassic Yanchang Formation in seven typical wells in the study area were selected.The results show that the fluid inclusions in the Chang 7 member of Yanchang Formation can be divided into two stages. The first stage inclusions mainly develop liquid hydrocarbon inclusions and a large number of associated brine inclusions, which are mainly beaded in fracture-filled quartz and fracture-filled calcite. The fluorescence color is blue and blue-green, and the homogenization temperature of the associated brine inclusions is between 90-110°C. The second stage inclusions are mainly gas-liquid two-phase hydrocarbon inclusions, gas inclusions and asphalt inclusions. Most of them are distributed in the fracture-filled quartz, and the temperature of the associated brine inclusions is between 120-130°C. Fluid inclusions in Chang 7 member of the Yanchang Formation can be divided into two stages. The CO2 inclusions and high temperature inclusions in the Chang 7 member of the Yanchang Formation are mainly derived from deep volcanic activity in the crust.

A new rock physics model for fractured oil shale reservoirs in Mahu oil field

The exploration of unconventional reservoirs such as oil shale has become a focus of research in the oil/gas industry, but due to the diversity of lithology and structural complexity of shale reservoirs, the study of their rock physics laws is a challenge. By analyzing the physical, lithologic, and fluid characteristics of oil shale reservoirs in the Mahu area of Xinjiang, China, we adopted a variety of effective-medium theories to carry out rock physics modeling. We analyzed the differences in the calculation results of various theoretical models, and finally constructed a set of rock physics modeling processes suitable for oil shale reservoirs. The analysis shows that the calculation results of Voigt-Reuss-Hill (VRH) and Hashin-Shtrikman (HS) average for mixed mineral matrix are very similar, but there are certain differences between the upper and lower bounds calculated by them. The upper and lower bounds of HS average are closer than VRH average. We used the Kuster-Toksoz effective-medium, differential effective-medium (DEM), and self-consistent approximation models to construct the rock skeleton and analyzed the differences of the models. The results of the three models are almost identical, but their assumptions and limitations differ. We used DEM in the final shale model, considering the large porosity and the order of inclusion filling. According to the fracture distribution characteristics of oil shale reservoirs, we used an inclined fracture model to describe the fractures with different structural characteristics. Finally, the established shale rock physics model was used to calculate the actual logging data, and the results of elastic parameters are consistent with the measured data. Through the inversion of the fracture parameters, the inversion results are consistent with the measured results as a whole, indicating that the model has certain applicability to the simulation of oil shale reservoirs.

Ranking the oil contribution of individual layers in a lacustrine shale oil system based on non-hydrocarbon analysis by FT-ICR MS

Identifying the dominating oil-producing layer(s) within a shaly system, typically characterized by multiple layers with similar properties, is always a critical yet formidable task, as the oil component disparities among these closely adjacent layers are too minor to be resolved by the traditional geochemical fingerprints. This challenge is now likely addressed by high-resolution Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS), which can resolve thousands of non-hydrocarbons that could serve as new fingerprints. Taking a typical shaly system in the Ordos Basin in China as an example, the specific proportions of non-hydrocarbon compounds from the retained petroleum of different source rock layers (rock extracts) and the produced oil at the wellhead were identified by FT-ICR MS. Their compositional similarity was calculated using a multidimensional scaling (MDS) method, and the layers hosting the retained petroleum with higher compositional similarity to the produced oils are considered to be the main contributors to oil production. The results show that the main producing layers identified by FT-ICR MS differ from those proposed based on traditional fingerprints like the Rock-Eval parameters. A typical example is that the thick low-TOC shales, conventionally proposed to be unessential to oil production, seem to have a similar contribution, if not higher, to their thick silty counterparts. This divergence may be attributed to the fact that the conventional fingerprints primarily rely on the rock extracts from a vertical well section, which may only represent a limited lateral area, while the non-hydrocarbon similarity approach involving the produced oil appears to be more realistic, as it can consider the engineering processes, like the horizontal well track and the hydraulic fracturing effects. The current approach provides a novel route for identifying the dominating producing layer(s) in a shale oil system, which may have extensive potential for optimizing the production strategy of shale oil wells.

Simulation Optimization on Multi-Well Fracturing Sequence of Chang 7 Formation

In order to study the engineering problems of shale oil horizontal well platform fracturing mode, a three-dimensional geological model and a three-dimensional geomechanical model were constructed according to the characteristics of Chang 7 section in Ordos Basin. The fracture propagation under different well spacing, cluster spacing, and fracturing sequence was simulated. The PEBI grid was used to refine the local grid of the fractures and predict the performance of the multi-well pad. The finite element model was used to analyze the change of induced stress field. The numerical simulation analysis shows that: 1) Comparing the simulation results of sequence fracturing and zipper fracturing under the condition of 300 m well spacing, the induced stress generated by zipper fracturing is more conducive to the formation of complex fractures, improving the effect of transformation and higher production after fracturing. 2) Under the condition of 200 meters or 300 meters well spacing, zipper fracturing is carried out, and the cluster spacing is reduced from 5 meters to 3 meters. The stress shadow between wells and sections leads to adverse effects, and the production will decrease after fracturing. Therefore, 5 meters is recommended as the cluster spacing.

Study of Geomechanical Properties of the Pimienta Formation with Undrained Multi-stage Triaxial Tests, Central-Western Tampico Misantla Basin, Mexico

The Pimienta Formation (J-Pi) of the Tampico Misantla Basin (TMB) in Mexico is known for its potential as unconventional onshore hydrocarbon reserves. The area of interest in this study is located in the western-central part of the TMB, where no significant production has been established from unconventional resources. Given the low permeability and low porosity characteristics of the carbonaceous mudstone in the Pimienta formation, it is necessary to implement techniques to increase the area of flow from the reservoir to the borehole, achieving profitable oil and gas extraction.The geomechanical properties of rock strata are essential inputs for the design and implementation of shale oil and gas production engineering, such as horizontal drilling and hydraulic fracturing. Understanding the capabilities of the rock to yield and contain hydraulic fractures is essential to designing safe and efficient well stimulations. Likewise, the wellbore stability is of critical importance to the successful development of secondary and tertiary recovery systems.In this study, core samples from the Pimienta Formation in the TMB are analyzed through undrained multi-stage triaxial tests, emphasizing the estimated in-situ geo stresses and the effect of the mineral composition of the rock. The geomechanical parameters of compressional strength, Poisson ratio (PR), and Young’s modulus of the Pimienta formation are obtained from the analysis of the experimental data and finding correlations to the mineral composition of the samples. A detailed characterization is completed under the conventional rock mechanics methodologies of Mohr-Coulomb and Hoek-Brown failure criterion, as well as rock classification of Geological Strength Index (GSI) and Brittleness Index (BI).

A novel multiphase and multicomponent model for simulating molecular diffusion in shale oil reservoirs with complex fracture networks

Molecular diffusion is critical for enhanced oil recovery (EOR) in shale oil reservoirs with complex fracture networks. Understanding the influence of fractures on diffusive mass transfer is crucial for predicting oil recovery and remaining oil distribution. Diffusive mass transfer between fractures and matrix is critical in comprehensively and effectively simulating molecular diffusion. Resolution of matrix cells significantly affects diffusion accuracy at the fracture–matrix interface. Low resolution results in multiple fractures in the same matrix cell, leading to decreased precision in calculating mass transfer by conventional methods. To address this, a novel multiphase and multicomponent model is proposed. The new model integrating the consideration of fracture spacing modifies molecular diffusion transmissibility between fracture and matrix in an embedded discrete fracture model. The discretization employs the two-point flux approximation in the finite-volume method. Validation compares the coarser mesh to the finest grid as a reliable reference. Results show the proposed model accurately captures diffusive mass transfer in a coarser mesh. Modified models study molecular diffusion's effects on EOR in shale oil reservoirs with complex fracture networks by CO2 huff and puff. Results indicate that increasing injection rates cannot improve oil recovery under extremely low porosity and permeability. Molecular diffusion facilitates CO2 penetration into the formation. This expands the swept CO2 volume and increases both volume expansion and formation energy. In addition, the light and heavy components of the crude oil are diffused into the fractures and eventually produced, which reduces gas production in the case of diffusion.

CO2-enhanced oil recovery with CO2 utilization and storage: Progress and practical applications in China

CO2 capture, utilization, and storage (CCUS) is a strategic emerging technology that has undergone rapid development in recent years. CO2-Enhanced oil recovery with CO2 utilization and storage (CCUS-EOR) is currently the most practicable large-scale carbon reduction technology and has become a key tool for large-scale applications of CCUS. In the inceptive period, CCUS-EOR was targeted towards flooding, but has since been extensively adopted for industrialization. At present, CCUS-EOR is being developed for synergistic flooding and storage, and is expected to gradually transition to utilization in geological storage for supporting large-scale carbon reduction to achieve the goal of carbon neutrality. The primary mechanisms controlling CCUS-EOR differ for high-permeability, high-water-cut oil reservoirs; low-permeability oil reservoirs; extra-low permeability oil reservoirs; and tight and shale oil reservoirs. Therefore, identifying the main constraints in the CO2 flooding process and formulating effective development strategies are necessary for maximizing both oil recovery and storage. In the geological storage of CO2, attention must be paid to key factors such as the storage capacity, injectivity, and safety. The storage performance can be enhanced through methods such as synergistic CO2-enhanced water recovery and CO2 storage (CCS-EWR), as well as rapid carbon mineralization in basalt. Globally, CCUS projects have undergone rapid growth, with more than 90 % of operational projects led by or involving oil and gas companies. In China, CCUS-EOR is currently in the early stage of industrial application. The first million-ton CCUS project has recently been completed. China has great potential for CCUS-EOR. An advantage of CCUS-EOR is the early adoption to large-scale applications, while CO2 storage in saline aquifers provides a foundation for promoting large-scale development. In the future, multiple CCUS-EOR clusters are expected to be established in the Bohai Bay Basin, Songliao Basin, Ordos Basin, Yangtze River Delta, and Pearl River Delta regions, which will drive high-quality development of CCUS applications in China. ChineseLibrary Classification Number TE341. Document CodeA.