Oil Shale Research Articles

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.

Experimental and numerical investigation on the pyrolysis of oil shale particles in a bubbling fluidized bed

The efficient utilization of oil shale resource is beneficial to environment and the resource diversity. In this work, a bubbling fluidized bed (BFB) reactor was first used to pyrolyze Huadian oil shale experimentally, mainly focusing on the influence of fluidization flow rates. The yield of shale oil, char and non-condensable gas varies little at different fluidization flow rates, but the components in shale oil are different due to the secondary cracking, such as the fractions and species of aliphatic hydrocarbons, aromatic hydrocarbons and non-hydrocarbons. Then, the dense discrete phase model (DDPM) was used to track the trajectories of oil shale particles with different diameters in a bubbling fluidized bed. Population balance model (PBM) coupled Eulerian model was used to well describe the bubbling status of bed materials to characterize the hydrodynamic behaviors. Furthermore, a segmented kinetic model was compiled by UDF module to illuminate the pyrolysis of oil shale particles. The multi-phase reactive flow modeling clearly indicated the distribution of oil shale particles and gaseous products in BFB reactor, as well as pyrolysis time and the secondary cracking at different fluidization flow rates. In summary, this work provides a reference basis for complete pyrolysis of oil shale particles in a bubbling fluidized bed and generating shale oil with high yield and good quality.

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.

Lithofacies Characteristics of Continental Lacustrine Fine-Grained Sedimentary Rocks and Their Coupling Relationship with Sedimentary Environments: Insights from the Shahejie Formation, Dongying Sag

Lacustrine fine-grained sedimentary rocks in the Dongying Sag of the Bohai Bay Basin in China exhibit significant potential for hydrocarbon exploration. This study investigates the lithofacies types and sedimentary evolution of the Paleogene Shahejie Formation’s lower third member (Es3l) and upper fourth member (Es4u), integrating petrological and geochemical analyses to explore the relationship between lithofacies characteristics and sedimentary environments. The results show that the fine-grained sedimentary rocks in the study area can be classified into 18 lithofacies, with seven principal ones, including organic-rich laminated carbonate fine-grained mixed sedimentary rock lithofacies and organic-rich laminated limestone lithofacies. In conjunction with analyses of vertical changes in geochemical proxies such as paleoclimate (e.g., CIA, Na/Al), paleoproductivity (e.g., Ba), paleosalinity (e.g., Sr/Ba), paleo-redox conditions (e.g., V/Sc, V/V + Ni), and terrigenous detrital influx (e.g., Al, Ti), five stages are delineated from bottom to top. These stages demonstrate a general transition from an arid to humid paleoclimate, a steady increase in paleoproductivity, a gradual decrease in paleosalinity, an overall reducing water body environment, and an increasing trend of terrestrial detrital input. This study demonstrates that the abundance of organic matter is primarily influenced by paleoproductivity and paleo-redox conditions. The variations in rock components are predominantly influenced by paleoclimate, and sedimentary structures are affected by the depth of the lake basin. Special depositional events, such as storm events in Stage II, have significantly impacted the abundance of organic matter, rock components, and sedimentary structures by disturbing the water column and disrupting the reducing conditions at the lake bottom. The present study offers crucial insights into the genesis mechanisms of continental lacustrine fine-grained sedimentary rocks, facilitates the prediction of lithofacies distribution, and advances the exploration of China’s shale oil resources in lacustrine environments.

Influence of Organic Matter Thermal Maturity on Rare Earth Element Distribution: A Study of Middle Devonian Black Shales from the Appalachian Basin, USA

This study focuses on understanding the association of rare earth elements (REE; lanthanides + yttrium + scandium) with organic matter from the Middle Devonian black shales of the Appalachian Basin. Developing a better understanding of the role of organic matter (OM) and thermal maturity in REE partitioning may help improve current geochemical models of REE enrichment in a wide range of black shales. We studied relationships between whole rock REE content and total organic carbon (TOC) and compared the correlations with a suite of global oil shales that contain TOC as high as 60 wt.%. The sequential leaching of the Appalachian shale samples was conducted to evaluate the REE content associated with carbonates, Fe–Mn oxyhydroxides, sulfides, and organics. Finally, the residue from the leaching experiment was analyzed to assess the mineralogical changes and REE extraction efficiency. Our results show that heavier REE (HREE) have a positive correlation with TOC in our Appalachian core samples. However, data from the global oil shales display an opposite trend. We propose that although TOC controls REE enrichment, thermal maturation likely plays a critical role in HREE partitioning into refractory organic phases, such as pyrobitumen. The REE inventory from a core in the Appalachian Basin shows that (1) the total REE ranges between 180 and 270 ppm and the OM-rich samples tend to contain more REE than the calcareous shales; (2) there is a relatively higher abundance of middle REE (MREE) to HREE than lighter REE (LREE); (3) there is a disproportionate increase in Y and Tb with TOC likely due to the rocks being over-mature; and (4) the REE extraction demonstrates that although the OM has higher HREE concentration, the organic leachates contain more LREE, suggesting it is more challenging to extract HREE from OM than using traditional leaching techniques.

Formulation optimization of oil shale semi-coke/lime/cement solidified loess based on ternary nephogram and establishment of elastic-plastic damage model

Oil shale semi-coke (OSS) is a industrial solid waste produced after the dry distillation refining of oil shale. Due to its internal enrichment of activity silico-aluminate minerals, it can be utilized to prepare low-carbon cementitious materials through alkali activation. In this study, a composite material for reinforcing loess was synthesized using OSS, lime, and cement. Drawing upon the ternary design method, the optimization of oil shale semi-coke/lime/cement stabilized loess (OLC-SL) formulation was explored. Through microscopic analysis, the enhancement mechanism of OLC-SL was probed. Furthermore, it comprehensively understood the stress-strain characteristics of OLC-SL by conducting triaxial experiments and developed an elastic-plastic damage model for OLC-SL through numerical. The outcomes of this study provide novel insights and theoretical support for the resource utilization of OSS waste, and hold crucial implications for promoting the large-scale application of OSS waste in the disposal of expansive loess.

Flow Characterization in Fractured Shale Oil Matrices Using Advanced Nuclear Magnetic Resonance Techniques

The evaluation of flow dynamics in fractured shale oil reservoirs presents significant challenges due to the complex pore configurations and high organic material concentration. Conventional methods for petrophysical and fluid dynamic evaluations are insufficient in addressing these complexities. However, nuclear magnetic resonance (NMR) technology is an effective technique for quantitatively delineating fluid micro-transport properties across the reservoir core. This study presents an experimental methodology rooted in NMR technology to quantify the flow capabilities within the shale oil matrix. This approach incorporates high-pressure saturation flow experiments across seven distinct core samples to gauge the micro-transport phenomena of fluids across various pore dimensions. The results revealed that under high-pressure saturation, shale cores devoid of fractures demonstrated an average crude oil saturation rate of merely 19.44%. Cores with evident stratification exhibited a 16.18% increase in flow capacity compared to their non-stratified counterparts. The flow dynamics within these shale reservoirs exhibited a range of behaviors, from non-linear to linear. In lower-permeability zones, non-linear patterns became increasingly apparent. An NMR T2 spectrum analysis was used to identify the minimum effective pore size conducive to shale oil flow within the matrix, which was between 8 and 10 nanometers. These insights provide a foundation for a deeper understanding of the mechanisms behind oil and gas migration in fractured shale oil matrices, offering valuable insight into their extractive potential.

Mechanisms of carbon dioxide extracting oil at the boundary layer on shale nanopore surface: insights from molecular dynamics

Boundary layer formed by crude oil on the shale nanopores surface hinders fluidity of crude oil and leads to a decline in oil recovery. CO2 injection has been considered as an effective method to enhance shale oil recovery. However, the impact of CO2 on the disruption of boundary layers within shale nanopores and the extraction mechanisms of crude oil during the recovery process remains unclear. In this work, molecular dynamics simulation was employed to investigate the process of using scCO2 to extract crude oil from shale nanopore surface. During the process of scCO2 extraction, polar molecules have the capability to reduce the diffusion coefficient, prolong the residence time, and decrease flowability of decane, ultimately resulting in a deterioration of its kinetic properties. Phenol, with its hydrophilic hydroxyl group, closely adheres to the shale surface, while the oleophylic benzene ring covers the shale surface, causing a transition in the wettability of this segment from hydrophilic to oleophylic. As a result, a substantial adsorption of decane occurs on phenol. The research findings contribute to the comprehension of the scCO2 extraction mechanism and the advancement of unconventional oil and gas resources.

A novel rock physics model of organic-rich shale considering maturation influence

Geochemical parameters, e.g. maturity, and total organic carbon (TOC) content, play a crucial role in the prediction of sweet spots and the exploration of oil and gas in organic-rich shales. Thermal maturity significantly affects the conversion of solid organic matter (OM) into hydrocarbons and the evolution of microstructures, thereby altering the overall elastic properties of shales. To clarify how the maturity affects shale property, we propose a novel Rock Physics Model (RPM) of organic-rich shale, in which we consider the continuous process of thermal maturity.#xD;Firstly, we present how to estimate maturity level, TOC content, and organic porosity using logging data. Secondly, different from only considering the discrete-stage maturity, we establish a novel RPM, in which a continuous kerogen maturation process serves as a key control condition. Furthermore, we propose how to calibrate the volumetric proportion of each porosity type as a function of maturation. Finally, we apply the RPM to investigate how sweet spot parameters (thermal maturity, TOC content, and brittle mineral content), overpressure and diagenesis affect the overall elastic properties and anisotropy of shale. Results demonstrate that using the proposed RPM we may predict acoustic velocity of shale formations reliably, and kerogen evolution has a noticeable impact on the elastic properties of shale rocks, particularly during the wet gas window stage of mid-to-high maturation. We conclude that thermal maturity emerges as a crucial sweet spot parameter in the case of exploration of oil and gas in organic-rich shales.

Dynamic Evolution Mechanism of Reservoir Physical Properties during Oil Shale In Situ Conversion

Dynamic Evolution Mechanism of Reservoir Physical Properties during Oil Shale In Situ Conversion

Innovative synthesis of low-carbon cemented backfill materials through synergistic activation of solid wastes: An integrated assessment of economic and environmental impacts

The accumulation of large amounts of steel slag (SS) and oil shale residue (OSR) causes serious pollution due to the lack of effective ways to utilize them. In this study, OSR, SS, and soda residue (SR) were used to synergistically prepare all-solid-waste low-carbon cemented backfill material (ALCCB). No cement and chemical additives were added to this material, and synergistic activation enabled full utilization of the solid wastes. The total solid waste utilization rate was 100 %. The mechanical characteristics of the ALCCB and the heavy metal leaching rates were determined. The unconfined compression strength of the ALCCB after 28 days was 5.97 MPa, while the slump was 205 mm. These results met the performance requirements for a filling material. The leaching rates for the heavy metals after 28 days conformed to the guidelines for Class III groundwater quality. The mechanism underlying synergistic hydration of the solid wastes was analyzed at the micro- and macroscale with X-ray diffraction (XRD), thermogravimetric analysis (TG), scanning electron microscopy (SEM), and mercury intrusion porosimetry (MIP). The results indicated that hydration of the ALCCB occurred continuously during curing, and the faster early hydration reaction stabilized heavy metal curing at 7 d. In addition, ALCCB offers greater economic and environmental advantages than cementitious materials. Notably, the economic and environmental benefits of ALCCB were found to supersede those of cement-based materials, with a cost reduction of 42.6 % and a CO2 emission reduction of 86.9 %. This innovative low-carbon mine backfill material effectively promotes the utilization of solid waste resources and supports sustainable development.

Formation and evolution of shale overpressure in deep Wufeng-Longmaxi Formation in southern Sichuan basin and its influence on reservoir pore characteristics

In the deep Longmaxi Formation shale gas reservoirs of the southern Sichuan Basin, strong overpressure is universally developed to varying degrees. However, there is currently a lack of in-depth research on the formation mechanisms, evolutionary patterns, and the controlling effects on reservoir pore characteristics of strong overpressure. This limitation significantly restricts the evaluation of deep shale gas reservoirs. This study selected typical overpressured shale gas wells in Yongchuan, Luzhou, and Dazu areas as research subjects. Through comprehensive methods such as log analysis, fluid inclusion analysis, and numerical simulation, the dominant mechanisms of strong overpressure formation were determined, and the pressure evolution from early burial to late strong uplift was characterized. Additionally, the impact of varying degrees of overpressure on reservoir pore characteristics was studied using techniques such as scanning electron microscopy, gas adsorption-mercury intrusion, and helium porosity testing. The research findings indicate that hydrocarbon generation expansion is the primary mechanism for strong overpressure formation. The pressure evolution in the early burial phase is controlled by the processes of kerogen oil generation and residual oil cracking into gas. The reservoir experienced three stages: normal pressure (Ordovician to Early Triassic), overpressure (Early Triassic to Early Jurassic), and strong overpressure (Early Jurassic to Late Cretaceous), with pressure coefficients of approximately 1.08, 1.56, and 2.09, respectively. During the late strong uplift phase, the adjustment of early overpressure occurred due to temperature decrease and gas escape, leading to a decrease in formation pressure from 140.55 MPa to 81.63 MPa, while still maintaining a state of strong overpressure. Different degrees of strong overpressure exert a significant control on the physical properties of shale reservoirs and the composition of organic matter pores. Variations exist in the organic matter pore morphology, structure, and connectivity within the deep Wufeng-Longmaxi shale. Higher overpressure favors the preservation of organic large pores and reservoir porosity. Under conditions of strong overpressure development, deep siliceous shales and organically rich clay shales exhibit favorable reservoir properties. By determining the dominant mechanisms of strong overpressure in the Wufeng-Longmaxi Formation and studying pore characteristics, this research not only deepens the understanding of the geological features of deep shale gas reservoirs but also provides a new perspective for understanding the overpressure mechanisms and reservoir properties of deep shale gas reservoirs. Moreover, it is of significant importance for guiding the exploration and development of deep Longmaxi shale and provides valuable references for further research in related fields.

Two-dimensional spectrum characteristics and oil movability study of the shale oil reservoir

Shale oil is mainly stored in the nano–micro-pores of shale in the form of adsorption or in a free state. Among them, only free-state oil is the main contributor to shale oil production under natural elastic energy. Therefore, it is crucial to evaluate the movability of crude oil effectively. In this paper, focusing on the Jurassic shale oil reservoir core in the middle-eastern Sichuan region of China, low-field nuclear magnetic resonance (NMR) technology is used to analyze the basic characteristics of shale oil core samples. Experiments on the low-field NMR one-dimensional and two-dimensional spectrum characteristics of the original core, heat-treated core, and thermogravimetric-treated shale core are carried out. The effects of the TG-MS method, T2 method, and the volatilization of light oil components on the movability of shale oil reservoirs are analyzed, and the movability characteristics of shale oil reservoirs in the middle-eastern Sichuan region are preliminarily clarified. The results show that under thermal treatment, the distribution range of the two-dimensional spectrum of the core oil occurrence area is significantly reduced, and the T1 and T2 distribution ranges are reduced by 10.9% and 60.7%, respectively. According to the TG-MS method, the mobile oil, bound oil, and adsorbed oil account for 74.7%, 8.1%, and 17.2%, respectively. The quantitative calculation of movable oil saturation by NMR combined with heat treatment is 65.6%, which is lower than that calculated using the thermogravimetric method. In order to calculate the movability more accurately, the scale effect between different samples should be considered. This study could provide a theoretical basis for the subsequent shale oil development program.

Effect of wettability on fracturing fluid microscale flow in shale oil reservoirs

The wettability of shale reservoirs has an important influence on the flow of external fluids. In this paper, the effect of wettability on the self-absorption of hydraulic fracturing fluid under different pore size conditions is first analyzed. Then, the mechanism of the influence of wettability pore size on the flow coefficient is elucidated. The results show that (a) as the pore size decreases, the importance of various forces acting on the fluid during the flow process changes, and the solid-liquid interaction will greatly affect the fluid flow in the nanopore. (b) When the radius is 5, the flow enhancement increases from 0.6331 to 0.998 as the radius increases from 0 to 3.141594.(c) The shale inorganic material contains a variety of minerals, and the interaction forces between different mineral surfaces and water molecules are different, resulting in different apparent viscosities.

Mechanisms of CO2-rich industrial waste gas enhanced shale oil recovery in kerogen slit based on adsorption behavior, gas flooding and surfactant synergy study

Enhanced oil recovery (EOR) by injection of CO2-rich industrial waste gas has been proposed as an energy-efficient and environmentally friendly method for shale oil reservoirs, in which the waste gas can be utilized and sequestered to reduce greenhouse gas emissions. In this work, the adsorption behaviors of shale oil and waste gas components in kerogen slits and the effects of gas flooding on EOR were investigated using molecular dynamics (MD) method, which can provide technical guide for shale oil development. In terms of the adsorption behaviors, an intensity decrease of oil adsorption is observed in kerogen slits after the injection of the waste gas components. Desorption of shale oil during injection of SO2 and CO2 is more pronounced in shallow reservoirs, whereas it is more evident for NO and N2 in deep reservoirs. The desorption efficiency can be 10.91 % for pure CO2 injection and 9.09 % for NO injection at a depth of 1000 m, and the relative stability ratios of CO2 and NO sequestration are 77.09 % and 76.06 %, respectively. For gas flooding, the existence of pressure difference provides favorable conditions for gas molecules to pass through the oil zone, and waste gas can be more effective than pure CO2 as driving gas. For the waste gas injection, the percentage of CO2 retained in the kerogen nanopores is much higher than that of pure CO2 injection, suggesting that more CO2 molecules can enter into kerogen matrix to take part in the displacement process. Furthermore, the effect of surfactants on oil desorption and displacement was also investigated and the interaction energy of the surfactant/oil/gas system was calculated and analyzed, finding that addition of the oil-soluble surfactants can be beneficial to shale oil displacement. This work can provide a comprehensive evaluation of the feasibility of CO2-rich industrial waste gas application for EOR, which is of great significance in the effective production of shale oil and the sequestration of waste gas in shale reservoirs.

Integrated Study on Carbon Dioxide Geological Sequestration and Gas Injection Huff-n-Puff to Enhance Shale Oil Recovery

Integrated Study on Carbon Dioxide Geological Sequestration and Gas Injection Huff-n-Puff to Enhance Shale Oil Recovery

A novel algorithm for asphaltene precipitation modeling in shale reservoirs with the consideration of capillary pressure during the CCUS processes

Tight and shale reservoirs have markedly expanded their role in global oil and gas production. However, the overall recovery from these reservoirs is suboptimal, leaving much of the shale oil unrecovered. CO2 flooding is a promising enhanced oil recovery (EOR) technique that can improve oil extraction and simultaneously facilitate carbon capture, utilization, and storage (CCUS). However, this method presents challenges, notably the precipitation and deposition of asphaltene, which risks plugging the nanoporous structure characteristic of shale reservoirs. Given that the nanopore sizes in these reservoirs align closely with asphaltene particle dimensions, the risk of pore and throat blockages during gas injection is pronounced. Although various asphaltene precipitation models have been proposed, there is still a lack of robust algorithms accounting for the substantial influence of capillary pressure on asphaltene precipitation in these nanopores. In this study, a novel three-phase vapor–liquid-asphaltene equilibrium calculation algorithm coupled with capillary effect is developed. The algorithm is first validated by comparing with the experimental data of the Px phase diagram and asphaltene precipitation amount. The validated algorithm is then used to conduct example calculations to demonstrate the robustness of the new algorithm and to examine the impact of capillarity on the three-phase vapor–liquid-solid (VLS) equilibria. Computation results show that capillary pressures in nanopores substantially modify the three-phase VLS equilibria, causing shifts in saturation pressure and influencing asphaltene precipitation. Generally, asphaltene precipitation in nanopores occurs at a lower pressure and gas injection concentration. The smaller pore sizes intensify these effects, but the impact diminishes as pressure increases. Additionally, the gas composition also greatly affects asphaltene precipitation. The results reveal that this new algorithm is robust across different conditions, offering an innovative approach that reliably predicts asphaltene precipitation considering the effect of capillary pressures, paving the way for improved EOR and CCUS in shale reservoirs.