Shale Oil Reservoirs Research Articles

Characteristics of Crude Oil Production in Microscopic Pores of CO2 Huff and Puff in Shale Oil Reservoirs

Characteristics of Crude Oil Production in Microscopic Pores of CO₂ Huff and Puff in Shale Oil Reservoirs

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.

Efforts to untie the multicollinearity knot and identify factors controlling macropore structures in shale oil reservoirs

Efforts to untie the multicollinearity knot and identify factors controlling macropore structures in shale oil reservoirs

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.

CO2–Water–Rock Interaction and Its Influence on the Physical Properties of Continental Shale Oil Reservoirs

Shale oil resources are abundant, but reservoirs exhibit strong heterogeneity with extremely low porosity and permeability, and their development is challenging. Carbon dioxide (CO2) injection technology is crucial for efficient shale oil development. When CO2 is dissolved in reservoir formation water, it undergoes a series of physical and chemical reactions with various rock minerals present in the reservoir. These reactions not only modify the reservoir environment but also lead to precipitation that impacts the development of the oil reservoir. In this paper, the effects of water–rock interaction on core porosity and permeability during CO2 displacement are investigated by combining static and dynamic tests. The results reveal that the injection of CO2 into the core leads to reactions between CO2 and rock minerals upon dissolution in formation water. These reactions result in the formation of new minerals and the obstruction of clastic particles, thereby reducing core permeability. However, the generation of fine fractures through carbonic acid corrosion yields an increase in core permeability. The CO2–water–rock reaction is significantly influenced by the PV number, pressure, and temperature. As the injected PV number increases, the degree of pore throat plugging gradually increases. As the pressure increases, the volume of larger pore spaces gradually decreases, resulting in an increase in the degree of pore blockage. However, when the pressure exceeds 20 MPa, the degree of carbonic acid dissolution will be enhanced, resulting in the formation of small cracks and an increase in the volume of small pores. As the temperature reaches the critical point, the degree of blockage of macropores gradually increases, and the blockage of small pores also occurs, which eventually leads to a decrease in core porosity.

Research on porosity characterization methods of shale oil reservoirs in Lianggaoshan Formation, Sichuan Basin

Shale oil, an important component of unconventional oil and gas resources, mainly exists in the storage spaces such as shale pores, microfractures, etc. Porosity is commonly used to quantitatively describe the storage space of shale oil and is a key parameter in reservoir evaluation. However, there are significant differences in the results by existing experimental methods for porosity measurement, and moreover, it is difficult to compare the porosity obtained by the experimental measurement method with the logging calculation method. It is urgent to explore reasons for the differences in porosity measurement between various porosity experiments and logging calculations of the shale oil reservoir, and propose an effective method for shale oil reservoir to characterize porosity. In this research, core samples of shale oil reservoirs from the Lianggaoshan Formation of the Sichuan Basin were selected to measure the porosity by means of experimental methods including helium gas charging, saturation liquid method, nuclear magnetic resonance (NMR), etc. Meanwhile, porosity was calculated using the combination method of lithology scanning (LS) logging and conventional logging as well as the NMR logging method. Subsequently, porosity experimental results and logging calculation results were compared to clarify the applicability of various porosity characterization methods. The research results indicate that: 1) The porosity measurement results by the saturation liquid method and the NMR experimental method are close, both greater than that using the helium gas charging method; 2) The hydrogen signal of the dry-state sample is significant in the NMR experiment, mainly originating from organic matter and clay minerals; 3) The NMR short relaxation component in the water-saturated state primarily reflects the signal of organic matter and clay mineral matrix, while the long relaxation component reflects the pore fluid component; 4) After deducting the NMR signal of the dry-state core, the core NMR porosity measurement results under the water-saturated state agree well with that using the saturation liquid method, which is an indicative of effective reservoir porosity; 5) The NMR logging is limited by its echo spacing and cannot reflect the signal from organic matter and the crystal water in clay minerals at T2 < 0.3 ms. Taken together, the porosity measurement method of subtracting the dry-state NMR signal from the water-saturated state NMR signal is considered effective and can be used to reflect the porosity of shale oil reservoirs in the Lianggaoshan Formation of the Sichuan Basin.

Mineral diagenesis in lacustrine organic-rich shales: Evolution pathways and implications for reservoir characteristics

Porosity in shale reservoirs is profoundly influenced by diagenetic processes that shape the evolution of pore space. In the Songliao Basin, the first member of the Qingshankou Formation (K2qn1) shale serves as a typical lacustrine clay-rich shale oil reservoir. It exhibits variable mineralogy and thermal maturity, with its reservoir quality strongly influenced by these variations. This study integrates microscopic observations, including field emission scanning electron microscopy (FE-SEM), cathodoluminescence (CL), and organic petrology, with bulk rock investigations employing X-ray diffraction (XRD), Rock-Eval pyrolysis, and elemental analysis, to reconstruct the diagenetic pathways leading to changes in porosity. The findings reveal that K2qn1 shale is primarily composed of extrabasinal grain assemblages, such as detrital quartz and clay minerals, with sedimentary organic matter mainly as lamalginite. As maturity exceeds 0.8 %Ro, the presence of authigenic clay minerals, primarily characterized by chlorite, becomes widespread, often associated with bitumen impregnation. Additionally, authigenic dolomite and pyrite form during the synsedimentary to early diagenetic stages. In immature to marginally mature stages (<0.6 % Ro), mechanical compaction is the primary factor leading to porosity reduction. Pores associated with organic matter become visible when maturity reaches the oil window (>0.7 % Ro). At the peak of hydrocarbon expulsion (approximately 1.2 % Ro), a high frequency of organic matter shrinkage pores at interfaces to clay minerals is present, likely playing a significant role in enhancing permeability. Although localized occurrences of dissolution and cementation can be observed, the development of these diagenetic processes is limited and exerts minimal influence on the physical properties of the bulk rock. This study significantly contributes to our understanding of the mechanisms governing diagenetic processes and reservoir evolution in markedly heterogeneous lacustrine shale, considering the diverse origins of grain assemblages.

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.

Study on Fracture Propagation Rules of Shale Refracturing Based on CT Technology

Reactivating oil and gas wells, increasing oil and gas production, and improving recovery provide more opportunities for energy supply especially in the extraction of unconventional oil and gas reservoirs. Due to changes caused by well completion and production in pore pressure around oil and gas wells, subsequently leading to changes in ground stress, and the presence of natural and induced fractures in the reservoir, the process of refracturing is highly complex. This complexity is particularly pronounced in shale oil reservoirs with developed weak layer structures. Through true triaxial hydraulic fracturing experiments on Jimsar shale and utilizing micro-CT to characterize fractures, this study investigates the mechanisms and patterns of refracturing. The research indicates: (1) natural fractures and the stress states in the rock are the primary influencing factors in the fracture propagation. Because natural fractures are widely developed in Jimsar shale, natural fractures are the main influencing factors of hydraulic fracturing, especially in refracturing, the existing fractures have a greater impact on the propagation of secondary fracturing fractures. (2) Successful sealing of existing fractures using temporary blocking agents is crucial for initiating new fractures in refracturing. Traditional methods of plugging the seam at the root of existing fractures are ineffective, whereas extensive injection of blocking agents, forming large “sheet-like” blocking bodies in old fractures, yields better sealing effects, promoting the initiation of new fractures. (3) Moderately increasing the pumping rate and viscosity of fracturing fluid is advantageous in forming “sheet-like” temporary blocking bodies, enhancing the complexity of the network of new fractures in refracturing. (4) When there is a high horizontal stress difference, after sealing old fractures, the secondary hydraulic fractures initiate parallel to and extend from the old fractures. In cases of low horizontal stress difference, the complexity of secondary hydraulic fractures increases. When the horizontal stress changes direction, the secondary hydraulic fractures also change direction. It is recommended to use high-viscosity fracturing fluid and moderately increase the pumping rate, injecting blocking agents to seal old fractures, thereby enhancing the complexity of the network of refracturing. These findings provide important technical guidance for improving the efficiency of shale oil reservoir development.

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.

Microscopic pore-throat classification and reservoir grading evaluation of the Fengcheng formation in shale oil reservoir

Different basins in China have proposed various reservoir grading standards for shale oil. Based on a comprehensive understanding of the basic characteristics of the shale oil reservoir in the Mahu Depression, this paper uses data from high-pressure mercury injection, physical properties, nuclear magnetic resonance, depletion development, and CO2 displacement development tests to analyze the microscopic pore structure features of the Fengcheng Formation shale oil reservoir. On this basis, the classification boundaries of the pore throats in the shale oil reservoir were analyzed, and a reservoir grading standard suitable for the Fengcheng Formation shale was proposed: large pore throats (greater than 1000 nm), medium pore throats(100∼1000 nm), small pore throats (20∼100 nm), and ultra-small pore throats (less than 20 nm). The medium pore throat is the lower limit for depletion development, the small pore throat is the lower limit under CO2 displacement conditions, and the ultra-small pore throat cannot be utilized under current conditions. The classification effect of the shale oil reservoir is verified using the production characteristics of Well MY1, the liquid production profile, and the results of geological "sweet spots" studies. The results show that the classification scheme for the microscopic pore throats of the Fengcheng Formation shale oil is reliable and feasible.

Research on Inversion Log Evaluation Method of Special Mineral in Alkali Lake Shale Oil Reservoir—A Case Study of the Fengcheng Formation in the Mahu Sag, China

The Fengcheng Formation in the Mahu Sag of the Junggar Basin, China, is characterized by alkaline lake deposits, featuring abundant alkaline minerals. The content of alkaline minerals affects the physical properties and oil-bearing properties of the reservoir, and existing mineral inversion methods cannot calculate the content of alkaline minerals. Based on Litho Scanner Log data, we can calculate the dry weight of elements using the oxide closure model. By improving the rock volume physical model; adding trona, shortite, eitelite, and reedmergnerite to the rock volume physical model; and combining with the least squares method, the mineral content calculation was carried out, using the inversion method of combination models (Shortite Model, Eitelite Model, Reedmergnerite Model, and Trona Model) to achieve mineral inversion of alkali-bearing shale oil reservoirs. Litho Scanner Log is expensive, and its widespread application will increase exploration costs. This article scales the mineral inversion results of Litho Scanner Log into conventional log data, improves the rock volume physical model of conventional log, and uses a combination model to achieve mineral inversion of alkali-bearing shale oil reservoirs in conventional log. Compared with the results of X-ray diffraction experiments, the average absolute error of all minerals except for trona and feldspar is less than 10%, and the inversion results are consistent with the core test results. The research results of this article can provide theoretical and technical support for the log evaluation of alkali-bearing shale oil reservoirs.

Influence of High-Density Bedding Plane Characteristics on Hydraulic Fracture Propagation in Shale Oil Reservoir

Influence of High-Density Bedding Plane Characteristics on Hydraulic Fracture Propagation in Shale Oil Reservoir

Impact of Osmotic Pressure on Seepage in Shale Oil Reservoirs

Impact of Osmotic Pressure on Seepage in Shale Oil Reservoirs

Prediction of Self‐Flow Production in Segmented Hydraulic Fractured Horizontal Shale Wells Based on EDFM

Terrestrial shale oil resources in China are abundant. However, its development in China is still in the early stages. And its scale of transformation and production systems is still being explored. Currently, reservoir numerical simulation on shale oil reservoirs faces two main challenges: (1) multiscale flow of matrix–microfracture–hydraulic fractures in shale oil reservoirs and (2) bidirectional coupling of reservoir–wellbore–nozzle systems. This paper proposes a self‐flow model for horizontal shale wells that describes multiscale fractures and production controlled by the nozzle. The model integrates the embedded discrete fracture model (EDFM), pipe flow model, and nozzle flow model. The accuracy of the model has been validated through comparisons with other reference models and field data. Then, this study analyzes the effects of different natural fracture densities, horizontal section lengths, number of fracturing stages, and nozzle diameters on the production capacity during the self‐flow period. The results indicate that reservoirs with developed natural fractures can enhance the development efficiency during the self‐flow period, and appropriate horizontal section lengths and fracturing stages contribute to achieving maximum economic benefits in development. Additionally, smaller nozzle diameters lead to longer self‐flow periods and higher cumulative production. The research findings of this paper can be applied to simulate the production of hydraulic fractured horizontal shale wells.

Surfactant slug assisting CO2 huff and puff in enhancing shale oil reservoir recovery

Focusing on problems of rapid production decline and poor development effect after volume fracturing of the shale oil reservoir, a production method of SC-HNP (surfactant slug assisting CO2 huff and puff) was proposed. Taking CQ block (CQ, the reservoir block name) as an example, laboratory experiments were carried out using typical oil samples and core samples, and a numerical simulation model of SC-HNP was established based on the experimental results. The production performance and oil recovery mechanism were analyzed, and the oil production by SC-HNP of a typical well was predicted. The results showed that (1) the oil recovery degree of the surfactant imbibition experiment is 34.5%, showing good imbibition oil recovery effect. CO2 has good swelling effect and viscosity reduction ability to the oil. (2) SC-HNP combines the effects of the surfactant and CO2, and it has the best replenishing formation energy ability and the highest oil production level. Its improved recovery degree is about 2.4% (one cycle), showing the best development effect. (3) Compared with SF-HNP (surfactant huff and puff), SC-HNP can improve the oil displacement effect in the far-well fractured area, and compared with CO2-HNP (CO2 huff and puff), SC-HNP can improve the oil displacement effect in the near-well fractured area. (4) Using SC-HNP, it is predicted that the oil recovery degree of well CQP-32 (CQP-32, the well name) can be increased by 1.84%, which significantly improves the development effect, and the CO2 storage percent is about 32%.

Lithofacies identification and prediction of Chang 7&lt;SUB align="right"&gt;3 shale oil reservoirs in Ordos Basin: insights from the multi-resolution graph-based clustering analysis

Lithofacies identification and prediction of Chang 7&lt;SUB align="right"&gt;3 shale oil reservoirs in Ordos Basin: insights from the multi-resolution graph-based clustering analysis

Numerical simulation study on factors affecting the pre-CO2 fracturing effect in shale oil reservoirs: A case study on Kong-2 member in Cangdong Sag, China

A novel procedure has emerged in recent years within oilfields ? namely, the utilization of a hybrid fracturing method employing pre-CO2 injection along with sand-carry slick water. In this paper, based on the real logging data of shale oil reservoirs in the second member of Cangdong Sag, Huanghua Depression, combined with the GOHFER, a coupled 3-D hydraulic fracture propagation model is proposed. This research delves into an examination of how engineering factors exert their influence on the process of fracture propagation. The quantitative analysis is conducted encompassing critical fracture parameters such as half-length, height, and width, and self-defined fracture seepage area and fracture front fractal dimension. The research findings indicate that as injection displacement increases, the fracture shape undergoes a transformation from being ?long, low, and wide? to becoming ?short, high, and narrow?.

Molecular dynamics simulation on the displacement behaviour of crude oil by CO2/CH4 mixtures on a silica surface.

Produced gas re-injection is an effective and eco-friendly approach for enhancing oil recovery from shale oil reservoirs. However, the interactions between different gas phase components, and the oil phase and rocks are still unclear during the re-injection process. This study aims to investigate the potential of produced gas re-injection, particularly focusing on the effects of methane (CH4) content in the produced gas on shale oil displacement. Molecular dynamics simulations were employed to analyze the interactions between gas, oil, and matrix phases with different CH4 proportions (0%, 25%, 50%, and 100%), alkanes and under various burial depth. Results show that a 25% CH4 content in the produced gas achieves almost the same displacement effect as pure carbon dioxide (CO2) injection. However, when the CH4 content increases to 50% and 100%, the interaction between gas and quartz becomes insufficient to effectively isolate oil from quartz, causing only expansion and slight dispersion. Interestingly, the presence of CH4 has a synergistic effect on CO2, facilitating the diffusion of CO2 into the oil film. During the gas stripping process, CO2 is the main factor separating oil from quartz, while CH4 mainly contributes to oil expansion. In addition, for crude oil containing a large amount of light alkanes, extracting light components through mixed gas may be more effective than pure CO2. This study offers valuable insights for applications of produced gas re-injection to promote shale oil recovery.

Diagenetic alterations induced by lamina-scale mass transfer and the impacts on shale oil reservoir formation in carbonate-rich shale of the Permian Lucaogou Formation, Jimusar Sag

Diagenesis plays a crucial role in shale oil reservoir formation. However, complex organic-inorganic interactions result in pore system formation and heterogeneity changes at the centimeter, or even micrometer scale, which controls the evolution of shale oil reservoirs. In this paper, an integrated approach including core observation, thin section observation, cathodoluminescence thin section observation, scanning electron microscope, μ-XRF analysis, electron microprobe analysis, AMICS analysis, LA-ICP-MS analysis, and isotope analysis was used to clarify the laminae combination carbonate-rich shale, diagenetic alterations in different types of shale laminae and the controls on shale oil reservoir formation. According to the lamina combination, the carbonate-rich shale in the Permian Lucaogou Formation can be divided into three types. They are shale consists of dolomitic lamina and terrigenous felsic lamina (Type A shale), shale consists of calcite-rich tufaceous lamina and terrigenous felsic lamina (Type B shale) and shale consists of calcareous lamina and tufaceous lamina (Type C shale). Dolomite cementation is the major diagenesis in terrigenous felsic lamina of Type A shale. The dolomite can be identified as the early stage forming from recrystallization of micrite dolomite, and the late stage precipitate from adjacent dolomitic lamina. In the terrigenous felsic lamina of Type B shale, however, the calcite cementation is the dominated diagenesis, which was sourced from adjacent calcite-rich tufaceous lamina. Also, some feldspar dissolutions occurred in terrigenous felsic lamina during organic matter evolution. For the Type C shale, the main diagenetic alteration is micrite calcite recrystallization in calcareous lamina. The dissolution and precipitation of carbonate minerals between different laminae of carbonate-rich shale reveal that the organic matter evolution significantly influence the diagenetic alterations of inorganic minerals. Particularly, the diagenetic mass transfer and redistribution at the micro-scale in a relatively diagenetic system were confirmed by organic-inorganic interactions in laminated shale. In this process, dissolution pores and recrystallization pores have provided considerable reservoir pores for shale oil.