Shale Oil Production Research Articles

Investigation of oil/water two-phase flow behavior in laminated shale porous media considering heterogeneous structure and fluid-solid interaction

The laminated structure of continental shale oil reservoirs introduces significant macro and micro heterogeneity, posing challenges for efficient shale oil extraction. Existing microscopic experimental and simulation methods are insufficient to accurately simulate the fluid flow behavior in mud–lime interactive laminated shale reservoirs. This study delves into the complexities of laminated shale reservoirs with a focus on their heterogeneous structure and wettability. Using scanning electron microscopy, we extracted the structural features of laminated shale reservoirs and established a Multicomponent and multiphase -multi relaxation time-Lattice Boltzmann model(MCMP-MRT-LBM) that considers nanoscale effects such as wall adsorption, liquid–solid slippage, and liquid–liquid slippage. We investigated the occurrence state, the flow behavior, and the phase seepage characteristics of crude oil in laminated shale at different water saturation stages and explored the reasons behind interlayer channeling and the conditions under which crude oil is mobile within limestone and mudstone layers. Then, we examined the impact of varying factors, including heterogeneous wettability, displacement pressure gradients, and pore size, on relative permeability, water injection capacity, sweep efficiency, and crude oil recovery in laminated reservoirs. The results indicate that wettability and pore size distribution, driven by capillary and viscous forces, dictate the occurrence state of remaining oil. Wettability primarily influences fluid distribution, whereas pore size distribution substantially impacts fluid morphology. It also highlights the pivotal role of flow velocity differences between layers in causing interlayer channeling. Increasing the capillary number promotes crude oil mobility within mudstone layers, with the initiation pressure gradient in mudstone layers being 2.5 times that of the limestone layer. The examination of the oil–water relative permeability reveals the dominance of pressure gradients in affecting oil flow capabilities, while pore size significantly influences water flow capacity. By optimizing various factors, it is possible to enhance water injection capacity and sweep efficiency, resulting in a substantial 5%–10% increase in crude oil recovery from laminated shale reservoirs.

Numerical Simulation Study on the Effect of Preinjected CO2 on the Hydraulic Fracturing Behavior of Shale Oil Reservoirs.

Due to the low permeability and apparent mechanical anisotropy of shale reservoirs, shale oil production highly depends on the performance of hydraulic fracturing of the tight reservoir. Pre-injection of CO2 before hydraulic fracturing treatment has been proven beneficial to enhance shale oil production. A comprehensive understanding of the effect of changes in the properties of shale reservoirs after preinjected CO2 on the hydraulic fracturing behavior of shale reservoirs is essential to improve the stimulated reservoir volume (SRV) of shale oil reservoirs. In this study, comprehensive evaluating parameters were proposed to specify the variation of mechanical properties of shale rock at different soaking times of CO2 based on published testing parameters of shale. Accordingly, a three-dimensional (3D) numerical model was established and three groups of horizontal well fracturing cases with different cluster spacings were conducted based on the adaptive FE-DE method to simulate and compare the hydraulic fracturing behavior in the reservoirs with different mechanical properties. We established a quantitative relationship between the alterations in reservoir properties and the stimulated reservoir volume. The results indicate that both the brittleness and conductivity properties of shale rock are dramatically improved as the increment of soaking time of CO2. It is beneficial to improve the SRV, and the initiation pressure is reduced with the increment of soaking time of CO2. However, as the stress shadow effect is involved in the horizontal well fracturing, the complexity of the hydrofracturing crack is significantly enhanced to restrain the development of hydrofracturing crack. When the cluster spacing is larger, the stress shadow effect is weakened, and the weakening effect of CO2 soaking on reservoir is more obvious.

Co-Pyrolysis of Woody Biomass and Oil Shale—A Kinetics and Modelling Study

The co-pyrolysis of biomass and fossil fuels has been the subject of studies on sustainable energy. Co-feeding oil shale with woody biomass can contribute to a transition into carbon neutrality. The present study analysed the thermal decomposition behaviour of oil shale and biomass blends (0:1, 3:7, 1:1, 7:3, 9:1, and 1:0) through thermogravimetric analysis (TGA) at 80–630 °C with a heating rate of 10 °C/min in CO2 and N2 atmospheres. A comparison of theoretical and experimental residual mass yields of oil shale–biomass mixtures indicated no significant interactions between the fuels. The blends contributed to a decrease of up to 34.4 wt% in solid residues compared to individual pyrolysis of oil shale, and the TGA curves were shifted from up to 10 °C to a lower temperature when the biomass ratio increased. The use of a CO2 atmosphere resulted in the production of solid residues, comparable to the one obtained with the N2 atmosphere. CO2 atmosphere can be used in oil shale–biomass co-pyrolysis, without affecting the decomposition process or increasing the yield of residues. A kinetic model method is proposed based on TGA data at 10, 20, and 30 °C/min. The apparent activation energies for a temperature range of 200–520 °C were in the order of 139, 155, 164, 197, 154, and 167 kJ/mol for oil shale–biomass 0:1, 3:7, 1:1, 7:3, 9:1, and 1:0 blends, respectively. From the isoconversional kinetic analysis, a two-stage pyrolysis was observed, which separated biomass and oil shale pyrolysis. A simulation of biomass and oil shale co-pyrolysis was conducted in Aspen Plus® using TGA-derived kinetic data. The model prediction resulted in a close match with the experimental thermogravimetric data with absolute errors from 1.75 to 3.78%, which highlights the relevance of TGA analysis in simulating co-pyrolysis processes.

Multi-phase behavior and pore-scale flow in medium-high maturity continental shale reservoirs with Oil, CO2, and water

The application of CO2 to enhancing the recovery of continental shale oil has attracted considerable attention. However, the introduction of CO2 leads to intricate phase behavior and flow mechanisms. In this study, firstly, a three-phase equilibrium model is developed, with nano-confinement effects taken into consideration, to analyze the phase behavior of continental shale oil-CO2-water systems in both a bulk phase and nanopores. Building upon this, an improved pore network model is introduced to simulate steady-state oil–water flow while considering the alterations in fluid properties resulting from CO2 dissolution. The findings reveal that with the increase of CO2 injection, a transition from two phases of liquid and water to two phases of vapor and water, three phases of liquid, vapor and water, two phases of vapor and water, and ultimately a pure vapor phase occurs. The dissolution of CO2 exerts a pronounced impact on the composition and properties of the oil phase, and the viscosity and interfacial tension reduction effects play a central role in affecting the flow capacity. Nano-confinement effects facilitate the transfer of vapor-phase molecules into the water and oil phases, thus increasing the concentration of CO2 in the oil and water phases. The pore-scale flow results reveal that upon injection, water quickly traverses the larger pores. More smaller pores become accessible after CO2 dissolution, significantly boosting the extraction of shale oil from these smaller pores and slightly reducing the water output.

Unravelling oceanic wave patterns: A comparative study of machine learning approaches for predicting significant wave height

Predicting significant wave height (SWH) is critical to ocean engineering, navigation, and renewable energy harvesting. This study comprehensively analyzes several machine learning (ML) and deep learning (DL) models. These include the adaptive neuro-fuzzy inference system with subtractive clustering ANFIS (SC), an artificial neural network with Bayesian regularization ANN (BR), bidirectional long-short-term memory (BiLSTM), bidirectional gated recurrent unit (BiGRU), and BiGRU with attention mechanism (AM), all employed for the prediction of SWH. The models were evaluated using data from three stations: a Canadian station in the North Atlantic Ocean and two Chinese stations in the East China Sea. Our study demonstrates the superior performance of the ANFIS (SC) model across all stations. For instance, the ANFIS model achieved an R2 value of 0.9979 at the Canadian station, outperforming the gated recurrent unit (GRU) based model with an R2 of 0.9127 from previous research. Similarly, at the Lianyungang (LYG) station, the ANFIS model achieved an R2 value of 0.9812, surpassing the performance of the GRU network used in prior studies, which reached an R2 of 0.6436 for 6-hour forecasts. Moreover, our study outperforms the convolutional neural network (CNN) based BiGRUAM model used for shale oil production prediction regarding R2 values. Furthermore, compared to the dynamic ensemble ESN model used for wave height prediction, our ANFIS model demonstrated more robust and consistent performance. Therefore, this research significantly contributes to the field of SWH prediction by presenting the superior performance of the ANFIS model across different geographical locations and conditions. This research opens new avenues for future research and practical applications in oceanography, weather forecasting, and renewable energy harvesting.

Van der Waals interaction of nanonized oil particles in a porous medium

The article presents an analytical calculation of the van der Waals forces acting on oil by nanoparticles, which suggests their role in changing the rheological properties of oil and the subsequent transition to a new regime. The significance of accounting for intermolecular van der Waals forces is emphasized in the realm of shale oil production, elucidating the foundational principles of nanotechnological phenomena arising from the treatment of formations with metallic nanosystems, characterized by low concentrations and the perturbance effect. The results demonstrate a plane and sphere model for nanofluid behavior in porous media, especially between oil, reservoir particles and nanoparticles. The free energy associated with the non-retarded interactions of van der Waals forces is expressed through equations that exhibit a proportional relationship with the Hamaker number. Using addition rules for multicomponent systems, the study calculates Hamaker constants for the nano-oil model under consideration, demonstrating the superiority of nano-induced van der Waals forces compared to forces in porous media without the influence of nanosystems. In addition, based on experimental data from a study of the injection of a nanosolution into a formation, 5 models illustrating the relationships among surface tension, van der Waals pull-off force, and nanoparticle concentration to ensure the pragmatic essence of the tension minimization process.

Propagation of Combustion Front within Fractured Shale and Its Influence on Shale Structure and Crude Oil Properties: An Experimental Study

Summary The in-situ combustion (ISC) technique has emerged as a significant approach for shale oil production. However, currently, there is a lack of experimental evidence supporting the stable propagation of combustion front within fractured shale. This study aimed to investigate the combustion characteristics within fractured shale by using a self-designed combustion tube (CT) and an experimental scheme. Subsequently, an analysis of shale structure and oil properties was conducted. The results demonstrated that while the combustion front could propagate through shale with a single fracture width of approximately 43 μm, the combustion intensity gradually diminished, leading to an inability to sustain stable propagation in the later part of the oil-detritus mixtures. The combustion intensity within the shale was enhanced by preheating the shale at 250°C, resulting in an improved oil recovery from 67.8% to 77.9%. The findings indicated that the complex fractured shale allowed for the stable propagation of the combustion front without a significant decrease in combustion intensity. Moreover, the T2 spectrum analysis of shale revealed a gradual expansion of the pore-fracture structure and improved shale connectivity after combustion. The T1-T2 response illustrated the transformation of solid and heavy components into lighter components. Furthermore, the content of saturates and H in the oil increased after combustion, whereas there was a significant decrease in resins, O, and S. Overall, this study provided technical evidence supporting the feasibility of employing the ISC technique for the development of shale oil reservoirs with additional fractures.

Micro-occurrence characteristics and charging mechanism in continental shale oil from Lucaogou Formation in the Jimsar Sag, Junggar Basin, NW China.

The micro-occurrence characterization of shale oil is a key geological issue that restricts the effective development of continental shale oil in China. In order to make up for the lack of research in this area, this paper carries out a series of experiments on the shale oil of the Lucaogou Formation using a multi-step extraction method, with the aim of exploring the micro-occurrence types and mechanisms of shale oil in the Lucaogou Formation, as well as exploring its direct connection with production and development. In this paper, shale oil in the reservoir is divided into two categories: free oil and residual oil. The polar substances and OSN compounds are the key factors determining the occurrence state of shale oil. Abundant polar substances and OSN compounds can preferentially react with mineral surfaces (including coordination, complexation, ionic exchange, and so on) to form a stable adsorption layer, making it difficult to extract residual oil in actual exploitation. Free oil is mainly composed of aliphatic hydrocarbons, and its adsorption capacity is related to the length of the carbon chain, i.e. long carbon chain, strong adsorption capacity, and poor movability. Free oil is widely stored in pores and cracks, and that with high mobility can be the most easily extracted, making it the main target at present exploitation. In the current state of drilling and fracturing technology, research should prioritize understanding the adsorption and desorption mechanisms of crude oil, particularly residual oil. This will help optimize exploitation programs, such as carbon dioxide fracturing and displacement, to enhance shale oil production.

Desarrollos recientes en el mercado del petróleo

Rationale Oil prices have fluctuated considerably over the past year. Against this background, it is worth analysing the factors behind recent oil price developments, as well as some key aspects for assessing the outlook for the near future. Takeaways •Following the downward trend seen in the second half of 2022, the price of oil hovered around $80 abarrel throughout 2023, albeit with notable fluctuations. •The Q3 uptick in oil prices can essentially be attributed to supply-side factors, such as the OPEC+production cuts, while lacklustre demand appears to lie behind the moderation observed during therest of the year. •Looking ahead, the potential for geopolitical tensions to push up oil prices could be offset, at leastpartially, by the release of inventories, the deployment of spare capacity and the response from otherproducers, such as the United States, although shale oil production is increasing more slowly than inthe pre-pandemic period.

Hierarchical cluster and principal component analyses of multi-scale pore structure and shale components in the Upper Triassic Chang 7 Member in the Ordos Basin of China

An important issue concerning the sustainable production of shale oil is the characterization of pore structure at various scales, but there is an insufficient understanding of the coupled relationship between pore structure and shale components. Integrated analyses using field emission-scanning electron microscopy, mercury intrusion porosimetry, nitrogen physisorption, and small angle neutron scattering were conducted on nine shale samples from the Upper Triassic Chang 7 Member in Ordos Basin to investigate the relationship between multi-scale pore structure and shale minerals and organic matter (OM). The results show that the clays minerals (mainly illite-smectite) are usually combined with OM to form complex OM-hosted pores, and inorganic pores consist of both inter- and intra-particle pores (mostly related to clay platelet clusters). Three groups of shales classified by hierarchical cluster analyses (HCA) vary widely in pore structure, with the highest pore volume and largest pore diameter observed in a decreasing order of Group (1), Group (2), and Group 3. Principal component analysis (PCA) shows that brittle minerals (mainly quartz) have preserved interP pores that contribute to the development of high pore volumes and large pore-throat diameters, and ductile clays minerals and OM tend to fill pores and reduce pore diameter and volume. The complex nature of shale porosity is influenced by multiple factors, and hence accurate and comprehensive characterization requires the use of diverse methods including both experimental and theoretical analyses. An integrated approach to elucidating the factors controlling pore structure in medium-to-low maturity shale will help with efficient shale oil production.

Carbon Storage Potential of Shale Reservoirs Based on CO2 Fracturing Technology

The development of shale reservoirs is important in ensuring China’s national energy security by achieving energy independence. Among the key technologies for shale oil production, CO2 fracturing is an effective method that can not only enhance oil recovery but also promote large amounts of CO2 storage, thereby supporting China’s goals of achieving a carbon peak and carbon neutrality. This research paper aims to study the impacts and prospective applications of CO2 fracturing in shale reservoirs, using real exploitation parameters from the GYYP1 well in the Songliao Basin. By utilizing numerical simulation, the dynamics of CO2 production are analyzed. Adsorption and diffusion are identified as pivotal mechanisms for CO2 storage in shale reservoirs. After the analysis of the fracturing process, approximately 22.13% of CO2 is found to be adsorbed, which decreases to 11.06% after ten years due to pressure decline. Diffusion increases the volume of CO2 interacting with a greater extent of shale, thereby enhancing the adsorption mechanism. Over time, the diffusion process results in a remarkable increase of 26.02% in CO2 adsorption, ensuring the long-term and stable storage of CO2 within the shale reservoir. This investigation delves into the contribution of these two crucial mechanisms of CO2 storage in shale reservoirs, ultimately predicting that, by 2030, approximately two million tons of CO2 can be effectively stored in the Daqing Oilfield through CO2 fracturing in shale oil reservoirs. Such an achievement will undoubtedly contribute to the sustainable development of the energy sector and foster the transformation and upgrading of China’s energy structure.

Optimization of high-temperature gas parameters and analysis of the impact of oil shale thickness on the in situ development process

In situ shale oil extraction is an efficient and environmentally friendly development method. This article employs in situ extraction technology to heat shale oil, optimizing its high-temperature gas parameters based on indicators such as cumulative oil production rate and cumulative power consumption in the shale oil region. Using the optimized high-temperature gas parameters, an exploration of shale oil with different thicknesses was conducted. The results indicate that out of nine different high-temperature gas parameters, five cannot induce complete fracturing in the shale oil region. Models II, III, I, and IV each reach the onset of shale oil fracturing in the entire region after 870, 900, 1020, and 1080 days, respectively. The heating rate factor peaks at 1620, 1620, 1800, and 1980 days, with values of 0.277, 0.305, 0.317, and 0.32, respectively. Compared to Model II, the peak of the heating rate factor in Model I is the highest, showing an increase of 15.52%. Among these models, Model I has the lowest unit volume power consumption at 1063.41 kW/m3. The unit volume power consumption in Model I exhibits the most significant reduction, with a maximum decrease of 16.45% compared to the other three shale oil models of different thicknesses. The research results provide a basis for the engineering development of shale oil.

Experimental study on the effect of foam in preventing gas channeling in shale reservoir

Shale oil resources have enormous potential and broad development prospects in China. Especially with the rapid development of horizontal well volume fracturing technology, the production of shale oil has been greatly increased, and it has become an important position to increase oil and gas storage and production. However, due to the existence of artificial and natural fractures produced by fracturing, gas channeling will occur in the process of huff-n-puff gas injection, which will affect the production and lead to poor development effect. In this paper, foam is used as an anti-channeling agent in the process of huff-n-puff gas injection. The results of microfluidic experiments show that the production mode of foam in porous media is liquid membrane hysteresis and liquid membrane separation. In porous media, foam first blocks large channels such as fractures, and then enters the matrix. The oil recovery mechanism of foam assisted gas injection in porous media is to improve the sweep efficiency and oil displacement efficiency of gas. Compared with N2 huff-n-puff, the oil recovery of the first cycle of foam assisted N2 huff-n-puff increased by 4.50%, and the third cycle increased by 9.58%. It is proved that foam has good anti channeling effect in gas huff-n-puff injection process. The research results provide an effective method for efficient gas injection development of shale oil.

Characterization and reconstruction of rough fractures based on vector statistics

The characteristics of fracture networks are of great significance for unconventional geo-energy exploitation such as shale oil, shale gas and geo-thermal extraction. Natural fractures and induced fractures after reservoir stimulation control the mechanical properties and fluid flow of the reservoirs. The quantitative characterization and reconstruction of rough fractures are essential for studying the fluid flow and mechanical properties of the reservoirs with complicated fracture networks. Based on vector statistics, a vector statistical method (VSM) for quantitative characterization of rough fractures is proposed and tested using 10 standard joint profiles. Furthermore, the growth vector counting method (counting method) and growth vector probability method (probability method) for single rough fractures in two-dimensional (2D) and three-dimensional (3D) models are proposed. Afterward, a morphology comparison and quantitative evaluation of single rough fractures before and after reconstruction are conducted. When the counting and probability methods are used to reconstruct single rough fractures, the difference in the tortuosity and fractal dimensions of the original and reconstructed fractures are less than 5% and 2.5%, respectively. It implies the counting and probability methods proposed herein can reconstruct rough fractures with approximate statistical characteristics and quantitative characterization parameters. Subsequently, the counting and probability methods for single rough fractures are further developed for 2D and 3D modeling of conventional and rough discrete fracture networks. The results indicate that the growth vector counting and probability methods proposed in this study have significant potential for rough discrete fracture network modeling. In addition, the merits and limitations of the proposed algorithms in modeling discrete fracture network models are discussed.

A surrogate shale oil model based on a multi-objective fusion adaptive optimization considering its pyrolysis characteristics

A surrogate shale oil model was proposed based on model compounds with optimal proportions to reduce the complexity of Huadian shale oil to analyze its pyrolysis kinetics. There are mainly n-alkanes and n-olefins with C8–C36 in shale oil according to GC-MS results, a small amount of aromatics and alcohols, as well as trace of esters, ketones and nitriles, etc. Pyrolysis behavior of shale oil was investigated by Py-GC-MS and FTIR, including the evolution of pyrolytic products and functional groups. Here, n-eicosane, 1-octadecene, pentadecanol and nonylbenzene were selected as surrogates based on GC-MS result. To obtain the optimal surrogate model, a novel multi-objective fusion adaptive optimization function with constraints was proposed to determine the optimal weighting factor of each component from the pareto optimal set. Then, the detailed pyrolysis kinetic mechanisms containing 745 species and 19392 reactions were developed to study its thermochemical conversion. Moreover, the skeletal mechanism reduced by decoupling and directed relation graph (DRG) was used to describe the thermal flow reactivity of these four components. In sum, this work provides an integrated description of shale oil pyrolysis, and gives a new method for studying the pyrolysis of oil shale intrinsically.

Numerical simulation of CO2-enhanced oil recovery in fractured shale reservoirs using discontinuous and continuous Galerkin finite element methods

Introduction: This study explores the potential of enhancing shale oil recovery and reducing CO2 emissions through CO2 injection in fractured shale reservoirs. The importance of this approach lies in its dual benefit: improving oil extraction efficiency and addressing environmental concerns associated with CO2 emissions.Method: We employed a discrete fracture-matrix model to simulate CO2 flooding in fractured shale reservoirs, utilizing both discontinuous Galerkin (DG) and continuous Galerkin (CG) finite element methods. The DG-CG FEM’s accuracy was validated against the McWhorter problem, ensuring the reliability of the simulation results. Our model also considered various factors, including reservoir heterogeneity, fracture permeability, CO2 injection volume, and gas injection patterns, to analyze their impact on shale oil recovery.Result: Our simulations revealed that fractured reservoirs significantly enhance shale oil production efficiency compared to homogeneous reservoirs, with an approximate 48.9% increase in production. A notable increase in shale oil production, by 15.8%, was observed when fracture permeability was increased by two orders of magnitude. Additionally, a fourfold increase in CO2 injection rate resulted in a 31.5% rise in shale oil production. Implementing a step-by-step reduction in injection volume while maintaining the total CO2 injection constant proved to be more effective than constant-rate injections.Discussion: The study demonstrates the effectiveness of CO2 flooding in fractured shale reservoirs for enhancing shale oil recovery.

Investigation on the flow behavior and mechanisms of water flooding and CO2 immiscible / miscible flooding in shale oil reservoirs

Shale reservoirs represent a significant untapped source of recoverable oil, and even a slight increase in recovery can yield substantial benefits. In recent years, there has been a growing interest in the development of shale reservoirs due to their vast potential. Shale reservoirs are characterized by their intricate pore structures, ultra-low porosity, and extremely low permeability. Consequently, fluid flow within shale formations is highly complex, and the distribution of shale oil is diverse. There is an urgent need to conduct research into the flow behavior of shale reservoirs and the modes of crude oil occurrence within them, in order to support effective shale oil extraction in the field. In this work, we established a MCMP-MRT-LBM model considering nano-scale confinement effects such as slip and adsorption. The model is employed to simulate single pore channels and blind-end pores to investigate the distinct mechanisms involved in water flooding, CO2 immiscible flooding, and CO2 miscible flooding. Subsequently, the research explores the fluid flow characteristics associated with these three development methods within porous media, as well as the distribution of remaining oil. Then we compared the oil displacement efficiency, swept volume, actual liquid injection volume and displacement front position of the three fluids in porous media. The results reveal that water flooding exhibits superior displacement performance in single pore channels, while CO2 miscible flooding proves to be the most effective method for exploiting oil in blind-end pores. In porous media, CO2 miscible flooding successfully mitigates fingering phenomena and efficiently recovers crude oil located at blind-end and corner regions of the pores. The recovery efficiency achieved through CO2 miscible flooding is approximately 30% higher than that of water flooding and about 10% greater than CO2 immiscible flooding.

CO2-Enhanced Radial Borehole Development of Shale Oil: Production Simulation and Parameter Analysis

Shale oil resources, noted for their broad distribution and significant reserves, are increasingly recognized as vital supplements to traditional oil resources. In response to the high fracturing costs and swift decline in productivity associated with shale oil horizontal wells, this research introduces a novel approach utilizing CO2 for enhanced shale oil recovery in radial boreholes. A compositional numerical simulation method is built accounted for component diffusion, adsorption, and non-Darcy flow, to explore the viability of this technique. The study examines how different factors—such as initial reservoir pressure, permeability, numbers of radial boreholes, and their branching patterns—influence oil production and CO2 storage. Our principal conclusions indicate that with a constant CO2 injection rate, lower initial reservoir pressures predominantly lead to immiscible oil displacement, hastening the occurrence of CO2 gas channeling. Therefore, maintaining higher initial or injection pressures is critical for effective miscible displacement in CO2-enhanced recovery using radial boreholes. Notably, the adsorption of CO2 in shale oil results in the displacement of lighter hydrocarbons, an effect amplified by competitive adsorption. While CO2 diffusion tends to prompt earlier gas channeling, its migration towards areas of lower concentration within the reservoir reduces the extent of channeling CO2. Nonetheless, when reservoir permeability falls below 0.01 mD, the yield from CO2-enhanced recovery using radial boreholes is markedly low. Hence, selecting high-permeability “sweet spot” regions within shale oil reservoirs for the deployment of this method is advisable. To boost oil production, utilizing longer and broader radial boreholes, increasing the number of boreholes, or setting the phase angle to 0° are effective strategies. Finally, by comparing the production of shale oil enhanced by CO2 with that of a dual horizontal well fracturing system enhanced by CO2, it was found that although the former’s oil production is only 50.6% of the latter, its cost is merely 11.1%, thereby proving its economic viability. These findings present a new perspective for the economically efficient extraction of shale oil, offering potential guidance for industrial practices.

Oil shale pyrolysis and electric heating in situ mining technology improvements

Oil shale pyrolysis and electric heating in situ mining technology improvements

Groundwater environmental impact caused by in-situ pyrolysis of oil shale

Groundwater environmental impact caused by in-situ pyrolysis of oil shale