Unconventional Oil Resources Research Articles

Research Progress and Prospects of Oil Saturation Evaluation Methods in Shale Oil Reservoirs

The core of the exploration and development of unconventional oil and gas resources, such as shale oil, lies in the effective identification and scale utilization of the sweet spot. Oil saturation is an important parameter in evaluating the sweet spot. Aiming to solve the many current problems of oil saturation logging evaluations of shale oil reservoirs, this study outlines the research progress of oil saturation logging evaluations of shale oil from the three aspects, namely, the electrical method, non-electrical method, and machine learning, through researching the literature and practical applications. At the same time, several typical saturation models are applied to shale oil reservoirs in the Qingshankou Formation of the Gulong Depression, and applicability analyses are conducted. Lastly, the advantages and disadvantages of each oil saturation calculation model are summarized, and suggestions are given for conducting research using each type of method. This study has certain significance in the selection of oil saturation logging evaluation methods for shale oil reservoirs and provides directions for improvement.

Use of In-Situ ESR Measurements for Mechanistic Studies of Free Radical Non-Catalytic Thermal Reactions of Various Unconventional Oil Resources and Biomass

The exhaustion of conventional light oils necessitates the shift towards unconventional sources such as biomass, heavy oil, oil shale, and coal. Non-catalytic thermal cracking by a free radical mechanism is at the heart of the upgrading, prior to refining into valuable products. However, thermal pyrolysis is hindered by the formation of asphaltenes, precursors to coke, limiting cracking, causing equipment fouling, and reducing product stability. Free radicals are inherently present in heavy fractions and are generated during thermal processes. This makes these reactive intermediates central to understanding these mechanisms and limiting coking. Electron spin resonance (ESR) spectroscopy facilitates such mechanistic studies. Over the past decade, there has been no review of using in-situ ESR for studying thermal processes. This work begins with a brief description of free radicals’ chain reactions during thermal reactions and the wealth of information ESR provides. We then critically review the literature that uses ESR for mechanistic studies in thermal pyrolysis of biomass, heavy oil, shales, and coal. We conclude that limited literature exist, and more investigations are necessary. The key findings from existing literature are summarized to know the current state of knowledge. We also explicitly highlight the research gaps.

Study on plugging mechanism and acidizing plugging removal technology of shale reservoir

Abstract Ordos Basin is rich in unconventional oil and gas resources. Shale resources are developed in source rock series. With the continuous development, many oil wells have different degrees of blockage in the production process. It has different levels of complex performance in wellhead, wellbore and formation, which seriously restricts reservoir production. The formation fluid, reservoir rock samples and plugging materials were analyzed from multiple angles by means of nuclear magnetic electron microscopy, X-ray and acid dissolution to determine the source and formation mechanism of plugging materials. The analysis results show that the main component of the formation mineral is quartz, and the formation crude oil is mainly alkane. The scale sample is a mixture of formation minerals, scaling and corrosion products, and the content varies greatly. It is considered that the particle migration in the reservoir is an important cause of inorganic damage, and the organic matter damage cooperates with the inorganic damage to make the damage more serious. On this basis, this paper puts forward the organic cleaning of wellhead and wellbore, and then inorganic plugging removal of formation plugging, and constructs the deep acidification system of 12 % HCL + 10 % HBF4 and 10 % GT-α. The experiment shows that the effective production ratio can reach 3.6, and the effect of acidizing and plugging removal is remarkable. This study has formed an effective plugging treatment technology for shale reservoir, which can provide technical support for similar reservoir acidification.

Key Technologies for Volume Fracturing of Yingxiongling Shale Oil in the Qaidam Basi

Abstract The Yingxiongling shale oil in the Qaidam Basin is the preferred choice for Qinghai Oilfield to enter the field of unconventional oil and gas resources, and volume fracturing is the core technology for shale oil exploration and development. Through the analysis of the geological and engineering characteristics of the Yingxiongling shale oil, it is found that there are difficulties in volume fracturing of the Yingxiongling shale oil, such as frequent changes in vertical mechanical properties and limited vertical control range; large stress differences, making it difficult to form complex artificial fractures; difficulty in opening multiple clusters of perforation holes; high water shortage in the plateau, high mineralization of the formation backflow fluid, and difficulty in reusing the backflow fluid. By iteratively modeling three-dimensional geomechanics, a high-resolution three-dimensional geomechanical model is established to guide the optimization of volume fracturing schemes. Through the integration of geological and engineering selection and clustering, three-stage active control technology for cracks, and the dual temporary plugging process of boreholes and cracks, the targeted and complex degree of artificial crack transformation can be improved. Through the study of high salinity fracturing fluid system, it has been found that high salinity backflow fluid can replace slick water and alleviate the demand for fresh water in volume fracturing. The article analyzes the difficulties of shale oil volume fracturing and studies the formation of an effective set of key techniques for volume fracturing, achieving the goal of improving the degree and effectiveness of transformation, and providing support for the exploration and development of the Yingxiongling shale oil in the Qaidam Basin.

Current Status and Trends in Shale Oil and Gas Drilling Engineering Technology Development at Home and Abroad

Abstract Shale oil and gas is an important component of unconventional oil and gas, and the United States has achieved energy independence through the shale revolution. China has abundant unconventional oil and gas resources, and the vigorous development of shale oil and gas is a necessary path for the development of China’s oil and gas industry. By systematically analyzing the developmental characteristics of shale oil and gas major countries, represented by North America, this study compares domestic and foreign shale oil and gas drilling engineering technologies from the perspectives of development process, well construction cycle, drilling parameters, and other aspects. It clarifies the advantages and challenges of Chinese shale oil and gas drilling engineering technology and provides targeted recommendations. The drilling mode for shale oil and gas in China has progressed from single horizontal wells to large-scale platform factory operations, significantly reducing costs and increasing efficiency. However, due to the complex geological conditions of shale formations and poor surface environment, China’s shale oil and gas wells have a horizontal section length about 1000 meters shorter than those in North America, and the well construction cycle is 2-3 times longer. There are still certain gaps in drilling efficiency and operating costs compared to foreign countries. By systematically analyzing the development process and parameter characteristics of shale oil and gas drilling engineering technology at home and abroad, this study clarifies the current status of drilling engineering technology, providing references for the integration and promotion of mature technologies, demonstration of key core technology breakthroughs, and exploration of cutting-edge technology research and development.

Application of Simul-frac technology in Longdong shale oil field

Abstract This paper for the transformation of unconventional reservoir large-scale volume fracturing of long operation cycle, equipment occupancy, through the well optimization, fracturing design optimization, supporting equipment, construction organization mode upgrade, in the changqing oilfield longdong shale oil HX platform realized a single set of fracturing vehicle for two well synchronous shunt fracturing, created a single unit 17 hours fracturing 10 shale oil reservoir transformation new record. Compared with the production mode of two sets of fracturing units on the same platform, the efficiency of synchronous shunt fracturing operation of single unit increased by 32.1% and the number of equipment used decreased by 17.3%, which initially reflected the advantages of synchronous shunt fracturing technology in improving quality and efficiency. Through the output tracking analysis of the horizontal Wells of synchronous shunt fracturing transformation for half a year, the four Wells showed good transformation effect. Synchronous shunt fracturing technology in changqing oilfield shale oil platform successful application for the future unconventional oil and gas resources cluster well fracturing transformation speed to provide new ideas, the technology can improve the efficiency of oil service enterprises, reduce the completion cycle and comprehensive operation cost, for oilfield company, can quickly build production effect.

Discussion on the Automatic Design Method of Well Trajectory for Cluster Well Platform

Abstract Shale oil and gas and other unconventional oil and gas resources adopt the development mode of cluster well group to achieve economic benefit development. Cluster well groups have the characteristics of small spacing between wellheads and limited space, and generally adjust trajectory parameters by designing individual artificial Wells one by one to meet the needs of geological target hitting and anti-collision and circumnavigation. Trajectory design affects the whole body, and the change of trajectory of one well causes all Wells on the same platform to readjust design parameters, which seriously affects the design efficiency. Therefore, on the basis of summarizing the experience of manual trajectory design, combining classical path planning algorithm and global planning algorithm, an automatic trajectory design model is established. A* path optimization algorithm and ant colony algorithm are used to construct the routing strategy method and rule set, and adapt the efficient manual guidance strategy for different risk classifications to achieve efficient automatic routing. A cluster well trajectory automatic design and routing module has been developed. Automatic trajectory design tested 15 platforms, with an average time of 60s. The efficiency of trajectory design was greatly improved, and it has important guiding significance for the development of automated drilling technology.

Differential hydrocarbon generation characteristics of organic matter with green algae and cyanobateria origins in the Permain Lucaogou Formation of the Santanghu Basin

Organic-rich fine-grained rocks are key carriers of unconventional oil and gas resources, making it crucial to understand their hydrocarbon generation and evolution characteristics. This study examines the fine-grained rocks of the second member of the Lucaogou Formation (P2l2) in the Tiaohu and Malang Sags of the Santanghu Basin, focusing on how different organic matter (OM) backgrounds - primarily green algae and cyanobacteria - affect hydrocarbon generation and crude oil properties. Kinetic analysis and hydrous pyrolysis experiments on shales rich in green algae, cyanobacteria, and their mixtures revealed that green algae - derived OM requires lower activation energy to initiate hydrocarbon generation, results in an earlier oil generation peak, and has a broader oil window. Conversely, cyanobacteria - derived OM needs higher activation energy to start hydrocarbon generation, has a later oil peak, and a more concentrated generation period. These findings led to two models: the "green algae origin - early hydrocarbon generation - early oil peak - broad oil window model" and the "cyanobacteria origin - late hydrocarbon generation - late oil peak - concentrated oil generation model." Correlation analysis showed that aromatic hydrocarbons, resins, and asphaltenes significantly degrade crude oil quality. Hydrous pyrolysis experiments indicated that the heavy component content (aromatic hydrocarbons + resins + asphaltenes) in liquid hydrocarbons follows the order: residual oil > absorbed oil > expelled oil, with content initially increasing and then decreasing with maturity, and the color change of liquid hydrocarbons in dichloromethane reflects heavy component content changes effectively. Calculations of density and viscosity of liquid hydrocarbons, based on heavy component content and crude oil properties, were compared with the longitudinal distribution of crude oil properties in the study area. Results show that the hydrocarbon generation characteristics of green algae and cyanobacteria control crude oil properties, highlighting significant intra-source differentiation in the P2l2 shale and validates the phase separation approach in hydrous pyrolysis experiments. The P2l2 shale, with its high OM content and substantial hydrocarbon generation, holds great potential for shale oil exploration, but both reservoir quality and crude oil property evolution under different OM backgrounds should be considered when selecting favorable areas.

Numerical simulation study of fracture propagation by internal plugging hydraulic fracturing

Internal temporary plugging fracturing technology improves the stimulated volume by forming a more complex fracture network, significantly enhancing the reservoir stimulation effect and effectively developing unconventional oil and gas resources. However, the current understanding of the fracture propagation mechanism on internal temporary plugging fracturing is still unclear, making it difficult to determine the main controlling factors that affect the shape of the fractures. In addition, the lack of practical numerical simulation methods for temporary plugging fracturing makes it challenging to provide guidance for field scheme design. Utilizing the finite element cohesive zone method, which incorporates globally embedded cohesive elements, this study constructs a comprehensive numerical model to investigate the propagation behavior of temporarily plugging fracturing fractures. The model delves into the impact of various geological and construction parameters on the opening conditions of branch fractures during the temporary plugging fracturing process, as well as the propagation patterns of fractures within naturally fractured reservoirs. The research findings indicate that the construction factors have the following impacts: When the pumping rate and viscosity of the fracturing fluid are comparatively high, the resulting fluid pressure within the fracture escalates, resulting in the creation of numerous branch fractures within the naturally fractured reservoir. This, in turn, augments the fracture’s complexity. However, these two factors have little influence on the maximum deflection distance of the deflected fracture. As for the geological factors, an increase in the horizontal stress difference will decrease the maximum deflection distance of the deflected fracture, reducing the number of natural fractures intersected and shortening the length of the deflected fracture. Conversely, an increase in the approach angle will increase the maximum deflection distance of the deflected fracture, thereby expanding the affected area. Additionally, the influence of Young’s modulus and Poisson’s ratio on fracture propagation is very slight. A decrease in the tensile strength of natural fractures leads to more natural fractures being intersected during the process, resulting in increasing the length of the fracture and an improvement in the complexity of the fracture grid.

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.

Numerical Simulation Analysis of Interlayer Interference in Coal Measure "Three-gas Combined Production" Well

China has abundant reserves of coalbed methane, shale gas and tight gas, which are widely distributed and constitute an important part of China's unconventional oil and gas resources. If only a single gas is developed, it will be difficult to exploit, with low output and economic benefits. Therefore, the technology of "three-gas combined production" of coal measures is of great significance to increase the degree of reserve utilization, reduce the development layer size, and increase the gas production and mining life of a single well. In this paper, CMG numerical simulation software is used to numerically simulate and analyze the interlayer interference of coal measure "three-gas combined production" well, and the factors such as daily gas production and cumulative gas production, pressure field and gas saturation distribution of single-layer and three-gas combined production are respectively compared and analyzed, which provides reference for the knowledge of productivity law of "three-gas" combined production and the analysis of interlayer interference factors.

Interfacial Cooperative Assembly of Surfactants and Opposite Wettability Nanoparticles Stabilizes Water-in-Oil Emulsions at High Temperature.

Pickering emulsions have promising applications in the development of unconventional oil and gas resources. However, the high-temperature environment of the reservoir is not conducive to the stabilization of Pickering emulsions. In addition, the preparation of Pickering emulsions under low-energy emulsification and low-concentration emulsifier conditions is a difficult challenge. Here, we report a high-temperature resistant water-in-paraffin oil Pickering emulsion, which is synergistically stabilized by polyglycerol ester (PGE) and nanoparticles with opposite wettability (lipophilic silica and hydrophilic alumina). This emulsion can be prepared under mild stirring (500 rpm) conditions and can be stable at 140 °C for at least 30 days. The synergistic effects of surfactant, silicon nanoparticles (MSNPs) with different wettability, and alumina nanoparticles (AONPs) on the stability of both emulsions and water-oil interfacial membranes were investigated through bottle experiments, cryogenic scanning electron microscopy (cryo-SEM), optical microscopy, fluorescence microscopy, etc. The results showed that both hydrophobic MSNPs and hydrophilic AONPs are adsorbed together at the water-oil interface to stabilize the W/O emulsion, which can be prepared by 500 rpm stirring. The stability of emulsions strongly depends on the wettability of MSNPs, and the MSNP with moderate hydrophobicity (for example, aqueous phase contact angle of 136°) makes the emulsion exhibit the highest stability against aggregation and settling at elevated temperatures. The emulsion stabilization mechanism was revealed in terms of the adsorption capacity of the surfactant by MSNPs, the adsorption morphology and desorption energy of nanoparticles at the water-oil interface adsorption layer, and emulsion rheology. These findings demonstrate a novel and simple strategy to prepare Pickering W/O emulsions with high-temperature stability at low shear strength.

Barremian–Albian unconventional shale oil and wet gas resource systems in northeastern Tunisia

Barremian–Albian unconventional shale oil and wet gas resource systems in northeastern Tunisia

Quantification of seepage characteristics in shale oil reservoirs: A triple medium model-driven approach

Shale oil is an important unconventional oil and gas resource depicting a complex microstructure with various pore types and fluid distribution. In particular, the fluid flow mechanism and the associated percolation characterization theory have recently gained notable interest. Here we establish a mathematical model to describe non-wetting and wetting phase imbibition in shale oil formation. The model is based on the triple continuum medium theory taking into account the wetting characteristics of the shale/oil/brine system, the percolation processes in inorganic and organic pores, and the dynamic process of adsorption and absorption of crude oil in kerogen. The experimental results of oil and water imbibition were fitted thereby obtaining seepage physical parameters and validating the realiability of the proposed model. The impact of physical properties (e.g. inorganic and organic permeability, equivalent cross-flow coefficient, and diffusion coefficient) on the dynamic characteristics of the imbibition process was also evaluated. The results show that the inorganic permeability is between 10−7–10−4μm2 and the organic permeability is between 10−10–10−6μm2. The imbibition rate demonstrates a positive correlation with inorganic and organic permeability, equivalent cross-flow coefficient, and diffusion coefficient. The larger the difference between inorganic and organic permeability, the more pronounced the “bi-horizontal segment” feature of the shale oil imbibition saturation curve. The proposed model effectively calculates the reserves in both organic and inorganic pores, thereby addressing the time-consuming challenges associated with experimentally obtaining seepage parameters. This study thus provides a theoretical basis for precisely evaluating fluid flow in shale oil reservoirs.

Molecular Insight into CO2 Improving Oil Mobility in Shale Inorganic Nanopores Containing Water Films.

CO2 injection into shale reservoirs has been recognized as one of the most promising techniques for enhanced oil recovery and carbon capture, utilization, and storage. However, the omnipresent nanopores and the water films formed near the pore walls affect the understanding of mechanisms of CO2 regulating crude oil mobility in shale nanopores. In this work, we employ molecular dynamics simulations to study the occurrence and flow of CO2 and octane (nC8) mixtures in quartz nanopores containing water films, to illustrate the impact mechanisms of CO2 on nC8 mobility. The results indicate that nC8 exists between water films, and CO2 is mainly miscible with nC8 in the pore center, and a small portion of it accumulates at the interface between nC8 and the water film. CO2 significantly decreases the apparent viscosity of nC8 in both the bulk nC8 region and the nC8-water interface region, improving nC8 fluidity. As the percentage of CO2 in the CO2 and nC8 mixtures increases from 0 to 50%, the mean flow velocities of nC8 in the bulk phase region and the nC8-water interface region increase by 92.85 and 60.64%, respectively. Three major microscopic mechanisms of CO2 improving nC8 fluidity in quartz nanopores with water films are summarized: (i) CO2 reduces friction between nC8 and the water film by increasing the angle between nC8 molecules and the plane of the water film; (ii) CO2 widens the distance between nC8 molecules, causing the volume expansion of nC8 and its viscosity reduction; (iii) CO2 significantly increases the most probable and average velocities of nC8 molecules, thus improving their mobility. Our results enhance the comprehension of how CO2 facilitates oil flow in water-bearing shale reservoirs and the exploitation of unconventional oil resources.

Dynamic Evolution Law of Production Stress Field in Fractured Tight Sandstone Horizontal Wells Considering Stress Sensitivity of Multiple Media

Inter-well frac-hit has become an important challenge in the development of unconventional oil and gas resources such as fractured tight sandstone. Due to the presence of hydraulic fracturing fractures, secondary induced fractures, natural fractures, and other seepage media in real formations, the acquisition of stress fields requires the coupling effect of seepage and stress. In this process, there is also stress sensitivity, which leads to unclear dynamic evolution laws of stress fields and increases the difficulty of the staged multi-cluster fracturing of horizontal wells. The use of a multi-stage stress-sensitive horizontal well production stress field prediction model is an effective means of analyzing the influence of natural fracture parameters, main fracture parameters, and multi-stage stress sensitivity coefficients on the stress field. This article considers multi-stage stress sensitivity and, based on fractured sandstone reservoir parameters, establishes a numerical model for the dynamic evolution of the production stress field in horizontal wells with matrix self-supporting fracture-supported fracture–seepage–stress coupling. The influence of various factors on the production stress field is analyzed. The results show that under constant pressure production, for low-permeability reservoirs, multi-stage stress sensitivity has a relatively low impact on reservoir stress, and the amplitude of principal stress change in the entire fracture length direction is only within the range of 0.27%, with no significant change in stress distribution; The parameters of the main fracture have a significant impact on the stress field, with a variation amplitude of within 2.85%. The ability of stress to diffuse from the fracture tip to the surrounding areas is stronger, and the stress concentration area spreads from an elliptical distribution to a semi-circular distribution. The random natural fracture parameters have a significant impact on pore pressure. As the density and angle of the fractures increase, the pore pressure changes within the range of 3.32%, and the diffusion area of pore pressure significantly increases, making it easy to communicate with the reservoir on both sides of the fractures.

Analysis of Critical Instability Conditions for Solid-Phase Plugging of Natural Fractures during Temporary Plugging and Fracturing.

Hydraulic fracturing has become a key technology for the development of unconventional oil and gas resources, such as deep shale. Due to the development of natural fractures in deep shale reservoirs, the opening of natural fractures during the fracturing process can cause a significant loss of fracturing fluid, resulting in a reduction in the width of the main fracture and construction risks, such as sand plugging. It is important to improve the fracturing effect of deep shale reservoirs by plugging natural fractures with solid phases, reducing filtration, and improving the efficiency of the fracturing fluid. Ensuring the effectiveness of solid plugging is key to optimizing the fracturing design and improving the stimulation effect after fracturing. In this study, solid plugging technology is introduced into the filtration control process of natural fractures. By setting a plugging zone with a certain length and permeability inside the natural fracture, a stability prediction model for the plugging zone of natural fractures is established, and the instability conditions of the plugging zone are analyzed. The simulation results indicate that the instability of the plugging zone is related to permeability and there is a critical permeability. When the permeability of the plugging zone is greater than this value, expansion instability will occur, and when it is less than or equal to this value, shear slip instability may occur. The strength of shear slip instability is mainly determined by the length of the plugging zone, the friction angle of the natural fracture surface, the friction angle between the plugging particles, and the porosity of the plugging zone. The friction angle of natural fracture surfaces affects only the strength of slip instability, while the friction angle of plugging particles and porosity mainly affect the strength of shear instability. The research results provide a theoretical basis for the optimization of fracturing construction parameters in deep shale reservoirs.

Geological Modeling of Shale Oil in Member 7 of the Yanchang Formation, Heshui South Area, Ordos Basin

In recent years, the Chang 7 member of the Mesozoic Triassic Yanchang Formation in the Ordos Basin has emerged as a significant repository of abundant and distinctive unconventional oil resources. The Heshui area boasts substantial shale oil reserves, with reported third-level reserves surpassing 600 million tons. However, the region in the southern part of Heshui is marked by pronounced variability in reservoir quality, intricate oil–water dynamics, low formation energy, and suboptimal fluid properties, leading to divergent development outcomes for horizontal wells. There is an imperative need to devise and refine new geological models to underpin the efficient exploitation of shale oil in the southern Heshui area. This study focuses on the shale oil reservoir of the Chang 7 member in the southern Heshui area of the Ordos Basin, conducting detailed stratigraphic correlation and establishing a refined isochronous stratigraphic framework. Utilizing PetrelTM modeling software (version 2018), we integrate deterministic and stochastic modeling approaches, adhering to the principles of isochronous and phased modeling. By assessing the thickness of sand and mudstone layers and the overall stratigraphic sequence, we derive a geological probability surface. Subsequently, this surface is harnessed to constrain the lithofacies, yielding a constrained lithofacies model. Employing sequential indicator simulation and sequential Gaussian stochastic simulation, we develop a reservoir attribute model that is anchored in the lithofacies model and its controls, culminating in a robust and dependable static model. Employing the geological probability surface constraint method, we meticulously construct the reservoir matrix model, amalgamating individual well data with the inherent certainty and randomness of reservoir plane thickness. This approach further enhances the model’s accuracy and mitigates the uncertainty and randomness associated with inter-well interpolation to a significant degree.

Lithofacies assemblage and effects on diagenesis in lacustrine tight sandstone reservoirs: Samples from Upper Triassic Yanchang Formation, Ordos Basin, China

Lacustrine basins are rich in unconventional oil and gas resources and the heterogeneity of matrix reservoir quality seriously affects its development. Previous studies have recognized that diagenesis is the key factor affecting the heterogeneity of matrix reservoir quality, but diagenesis controlled by lithofacies assemblages is poorly studied. In this study, tight sandstones in the Triassic (Ladinian-Carnian) Chang 7 Member of Ordos Basin were taken as examples. Lithofacies, lithofacies assemblages, diagenesis evolution and distribution were investigated by casting thin section analysis, scanning electron microscopy (SEM), X-ray diffraction (XRD), fluid inclusion and carbon-oxygen isotope. The results indicate that eight lithofacies assemblages in Chang 7 exhibit variations in lithofacies, sand-mud ratio and grain size rhythm, controlling the distribution and intensity of diagenesis. Variations in average proportion of lithofacies assemblages are linked to lake level cycles. Compared to cementation, the mechanical compaction has a higher adverse effect on primary porosity of tight sandstones in Chang 7. Siltstone lithofacies show stronger compaction and cementation (mainly clay cementation), whereas fine sandstone lithofacies exhibit stronger dissolution, especially FSpc (fine sandstone with parallel or cross-bedding). Modest proportions of illite (<4%) and chlorite (<1.5%) in fine sandstones tend to form clay coatings, resisting compaction and preserving more porosity. Conversely, abundant pore-filling illite (>4%) and chlorite (>1.5%) result in a noticeable decline in porosity. Particle size and sorting affect reservoir quality by controlling compaction strength. The origin of carbonate cement in sandstones is closely related to mud-rich lithofacies within lithofacies assemblages. Carbonate cementation preferentially occurs in fine sandstones within 0.4 m from the sand-mud interface and the thickness of adjacent mud-rich lithofacies is greater than 0.1 m. Interfaces between fine sandstones serve as fluid migration pathways and bidirectional erosion, facilitated by high porosity and feldspar content. In contrast, the clay-rich matrix in siltstones acts as a barrier hindering fluid migration, creating unidirectional erosion in fine sandstones near the interfaces between siltstones and fine sandstones. Ultimately, five evolution processes linking diagenesis with lithofacies assemblages are summarized, highlighting the differential reservoir quality. This study contributes to understanding the mechanism behind diagenetic variations in tight sandstones and the reservoir evaluation. Consequently, it offers geological reference for the development of unconventional oil and gas resources in comparable lacustrine basins.

Hot Compressed Water for Conversion and Upgrading of Unconventional Oil Resources: State of the Art, Perspectives, and Future Directions

Hot Compressed Water for Conversion and Upgrading of Unconventional Oil Resources: State of the Art, Perspectives, and Future Directions