Shale Oil Reservoirs Research Articles

A compositional numerical study of vapor–liquid-adsorbed three-phase equilibrium calculation in a hydraulically fractured shale oil reservoir

The development of carbon capture, utilization, and storage technologies has notably advanced CO2-enhanced oil recovery (EOR) in shale oil reservoirs, which are characterized by abundant nanopores. These nanopores induce unique phase behaviors in hydrocarbons, challenging traditional phase equilibrium calculation methods. This paper presents a novel three-phase thermodynamic model (vapor–liquid-adsorbed three-phase equilibrium calculation) that addresses these challenges by considering the nanopore capillary pressure, critical parameter transitions, and material exchange between the adsorbed and bulk phases. Grounded in the multicomponent Langmuir–Freundlich adsorption equation and the Peng Robinson equation of state, this model is integrated into the MATLAB Reservoir Simulation Toolbox using an embedded discrete fracture model framework, enabling detailed study of CO2 and hydrocarbon phase behaviors within shale oil nanopores. The results reveal that there are significant nano-constrained effects on multicomponent fluid phase behavior, particularly in pores smaller than 20 nm, leading to notable changes in bubble and dew point pressures, as well as critical condensation pressures and temperatures. CO2 injection further complicates the system, enhancing interactions and expanding the coexistence region of the liquid and gas phases on the pressure–temperature diagram, especially across varying pore sizes. Optimization research on CO2 huff and puff technical parameters for shale oil reservoirs suggests the following optimal settings: a CO2 injection rate of 100 t/day, a shut-in time of 30 days, and six huff and puff cycles. The results of this study offer critical insights into CO2-EOR mechanisms in shale oil reservoirs and emphasize the importance of nanopore properties in EOR.

Comprehensive study of hydraulic fracturing in shale oil reservoirs comprising shale–sandstone transitions

Hydraulic fracturing technology is a crucial technique for effectively developing shale oil reservoirs. In field fracturing treatment operations, these reservoirs are often consisting of a combination of various rock types that making them complex. Therefore, this study specially focuses on the sandstone–shale layers in the G zone of the Daqingzi Well G Area in the southern part of the Songliao Basin. It aims to provide essential parameter support for subsequent theoretical and numerical research through laboratory mechanical experiments. Using the finite discrete element method, we have established four different numerical models for the hydraulic fracturing of shale oil with varying geological conditions, (including transition zones). The study reveals that when the vertical stress difference is 6 MPa, the crack height increases, and the offset distance decreases. At 8 and 10 MPa, crack propagation exhibits a “forking” phenomenon. A decrease in rock cohesion leads to increased offset distances in the transition zone, along with an increase in crack height. For type a and b transition zones, it is recommended to use a fracturing fluid with a viscosity of approximately 10 mPa s and a flow rate of 12 m3/min for fracturing. For type c transition zones, it is advisable to select fracturing fluid with a viscosity in the range of 10–30 mPa s and use a flow rate of 12 m3/min for fracturing. For the type d transition zones in the fracturing reservoir, it is recommended to use fracturing fluid with a viscosity of around 10 mPa s and a flow rate of 15 m3/min for optimal field fracturing operations.

Machine learning-based grayscale analyses for lithofacies identification of the Shahejie Formation, Bohai Bay Basin, China

It is of great significance to accurately and rapidly identify shale lithofacies in relation to the evaluation and prediction of sweet spots for shale oil and gas reservoirs. To address the problem of low resolution in logging curves, this study establishes a grayscale-phase model based on high-resolution grayscale curves using clustering analysis algorithms for shale lithofacies identification, working with the Shahejie Formation, Bohai Bay Basin, China. The grayscale phase is defined as the sum of absolute grayscale and relative amplitude as well as their features. The absolute grayscale is the absolute magnitude of the gray values and is utilized for evaluating the material composition (mineral composition + total organic carbon) of shale, while the relative amplitude is the difference between adjacent gray values and is used to identify the shale structure type. The research results show that the grayscale phase model can identify shale lithofacies well, and the accuracy and applicability of this model were verified by the fitting relationship between absolute grayscale and shale mineral composition, as well as corresponding relationships between relative amplitudes and laminae development in shales. Four lithofacies are identified in the target layer of the study area: massive mixed shale, laminated mixed shale, massive calcareous shale and laminated calcareous shale. This method can not only effectively characterize the material composition of shale, but also numerically characterize the development degree of shale laminae, and solve the problem that difficult to identify millimeter-scale laminae based on logging curves, which can provide technical support for shale lithofacies identification, sweet spot evaluation and prediction of complex continental lacustrine basins.

Lamina-scale diagenetic mass transfer in lacustrine organic-rich shales and impacts on shale oil reservoir formation

Lamina-scale diagenetic mass transfer in lacustrine organic-rich shales and impacts on shale oil reservoir formation

Simulation of CO2 enhanced oil recovery and storage in shale oil reservoirs: Unveiling the impacts of nano-confinement and oil composition

Simulation of CO2 enhanced oil recovery and storage in shale oil reservoirs: Unveiling the impacts of nano-confinement and oil composition

Utilizing well-reservoir pseudo-connections for multi-stage hydraulic fracturing modeling in tight gas saturated formations

Purpose. Research is aimed at integrating multi-stage hydraulic fracturing in horizontal wells with hydrodynamic simulation as a mandatory part of planning the mining of any shale oil or gas reservoir. Methods. Geological and hydrodynamic reservoir modeling is part of the research. The properties and geometries of the hydraulic fracture network and its representation in the dynamic reservoir model were assessed. The comparative characterization was carried out based on the two methods of fracture modeling: cell dimension reduction for explicit fracture modeling (LGR – local grid refinement) and implicit fracture modeling method, presented in this paper, with additional pseudo-connections between well and reservoir. Findings. A hydrodynamic model for low-permeable reservoir, produced by horizontal well, hydraulically fractured with 5 stages, has been generated. This model is calibrated to the production history and flowing bottom hole pressure by applying two methods of fracture modeling. Modeling results show that it is possible to replicate historical well production by using both methods. However, the proposed method with pseudo connections has several advantages compared to the generally accepted, local grid refinement (LGR) method. Originality. For the first time, a system of pseudo connections between well and reservoir was constructed to model a multi-stage hydraulic fracturing for a hydrodynamic model of tight reservoir. Hydrodynamic simulation results were refined and calibrated to the history of hydrocarbon production and flowing bottom hole pressure data using the pseudo-connections and LGR methods. The similarity of the results by applying LGR and pseudo-connections methods was revealed. Practical implications. The use of pseudo connections for hydraulic fracturing modeling can reduce simulation run time for cases where multi-stage hydraulic fracturing has already been carried out or is planned in the future. Additionally, the use of this method allows testing a larger number of realizations and scenarios, including hydraulic fracturing design (number of stages, size and conductivity of resulted fracture systems, fracture orientation, etc.), well placement and fracture growth relative to well trajectory. Also, there is no need to rebuild a model every time for each realization, as is the case with the LGR method.

The occurrence of pore fluid in shale-oil reservoirs using nuclear magnetic resonance: The Paleogene Funing Formation, Subei Basin, Eastern China

The occurrence characteristics of pore fluids restrict shale oil recovery. Various approaches have been proposed to analyze the microdistribution of shale oil, but they are limited by the simultaneous characterization of the occurrence of oil and water within shale pore networks. This study conducted a range of nuclear magnetic resonance (NMR) T2 and T1–T2 measurements on the shales at different states, sampled from the Paleogene Funing Formation in the Gaoyou Sag, Subei Basin. A novel water and oil restoration method was introduced to restore pore fluid distributions in shales. The T1–T2 pattern with eight regions was determined for shale oil reservoirs. The pore oil and water in different states were quantitatively calculated using NMR T1–T2 spectra and compared with the results from Rock-Eval. In addition, the occurrence pattern of pore fluids in shales was proposed. The primary results indicated that free oil derived from multistage Rock-Eval is generally lower than that determined using the NMR T1–T2 spectrum. The NMR T1–T2 spectrum specializes in detecting the adsorbed, capillary-bound, and movable oil in pore systems but is limited in quantitatively identifying oil absorbed in organic matter. The occurrences and distributions of pore oil and water in different states can be effectively revealed by the T1–T2 spectrum. Capillary-bound water is predominantly associated with micropores (<100 nm) and, to a lesser extent, with mesopores (100–1000 nm); a similar pattern is observed for adsorbed oil. As a result, adsorbed oil is significantly restricted by pore water. Capillary-bound oil primarily occurs in mesopores, whereas macropores (>1000 nm) are saturated with movable oil. Hence, the distribution of capillary-bound oil is still affected by pore water, whereas movable oil is not. The authors are confident that the results presented in this study offer innovative insights into the occurrence and distribution of pore fluids in shale pore networks.

Multi-factor numerical simulation and response characteristics of two-dimensional nuclear magnetic resonance in digital cores

Two-dimensional nuclear magnetic resonance (2D NMR) logging is an important technology for reservoir evaluation in oil and gas exploration and development, and it has unique advantages in fluid identification. However, in oil shale reservoirs, the mechanisms of 2D NMR logging are complex, and the response characteristics of various factors are unclear. Numerical simulation based on digital core is a significant method to study the influences of multiple factors on 2D NMR. This manuscript introduces the construction method of high-resolution three-dimensional (3D) digital core models, and expounds the principle and workflow of 2D NMR numerical simulation. High-resolution 3D digital cores were constructed based on X-CT, MAPS, and QEMSCAN data of Berea sandstone and Daqing Gulong shale, respectively. Based on 3D digital cores, 2D NMR numerical simulations were carried out on temperature/viscosity, echo spacing, and frequency. Then, 2D NMR mechanisms were analyzed and the response characteristics of multiple factors were summarized. The results show that the T2 and T1 of the water peak have a linear negative correlation with temperature/viscosity, and the T2 and T1 of the oil peak have a linear positive correlation. For Daqing Gulong shale, the T2 of the water peak has a linear positive correlation with echo spacing, while for Berea sandstone, echo spacing has little effect. For Berea sandstone, the T1 of the water peak is linearly positively correlated with frequency. For Daqing Gulong shale, the T1 of the water peak and oil peak are both linearly positively correlated with frequency. The response characteristics of multiple factors could provide a reference and basis for the interpretation and evaluation of 2D NMR logging under complex conditions.

Accumulation mechanism of multi-type unconventional oil and gas reservoirs in Northern China: Taking Hari Sag of the Yin’e Basin as an example

Abstract Many multi-types of unconventional oil and gas reservoirs have been found in some faulted basins in northern China, showing good exploration potential. However, the hydrocarbon accumulation mechanism in these areas is still unclear, which limits the understanding of the distribution of oil and gas. In this study, we took Hari Sag in Yin’e Basin as an example, conducted a systematic analysis on various types unconventional oil and gas reservoirs, and revealed its characteristics and accumulation mechanisms. The study showed that there were many types of unconventional oil and gas reservoirs in Hari Sag, such as biogas reservoirs, shale gas reservoirs, shale oil reservoirs, tight sandstone oil reservoirs, tight sandstone gas reservoirs, and volcanic gas reservoirs. These reservoirs generally had characteristics of “near/within source rocks accumulation,” “coexistence of oil reservoirs and gas reservoirs,” “shallow oil and deep gas,” and so on. Research on the mechanism of hydrocarbon accumulation showed that: the lack of effective hydrocarbon migration pathway was the main reason for “near/within source rocks accumulation” of oil and gas reservoirs; the differences in the thermal evolution degree of the main source rocks at different structural positions in the sag made the distribution characteristics of hydrocarbon as “coexistence of oil reservoirs and gas reservoirs” and “shallow oil and deep gas”; and the joint development of multi-type effective unconventional reservoirs created the situation of “coexistence of multi-type unconventional oil and gas reservoirs.” It is predicted that six types of unconventional oil and gas reservoirs have a cumulative area of 381 km2, indicating that the Hari Sag has great potential for unconventional oil and gas exploration. The research results can not only guide the unconventional oil and gas exploration in Hari Sag but also provide a theoretical basis for exploration research in similar blocks.

Experimental investigation on forced imbibition characteristics of shale oil reservoir based on nuclear magnetic resonance method

After large-scale fracturing of shale reservoirs, the fracturing fluid will imbibe in the reservoir. In order to clarify the characteristics of imbibition and the distribution characteristics of crude oil in the stage of forced imbibition, this paper selects the core of some blocks in Qinghai and Gulong areas to carry out the shale forced imbibition experiment. Nuclear magnetic resonance technology is used to monitor the variation of crude oil. And the influence of core permeability and contact angle on forced imbibition is further analyzed. The results of the study show that the shale has a strong imbibition effect on the fracturing fluid. The content of oil phase in the core decreases, and the phenomenon of oil-water replacement occurs. Priority porosity for fracking fluids exists in the process of imbibition, where fracturing fluid preferentially enter smaller pores and can cause a short-term increase in the oil phase content in larger pores. With the continuous process of imbibition, the rate of imbibition oil gradually slowed down, and the fracturing fluid gradually permeates evenly into the rock sample. Both permeability and wettability affect the imbibition capacity of fracturing fluid in the forced imbibition stage.

Laminae Characteristics and Their Relationship with Mudstone Reservoir Quality in the Qingshankou Formation, Sanzhao Depression, Songliao Basin, Northeast China

Lamination is the predominant and widely developed sedimentary structure in mudstones. Similar to organic pores in shale gas reservoirs, the inorganic pores in the laminae of shale oil reservoirs are equivalently important high-quality reservoir spaces and flow channels. The laminae characteristics are strongly heterogeneous, being controlled by both deposition and diagenesis. However, the origin of this diversity is poorly understood. A detailed examination of cores, thin sections, and scanning electron microscopy analyses were conducted on the lacustrine mudstone of the Qingshankou Formation in the Songliao Basin to study the influence of deposition and diagenesis on laminae characteristics and their relationship to reservoir quality. Three types of laminae are mainly developed, namely thick siliceous laminae, thin siliceous laminae, and thin siliceous and argillaceous mixed laminae. Deposition controls the type and distribution of laminae. The thin siliceous and argillaceous mixed laminae are controlled by climate-driven seasonal flux variations. The thick siliceous laminae and thin siliceous laminae are controlled by bottom current or gravity-driven transport processes due to increased terrestrial input. The thin siliceous laminae have the optimum reservoir properties, followed by the thin siliceous and argillaceous mixed laminae, while the thick siliceous laminae have the worst properties. Diagenesis controls the pore evolution of the laminae. Different laminae have different paths of diagenesis. The thin siliceous laminae are mainly cemented by chlorite, preserving some primary porosity. The clay mineral content of the thin siliceous and argillaceous mixed laminae is high, and the primary pores are mainly destroyed by the strong deformation of the clay minerals during compaction. The thick siliceous laminae are intensely cemented by calcite, losing most of the porosity. The present study enhances the understanding of reservoir characteristics in laminae and provides a reference for shale oil exploration.

Oil saturation quantitative evaluation in lacustrine shale: Novel insights from NMR T1-T2 and displacement experiments

Oil saturation is important for shale reservior to identify favorable sections and determine the geological sweet spots. Current oil saturation evaluation methods, including experiments and empirical formulas, are not suitable for shale reservoir because of the complex mineral, fluid components and pore structure characteristics. A novel method was proposed to accurately calculate the shale oil saturation through the morphological dynamic variation characteristics of the 1D NMR T2 spectra and the signal intensity of the different hydrocarbon-bearing components of the 2D NMR T1-T2 map of shale samples with different oil and water saturation The results (1) indicated that the NMR T2 spectrum revealed that the pore structure of shale samples is complex and highly heterogeneous, and the primary factor that determines the volume of displaced oil in the displacement experiment with slight differences in wettability is the shale’s pore size distribution. (2) shown that the NMR T1-T2 map serves as a useful tool in distinguishing different hydrocarbon-bearing components of shale samples, including kerogen, adsorbed oil, free oil, structural, adsorbed water, and free water. Typically, kerogen is found in the top left region of the T1-T2 map with 10 < T1 < 100 ms & 0.02 < T2 < 0.2 ms. Based on this, T2 threshold for free oil and adsorbed oil are 2 and 0.2 ms, and the corresponding threshold of pore radius are 40 and 4 nm according to the NMR theory. (3) found that the morphological characteristics of 1D NMR T2 spectra vary with the variation of shale oil saturation. Specifically, T2 geometric mean (T2gm) and interval porosity corresponding to the first peak (Ap1) are positively and negatively correlated with oil saturation respectively. Then, oil saturation calculation method is established using the above two parameters and the Root Mean Square Error (RMSE) between the measured and calculated results is 5.85 %, which reflecting the accuracy and validity. In general, this method allows the shale oil saturation to be accurately calculated and provides basis for the determination of favorable sections and evaluation of resource of shale oil reservoir. Moreover, it also offers a new idea for the oil saturation prediction by NMR logging.

Multiphase behavior and fluid flow of oil–CO2–water in shale oil reservoirs: Implication for CO2-water-alternating-gas huff-n-puff

Based on the CO2-WAG (water-alternating-gas) flooding for conventional reservoirs, CO2-WAG huff-n-puff in shale reservoirs is proposed. To clarify the phase behavior and fluid flow of oil–CO2–water in the CO2-WAG huff-n-puff process, a series of experimental studies are conducted under different injection sequences of CO2 and water. The results show that the saturation pressure of the oil–CO2–water systems is lower than that of the oil–CO2 systems since a portion of the CO2 is dissolved in water. In addition, CO2 injection followed by water can significantly reduce the dissolution of CO2 in the water. CO2 and water preferentially flow into the macropores and bedding fractures of the oil-saturated cores at the injection stage, and the oil in mesopores and micropores reflows into macropores and bedding fractures at the soaking stage. At the depressurization production stage, the oil in mesopores and micropores is gradually extracted. Compared to water injection followed by CO2, injecting CO2 first can avoid the barrier effect caused by the subsequent injection of water and promotes oil flow into mesopores and micropores in the matrix. At the end of production, the oil recovered from water injection followed by CO2 mainly originates from macropores, while that from CO2 injection followed by water primarily comes from mesopores.

Heat front propagation in shale oil reservoirs during air injection: Experimental and numerical studies

Air injection technique for developing shale oil has gained significant attention. However, the ability of the heat front to consistently propagate within the shale during air injection remains uncertain. To address this, we investigated the heat front propagation within oil–detritus mixtures, shale cores, and fractured shale cores using a self-designed combustion tube (CT) and experimental schemes. By integrating the results obtained from high-pressure differential scanning calorimetry and CT, we developed a comprehensive reaction kinetics model to accurately analyze the main factors influencing the heat front propagation within fractured shale. The findings revealed that in the absence of additional fractures, the heat front failed to propagate within the tight shale. The flow of gases and liquids towards the shale core was impeded, resulting in the formation of a high-pressure zone at the front region of the shale. This pressure buildup significantly hindered air injection, leading to inadequate oxygen supply and the extinguishment of the heat front. However, the study demonstrated the stable propagation of the heat front within the oil–detritus mixtures, indicating the good combustion activity of the shale oil. Furthermore, the heat front successfully propagated within the fractured shale, generating a substantial amount of heat that facilitated the creation of fractures and enhanced gas injection and shale oil flow. It was important to note that after the heat front passed through the shale, the combustion intensity decreased. The simulation results indicated that injecting air into the main fracturing layers of the shale oil reservoir enabled the establishment of a stable heat front. Increasing the reservoir temperature (from 63 to 143 °C) and oxygen concentration in the injected gas (from 11% to 21%) promoted notable heat front propagation and increased the average temperature of the heat front. It was concluded that temperature and oxygen concentration had the most important influence on the heat front propagation, followed by pressure and oil saturation.

Efficient placement technology of proppants based on structural stabilizers

Fiber is highly escapable in conventional slickwater, making it difficult to form fiber-proppant agglomerate with proppant and exhibit limited effectiveness. To solve these problems, a novel structure stabilizer (SS) is developed. Through microscopic structural observations and performance evaluations in indoor experiments, the mechanism of proppant placement under the action of the SS and the effects of the SS on proppant placement dimensions and fracture conductivity were elucidated. The SS facilitates the formation of robust fiber-proppant agglomerates by polymer, fiber, and quartz sand. Compared to bare proppants, these agglomerates exhibit reduced density, increased volume, and enlarged contact area with the fluid during settlement, leading to heightened buoyancy and drag forces, ultimately resulting in slower settling velocities and enhanced transportability into deeper regions of the fracture. Co-injecting the fiber and the SS alongside the proppant into the reservoir effectively reduces the fiber escape rate, increases the proppant volume in the slickwater, and boosts the proppant placement height, conveyance distance and fracture conductivity, while also decreasing the proppant backflow. Experimental results indicate an optimal SS mass fraction of 0.3%. The application of this SS in over 80 wells targeting tight gas, shale oil, and shale gas reservoirs has substantiated its strong adaptability and general suitability for meeting the production enhancement, cost reduction, and sand control requirements of such wells.

Optimization method of fracturing fluid volume intensity for SRV fracturing technique in shale oil reservoir based on forced imbibition: A case study of well X-1 in Biyang Sag of Nanxiang Basin, China

An optimization method of fracturing fluid volume strength was introduced taking well X-1 in Biyang Sag of Nanxiang Basin as an example. The characteristic curves of capillary pressure and relative permeability were obtained from history matching between forced imbibition experimental data and core-scale reservoir simulation results and taken into a large scale reservoir model to mimic the forced imbibition behavior during the well shut-in period after fracturing. The optimization of the stimulated reservoir volume (SRV) fracturing fluid volume strength should meet the requirements of estimated ultimate recovery (EUR), increased oil recovery by forced imbibition and enhancement of formation pressure and the fluid volume strength of fracturing fluid should be controlled around a critical value to avoid either insufficiency of imbibition displacement caused by insufficient fluid amount or increase of costs and potential formation damage caused by excessive fluid amount. Reservoir simulation results showed that SRV fracturing fluid volume strength positively correlated with single-well EUR and an optimal fluid volume strength existed, above which the single-well EUR increase rate kept decreasing. An optimized increase of SRV fracturing fluid volume and shut-in time would effectively increase the formation pressure and enhance well production. Field test results of well X-1 proved the practicality of established optimization method of SRV fracturing fluid volume strength on significant enhancement of shale oil well production.

Research on quantitative analysis method of shale oil reservoir sensitivity based on mineral analysis

Mineral compositions of shale reservoirs are complex and highly influenced by external fluids. At present, there are limited studies on the effect of mineral expansion rate on external fluids, and there is a lack of systematic research on the sensitivity of shale reservoir porosity to external fluids. In this paper, firstly, X-Ray Diffractometer (XRD) experiments were carried out to study the mineral composition of shale reservoirs, revealing the mechanism of shale minerals interacting with acidic/alkaline fluids. Secondly, the sensitivity evaluation experiments of single mineral external fluid immersion were conducted on the main minerals in shale. Finally, a prediction method for the sensitivity of shale reservoir porosity to external fluids (acidic/alkaline fluids, oil slicks) was established. The results show that: (a) Volume expansion of quartz after 48 h of immersion in alkaline fluids at pH = 9 and pH = 11 and the expansion rate is maximum at pH = 9 i.e. 0.16. (b) Volume expansion of chlorite after 48 h immersion in alkaline fluid and maximum expansion at pH = 13 i.e. 0.55. (c) The improvement of total porosity of shale by acid solution is weak. (e) Alkaline solution has a weak damage to the total porosity of shale, and the degree of damage increases and then decreases with the increase of the strength of alkaline solution.

Visualization of dynamic micro-migration of shale oil and investigation of shale oil movability by NMRI combined oil charging/water flooding experiments: A novel approach

Investigating the micro-migration processes of hydrocarbons within interbedded shale reservoirs, and quantitatively characterizing the movability of shale oil, are highly important for the exploration and development of continental shale oil. However, due to complex pore-fracture structures, the characterization of the micro-migration and movability of shale oil presents significant difficulties, and the lack of suitable technology restricts the understanding of shale oil accumulation mechanisms and the evaluation of movability. This study employs nuclear magnetic resonance imaging (NMRI) technology in conjunction with oil charging and water flooding experiments, to innovatively visualize and quantitatively characterize the dynamic micro-migration features and movability of hydrocarbons within the pore-fracture structures of shale. The results indicate a significant increase in oil saturation within the interbedded shale oil reservoir during the oil charging process, with the oil phase primarily accumulating in larger pores (T2 = 1–100 ms). The micro-migration and accumulation process of interbedded shale oil can be divided into three stages: the initial stage dominated by water phases in the pore spaces due to insufficient oil filling pressure, the intermediate stage marked by a rapid increase in hydrocarbons in the pore spaces, and the final stage where oil fills the entire pore system resulting in high oil saturation. The movability of different types of shale oil during water flooding varies significantly and is mainly influenced by pore-fracture structures. Interbedded shale oil reservoirs with larger pores exhibits a higher movable oil saturation (approximately 36.94%), while matrix-type shale oil reservoirs shows greater heterogeneity and lower fluid movability (approximately 14%). However, the shale oil movability of matrix-type shale oil reservoir with developed microfractures can reach 40%. More specifically, the fluid movability in smaller pore-microfracture structures (T2 < 0.5 ms) is as high as 56.88%, surpassing that in larger pores (T2 > 0.5 ms) (32.78%). Larger pores and microfractures substantially enhance the movability of hydrocarbons in the shale matrix, thus improving shale oil recoverability. In contrast, due to the higher capillary pressure (Pc) and flow resistance (Pv), smaller pores contribute less to the movability of shale oil. Overall, the outcomes of this study not only advance our understanding of the micro-migration and accumulation patterns of interbedded shale oil but also offer new insights for geological and engineering integration research on shale oil.

Nanofluidic Study of Multiscale Phase Transitions and Wax Precipitation in Shale Oil Reservoirs

During hydraulic fracturing of waxy shale oil reservoirs, the presence of fracturing fluid can influence the phase behavior of the fluid within the reservoir, and heat exchange between the fluids causes wax precipitation that impacts reservoir development. To investigate multiscale fluid phase transition and microscale flow impacted by fracturing fluid injection, this study conducted no-water phase behavior experiments, water injection wax precipitation experiments, and water-condition phase behavior experiments using a nanofluidic chip model. The results show that in the no-water phase experiment, the gasification occurred first in the large cracks, while the matrix throat was the last, and the bubble point pressure difference between the two was 12.1 MPa. The wax precipitation phenomena during fracturing fluid injection can be divided into granular wax in cracks, flake wax in cracks, and wax precipitation in the matrix throat, and the wax mainly accumulated in the microcracks and remained in the form of particles. Compared with the no-water conditions, the large cracks and matrix throat bubble point in the water conditions decreased by 6.1 MPa and 3.5 MPa, respectively, and the presence of the water phase reduced the material occupancy ratio at each pore scale. For the smallest matrix throat, the final gas occupancy ratio under the water conditions decreased from 32% to 24% in the experiment without water. This study provides valuable insight into reservoir fracture modification and guidance for the efficient development of similar reservoirs.

Complex fracture description and quasi-elastic energy development mathematical model for shale oil reservoirs

Reservoir numerical simulation is an important tool and method for the reasonable and efficient development of shale reservoirs. Accurate description of three-dimensional fractures in shale reservoir development is a necessary and sufficient condition to improve the accuracy and robustness of shale reservoir numerical simulation. This paper achieves precise characterization of complex fracture shapes and oil, gas and water flow by establishing an embedded discrete fracture model based on a non-structural network, which has advantages in the fine characterization of complex morphological fractures in the reservoir and the grid division of the reservoir. In the large matrix solution method, the Newton-Raphson method is used to linearize the nonlinear equations, the Jacobian matrix is ​​constructed, the ILU method is used for preprocessing, the conjugate gradient method is used to solve the linear equations, and the shale oil quasi-elasticity is established A fully implicit solution method for mathematical models of energy development.