Shale Oil Recovery Research Articles

Diffusion Effect on Shale Oil Recovery by CO2 Huff-n-Puff

The CO2 diffusion effect is an important mechanism of injected CO2 penetrating the reservoir matrix and diffusing into the oil phase during the huff-n-puff (HNP) process. However, the CO2 diffusion coefficient of shale is still uncertain under the reservoir conditions, and the contribution of diffusion to enhanced oil recovery (EOR) needs to be further explored. In this study, the CO2 diffusion coefficient of shale is determined under the simulated reservoir conditions (9–10 MPa, 90 °C) in the laboratory, and the determined CO2 diffusion coefficient is applied in the reservoir numerical model to evaluate the contribution of the CO2 diffusion effect to EOR in the HNP process. First, a radial constant volume diffusion (RCVD) device was built to measure the CO2 diffusion coefficient by the pressure decay method. After that, both the analytical solution and the numerical solution are used to ensure that the result is correct. Finally, a field-scale model consisting of one stage of hydraulic fracture in a shale oil reservoir is established. The effects of reservoir properties such as fracture spacing, fracture half-length, and operational properties of HNP like injection rate, injection time, and soaking time on oil recovery were discussed when the diffusion was included and excluded. The CO2 diffusion coefficient of a shale core is ranging from 1.44 × 10–7 to 5.50 × 10–7 cm2/s, and it is reasonable to be applied in the field reservoir numerical simulation model. According to simulation results, the lower fracture spacing and longer fracture half-length make more CO2 diffuse into the shale matrix, which are critical parameters, to promote the CO2 diffusion effect. When the injection rate is slow and the injection time is short, the CO2 diffusion effect in the reservoir may contribute more to EOR. A high injection rate means sufficient pressure supplement, and the CO2 diffusion effect may become relatively negligible. The soaking time may not be necessary for the EOR of HNP, but the longer soaking time will promote the contribution of CO2 diffusion to EOR, and the incremental recovery is about 0.15–0.26%.

Geochemical characteristics of shales from the first member of Qingshankou Formation in Gulong Sag, Songliao Basin, China: Implication for mechanism of organic matter enrichment

Commercial oil production from the first member of the Qinshankou Formation in the Songliao Basin, China has proven it can be a promising target for shale oil recovery. However, geochemical characteristics and the mechanism of organic matter (OM) enrichment in this layer remain unknown. Herein, a large number of samples collected from the first member were analyzed through a combination of organic and inorganic geochemical methods. Results show, bedding oil shale and laminated shale are prominent facies in this member. Moreover, this member mainly consists of type-I and –II kerogen at highly thermal mature stage, belonging to good to excellent source rock. Overall, this member has been deposited in the semi-humid to humid and warm paleoclimate, fresh to brackish water mass, and dysoxic to anoxic conditions. This member is enriched in P2O5, indicating the high primary productivity. Moreover, lack of relation between P2O5, with Al2O3 and Fe2O3 concentrations, suggests that the contribution of terrigenous detritus influx and the effect of Fe cycle for P enrichment in sediments can be disregarded. The terrigenous detritus influx, rapid sedimentation rate and marine transgression were found to be detrimental to the OM enrichment. Moreover, more serious oxygen deficiency in water mass along with slightly lower sedimentation rate, made the lower part of this member to yield better preservation conditions and weaker dilution effect, which resulted in the formation of OM with better quality and higher abundance. Collectively preservation conditions were found to be significant for the OM enrichment.

Effect of CO2 Corrosion and Adsorption-Induced Strain on Permeability of Oil Shale: Numerical Simulation

Permeability is a crucial parameter for enhancing shale oil recovery through CO2 injection in oil-bearing shale. After CO2 is injected into the shale reservoir, CO2 corrosion and adsorption-induced strain can change the permeability of the oil shale, affecting the recovery of shale oil. This study aimed to explore the influence of CO2 corrosion and adsorption-induced strain on the permeability of oil shale. The deformation of the internal pore diameter of oil shale induced by CO2 corrosion under different pressures was measured by low-pressure nitrogen gas adsorption in the laboratory, and the corrosion model was fitted using the experimental data. Following the basic definitions of permeability and porosity, a dynamic mathematical model of porosity and permeability was obtained, and a fluid–solid coupling mathematical model of CO2-containing oil shale was established according to the basic theory of fluid–solid coupling. Then the effects of adsorption expansion strain and corrosion compression strain on permeability evolution were considered to improve the accuracy of the oil shale permeability model. The numerical simulation results showed that adsorption expansion strain, corrosion compression strain, and confining pressure are the important factors controlling the permeability evolution of oil shale. In addition, adsorption expansion strain and corrosion compression strain have different effects under different fluid pressures. In the low-pressure zone, the adsorption expansion strain decreases the permeability of oil shale with increasing pressure. In the high-pressure zone, the increase in pressure decreases the influence of expansion strain while permeability gradually recovers. The compressive strain increases slowly with increasing pressure in the low-pressure zone, slowly increasing oil shale permeability. However, in the high-pressure area, the increase in pressure gradually weakens the influence of corrosion compressive strain, and the permeability of oil shale gradually recovers.

THE FRACTAL MATHEMATICAL MODELS FOR SPONTANEOUS AND FORCED IMBIBITION WITH DIFFERENT CROSS-SECTION SHAPES IN SHALE OIL RESERVOIR

Large-scale hydraulic fracturing is the critical technology for effective shale oil production. However, the imbibition flow mechanisms of fracturing fluid in shale micropores and the influence of shale microstructure and physical properties are still indistinct, which makes the optimization goal of fracturing flowback unclear and restricts the enhancement of shale oil recovery. Therefore, based on SEM and XRD experiments, it is analyzed that shale has the characteristics of multiple pores, which are divided into organic pores, brittle mineral pores, and clay pores. Nonetheless, how the tube cross-section controls the interface displacement is not well discussed in the available literature, especially in irregular triangles, rectangles and other non-circular shapes. This paper studies the influence of cross-section shapes on the capillary force by considering the corner flow of the wetting phase, and it analyzes the imbibition dynamics of different types of pores. Using the shale multi-pores physical model and fractal theory, the shale semi-analytical solution models of SI and FI are established. Theoretical analysis of the water imbibition mechanisms shows that the key factors controlling SI and FI volume include imbibition time, fluid properties, pore cross-section shapes, tortuosity, and forced pressure.

Simulation of water self-imbibition in nanometer throat-pore structure filled with oil

Water self-imbibition potentially serves as a driving force for shale oil recovery due to the sizeable capillary pressure in the nanometer pores of shale. Understanding the water self-imbibition mechanism at the nanometer pore-scale helps promote shale oil recovery. In this work, we performed the direct numerical simulation using the phase-field model to study water self-imbibition dynamics in the nanometer throat-pore structure filled with oil. The effects of throat/pore morphologies (throat size, coordination number, and pore shape) and fluid properties (interfacial tension, contact angle, and viscosity) on the water imbibition dynamics were studied in detail. We distinguished two types of imbibition processes and found that the throat/pore morphologies significantly affect the final oil displacement ratio. Meanwhile, the interfacial tension and water contact angle mainly influence the imbibition rate (i.e., the oil displacement rate), while the water viscosity influences both the imbibition rate and the final oil displacement ratio. A qualitative correlation of the imbibition time and fluid properties is deduced by comparing classical theory predictions and simulation results. The quantitative deviations caused by local confinement are delineated as well.

Direct Visualization of Nanoscale Salt Precipitation and Dissolution Dynamics during CO2 Injection

CO2 injection to enhance shale oil recovery provides a win-win solution to meet the global fuel shortage and realize ultimate carbon neutrality. When shale reservoirs contain high salinity water, CO2 injection can result in salt precipitation to block the nanometer pores in the shale, causing undesirable formation damage. Understanding salt precipitation and dissolution dynamics at the nanoscale are fundamental to solving this practical challenge. In this work, we developed a shale micromodel to characterize salt precipitation and dissolution based on nanofluidic technology. By directly distinguishing different phases from 50 nm to 5 μm, we identified the salt precipitation sites and precipitation dynamics during the CO2 injection. For the salt precipitation in the nanometer network, we identified two precipitation stages. The ratio of the precipitation rates for the two stages is ~7.9 times that measured in microporous media, because of the slow water evaporation at the nanoscale. For the salt precipitation in the interconnected micrometer pores, we found that the CO2 displacement front serves as the salt particle accumulating site. The accumulated salt particles will in turn impede the CO2 flow. In addition, we also studied the salt dissolution process in the shale micromodel during water injection and found the classical dissolution theory overestimates the dissolution rate by approximately twofold. This work provides valuable pore-scale experimental insight into the salt precipitation and dissolution dynamics involved in shale formation, with the aim to promote the application of CO2 injection for shale oil recovery.

Release Mechanism of Volatile Products from Oil Shale Pressure-Controlled Pyrolysis Induced by Supercritical Carbon Dioxide.

The compactness of the oil shale reservoir and the complexity of the pore structure lead to the secondary reaction of kerogen in the process of hydrocarbon expulsion, which reduces the effective recovery of shale oil. In this paper, supercritical carbon dioxide was used as a heat carrier and a displacement medium. In a self-designed fluidized bed experimental system for pressure-controlled pyrolysis of oil shale, the experiments of oil shale pyrolysis under standard atmospheric pressure and 7.8-8.0 MPa pressure in nitrogen and carbon dioxide atmospheres were completed. The extraction efficiency of supercritical carbon dioxide at low temperature is obvious, but with the increase of temperature, the effect of extraction on pyrolysis is lower than that of temperature. Under a nitrogen atmosphere, the secondary reaction of shale oil is mainly secondary pyrolysis and aromatization. However, in a supercritical carbon dioxide atmosphere, the main reactions are secondary addition and aromatization. In addition, compared with that in the standard atmospheric pressure, it was found that the olefin synthesis reaction was obviously inhibited under a high-pressure nitrogen or supercritical carbon dioxide atmosphere.

Comprehensive Outlook into Critical Roles of Pressure, Volume, and Temperature (PVT) and Phase Behavior on the Exploration and Development of Shale Oil

Shale oil has received increasing attention as an essential replacement for conventional oil resources. Shale oil recovery is a complex process controlled by interactions of many factors whose impact could be significantly different from conventional reservoirs. This study hence aims to fill the gaps in the literature by studying various aspects of the phase behavior of shale oil and their significance in different aspects of the recovery from oil shale. In the first part of this study, the standard practices, including experimental and theoretical methods for calculating the pressure, volume, temperature (PVT), and phase behavior of shale oil, is discussed in detail. Next, the effects of factors such as the composition of fluids, pore structure, and capillary forces on the phase behavior of hydrocarbon fluids are explained. The third part focuses on applying phase behavior for oil shale development. Moreover, the geological and geochemical processes that lead to the maturity of kerogen, the formation of shale oil, and the experimental methods by which those processes are currently studied are scrutinized. By studying the thermal and burial history of the hydrocarbon-generating strata and hydrocarbon-generating kinetics, the shale formation’s oil and gas phase distribution can be predicted. Consequently, the sweet spots for the recovery of light condensate oil can be more accurately determined. The application of enhanced oil recovery methods is an inevitable part of recovery from conventional and unconventional formations. Therefore, the last part of this study analyses the changes in the phase behavior of shale oil when an external component, i.e., CO2 or CH4, is injected into the reservoir. Reviewing the literature revealed that a more accurate prediction of hydrocarbon phase behavior can be made by combining different disciplines of science to achieve optimized plans for efficient shale oil development, making shale oil a more economically viable energy resource.

Adsorption Behaviors of Different Components of Shale Oil in Quartz Slits Studied by Molecular Simulation.

Understanding the adsorption state and molecular behavior of the diverse components of shale oil in shale slits is of critical importance for exploring novel enhanced shale oil recovery techniques, but it is hard to be achieved by experimental measurements. In this paper, molecular dynamics (MD) simulations are performed to quantitatively describe the microbehavior of shale oil mixtures containing different kinds of hydrocarbon components, including asphaltene, in quartz slits. The spatial distributions of all the presenting components are given, the interaction energy between the components and quartz is analyzed, and the diffusion coefficients of all the components are calculated. It was found that asphaltene molecules play a vitally important role in restricting the detachment and diffusion movement of all hydrocarbon components, which is actually a key problem limiting the recovery efficiency of shale oil. The effects of temperature, slit aperture, and the appearance of CO2 on the adsorption behavior of the different shale oil components are examined; the results suggest that the light and medium components are the fractions with the most potential in thermal exploitation, while injection of CO2 is beneficial for the extraction of all the components, especially the medium components. This work gives insights into the effect of asphaltene on shale oil recovery in quartz slits and might provide guidance on the utilization of thermal and CO2-enhanced enhanced oil recovery (EOR) techniques in shale oil production.

Oscillating electric field accelerating CO2 breaking through water bridge and enhancing oil recovery in shale: Insight from molecular perspective

CO2 injection is regarded as the most promising enhanced oil recovery (EOR) method for shale reservoirs. However, water bridges in shale nanopores greatly reduces the efficiency of CO2-EOR. Using molecular dynamics simulations, we propose an efficient strategy of applying oscillating electric fields to break the hydrogen bonds network and thus accelerating CO2 breaking through water bridge. The CO2-EOR processes under electric fields with different frequencies can be divided into five typical types. And to accelerate the breakdown of water bridge, more attention should be paid to the destruction of the hydrogen bonds network in the center of water bridge.

Genesis of Bedding Fractures in Ordovician to Silurian Marine Shale in Sichuan Basin

The effective utilization of shale bedding fractures is of great significance to improve shale gas recovery efficiency. Taking the Wufeng–Longmaxi Formation shale in Sichuan Basin as the research object, the formation process and mechanism of bedding fractures in marine shale are discussed, based on field observation and description, high-resolution electron microscope scanning, fluid inclusion detection, and structural subsidence history analysis. The results show that the formation of bedding fractures is jointly controlled by sedimentary characteristics, hydrocarbon generation, and tectonic movement: the development degree of bedding (fractures) is controlled by the content of shale organic matter and brittle minerals, and bedding fractures formed in the layers with high organic matter; tectonic movement created stress environment and space for bedding fractures and promoted the opening of bedding fractures; the time for calcite vein to capture fluid is consistent with the time of oil-gas secondary pyrolysis stage. The formation of the calcite vein is accompanied by the opening of fractures. The acid and oil-gas generated in the hydrocarbon generation process occupied the opening space and maintained the bedding fractures open. The study of the formation process of bedding fractures is helpful to select a suitable method to identify bedding fractures, and then effectively use it to form complex fracture networks in the fracturing process to improve shale oil and gas recovery.

The Characteristic and Distribution of Shale Micro-Brittleness Based on Nanoindentation.

Shale is a special kind of rock mass and it is particularly important to evaluate its brittleness for the extraction of gas and oil from nanoporous shale. The current brittleness studies are mostly macro-evaluation methods, and there is a lack of a micro-brittleness index that is based on nanoindentation tests. In this paper, nanoindentation tests are carried out on the surface of shale to obtain mechanical property, and then a novel micro-brittleness index is proposed. Drawing a heat map by meshing indentation, the distribution characteristics of the brittleness index for the surface of shale and the variation laws between the mineral and brittleness index are explored. The results showed that the dimensionless brittleness index involved parameters including indentation irreversible deformation, elastic modulus, hardness and fracture toughness. The micro-brittleness index of the shale ranged from 7.46 to 65.69, and the average brittleness index was 25.837. The brittleness index exhibited an obvious bimodal distribution and there was great heterogeneity on the surface of shale. The crack propagation channels were formed by connecting many indentation points on the shale surface with high brittleness. The total brittleness index of quartz minerals was high, but the cementation effect with different minerals was various. Although the general brittleness of clay was low, the high brittleness index phenomenon was also exhibited. Studying the micro-brittleness of shale provides a more detailed evaluation for the shale friability, which is used to determine the optimal shale oil and gas recovery regime.

Multiscale Pore Structure Evolution of Longmaxi Shale Induced by Acid Treatment

SummaryHydraulic fracturing to generate complex fracture networks is essential for shale reservoir development. However, the recovery of shale oil and gas is still low due to various engineering and geological factors. Acid treatment has been approved as a potential approach to enhance stimulated reservoir volume (SRV) by changing petrophysical and mechanical properties. Understanding the multiscale pore structure evolution behind the macro-performance change is critical in the application of acid treatment in shale reservoirs. In this study, cylindrical and powder shale samples from the Longmaxi formation are treated with 15 wt% hydrochloric acid (HCl) for 10 days. Before and after acid treatment, X-ray computed tomography (CT) and N2 adsorption techniques are used to characterize shale pore structure at microscale and nanoscale, respectively. Combined with the determination of variations in chemical compositions of shale samples and acid solutions, the mechanism of multiscale pore structure evolution induced by acid treatment is discussed. The N2 adsorption results uncover a considerable increase in volume and size of nanopores. All the nanopores increase in carbonate-rich shale, whereas the micropores and mesopores undergo a decrease in clay-rich shale. Reconstructed 3D CT images reveal the generation of large volumes of microscale pores and fractures, which leads to an increase in porosity of about 9%. The pore structure evolution in shale due to acid treatment is controlled by both mineralogy and microstructure. These findings demonstrate the promise of acid treatment for enhanced SRV and long-term productivity of shale oil and gas reservoirs in China.

Evaluation technology and practice of continental shale oil development in China

This paper analyzes the differences in geological and development characteristics between continental shale oil in China and marine shale oil in North America, reviews the evaluation methods and technological progress of the continental shale oil development in China, and points out the existing problems and development directions of the continental shale oil development. The research progress of development evaluation technologies such as favorable lithofacies identification, reservoir characterization, mobility evaluation, fracability evaluation, productivity evaluation and geological-mathematical modeling integration are introduced. The efficient exploration and development of continental shale oil in China are faced with many problems, such as weak basic theoretical research, imperfect exploration and development technology system, big gap in engineering technology between China and other countries, and high development cost. Three key research issues must be studied in the future: (1) forming differentiated development technologies of continental shale oil through geological and engineering integrated research; (2) strengthening the application of big data and artificial intelligence to improve the accuracy of development evaluation; (3) tackling enhanced shale oil recovery technology and research effective development method, so as to improve the development effect and benefit.

Study on Enhancing Shale Oil Recovery by CO2 Pre-Pad Energized Fracturing in A83 Block, Ordos Basin

The Ordos Basin is rich in shale oil resources. The main targeted layers of blocks A83 and X233 are the Chang 7 member of the Yanchang Formation. Due to extremely low permeability, a fracturing technique was required to enhance oil recovery. However, after adopting the stimulated reservoir volume-fracturing technology, the post-fracturing production of the A83 block is significantly lower than that of the X233 block. For this problem, the dominating factors of productivity of the two blocks were analyzed using the Pearson correlation coefficient (PCC) and the Spearman rank correlation coefficient (SRCC), showing that the main reason for the lower production of the A83 block is its insufficient formation energy. To solve this problem, the CO2 pre-pad energized fracturing method was proposed. To study the feasibility of CO2 pre-pad energized fracturing in the A83 block, an integrated reservoir numerical simulation model of well A83-1 was established based on the idea of integration of geology and engineering. Additionally, the productions within five years after conventional volume fracturing and CO2 pre-pad energized fracturing were compared. The results show that compared with conventional volume fracturing, the cumulative oil production of CO2 pre-pad energized fracturing increases by 11.8%, and the water cut decreases by 16.5%. The research results can guide the subsequent reservoir reconstruction operation in the A83 block and provide new ideas for fracturing in the future.

Preparation of low density, high-strength, strong hydrophobic particles (LHSPs) and its application as oil fracturing proppant

Aiming at the problems of the high density of conventional proppant and poor sand carrying performance of slick water in shale oil and gas exploitation. A kind of polymer microsphere with low density and high strength and strong hydrophobic properties (LHSPs) was synthesized by using a silane coupling agent in one step and used as proppants in petroleum fracturing. Fourier transform infrared spectroscopy (FT-IR), scanning electron microscopy (SEM) and X-ray diffraction (XRD) spectra showed that the silane coupling agent formed a rough interface on the particles, which greatly improved the strength and hydrophobicity of the microspheres. The density of LHSPs is 1.075 g·cm-³; Under 69 MPa, the breakage rate of LHSPs was 6.3%. The static water contact Angle is 124°, showing strong hydrophobic state. Meanwhile, the suspension performance test further shows that the ratio of quartz sand to LHSPs settlement is 288 at 120 °C. Water control experiments have also been used to prove that LHSPs can reduce the velocity of water flow and achieve the purpose of water control. The conductivity test shows that LHSPs have good conductivity in gas phase. As the pressure rises to 69 MPa, the quartz sand and LHSPs deflection capacity multiple reached 20 times. This work proves that the preparation of LHSPs is successful and has a broad application prospect in improving the fracturing effect and enhancing shale oil and gas recovery.

The microscopic pore crude oil production characteristics and influencing factors by DME-assisted CO2 injection in shale oil reservoirs

CO2 injection into shale oil reservoirs can effectively enhance recovery while simultaneously realizing geological storage. However, shale oil recovery by CO2 injection remains low. In this paper, classification and evaluation standards for shale oil reservoirs were established. Based on this, comparative experiments between pure CO2 flooding and dimethyl ether (DME)-assisted CO2 flooding were conducted, supplemented by nuclear magnetic resonance testing. The microscopic production characteristics of shale oil under different injection methods were analyzed. The effects of injection pressure, gas injection volume, and DME concentration on oil recovery were studied, and the potential of DME-assisted CO2 flooding was explored. The results show three types of shale samples: I, II, and III, with their corresponding physical properties, pore-throat structures, and percolation capacities decreasing in the same order. With the addition of DME, the CO2 solubility increased, while the produced oil viscosity significantly decreased. DME-assisted CO2 flooding has higher recovery compare with CO2 flooding. The increase is more significant as pressure increases. The increase in ultimate recovery was the largest for type III samples. In addition, regardless of whether pure CO2 flooding or DME-assisted CO2 flooding was applied, a higher injection pressure and injection volume mean higher recovery. The increase by DME-assisted CO2 flooding is much greater than that by pure CO2 flooding. During the miscible stage, the recovery is greater than that during the immiscible stage. The recovery increased with increasing DME molar concentration and then slowed down; therefore, the recommended molar concentration of DME in the mixed gas is 20 mol%. The research results provide new methods and ideas for enhancing shale oil recovery and realizing geological storage by CO2 injection.

Mechanism and influence factor of hydrocarbon gas diffusion in porous media with shale oil

Due to the compactness of shale reservoir matrix and the high conductivity of fractures, the hydrocarbon gas injection huff and puff method or displacement is the most realistic technology to improve shale oil recovery. The diffusion mechanism plays an important role in shale oil development; therefore, it is crucial to figure out the factors influencing diffusion, which could enhance shale oil recovery. In this paper, a physical simulation experiment is designed to evaluate the diffusion ability of hydrocarbon gas. Diffusion experiments are conducted to simulate diffusion in the bulk fluid and in the porous media, to learn about how the pressure, permeability and fracture affect the diffusion behavior. The diffusion coefficients between the bulk diffusion and core sample diffusion are compared. The experimental results show that the diffusion coefficient and mass transfer capacity are positively correlated with permeability and pressure: increasing these parameters can promote the diffusion process. The diffusion coefficient of hydrocarbon gas in a saturated oil core is significantly less than that in crude oil, which indicates that the porous media seriously affects the process of gas diffusion in crude oil. Fractures have little impact on the diffusion behavior. Combined with numerical simulation, the influencing factor of diffusion on the development effect of hydrocarbon gas injection is clarified. The recovery enhances and then decreases with the increasing diffusion coefficient. Cited as: Wanyan, Z., Liu, Y., Li, Z., Zhang, C., Liu, Y., Xue, T. Mechanism and influence factor of hydrocarbon gas diffusion in porous media with shale oil. Advances in Geo-Energy Research, 2023, 7(1): 39-48. https://doi.org/10.46690/ager.2023.01.05

Evaluation of Enhanced Oil Recovery Potential using Interfracture Water Flooding in a Tight Oil Reservoir

Abstract The recovery factor of horizontal wells in tight reservoirs after stage fracturing is low. The effect of water huff-puff on enhancing oil recovery is not obvious. Water channeling is serious during interwell water displacement. Conventional EOR (enhance oil recovery) methods are not effective. Scholars have proposed the method of interfracture water flooding after horizontal well fracturing to improve recovery efficiency in tight reservoirs. In order to study the EOR effects of interfracture water flooding and huff-puff in tight reservoirs, three different EOR schemes were designed: interfracture synchronous water flooding (IFSWF), interfracture asynchronous water flooding (IFAWF), and water huff-puff. The experiment results show the following: (1) in the physical simulation experiment of homogeneous cores, after injection of 0.8 PV formation water, the recovery rates of huff-puff, IFAWF, and IFSWF were 25.7%, 33.7%, and 38.6%, respectively. (2) In the simulation of fractured cores, the oil concentration of IFAWF is 2.7 times higher than that of IFSWF. (3) In the simulation of formation energy replenishment by fractured core, the formation pressure increased by IFAWF is 1.9 times higher than the pressure increased by IFSWF. The results of this study show that interfracture asynchronous flooding can increase the utilization efficiency of injected water, overcome heterogeneity, effectively supplement the energy of tight reservoir, increase the swept area, and improve the recovery factor. IFAWF is a more suitable EOR method for tight reservoirs. The findings of this study contribute to a better understanding of how to select methods to enhance tight oil recovery. At the same time, it provides a method and idea for improving oil recovery of shale oil with lower reservoir physical properties.

Phase Behavior in Nanopores and Its Indication for Cyclic Gas Injection in a Volatile Oil Reservoir from Duvernay Shale

Abstract Duvernay shale spans over 6 million acres with a total resource of 440 billion barrels’ oil equivalent in the Western Canada Sedimentary Basin (WCSB). The oil recovery factors typically decrease with the decreasing of gas-oil ratio (GOR) in oil window of Duvernay shale. The volatile oil recovery factors are typically 5–10%. Enhanced oil recovery technologies should be applied to improve the economics of the reservoirs. In this paper, the volatile oil from the Duvernay shale was taken as an example for phase behavior study. We analyzed the nanopore confinement on phase behavior and physical properties of Duvernay shale oil. The shift of critical properties was quantified within nanopores. With the confinement of nanopores, the viscosity, density, and bubble point pressure of the oil decrease with the shrinking of the pore size. Minimum miscibility pressure (MMP) was calculated for different injected gases. The MMP from high to low is N2>CH4>lean gas>rich gas>CO2. In the case of injecting the same gas component, the MMP decreases as the pore size decreases. The wellhead rich gas is suggested to be the main gas source for gas injection in Duvernay shale. The formation pressure should be rapidly increased to the MMP and maintained close to it, which would help to improve the effect of gas injection and enhance shale oil recovery. This paper can provide critical insights for the research of shale oil gas injection for enhanced oil recovery.