Tight Sandstone Reservoirs Research Articles

High-precision digital rock construction and electrical property upscaling in tight sandstone

The lithology and rock physical properties of tight sandstone reservoirs become increasingly complex, resulting in a more challenging reservoir evaluation process. Conventional rock physics experiments are too restrictive to adequately investigate formation properties. The emerging digital rock physics (DRP) technology in recent years effectively overcomes these constraints. Nevertheless, the current DRP faces two major challenges: the integration of multiple-resolution images and the upscaling of rock physics properties (electricity). In this paper, we propose an innovative method for assigning electrical characteristics to voxel units, enabling the integration of multi-resolution images, as well as a novel approach for establishing a new saturation model to achieve electrical property upscaling. Initially, core samples are selected and drilled based on logging data and lithology analysis, followed by multi-resolution scanning experiments, including X-ray CT, QEMSCAN, and MAPS. After that, mineral components are segmented, and multi-component digital rocks are constructed. Considering mineral voxel as the analytical units, pore characteristics within each mineral, which are extracted from MAPS, are used to generate 3-D pores by QSGS method. These generated 3-D pores are then merged with their respective mineral voxel. Subsequently, the electrical properties of the merged models are simulated and assigned to multi-component digital rock. This process enables the integration of multi-resolution images, leading to the construction of high-precision digital rocks. Additionally, high-precision digital rock-based electrical modeling is conducted, and a new saturation model is then established by combining digital rock physics, experiment rock physics, and theoretical rock physics. Finally, the new saturation model is applied to calculate saturation, accomplishing electrical property upscaling. Application results show the new saturation model improves the accuracy of saturation evaluation, demonstrating the feasibility of the upscaling method for electrical properties.

Experimental Study on the Efficiency of Fracturing Integrated with Flooding by Slickwater in Tight Sandstone Reservoirs

Tight reservoirs, with their nanoscale pore structures and limited permeability, present significant challenges for oil recovery. Composite fracturing fluids that combine both fracturing and oil recovery capabilities show great potential to address these challenges. This study investigates the performance of a slickwater-based fracturing fluid, combined with a high-efficiency biological oil displacement agent (HE-BIO), which offers both production enhancement and environmental compatibility. Key experiments included tests on single-phase flow, core damage assessments, interfacial tension measurements, and oil recovery evaluations. The results showed that (1) the slickwater fracturing fluid effectively penetrates the rock matrix, enhancing oil recovery while minimizing environmental impact; (2) it causes substantially less damage to the reservoir compared to traditional guar gum fracturing fluid, especially in cores with little higher initial permeability; and that (3) oil recovery improves as HE-BIO concentration increases from 0.5% to 2.5%, with 2.0% as the optimal concentration for maximizing recovery rates. These findings provide a foundation for optimizing fracturing oil displacement fluids in tight sandstone reservoirs, highlighting the potential of the integrated fracturing fluid to enhance sustainable oil recovery.

The Saturation Calculation of NMR Logging Based on Constructing Water Spectrum Function

Tight sandstone oil reservoirs are characterized by complex structures, poor pore connectivity, and strong heterogeneity, with features such as low porosity and ultra-low permeability. Conventional methods for calculating saturation cannot accurately evaluate the hydrocarbon saturation of these reservoirs. To address this, a study was conducted from the perspective of non-electrical logging methods, focusing on the inherent nuclear magnetic resonance (NMR) characteristics of different fluids to develop a saturation calculation method that avoids the influence of the rock matrix, thus enabling precise saturation measurement in tight sandstone oil reservoirs. The traditional NMR porosity model was modified by segmenting it using the clay-bound water cutoff value, aiming to identify the distribution pattern of fluids in pores outside the clay-bound water zone. Through theoretical derivation and water spectrum function simulation, a water spectrum function and its parameter range suitable for the NMR T2 distribution in tight sandstone reservoirs were determined. Using core-sealed core saturation as a reference, the particle swarm optimization (PSO) algorithm was applied to optimize the parameter range and construct the final water spectrum function tailored to tight sandstone oil reservoirs. The accuracy and practicality of this method were validated by applying the derived water spectrum function to NMR logging in the exploration block, allowing for precise saturation calculations and the accurate evaluation of tight reservoir saturation.

Dynamic stress response and fatigue characteristics of tight sandstone reservoirs with pulsating hydraulic fracturing

Dynamic stress response and fatigue characteristics of tight sandstone reservoirs with pulsating hydraulic fracturing

Numerical Simulation of the Coal Measure Gas Accumulation Process in Well Z-7 in Qinshui Basin

The process of coal measure gas accumulation is relatively complex, involving multiple physicochemical processes such as migration, adsorption, desorption, and seepage of multiphase fluids (e.g., methane and water) in coal measure strata. This process is constrained by multiple factors, including geological structure, reservoir physical properties, fluid pressure, and temperature. This study used Well Z-7 in the Qinshui Basin as the research object as well as numerical simulations to reveal the processes of methane generation, migration, accumulation, and dissipation in the geological history. The results indicate that the gas content of the reservoir was basically zero in the early stage (before 25 Ma), and the gas content peaks all appeared after the peak of hydrocarbon generation (after 208 Ma). During the peak gas generation stage, the gas content increased sharply in the early stages. In the later stage, because of the pressurization of the hydrocarbon generation, the caprock broke through and was lost, and the gas content decreased in a zigzag manner. The reservoirs in the middle and upper parts of the coal measure were easily charged, which was consistent with the upward trend of diffusion and dissipation and had a certain relationship with the cumulative breakout and seepage dissipation. The gas contents of coal, shale, and tight sandstone reservoirs were positively correlated with the mature hydrocarbon generation of organic matter in coal seams, with the differences between different reservoirs gradually narrowing over time.

High-resolution isochronous stratigraphic framework through well-seismic integration in tight sandstone: a case study of Luodai gas field, Sichuan, China

Tight gas sandstone represents a significant unconventional resource extensively discovered across numerous sedimentary basins around the world. Tight sandstone reservoirs are characterized by low porosity, low permeability, variable source material, rapid spatial and temporal changes, poor reservoir properties, and strong heterogeneity. Traditional geophysical methods struggle to meet the demands of exploration and development of these types of reservoirs. This study applies a high-precision comparative approach using well-seismic integration to establish a relative isochronous stratigraphic framework. Based on this framework, extracting seismic properties can effectively predict tight sandstone reservoirs. This paper, focusing on the Penglaizhen Formation in the Luodai Gas Field of the Western Sichuan Jurassic system. This entire process accomplished in three steps: starting with regional marker layers as the initial framework; followed by the establishment of a relative isochronous framework through precise well-seismic integration; and finally stratigraphic slicing techniques to delineate isochronous stratigraphic framework with shorter time intervals. Thereby enhancing the reliability of subsurface stratigraphic information and data accuracy. The study posits that current technological means cannot create a truly isochronous stratigraphic framework; thus, “isochronous” is considered a relative concept in this context. The framework aims to ensure temporal consistency by minimizing discrepancies through mutual constraints between well and seismic data, serving to exploration and development requirements. Furthermore, analyses such as sensitive attribute extraction, impedance inversion, and assessment of hydrocarbon potential in tight sandstone reservoirs demonstrate strong correlation with drilling results. This validation underscores the framework’s efficacy in interpreting industrial gas production flows, thereby providing robust support for future oil and gas exploration.

Study on combination of surfactant and acid for depressure and increasing injection oil displacement in heterogeneous sandstone reservoirs

This study addresses the challenges faced by unconventional tight sandstone reservoirs, including low porosity, permeability, high clay content, and complex wettability, which lead to increased flow resistance and injection pressures. The research aims to optimize depressure and increasing injection methods by investigating the effects of various two-phase and three-phase displacement systems, employing experimental treatments including acids, alkalis, and surfactants. Nuclear magnetic resonance, computed tomography, scanning electron microscopy, inductively coupled plasma, and wettability tests are utilized to investigate the mechanisms of these treatments. Key findings indicate that weak alkaline ethylenediaminetetraacetate tetrasodium and weak acids like hydroxyethylidene diphosphonic acid and acetic acid can cause significant pore blockage, while hydrochloric acid can dissolve pore minerals, achieves a high depressure rate of 89.42%. Although surfactants exhibit a negative effect in two-phase displacement systems, they demonstrate considerable potential in three-phase displacement. Surfactants can modify the wettability of rock surfaces, reduce oil saturation, and improve water phase permeability, resulting in a depressure rate of 11.68%. Notably, the combination of surfactants and HCl enhances the depressure rate to 60.82% and improves oil displacement efficiency from 26.12% to 57.96%. The optimal formulation identified is “0.5% unconventional agent (CNI-A) +3% HCl,” which improves oil displacement capacity and alleviates injection pressure, providing valuable insights for the management of heterogeneous sandstone reservoirs.

Characteristics and main controlling factors of the Sangonghe tight sandstone reservoirs in the Shengbei Sub-sag of the Turpan-Hami basin, China

The Sangonghe tight sandstone hydrocarbon reservoirs in the Shengbei Sub-sag of the Turpan-Hami Basin are key areas for hydrocarbon exploration. However, previous research has mostly focused on petrological characteristics, physical properties, and pore types. There is a lack of understanding regarding diagenesis, microscopic pore-throat features, and the impact of overpressure on the reservoir. This gap in knowledge poses a disadvantage for future studies and hydrocarbon exploration. This study examines the Sangonghe tight sandstone hydrocarbon reservoirs in the Shengbei Sub-sag of the Turpan-Hami Basin. It combines cast thin sections, physical property tests, high-pressure mercury injection experiments, low-temperature nitrogen adsorption experiments, and well logging overpressure identification to investigate the basic characteristics, diagenesis, and microscopic pore-throat features of these reservoirs. Based on this analysis, the study identifies the main controlling factors of the reservoir properties and presents three key findings. First, the reservoir rocks are primarily composed of lithic sandstone and feldspathic lithic sandstone with porosity ranging from 4% to 10% and permeability ranging between 0.1 and 10 mD, classifying it as a low-porosity, low-permeability tight sandstone reservoir. Second, the reservoir has undergone several diagenetic processes, with significant compaction and common occurrences of cementation and metasomatism. Acidic dissolution is the main dissolution process, but it is relatively weak. The pore-throat system exhibits poor and concentrated sorting, with nanometer-sized pores being predominant. These include 'ink-bottle' pores with narrow necks and wide bodies, and parallel plate-structured fissure pores. Finally, the development of the reservoirs is mainly influenced by sedimentation, dissolution, and overpressure. The parent rock provenance features a high content of stable heavy minerals, larger grain sizes, and thicker sand body layers. These factors enhanced the reservoir's resistance to compaction and promoted the development of primary intergranular pores. Additionally, organic acid fluids caused extensive dissolution of feldspar and lithic fragments, resulting in the formation of numerous secondary dissolution pores. Additionally, under-compaction overpressure helped preserve primary pores, while hydrocarbon generation overpressure extended the hydrocarbon generation period. This extended period provided the driving force for fluid migration, enhanced the transformation of reservoir space, and aided in hydrocarbon accumulation.

Quantitative characterization of porosity evolution in the Triassic Chang 8 tight sandstone reservoir during hydrocarbon accumulation in the Maling area, Ordos Basin, China

The Maling area in the Ordos Basin is characterized by delta front deposits. The principal oil-bearing layer, Chang 8 Member (the 8th member of the Triassic Yanchang Formation), manifests low-to-ultra-low porosity and permeability due to the interplay of depositional, diagenetic, and burial processes. The reservoir exhibits pronounced heterogeneity and diagenetic alterations, which limit the efficacy of hydrocarbon exploration. Methodologies employed for this research encompass grain size imaging, physical property assays, petrographic thin sections, scanning electron microscopy, high-pressure mercury intrusion, and X-ray diffraction. These techniques facilitated a comprehensive investigation into the diagenetic attributes and compaction mechanisms of the reservoir. A porosity evolution simulation equation tailored to the Chang 8 tight sandstone reservoir was formulated based on diagenetic evolution traits and geological influences. Interdependencies and correlations among various diagenetic processes were analyzed. During diagenesis, compaction, cementation, and replacement led to a reduction in primary porosity, whereas dissolution-induced secondary pores served as high-permeability channels. A quantitative model for porosity evolution was developed alongside qualitative assessments, achieving a deviation of 3.18% when compared to gas porosity measurements. Evaluation of four representative samples revealed that compaction-induced diagenetic alteration predominates, with burial depth, formation age, and cement types playing critical roles in the evolution of reservoir porosity. This differential diagenetic evolution elucidates the underlying causes of variability in reservoir properties and heterogeneity in pore structure, providing valuable insights for future exploration strategies.

Study on the Vertical Propagation Behavior of Hydraulic Fractures in Thin Interbedded Tight Sandstone

Hydraulic fracturing technology is vital for the efficient extraction of oil and gas from low-permeability tight sandstone reservoirs.Taking the central Bohai oilfield in China as an example, these fields are typically composed of thinly interbedded tight sandstone, characterized by low permeability and significant lithological heterogeneity between layers. Fractures may either be confined, limiting vertical growth and reducing production, or overextend into water-bearing zones, causing contamination and compromising reservoir integrity. Therefore, predicting vertical fracture propagation during field fracturing operations is critical for efficient resource extraction.However, there is still a lack of comprehensive understanding of the mechanisms governing vertical fracture growth offshore.This paper applies numerical simulations based on the finite element method to elucidate the interlayer fracture propagation behavior in low-permeability tight sandstone reservoirs. A fracture propagation model for thin interlayered tight sandstone formations is constructed, and the effects of various factors on hydraulic fracture propagation are systematically analyzed, including geological factors such as interlayer stress contrast, thickness, and differences in elastic modulus, as well as operational parameters including fracturing fluid viscosity and injection rate. This study clarifies the cross-layer propagation patterns of hydraulic fractures under the influence of multiple factors and yields a comprehensive prediction chart for fracture propagation thickness under the combination of complex factors. The results of this research can provide theoretical support for the design of reservoir stimulation operations in low-permeability tight sandstone oilfields.

Multiscale Characterization of Fractures and Analysis of Key Controlling Factors for Fracture Development in Tight Sandstone Reservoirs of the Yanchang Formation, SW Ordos Basin, China

Tight sandstone reservoirs, despite their low porosity and permeability, present considerable exploration potential as unconventional hydrocarbon resources. Natural fractures play a crucial role in hydrocarbon migration, accumulation, and present engineering challenges such as late-stage reformation in these reservoirs. This study examines fractures in the seventh member of the Triassic Yanchang Formation’s tight sandstone within the Ordos Basin using a range of methods, including field outcrops, core samples, imaging and conventional logging, thin sections, and scanning electron microscopy. The study clarifies the characteristics of fracture development and evaluates the relationship between dynamic and static rock mechanics parameters, including the calculation of the brittleness index. Primary factors influencing fracture development were quantitatively assessed through a combination of outcrop, core, and mechanical test data. Findings reveal that high-angle structural fractures are predominant, with some bedding and diagenetic fractures also present. Acoustic, spontaneous potential, and caliper logging, in conjunction with imaging data, enabled the development of a comprehensive probabilistic index for fracture identification, which produced favorable results. The analysis identifies four key factors influencing fracture development: stratum thickness, brittleness index, lithology, and rock mechanical stratigraphy. Among these factors, stratum thickness is negatively correlated with fracture development. Conversely, the brittleness index positively correlates with fracture development and significantly influences fracture length, aperture, and linear density. Fractures are most prevalent in siltstone and fine sandstone, with minimal development in mudstone. Different rock mechanics layer types also impact fracture development. These insights into fracture characteristics and controlling factors are anticipated to enhance exploration efforts and contribute to the study of similar unconventional reservoirs.

A method for calculating saturation in tight sandstone reservoirs based on the dual porosity model

IntroductionWith the continuous development of exploration and development, tight sandstone reservoirs have become an essential field of oil and gas exploration. The tight sandstone reservoirs are characterized by complex lithology, poor pore structure, and strong heterogeneity, which bring great difficulties to formation evaluation by well logs. Especially, the accuracy of the Archie formula for calculating the water saturation of tight sandstone reservoirs containing fractures is not high, saturation evaluation faces greater challenges. Therefore, how to calculate the saturation of tight sandstone reservoirs more accurately is an urgent problem to be solved.MethodsIn this paper, the tight sandstone reservoirs of the Jurassic Ahe Formation in the Tarim Basin were taken as the research area. A saturation model that combines the effects of shale and fractures was proposed. Specifically, if the shale content is more than 20%, the Indonesian formula is used to calculate the saturation. If the shale content is less than 20%, the dual porosity model is adopted. Based on the rock resistivity and nuclear magnetic resonance (NMR) experiment results, the porosity and T2 logarithmic mean values are selected as influencing factors to calculate the key parameters of the dual porosity model.Results and DiscussionThe saturation of tight sandstone reservoirs in the Jurassic Ahe Formation of the Tarim Basin is calculated through the method proposed in this paper. The case study shows that the accuracy of the proposed method is higher than that of the Archie model. The method proposed in this paper demonstrates excellent adaptability in the quantitative evaluation of saturation for tight sandstone reservoirs.

Preparation and performance evaluation of a low‐damage fracturing fluid for unconventional reservoirs

AbstractThe characteristics of tight matrix, underdeveloped natural fractures, small pore throat radius, poor pore connectivity, and abundant clay minerals result in a high potential for damage to the tight sandstone reservoirs of the Shaximiao Formation in the Qiulin Block in the Sichuan Basin. In order to reduce the retention damage caused by fracturing fluid to the tight sandstone reservoir, a low damage fracturing fluid system applicable to the target reservoir is developed in this work, and the indoor performance meets the requirements of on‐site fracturing operation. A low‐damage, heat‐resistant, shear‐stable amphiphilic polyacrylamide (PAAD) was prepared by free radical polymerization in aqueous solution using acrylamide, acrylic acid, and methacryloyloyloxyethyl dimethyloctadecyl ammonium bromide (DM18) as the monomers. The amphoteric polyacrylamide was characterized by Fourier infrared spectroscopy, nuclear magnetic resonance spectroscopy (1H NMR), light scattering molecular weight determination, and thermogravimetric analysis. Fracturing fluids were formulated with the amphiphilic hydrophobic associative polymer PAAD as a drag‐reducing agent, the fluorine‐containing and nonionic complex surfactant FD1 as a clean‐up additive, CT10‐4B as a bactericide and CT1‐12 as an emulsion breaker. The fracturing fluid formulation was preferred, and the performance of the fracturing fluid was evaluated in terms of temperature resistance and shear resistance, drag reduction, anti‐expansion, and core damage. The fracturing fluid showed good temperature and shear resistance, with a viscosity retention of 58.4% at 120°C and 170 s−1 shear for 1 h. At a loading of 0.1%, the drag reduction rate reaches 72.3%, the anti‐expansion rate of the gel‐breaking fluid is 86.04%, and the damage rate to the tight sandstone core is 16.25%. The results show that the fracturing fluid has good heat resistance and shear stability, as well as low damage and good resistance reduction and anti‐expansion properties. This work can provide new strategies for designing polymeric fracturing fluids with low damage, good heat resistance and shear stability.

Chronology and geofluids characteristics of calcite cement in the Upper Triassic Xujiahe Formation tight sandstone reservoir, Western Sichuan Basin, SW China

Geological fluid activities significantly influence diagenesis and hydrocarbon accumulations in reservoir rocks. However, it remains challenging to precisely determine the timing of these activities. This study aims to investigate the chronology and geofluids characteristics of calcite cement that leads to reservoir tightness in the Upper Triassic Xujiahe Formation in the Western Sichuan Foreland Basin, which is a critical exploration target for hydrocarbon resources. We examine calcite cement as a marker of fluid activities, employing petrological analyses, U-Pb dating, and in-situ carbon-oxygen isotope analysis. These methods are integrated with simulations of regional burial and thermal histories to assess pore evolution and hydrocarbon accumulation mechanisms in these tight sandstone reservoirs. Results reveal two main calcite cementation stages within the second member of the Xujiahe Formation (Xu-2 Member): early cements from the Middle Jurassic around 175 ± 11 Ma and late cements from the Late Jurassic between 161 and 156 Ma. Initially, basin-derived alkaline fluids and near-surface atmospheric freshwater supplied the calcium and carbon for early cements during ongoing basin subsidence. Calcium and carbon for the late calcite cements came from the dissolution of carbonate rock fragments by organic acids. The heavier δ13C is primarily associated with in-situ generation and consumption of carbon within the system, while the δ18Ofluid, which is close to modern seawater values, is mainly related to active water-rock reactions induced by processes such as the dissolution of carbonate rock fragments by organic acids. The closed diagenetic system due to calcite cementation in the Late Jurassic led to reservoir tightening. Therefore, basin-scale chronological constraints on calcite cement are of great significance for quantitatively studying sandstone reservoir densification and exploring the mechanism and control factors of hydrocarbon accumulation.

The influence of pore throat heterogeneity and fractal characteristics on reservoir quality: A case study of chang 8 member tight sandstones, Ordos Basin

The Chang 8 member of the Yanchang Formation in the Ordos Basin exhibits extensive development of tight sandstone reservoirs. In comparison to conventional reservoirs, these tight sandstone reservoirs demonstrate smaller pore-throat systems and stronger heterogeneity due to interactions between inherent sedimentary components and various diagenetic processes. To further investigate the influence of microscopic pore throat structure on macroscopic physical properties and oil content within the reservoir, a comprehensive study was conducted utilizing high pressure mercury injection, nuclear magnetic resonance, X-CT scanning, and other pore throat testing methods. This study was complemented by observation techniques such as polarizing microscope, scanning electron microscopy, and laser confocal imaging, to study the pore throat system of reservoirs under the influence of different sedimentary components and diagenesis. By comparison, it is observed that the radius of the primary pore throat system in the tight sandstone reservoir ranges from 0.01 to 1 μm. The structural characteristics of the pore throat system significantly impact the macroscopic physical properties of the reservoir. Due to variations in testing methods, high pressure mercury injection, nuclear magnetic resonance (NMR), and X-ray computed tomography (X-CT) reveal different fractal dimensions of the reservoir's pore throat system. Therefore, it is better to respectively utilize fractal dimension Df2, Df2-NMR, Df2-CT, and pore throat parameters to characterize the microscopic pore throat system with a radius ranging from 0.01 to 1 μm. The decrease in the average pore throat radius and the increased irregularity of pore shape contribute to heightened heterogeneity in the micro-pore throat structure within the reservoir. This negatively impacts its physical properties and oil content. Furthermore, it is important to note that the minimum threshold of pore throat radius plays a crucial role as a primary factor determining the fluid seepage capacity within this reservoir. Moreover, when isolated pores exist, reduced fluid mobility ensues, which further worsens the seepage conditions of the reservoir. The chlorite rims development reservoir shows a low fractal dimension in its micro-pore throats, contributing to superior macroscopic petrophysical properties and oil content. However, compression, siliceous cementation, and calcite cementation negatively impact the average pore throat radius by increasing micropores, inaccessible pores, and narrow throat content. This results in a stronger heterogeneity of the pore throat structure, leading to poor seepage conditions and lower oil content.

Research on Effective Development Methods and Development Potential of Tight and Difficult to Develop Reservoirs in Hailar Oilfield

Abstract In order to solve the problems of large undeveloped reserves and difficult development in the tight sandstone reservoir of Hailar Oilfield, from the perspective of “revitalizing ineffective and inefficient development wells, effectively utilizing tight reservoirs, and improving oilfield recovery”, with the widespread application of volume fracturing and other technologies, and in line with the principle of “starting with the easy and rich before the difficult and poor” in the development of ultra-low permeability fault block reservoirs, the transformation of tight sandstone reservoirs has been taken as an important supplement to the development and production of oil fields. This article takes the tight sandstone reservoir as the research object, aiming at the characteristics of low reserve abundance, longitudinal non-concentration of oil layers, and scattered development of sand bodies. Through detailed analysis and analysis of regional oil and gas migration systems, reservoir classification evaluation standards, fracturing process optimization, and development models, the potential of reservoir transformation and oil production capacity are systematically evaluated. Effective fracturing and post-fracturing energy-enhancing field tests are carried out for ultra-low permeability elastic mining areas, which have implemented the feasibility of utilizing difficult reservoirs, broken through the technical bottleneck of low production in tight sandstone reservoirs, and developed the theory and supporting technology of tight oil development in Hailar Oilfield. Based on the on-site test results, it is shown that the ultra-low permeability reservoir in Hailar Oilfield has the development conditions, indicating the direction of future development potential.

Differential controlling on the deep tight sandstone reservoirs: Insight from the second member of lower Triassic Xujiahe Formation in Xinchang area, western Sichuan basin, China

With advancements in deep exploration, the deep tight sandstone gas reservoir has become a significant exploration field. However, it remains challenging to develop on a large scale due to the unclear distribution of relatively high-quality reservoirs. In this paper, the petrology, reservoir properties, diagenesis, and structural fracturing of deep tight sandstone reservoirs are systematically studied, focusing on the second member of the Upper Triassic Xujiahe Formation (T3x2) in the Xinchang area, and the types of relatively high-quality reservoirs and their differential controlling are further clarified. According to the matching relationship between pores and fractures, tight sandstone reservoirs can be classified into four types: extremely tight, fractured, porous, and pore-fractured types. Among these, the porous and pore-fractured types are considered effective reservoirs. The formation of tight sandstone reservoirs is closely related to sedimentary microfacies, grain size, diagenesis and tectonic fracturing, with distinct controlling differences across reservoir types. Overall, sedimentary microfacies provide the foundation, while differential diagenesis and tectonic fracturing are the key factors influencing reservoir quality. Among them, the extremely tight sandstone reservoirs can form in various sedimentary microfacies, particularly in medium to fine, lithic-rich sandstones, where strong compaction and cementation are the main factors for the underdevelopment of reservoir space. In contrast, fractured reservoirs mainly form based on porous reservoirs through the superimposition of tectonic fracturing. The porous reservoirs are typically found in relatively high-energy environments such as distributary channels and mouth bars, with medium to coarse feldspar-rich sandstone. Dissolution and chlorite-liner cementation are the key factors for their pore formation. Similarly, pore-fractured reservoirs originate from porous reservoirs that have been further altered by superimposing tectonic fracturing.

Research on the microscopic pore-throat structure and reservoir quality of tight sandstone using fractal dimensions

The pore-throat structure is a crucial parameter for evaluating reservoir characteristics and assessing the potential of oil and gas resources. Understanding the relationship between reservoir pore-throat variations and oil-bearing properties is essential. Through a combination of techniques, including thin-section casting, scanning electron microscopy (SEM), micro-computed tomography (micro-CT), and high-pressure mercury injection (HPMI), we examined the tight sandstone reservoirs from the Chang 4 + 5 members of the Yanchang Formation in the study area. This analysis elucidates the relationship between the pore-throat structure and fractal characteristics of the samples and their oil-bearing properties. The results show that : (1) The tight sandstone reservoirs in the study area mainly develop three types of pores: dissolution pores, residual intergranular pores, and microfractures. Residual intergranular pores are primarily controlled by early compaction processes, while dissolution processes easily form secondary pores, increasing the porosity of the reservoir. Microfractures can significantly enhance both the permeability of the reservoir. (2) Using the characteristic parameters of HPMI, the reservoir is classified into four categories, labeled as type I to type IV. As the categories progress from type I to type IV, pore-throat size decreases, porosity and permeability decrease, and reservoir properties deteriorate. The overall fractal dimension of pores decreases, while the fractal dimensions of individual pore types increase. Pore connectivity becomes more complex, and heterogeneity strengthens. (3) Reservoir porosity shows a strong positive correlation with permeability. As reservoir properties improve, the number of macropores increases, leading to a higher Reservoir Quality Index (RQI) and better oil-bearing characteristics.

Evaluation of movable fluid and controlling factors in lacustrine gravity-flow tight sandstone reservoirs: Implications for predicting reservoir quality

Lacustrine gravity-flow tight sandstone reservoirs are rich in petroleum resources, and the presence of movable fluids is essential for the efficient recovery of tight oil. However, characterizing the properties of movable fluids and predicting their content are challenging due to the limited data available on these fluids. To address this research gap, it is imperative to conduct a comprehensive study on the distribution patterns and controlling factors of movable fluids within the lacustrine gravity-flow tight sandstone reservoirs of the Chang-7 Member in the Heshui region of the Ordos Basin. The study utilized a range of analytical techniques, such as thin section analysis, scanning electron microscopy (SEM), high-pressure mercury injection (HPMI), constant-rate mercury injection (CRMI), and nuclear magnetic resonance (NMR). We identified three distinct lithofacies and three types of pore-throat spaces within these lacustrine gravity-flow sandstones. The highest amount of movable fluid was observed in the submicron pore throats, followed by nanopore throats, while the micron pore throats exhibited the lowest amount. Our analysis indicates that petrophysical parameters, mineral composition, and pore throat structures collectively influence the content of movable fluids. Specifically, quartz and feldspar content are positively correlated with the movable fluid content, while clay and carbonate cement content are negatively correlated. Fine sandstones with massive bedding typically have a high content of movable fluids, which is associated with elevated quartz and feldspar content. In contrast, very fine sandstones to siltstones with parallel or ripple beddings have a very low content of movable fluids, characterized by high levels of carbonate and clay cementation. The study also suggests that the lower limit of the pore throat radius of movable fluid is about 0.03 μm. These findings offer novel insights for evaluating and predicting high-quality lacustrine gravity-flow tight sandstone reservoirs, enabling more effective exploration and development strategies.

Enhance Oil Recovery by Carbonized Water Flooding in Tight Oil Reservoirs

The low permeability of tight sandstone reservoirs limits the application of water flooding to enhance oil recovery. Due to the properties of CO2, people improve crude oil recovery by carbonizing water flooding. However, many studies have not prioritized determining the concentration of carbonated water before comparing the recovery rates of carbonated water flooding and pure water flooding after water flooding. This article takes the Chang 6 oil reservoir as the research object, and uses a combination of nuclear magnetic resonance testing and displacement experiments to conduct experiments on optimizing the concentration of carbonated water. Based on this, experiments on water flooding and carbon water flooding after water flooding to improve crude oil recovery are conducted to compare and analyze the oil enhancement potential of carbonated water flooding. The experimental results show that the physical properties, pore throat structure and seepage capacity of sandstone samples of type I, II and III decrease in turn. With the increase of carbonated water concentration, the expansion coefficient, viscosity reduction rate, contact angle reduction rate and core permeability loss rate of crude oil increase. The damage rate of 0.4mmol/cm3 carbonated water solution (17.6g CO2: 1L water) to the core permeability is only 0.98%, which is the optimal experimental concentration. During the water flooding process, crude oil in pores of different scales in Type I rock cores is utilized, and the degree of utilization in large pores is relatively high. Continuing to use carbonated water to drive oil in the rock cores after water flooding increased the recovery rate of crude oil by 15.24%; The degree of crude oil utilization in small pores of Tpye II core after carbonization and water flooding increased by 29.4%, and the final recovery rate of crude oil increased by 11.35% compared to the core after water flooding; The physical properties of Tpye III core are poor, with a small proportion of large pores, resulting in a 9.04% increase in crude oil recovery rate. Compared with pure water flooding, the recovery rate and utilization degree of large and small pores in the three types of rock cores after carbonization water flooding have been improved to varying degrees. Among them, the utilization degree of crude oil in large pores is the most significant, which increases the recovery rate of crude oil in the rock core after displacement. This study can provide a theoretical basis for improving crude oil recovery by carbonizing water flooding.