Oil Shale Research Articles

Total organic carbon content estimation for mixed shale using Xgboost method and implication for shale oil exploration

In this study, the Xgboost method is employed for TOC estimation in mixed carbonate and siliciclastic shale from the Hashan area, Junggar Basin. The results show that this approach is effective for TOC estimation in this area although the model performance is not very excellent with a correlation coefficient of 0.54 between measured TOC and predicted TOC values, likely due to a small samples dataset. Therefore, the PCA method is applied to debase dimension of well log data from five dimensional to two-dimensional data, which enhances the correlation coefficient between the predicted and measured TOC from 0.54 to 0.68. Based on the model, the isopleth maps of TOC distributions in Fengcheng Formation were redrawn showing two shale oil exploration targets, which likely correspond to two depositional centers of this strata. All the same, the model in this work provides reliable data for shale oil evaluation in the study area and a good example under similar geological setting.

Enhancing soybean cultivation sustainability: impact of limestone mining co-products on soil and plant chemical attributes

The increasing demand for sustainable agricultural practices necessitates innovative solutions for soil fertilization. This study aimed to assess the viability of using limestone mining co-products from the Irati and Corumbataí Formations as multi-nutrient sources for Glycine max cultivation. The experiment utilized a double factorial design (7 × 2) with five replications, randomly arranged and placed in pots within a greenhouse. The factors examined were the type of co-product (sedimentary rocks from the Irati Formation: rhythmite and bituminous shale; and the Corumbataí Formation: clayey siltstone) and the soil type (Haplic Arenosol and Rhodic Ferralsol). Soil ion content was assessed at 21 and 140 days after treatment application. Each pot housed four G. max plants, with leaf harvest occurring after 42 days of growth. Macronutrient content, leaf production, and soil ion availability were determined thereafter. Overall, co-product application led to increased soil pH and availability of essential ions, including K+, Mg2+, Ca2+, P, S-SO42−, and Si. At 140 days, rhythmite was notably effective in increasing pH, Ca2+, and Mg2+ in Haplic Arenosol, with respective increases of 22%, 224%, and 696%. Bituminous shale, on the other hand, significantly increased S-SO42− content by 67% and 426% in Rhodic Ferralsol and Haplic Arenosol, respectively. Moreover, the application of co-products resulted in enhanced accumulation of K, Ca, Mg, and S in G. max plants, alongside increased leaf production. In conclusion, the utilization of mining co-products positively influenced soil and plant chemical attributes, particularly enhancing leaf production in G. max. These findings highlight the potential of co-products as environmentally friendly solutions for soil fertilization, supporting sustainable agricultural practices. This research highlights a significant step towards sustainable agriculture by recycling mining waste into valuable soil amendments, which can improve crop yields and reduce the environmental impact of both mining and agricultural activities.Graphical

Pore structure of the mixed sedimentary reservoir of Permian Fengcheng Formation in the Hashan area, Junggar Basin

The Permian Fengcheng Formation (P1f.) in the Hashan area, situated on the southwestern margin of the Junggar Basin, has witnessed a remarkable breakthrough in shale oil exploration in recent years with nearly 789 million tons of shale oil resources. As a unique set of mixed sedimentary shales, the Fengcheng Formation in the Hashan area is characterized by mixed sedimentation of terrigenous siliciclastic sediments, authigenic minerals, and tuffaceous materials. However, the understanding of pore characteristics in the mixed sedimentary reservoir still remains limited, prohibiting accurate estimation of the oil content and insights into oil mobility. Scanning electron microscopy (SEM), X-ray diffraction (XRD), mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), X-Ray Computer Tomography (X-CT), and geochemical analysis were performed to investigate the pore size distribution and main controlling factors of the mixed sedimentary reservoir. Results showed that the main pore types in the mixed sedimentary reservoir are intergranular pores and dissolution pores. The pores of the P1f. mixed shales in the Hashan area were classified into II-micropores (< 25 nm), I-micropores (25–100 nm), mesopores (100–1000 nm) and macropores (> 1000 nm). In general, the mixed sedimentary rocks of P1f. formation feature few macropores but a large number of micropores and mesopores. The CS exhibits the most favourable physical properties among all lithofacies. It is concluded that the abundance and maturity of organic matter, mineral composition, sedimentary structure, and diagenesis of reservoir together impact the pore structure in the mixed sedimentary reservoirs. The maturity of organic matter and the content of tuffaceous minerals are the most significant in influencing the pore structure of P1f. shales. Overall, the pore structure of complex lithologic reservoir formed by mixed deposition and its influence on physical properties are studied, and the characteristics of the microscopic pore-throat system of the dominant lithofacies in the Hashan area are clarified, which is of great significance as a guide for the exploration and development of mixed sedimentary reservoirs in continental shale oil in China.

Study on organic carbon in medium-low mature shale oil reservoirs rich in type II kerogen: Oxidation behavior, thermal effect, and kinetics

In-situ combustion technology (ISC) was a potential technology for efficient development of medium–low maturity shale oil reservoirs. Clarifying the exothermic behavior of organic carbon oxidation will be beneficial for better control of ISC processes. In this work, the organic carbon composition, type II kerogen and residual oil, were separated and extracted from the shale samples of typical medium–low maturity shale oil reservoirs in the Ordos Basin, China. The synchronous thermal analyzer and mass spectrometry (STA-MS), Fourier transform infrared spectroscopy (FTIR), and ROCK-EVAL VI were used to study the products, heat release, and functional group changes of type II kerogen, residual oil, and shale during the oxidation process. The results indicated that the oxidation heat release of shale mainly came from the oxidation reaction between its residual oil and type II kerogen, but the oxidation heat release range of shale was relatively lagging compared to the single residual oil or type II kerogen affected by rock debris. Secondly, under atmospheric pressure, the type II kerogen experiences obviously higher heat release than residual oil and heavy oil, indicating its superior potential of in-situ heat release. In addition, the major productions that CO, H2O, SO2, and CO2 were quantitatively characterized, with CO2 having the highest production of 882.25 mg/g. Furthermore, combined with the molecular weight, an oxidation reaction equation of type II kerogen was constructed. Finally, the oxidation kinetics parameters of type II kerogen, residual oil, and shale were determined using Friedman and Ozawa-Flynn-Wall (OFW) models. It was found that the activation energy of shale was higher than II kerogen and residual in low temperature oxidation (LTO) and fuel deposition (FD) stages. This may be due to the joint reaction between kerogen and residual oil, thus exacerbating the challenge of shale in-situ ignition. However, due to the catalytic effect of rock debris, the activation energy of shale was lower than LTO in high temperature oxidation (HTO) stage, indicating that once fuel deposition was completed, organic carbon will undergo stable combustion. This study has theoretical guidance for the numerical simulation research of ISC development technology of maturity-low shale oil reservoirs.

IoT-ENHANCED SHALE OIL AND GAS GREEN DEVELOPMENT: STATUS AND FUTURE

Shale oil and gas, deemed as vital alternative resources to conventional oil and gas, have spurred significant interest in information-based exploration and development technologies within the industry in recent years [1]. China boasts extensive shale oil and gas reserves, with the International Energy Agency (EIA) estimating China's shale oil technology capable of extracting approximately 4.393 billion tonnes, ranking third globally. Additionally, China holds shale gas geological resources of about 134.4 trillion cubic meters, ranking first worldwide, showcasing immense development potential. Shale oil and gas, being unconventional resources, are distributed within the pore and fracture systems of organic-rich shale formations. Compared to conventional oil and gas, shale oil and gas exhibit weaker trap control and stronger distribution continuity, typically characterized by poor reservoir physical properties. Conventional extraction methods often struggle to yield industrial oil and gas flow from shale oil and gas resources, necessitating unconventional development technologies such as reservoir monitoring, directional wells, horizontal wells, and segmental fracturing [2]. However, these technologies come with challenges and risks, including complex production operations, high production data density, and environmental concerns such as surface ecological damage and pollutant emissions, further impacting shale oil and gas production. To facilitate the upgrading process of China's shale oil and gas industry, this paper presents the current status of Internet of Things (IoT) application technologies for shale oil and gas development and proposes a research outlook based on the concept of green development. Against the backdrop of energy transformation, it offers a reference framework for the sustainable development of China's extensive shale oil and gas resources.

EXPERIMENTAL STUDY ON THE FRACTURE CONDUCTIVITY IN SHALE OIL PRODUCTION

Unconventional oil and gas resources, such as shale oil and gas, are gradually attracting great attention from all countries of the world. Horizontal drilling and large-scale hydraulic fracturing technology are used to efficiently extract oil from shale formation. Effective placement of the proppant in the fractures and high long-term conductivity are the keys to solve the problems of oil well flow rate increase in shale oil and gas fields. In this work, the sieve analysis method and FCMS-V fracture conductivity determination device, as well as scanning electron microscope are used. They are used to experimentally investigate the filtration characteristics of hydraulic fracturing fractures and establish the key factors affecting the filtration characteristics. The object of the study is the core of the oil-saturated DG shale formation of Songliao Basin. Also in this paper, the indentation and crushing mechanism of proppant under reservoir conditions is studied. The influence of various factors was evaluated qualitatively and quantitatively. The following studies were conducted: the effect of sand granule size on conductivity, the effect of grain size distribution on conductivity, the effect of proppant concentration on conductivity, the effect of fracture closure pressure on conductivity, and the effect of proppant indentation on conductivity. The granule sizes of the proppant used range from 30/50 to 70/140 mesh. Proppant concentration: 2,5; 5; 10 kg/m2. Ratios of granule sizes for used mixtures: 1:1:1, 1:2:7, 1:4:5.And crack clamping pressure from 20 to 40 MPa. As a result of the study, dependences of initial and long-term fracture conductivity on clamping pressure, granulometric composition of proppant and its concentration were obtained. Using a scanning electron microscope, the degree of indentation and crushing of proppant under reservoir conditions in two media, namely shale core and steel plates, was visually evaluated. The results of experimental studies can be used to optimize the shale oil development system and have scientific and practical significance for shale oil production in continental deposits.

Evaluation of Post-fracturing Imbibition Oil Displacement Efficiency in Shale Reservoirs

In order to clarify the imbibition law of shale oil after fracturing with guanidine gum and nano-slickwater, this study quantitatively analyzed the imbibition efficiency of shale core under different time periods of two kinds of fracturing fluids through the imbibition experiment of natural shale core and nuclear magnetic resonance test technology, and preliminarily understood the microscopic crude oil production characteristics of pore throat of shale imbibition. The experimental results show that the imbibition oil removal efficiency of nano-slick water reaches 34.7 %, which is higher than that of guanidine gum fracturing fluid. In the high imbibition efficiency stage of rock samples, within 6 h of the beginning of the experiment, the small pore porosity reaches 20.8 %, the large pore and fracture reach 30 %, and the final imbibition oil displacement rate can reach 31.7% and 39.6 %. The development of micro-fractures and bedding fractures is beneficial to improve the imbibition efficiency. With the extension of time, the imbibition rate gradually decreases, and the utilization degree of pore throat is limited.

The Analysis of Differential Saturation in Shale Oil Accompanied by an Enhanced Classification of Fluid Distribution within the Pore

Shale oil saturated by high temperature (20 MPa) and high pressure (60 °C) conditions can not only realize the efficient saturation of shale, but also invert the shale oil return and drainage characteristics under the stratum temperature and pressure due to the heterogeneity of shale formations. In this study, the Chang 7 Member shale samples were collected, and the high-temperature and high-pressure containment device was utilized to saturate the shale oil efficiently under 20 MPa and 60 °C, and the differences of liquid hydrocarbon saturation and the degree of liquid hydrocarbon saturation for different types of pores and fractures in the shale were quantitatively characterized with a low-field nuclear magnetic resonance (NMR) technology. The results show that under the condition of formation temperature (60 °C) and pressure (20 MPa), shale oil saturation can be reached after 14 d of saturation in the shale samples. The shale oil saturation process can be roughly divided into three stages according to the various saturation rates: the rapid saturation stage, the slow saturation stage, and the second rapid saturation stage, and the degree of saturation of shale oil is characterized by a V-shape. The shale oil was distributed into four types of pore-fracture systems: adsorption pores, micropores, seepage fractures, and layer fractures. Additionally, the fluid dominantly distributes in the micropores and seepage fractures, the shale oil saturation degree of the micropores features a continuous increase, while that for the seepage fractures presents a V-shape, which finally determines the shale oil saturation characteristics of the shale.

Biogenic “phosphorus” effect of terrestrial lakes and its significance to oil shale during the Carnian period in the late Triassic

The Triassic lacustrine organic-rich shale (LORS) in Member 7 of the Yanchang Formation (Carnian stage) in the southern Ordos Basin is relatively well developed. Additionally, its organic matter abundance, lake biomass and biodiversity, exceed the maximum values of the other strata deposited during the same period. Apatite is one of the most important minerals and is closely related to biological activities. However, the types and genesis of the continental sedimentary apatite and its significance to shale oil are not clear. Here, the stratigraphy, petrology, and sedimentology of the phosphorus-bearing rock series in the Ma Quan section are studied and its sedimentary environment and phosphorus formation are discussed. The current research shows that apatite in the study area can be divided into three categories: collophanite, bone fossils, and spherical microfossils. These three types of biogenic “phosphorus” products provide effective records of the transformation of the biological substances into sedimentary organic matter. There are two main formation mechanisms: the direct action of organisms and the interaction between the organisms. Bone fossils and spherical microfossils are formed by the direct action of organisms, while collophanite is formed by the indirect action of organisms. The phosphatization methods of the organisms mainly include “coating”, “replacement”, and “filling”, and the presence of a ubiquitous phosphate filler potentially reflects a sufficient phosphate supply. Apatite also is highly important for the development of organic matter in oil shale. First, it changes the productivity conditions. Second, the apatite in the shell of spherical microfossils has a certain protective effect on the organic matter in the inner cavity. In the current study, the geological processes of collophanite deposition and mineralization are explained, an important basis for prospecting phosphate resources is provided, and a new field for the study of the organic matter enrichment mechanism of source rocks is established. At the same time, the process of lake biogenic phosphorus formation provides evidence from the continental deposits in the eastern margin of the Tethys region for exploring deep global changes.

Simulation of in-situ steam-driven oil seepage in single-fracture oil shale CT digital cores after pyrolysis at different temperatures

Based on digital cores of oil shale obtained from high-temperature steam in-situ pyrolysis and micro-CT scanning experiments, the real structures of oil shale after pyrolysis at different temperatures were seamlessly integrated into COMSOL through precise grid partitioning. This enabled the simulation of in-situ steam-assisted oil recovery two-phase flow fields. The study examines the dynamic evolution of phase interfaces, pressure fields, velocity fields, and oil displacement efficiency during the in-situ two-phase flow process in pore structures with varying degrees of development. The research indicates that: Firstly, the development and connectivity of pore structures significantly influence the advancement speed of the phase interface — the better the pore structure development, the faster the phase interface advances. Secondly, as seepage progresses, the stability of phase interface advancement improves, with the difference between the peak δa value before stabilization and the stabilized δa value decreasing over time. Thirdly, at the moment of steam injection, a surge in Pa within the seepage zone occurs. The complexity of the pore structure effectively mitigates the surge in Pa caused by the instantaneous gas drive effect. Finally, the total seepage volumetric flow rate Qtotal increases with time. The oil production ratio α at the outlet decreases slightly with time, but remains above 97.6 %, demonstrating the effectiveness of steam-assisted oil recovery.

The mechanical properties of Lucaogou shale layered samples and the influence of minerals on fracture propagation

Shale oil is one of the most promising alternative unconventional energies in the world, and Lucaogou Formation shows significant exploration potential, becoming the primary target in northwestern China. This paper compared the mechanical properties of shale layered samples from oil layer and interlayer of Lucaogou Formation, using uniaxial compressive tests with real-time micro-CT scanning. After that, the mineral analysis was conducted on one cross-section of the fractured sample to analyze the influence of mineral composition and distribution on micro-crack propagation. Such research has rarely been reported before. The results showed the surface porosity and elastic modulus of oil-bearing samples is larger than that of the interlayer samples, while the uniaxial compressive strength is lower. Besides, when there is only one dominant mineral with a content greater than 60%, a main crack tends to form at this area; When there are 2∼3 major minerals with a content of 10%∼60%, a fractured zone with many fine micro-cracks is more likely to form here. Finally, the higher the Moh’s hardness of the mineral, the more difficult it is for micro-cracks to develop through it.

Molecular dynamics study of shale oil adsorption and diffusion behavior in reservoir nanopores: Impact of hydrocarbon composition and surface type

Understanding shale oil adsorption in reservoir nanopores is essential for efficient extraction. This study used MD simulations to analyze the adsorption and diffusion of two- and multi-component hydrocarbons (Aromatics, Alkanes, Resin) on various shale surfaces (Calcite, Montmorillonite, Quartzite, Organic) at 353 K and 25 MPa. Hydrocarbons formed a bilayer adsorption structure comprising a high-concentration adsorption layer (L1, 0.35–0.90 g/cm3) and a low concentration weak adsorption layer (L2), with adsorption density ranked as Resin > Aromatics > Alkanes. Reservoir surfaces were classified as ionic (e.g., calcite, montmorillonite) and non-ionic (e.g., quartz, graphite), and polar hydrocarbons exhibited higher adsorption densities and energies on ionic surfaces due to combined electrostatic and van der Waals interactions, while non-ionic surfaces showed smaller adsorption differences. For multicomponent hydrocarbons, adsorption layer densities followed the order: graphite > MMT-SiO > quartz > calcite > MMT-Na, with competitive adsorption observed. The polar component exhibited a greater adsorption advantage on the calcite, MMT-SiO side and graphite surfaces due to electrostatic interactions and π-π interactions, and a lesser advantage on the MMT-Na side and quartz surfaces. Hydrocarbon diffusivity was influenced by molecular mass and polarity and ordered as Alkanes > Aromatics ≫ Resin. Polar molecules had a weaker diffusion than nonpolar molecules at similar molecular masses. Among the multicomponent hydrocarbons, the self-diffusion coefficient (Self-D) of Resin increased, while that of lighter components decreased compared to two-component systems. These findings offer strategies for improving shale oil recovery by tailoring injection fluids to reservoir types, anionic surfactants or chelating agents may be used to reduce electrostatic interactions in carbonate and clay reservoirs, while nonionic surfactants may be more effective in quartz reservoirs.

Study on fluid mobility in shale oil reservoirs considering mineral composition and stress sensitivity

Study on fluid mobility in shale oil reservoirs considering mineral composition and stress sensitivity

Intelligent seismic AVO inversion method for brittleness index of shale oil reservoirs

The brittleness index (BI) is crucial for predicting engineering sweet spots and designing fracturing operations in shale oil reservoir exploration and development. Seismic amplitude variation with offset (AVO) inversion is commonly used to obtain the BI. Traditionally, velocity, density, and other parameters are firstly inverted, and the BI is then calculated, which often leads to accumulated errors. Moreover, due to the limited of well-log data in field work areas, AVO inversion typically faces the challenge of limited information, resulting in not high accuracy of BI derived by existing AVO inversion methods. To address these issues, we first derive an AVO forward approximation equation that directly characterizes the BI in P-wave reflection coefficients. Based on this, an intelligent AVO inversion method, which combines the advantages of traditional and intelligent approaches, for directly obtaining the BI is proposed. A TransU-net model is constructed to establish the strong nonlinear mapping relationship between seismic data and the BI. By incorporating a combined objective function that is constrained by both low-frequency parameters and training samples, the challenge of limited samples is effectively addressed, and the direct inversion of the BI is stably achieved. Tests on model data and applications on field data demonstrate the feasibility, advancement, and practicality of the proposed method.

Sedimentary dynamics and depositional model for mud accumulation in deep lake basins: A case study in the Upper Triassic Chang-7 Member, Ordos Basin, northern China

Shales in deep lake basins have become the main focus of continental shale oil and gas exploration. In order to highlight the sedimentary dynamics of mud deposition in deep lake basins, a combination of core observation, thin section examination, X-ray diffraction, and QEMSCAN (quantitative evaluation of minerals by scanning electron microscopy) was used to analyze the depositional characteristics of mudrocks in the Chang-7 Member from the Yanchang Formation (Upper Triassic) in Ordos Basin, and to establish a depositional model for mud accumulation in deep lake basins. This study recognizes four mudrock lithofacies in the Chang-7 Member: (1) the laminated silt-bearing mudstone, which generally develops a binary composition of “silt–clay” or a ternary composition of “silt–clay–organic matter”; (2) the graded mudstone, mainly composed of dark gray and gray-black mudstone sandwiched by silt-bearing mudstone; (3) the massive mudstone, internally showing a uniform distribution of quartz, clay, and carbonate minerals, with also a small amount of organic detritus; and (4) the laminated shale, which is generally composed of clay laminae, and organic laminae of the former two. Sediment supply, topographic slope, and flood intensity combine to control the evolution of gravity flows and the transport and deposition of the mudrock in the Chang-7 Member. The influence of orogeny provides terrain gradient, water depth, abundant sediments at source areas, and triggering mechanism for the formation of gravity flows. Floods triggered by wetting events provide the impetus for sediment transport. Mud deposition in the Chang-7 Member was mainly related to the transport and sedimentation of mud by hyperpycnal flows and rapid sedimentation by buoyant plume flocculation. A comprehensive evolutionary model for shale accumulation in the deep lake basin is established by integrating various triggering mechanisms and mud transport sedimentary processes.

Study on the relationship between shale organic matter development and paleowater depth—A new understanding of the condensed section

Recent studies dispute the long-standing belief that highly organic-rich shales are predominantly linked to condensed section (CS) at the maximum flooding surface (MFS), proposing instead that they more commonly develop in shallow waters along basin margins. This hypothesis, however, has not been thoroughly investigated. Our study, focusing on the pivotal regions of the Longmaxi Formation and the Chang 7 Member for marine and continental shale exploration in China, integrates sequence stratigraphy with analyses of total organic carbon (TOC) and elemental geochemistry to pinpoint the environments conducive to the formation of organic-rich shales. The most organic-rich intervals, specifically the bottom of the Longmaxi Formation and the mid-to-lower Chang 73 sub-member, are located within the transgressive systems tract (TST), showing higher TOC levels in the middle to lower TST, compared to the CS of the MFS. The formation of high organic matter shale is related to warm, humid, and dysoxic shallow waters with minimal terrigenous influx and high primary productivity. We found a pronounced inverse relationship between organic matter concentration and water depth, with deeper waters promoting the decomposition and recycling of organic matter during sedimentation, thereby diminishing the TOC content. Moreover, volcanic activity also affected the organic enrichment in the Chang 7 Member. With high primary productivity, organic matter tends to accumulate in dysoxic slope zones. Consequently, high-organic content shale intervals are generally situated in shallow, dysoxic water environments, suggesting that the CS of the MFS may actually represent organic-poor intervals with limited source rock potential. The results of this study are of great significance for shale oil and gas exploration in China, and provide a new direction for the discovery of shale oil and gas sweet spots.

New Advance in the Study of Shale Oil Generation Peak Determination and Diagenetic Pore Evolution

Shale formations globally are widely distributed with abundant resources and varied thermal maturation ranges. However, the understanding of shale’s oil generation peak, diagenetic stages, and pore evolution remains incomplete. This study investigates shale samples of varying maturities and organic matter content from representative oil and gas basins in China and the United States. Comprehensive characterization was conducted using thermal simulation, rock X-ray diffraction analysis, N2 and CO2 adsorption, and mercury injection analysis. The study delineates the hydrocarbon generation process in shale, identifies the oil generation threshold, determines the peak oil generation, and categorizes shale’s diagenetic stages based on clay minerals and pore evolution. The results indicate: (1) highly mature shale exhibits delayed hydrocarbon expulsion and peak oil generation, starting at Ro values greater than 0.75% and reaching peak oil generation at Ro levels surpassing 1.2%. In contrast, peak oil generation in less mature shale initiates at Ro values of 1.1%, providing a more precise depiction of the shale’s diagenetic evolution stages; (2) the higher the TOC content of shale, the greater its hydrocarbon generation capacity, showing a robust positive correlation between hydrocarbon generation and TOC; (3) the diagenesis and pore evolution of shale can be categorized into four distinct stages: the early diagenesis stage (Ro &lt; 0.5%), dominated by mesopores, and with reduced pore volume and surface area; the middle diagenesis stage A (0.5%–1.1%), where shale pore volume has been enhanced while the surface area has been reduced; the middle diagenesis stage B (1.1%–2.0%), where an initial decrease followed by an increase in mesopore volume occurs, along with a modest increase in macropores; and the late diagenesis stage (Ro &gt; 2.0%), with increased organic pores and microfractures, while both pore volume and surface area expand. The study suggests that a Ro of 1.1% marks the peak oil generation period for shale, occurring during the early stage of middle diagenesis, characterized by larger pore volume and surface area, crucial for shale oil and gas enrichment.

Sustainable in-situ steam injection approach for shale oil extraction in Xinjiang, China: A technical and economic analysis

This work proposes a microgrid system for in-situ steam heating extraction of oil shale utilizing renewable energy sources. This system is designed for high efficiency and promises significant cost savings. This work couples the underground in-situ steam injection heating model and the microgrid system model to analyze the system's energy-saving and economics. Due to the technical and economic importance of Xinjiang oil shale in Northwest China, it is chosen as a case study to investigate the feasibility of the proposed method. The effect of steam temperature, pressure, and renewable resources at the oil shale extraction location on the economics of the system is examined. The results show that using renewable energy power is superior to hybrid and conventional power supply methods in terms of economy and energy efficiency. Moreover, renewable energy resulted in a 12.38 % reduction in the total net present cost (NPC) when the steam temperature increased by 40 °C. The total NPC of the project can be reduced by 28.61 % when the pressure of superheated steam is decreased by 4.0 MPa. The results indicate that the solar resource at the oil shale extraction location significantly impacts the system's economics. The study provides a theoretical basis for the economic analysis of oil shale steam injection extraction technology.

Study on the hydraulic fracture extension pattern of Gulong Shale Oil Reservoir in Songliao Basin

This study aimed to investigate the fracture extension pattern of the Gulong shale oil reservoir through rock mechanical tests, fracturing physical simulation experiments, and on-site tracer fracture monitoring to enhance fracturing stimulation effectiveness. The results of the rock mechanical tests revealed the anisotropic mechanical properties of the rocks attributed to the lamellation structure. Fracturing physical simulation experiments were conducted to determine the fracture extension pattern in the laboratory, indicating that increasing the fracturing fluid viscosity and injection rate could help overcome the vertical extension limitations caused by the lamellation structure. For the first time, on-site tracer fracture monitoring was implemented to study the hydraulic fracture extension pattern of the Gulong shale oil reservoir. The findings suggested that utilizing stages with three or four perforation clusters, a 50% slick water ratio, and temporary plugging could enhance fracture initiation efficiency and promote uniform extension. After modifying the parameters based on the research results, the on-site fracturing wells exhibited excellent fracturing stimulation effects. This study is significant for understanding the unique fracture extension pattern of the Gulong shale oil reservoir both in laboratory settings and on-site, providing technical recommendations for improving fracturing stimulation in other reservoirs with similar characteristics.

A comparative study of shale oil transport behavior in graphene and kerogen nanopores with various roughness via molecular dynamics simulations

Understanding the transport behavior of molecules within nanopores is crucial in various fields, including nanofluidic, bioengineering and geophysics. To elucidate oil flow within shale organic nanopores, the simplified carbon nanopores (e.g., graphene and CNTs) and realistic kerogen nanopores have been extensively applied. The variation in pore structure models leads to divergent findings in oil flow behavior. This study employs molecular dynamics simulations to compare alkane flows within graphene and kerogen nano-slits with similar surface roughness. We observe that using graphene nanopores with ultra-smooth surfaces may introduce errors of several orders of magnitudes in flux calculations. Conversely, when accounting for similar roughness, the static characteristics and flow behaviors in graphene and kerogen slit pores are largely comparable. The relative error of flux and the flow velocity could be lower than 6% when using graphene to replace the realistic kerogen. Alkane molecules exhibit a parabolic velocity profile, with a no-slip condition adjacent to the rough surfaces. In addition, when applying the Hagen-Poiseullie equation for alkane flow in rough nanopores, Gibbs dividing surface is recommended for defining the pore radius, reducing the error of flux predicted to below 10%. Our work fulfills the gap in accessing the suitability of using graphene as a model for oil transport in shale organic nanopores, and provides valuable insights and guidance for future studies on nanofluidic in shale, including molecular simulations, nanofluidic experiment designs, and multi-scale modeling.