Low-permeability Sandstone Research Articles

Synthesis and oil displacement performance evaluation of asymmetric anionic gemini surfactants

In order to further enhance the water flooding performance in low-permeability tight oil reservoirs, a novel gemini surfactant with high interfacial activity, hydrophilic wettability, and good injectivity and mobility control was developed. Using n-alkylamine (C12–C18), 3-chloro-2-hydroxypropylsulfonate sodium, sodium chloroacetate, and succinic anhydride as raw materials, a series of gemini surfactants with asymmetric hydrophilic head groups (GDCS m-4-m; m = 12, 14, 16, 18) were synthesized via substitution and ring-opening reactions. The structures of the synthesized products were characterized by FTIR and 1H NMR, and their surface and interfacial properties as well as their thickening abilities were evaluated. The optimal gemini surfactant was selected for further oil displacement and wettability alteration tests. The results indicate that the synthesized product is consistent with the molecular structure of the target design product. The surface tension and interfacial tension of GDCS m-4-m series surfactant solutions initially decrease and then increase with the increase in the number of carbon atoms in the hydrophobic carbon chain. Its thickening ability increases as the number of carbon atoms in the hydrophobic carbon chain increases. GDCS16-4-16 exhibited the best surface and interfacial activities, with a critical micelle concentration (CMC) of 0.344 mmol/L, surface tension of 24.04 mN/m, and an interfacial tension as low as 2.16 × 10−2 mN/m at 0.5 wt%. The flooding system formulated with GDCS16-4-16 demonstrated excellent mobility control and oil washing capabilities, and could shift the wettability of rock surfaces to highly hydrophilic. In dual-core flooding experiments, with gradient differentials of 3, 5, and 7, the comprehensive oil recovery increased by 12.81 %, 13.88 %, and 11.78 %, respectively, after injecting 0.4 PV of GDCS16-4-16 surfactant solution followed by subsequent water flooding. This indicates a significant potential to enhance recovery in low-permeability tight sandstone reservoirs, presenting promising application prospects in the development of such formations.

Evaluating the surface relaxivity and movable fluid of low-permeability sandstones based on low-field nuclear magnetic resonance

Comprehensive characterization of pore structure and fluid distribution is beneficial for efficiently exploring and developing low-permeability sandstone reservoirs. As a conversion parameter, the surface relaxivity is significant for characterizing the pore structure of porous media and evaluating fluid mobility. The surface relaxivity indicates the strength of the interaction between the fluid and the solid during the relaxation process. This paper conducts mercury intrusion porosimetry, low-temperature nitrogen adsorption, and nuclear magnetic resonance-centrifugation experiments on low-permeability sandstones, providing insight into the evolution of pore size and water content distribution. Combining mercury intrusion porosimetry with nuclear magnetic resonance, the surface relaxivity of samples is measured to be 9.57–23.79 μm/s. The surface relaxivity ranges from 0.70 to 3.72 μm/s utilizing low-temperature nitrogen adsorption and nuclear magnetic resonance. Based on the movable water saturation through the critical radius, the calculated surface relaxivities using two methods are compared. The result indicates that surface relaxivity determined by low-temperature nitrogen adsorption is smaller than that obtained through mercury intrusion porosimetry. This is attributed to overestimating the ratio of pore surface and pore volume in the low-temperature nitrogen adsorption, which is difficult to capture information about macropores. Conversely, the similar principle between mercury intrusion porosimetry and centrifugation leads to consistent movable water saturation, minimizing discrepancies in evaluating surface relaxivity. Therefore, the surface relaxivity determined by mercury intrusion porosimetry-nuclear magnetic resonance is more suitable for characterizing the pore structure and fluid mobility of low-permeability sandstones. In addition, the ink-bottle effect retains water in the macropore during centrifugation experiments.

Experimental and Numerical Investigations of Low-Permeability Sandstone Under Water Injection–Induced Dilation in West Oilfield, South China Sea

With the development of offshore oil fields, the reservoirs of X oilfield in the west of the South China Sea are poor in physical property, serious in pollution, and increasingly prominent in interlayer contradictions. Water injection dilation technology has strongly affected the development of loose sandstone reservoirs. To explore whether this technology applies to the low-permeability sandstone of X oilfield in the west of the South China Sea and the dilation effect and radius of water injection dilation technology on the target reservoir, low confining pressure rock mechanics experiments and numerical simulation of water injection in this reservoir section are carried out. The triaxial shear experiment of low confining pressure shows that the target reservoir sandstone with low-permeability can have a shear strength of 45 MPa when the effective confining pressure is 0.5 MPa, and the target reservoir core can have dilatancy. When the axial strain is 2.5%, the core dilatancy is 1%, and the permeability changes by 1.17 times. It was found that the core volume dilation was obviously under low effective confining pressure, and the permeability is 2 orders higher than in the initial condition. The numerical simulation of the target reservoir shows that the bottom-hole pressure reaches 47.12 MPa at the end of water injection in typical wells. The reservoir was deformed to different degrees around the well, and the top layer was raised by 5.58 mm. This paper characterizes the rock expansion potential and expansion flow capacity of low-permeability sandstone reservoirs from multiple perspectives and establishes a three-dimensional, full-size wellbore formation crustal stress strict matching geological model for offshore expansion wells. We have provided theoretical guidance for on-site construction.

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.

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.

Insights into the wetting mechanisms in low-permeability sandstone reservoirs and its evolution processes: The shahejie formation in the Dongying Depression, Bohai Bay basin

During the accumulation and development processes of low-permeability oil, wettability plays a crucial role in the percolation capacity of fluids. In particular, the evolution of low-permeability sandstones involves complex changes in formation fluid properties and mineral types, leading to a deficient understanding of wetting mechanisms in low-permeability sandstones. This gap significantly impedes research on the accumulation mechanisms of low-permeability oil. Focusing on the low-permeability sandstones in Shahejie formation of Dongying Depression, Bohai Bay Basin, tests like Casting thin section, scanning electron microscope, contact angle measurement, molecular dynamics simulation and the Amott method based on nuclear magnetic resonance technology were performed to comprehensively investigate sandstone wettability and its evolutionary process. The results indicate that the adsorption capacity of hydroxyl groups or monovalent cations (K+and Na+) for water molecules causes residual intergranular pores, feldspar dissolution pores, quartz dissolution pores, clay mineral intercrystalline pores and micro-cracks to exhibit hydrophilicity; while the adsorption capacity of divalent cations (Ca2+and Mg2+) for oil molecules causes the surface of dissolution pores of carbonate minerals to exhibit neutrality or lipophilicity. Additionally, changes in formation conditions (temperature, pressure, ion types, and ion concentration) significantly control the wettability of pore surfaces, further determining the overall wettability of low-permeability sandstone reservoirs. Throughout the evolutionary process of low-permeability sandstones, the Amott-Harvey index of low permeability sandstone is greater than zero, and the wettability exhibited hydrophilic or neutral. From A-stage eodiagenesis to B-stage mesodiagenesis, the Amott-Harvey index is 0.82, 0.12, 0.37, 0.03, and 0.49, and the wettability of reservoirs transitions through phases of strong hydrophilicity, weak hydrophilicity, hydrophilicity, neutrality, and hydrophilicity, respectively. Finally, an evolutionary model of the wettability of low-permeability sandstone reservoirs was established, which is of great significance for predicting the quality of low-permeability sandstone reservoirs.

Developmental characteristics of vertical natural fracture in low-permeability oil sandstones and its influence on hydraulic fracture propagation

Vertical natural fractures (NFs) are prevalent in low-permeability sandstone reservoirs. Presently, the impact of NFs on the extension of hydraulic fractures (HFs) remains partially unveiled, which restricts the scientific development of strategies for low-permeability, fractured oil sandstones. In this study, taking the oil sandstone of the He-3 Member, Hetaoyuan Formation, southeastern Biyang Depression as an example, we conducted a comprehensive investigation into the factors influencing vertical fracture development and the interaction between natural and hydraulic fractures. The cohesive unit simulations indicate that geostress is the principal factor influencing HF expansion, more so than NFs, with this influence intensifying as natural fracture density increases. As natural fracture density grows, the potential for two sets of conjugate natural fractures to form short HFs arises, which are limited in expansion scope, suggesting a need to reduce well spacing accordingly. Conversely, areas with a single set of NFs are more prone to developing longer HFs, warranting an increase in well spacing to avoid water channeling. High natural fracture densities may constrain the effectiveness of HFs. In fractured reservoirs with a 10 MPa horizontal stress difference, the length of HFs is 1.52 times that of HFs with 0 MPa and 5 MPa differences. However, the hydraulic fracture effectiveness index (FE) of the latter is 1.74 times higher than the former. For fractured reservoirs, the expansion capacity of HF length within a 5 MPa horizontal stress difference remains relatively stable; beyond this threshold, the expansion capacity increases with the growing horizontal stress difference, and the fracturing effect eventually deteriorates. Furthermore, as the strength of NFs escalates, the length and modified area of HFs initially decrease significantly before stabilizing. The complexity and FE value of HFs formed under strong natural fracture conditions are heightened, indicating a more effective fracturing outcome.

Multifactor Coupled Evaluation Model of Fracability Based on a Combinatorial Weighting Method: A Case Study of the Low-Permeability Sandstone Reservoirs of Yanchang Formation, Southwestern Ordos Basin, China

Multifactor Coupled Evaluation Model of Fracability Based on a Combinatorial Weighting Method: A Case Study of the Low-Permeability Sandstone Reservoirs of Yanchang Formation, Southwestern Ordos Basin, China

Enhanced oil recovery and carbon sequestration in low-permeability reservoirs: Comparative analysis of CO2 and oil-based CO2 foam

Excessive CO2 emissions contribute to global climate change thus mandating effective methods for CO2 utilization and sequestering. In this study, one-dimensional flow simulation experiments on CO2 flooding, CO2 Huff-n-Puff, oil-based CO2 foam flooding, and oil-based CO2 foam Huff-n-Puff are conducted using low-permeability sandstone cores modeled after the Q131 block in Liaohe Oilfield, characterized by porosity ranging from 15% to 20% and permeability between 25 mD to 35 mD. Low permeability reservoirs are rich in oil resources and may effectively sequester CO2. Parameters pertaining to oil and gas production and carbon storage are collected. Nuclear magnetic resonance (NMR) is employed to determine the spatial variation of oil saturation in the cores. The experimental results show 8.03% and 41.21% increase in oil recovery factor by foam flooding and foam Huff-n-Puff relative to CO2 as the recovery agent. Moreover, NMR analysis confirms lower residual oil saturation in core samples using foam, suggesting better displacement agent. Oil-based CO2 foam recovery contributed to effective carbon sequestration, with carbon storage increasing by 34.24% and 315% relative to CO2 flooding and CO2 Huff-n-Puff, respectively. CO2 storage mechanisms for oil-based CO2 foam recovery method are detailed.

Dilation Potential Analysis of Low-Permeability Sandstone Reservoir under Water Injection in the West Oilfield of the South China Sea

At present, many offshore oil fields are facing problems, such as pollution-induced near-well zone blockage, poor inter-well connectivity, and strong vertical heterogeneity, which lead to insufficient formation energy and low production in the middle and late stages of development. It is necessary to develop a new technology to overcome these issues. In this regard, water-injection-induced dilation technology, which was already proven to have positive effects on loose sandstone reservoirs, was controversially applied to an offshore low-permeability reservoir. To investigate whether the water-injection-induced dilation technology is suitable, experiments were conducted to analyze the dilation potential of offshore low-permeability sandstone reservoirs, namely, X-ray diffraction, laser particle size analysis, physical simulation, computed tomography scan, and electron microscope scanning experiments. The X-ray diffraction experiments showed that the samples had more than 80% non-clay mineral content and a high brittleness index, which meant more complex microfractures under water injection. Particle size analysis experiments revealed that the particle size was mainly between 10 μm and 100 μm, and thus belonged to coarse silty sand. According to the sorting grade, the sample particle size distribution was uniform and the reservoir was more prone to dilation. The true triaxial physical simulation showed that a volumetric dilation zone occurred around the wellbore, where complicated microfractures occurred. This paper provides adequate evidence and mechanisms of dilation potential for an offshore low-permeability sandstone reservoir.

Optimized interfacial tension and contact angle for spontaneous imbibition in low-permeable and oil-wet sandstone cores with light crude oil

Spontaneous imbibition is an important phenomenon of fluid transports in porous media, particularly in liquid environment with a certain range of interfacial tension and wettability. Meanwhile, the spontaneous imbibition could be enhanced with the additions of surfactants, through modifying the oil–water interfacial tension (IFT) and wettability. However, ultra-low IFT impairs the capillary pressure. Hence, appropriate ranges of the IFT and contact angle (CA), though lacking adequate investigations, are key to optimizing spontaneous imbibition. Here, a series of physical experiments were conducted to evaluate the spontaneous imbibition efficiency of surfactant solutions with wide-range IFTs (10−3–101 mN/m) in the porous media of permeability 11 mD, through designed interfacial property measurements with different surfactant concentrations. Besides, the inverse Bond number was employed to determine the optimized interfacial properties during the imbibition. Overall, the best imbibition-induced hydrocarbon recovery is reached at oil viscosity of 25.26 mPa·s, an IFT of 0.1–0.2 mN/m and a CA of 70–80°.

Prediction of deep low permeability sandstone seismic reservoir based on CBAM-CNN

The prediction of sand body is a key focus in evaluating reservoir distribution, playing a crucial role in oil and gas exploration and development. To clarify the development characteristics of the sand body in the Huangyan structural belt of the Xihu Sag and effectively identify the hidden channel, a new approach is proposed. This approach incorporates a Convolutional Block Attention Module (CBAM) into a Convolutional Neural Network (CNN). Well logging and seismic data were used to predict the distribution of sand body in the lower section of the Huagang Formation (H12). Firstly, based on known sand-stratum ratio data and well-side seismic data, the seismic attributes that are sensitive to the reservoir response are preferred through correlation analysis, which are used to construct a Polynomial Linear Regression (PLR) model to obtain the preliminary sand distribution prediction results. Secondly, the grid is divided according to this result. Then, three sample selection methods, namely proportional, fixed-range, and random, are used to construct three sample sets in conjunction with the geologic model guide. Finally, CBAM-CNN, CNN, Random Forest (RF), Support Vector Machines (SVM), and Backpropagation Neural Network (BPNN) are utilized for sand body prediction. The results indicate that when using the same model, the sample set selected by the fixed-range selection method yielded the best prediction outcome. When using the same sample set, the CBAM-CNN model outperformed the others. Among various strategies, training the CBAM-CNN model with the sample set derived from the fixed-range selection method led to the highest test set R2 of 0.913. The results of the sand body distribution indicate that fine river channels are more continuous, and reservoir boundaries are clearer, significantly outperforming other schemes. This outcome can serve as a guide for further reservoir delineation.

Geological genesis and identification of high-porosity and low-permeability sandstones in the Cretaceous Bashkirchik Formation, northern Tarim Basin

Abstract The genesis and prediction of high-porosity and low-permeability sandstone reservoirs are hot spots in oil and gas geology research worldwide. High-porosity and low-permeability sandstone reservoirs are developed in the Cretaceous Bashkirchik Formation of the Luntai Uplift in the northern Tarim Basin, China. In this article, we conducted a systematic study on the geological origin and logging identification of high-porosity and low-permeability tight sandstone based on core observation, thin section, logging index response, and mathematical discrimination methods. The results show that the K1bs sandstone segment in the study area generally contains calcium carbonate, which mainly comes from carbonate rock debris and calcite cement. Calcite cement mainly fills the pores between primary particles, and it is the main factor leading to the densification of the reservoir. The geological origin of the formation of low-permeability layer is mainly due to the early cementation of carbonate, and the development mode of the low-permeability layer is “high content of calcium debris → severe calcium cementation → poor petrophysical properties → formation of low-permeability layer.” The low-permeability layer has the characteristics of high gamma and high resistivity, and the multi-parameter discriminant method established based on the Fisher criterion has a good identification effect for the low-permeability layer. The low-permeability layer has a small thickness, poor stability and continuity, and strong longitudinal heterogeneity, thus it can form a low-permeability baffle inside the reservoir, which greatly reduces the oil and gas migration capacity.

Modelling and simulation of natural hydraulic fracturing applied to experiments on natural sandstone cores

Under in-situ conditions, natural hydraulic fractures (NHF) can occur in permeable rock structures as a result of a rapid decrease of pore water accompanied by a local pressure regression. Obviously, these phenomena are of great interest for the geo-engineering community, as for instance in the framework of mining technologies. Compared to induced hydraulic fractures, NHF do not evolve under an increasing pore pressure resulting from pressing a fracking fluid in the underground but occur and evolve under local pore-pressure reductions resulting in tensile stresses in the rock material. The present contribution concerns the question under what quantitative circumstances NHF emerge and evolve. By this means, the novelty of this article results from the combination of numerical investigations based on the Theory of Porous Media with a tailored experimental protocol applied to saturated porous sandstone cylinders. The numerical investigations include both pre-existing and evolving fractures described by use of an embedded phase-field fracture model. Based on this procedure, representative mechanical and hydraulic loading scenarios are simulated that are in line with experimental investigations on low-permeable sandstone cylinders accomplished in the Porous Media Lab of the University of Stuttgart. The values of two parameters, the hydraulic conductivity of the sandstone and the critical energy release rate of the fracture model, have turned out essential for the occurrence of tensile fractures in the sandstone cores, where the latter is quantitatively estimated by a comparison of experimental and numerical results. This parameter can be taken as reference for further studies of in-situ NHF phenomena and experimental results.

Study on the Occurrence Characteristics of the Remaining Oil in Sandstone Reservoirs with Different Permeability after Polymer Flooding.

After polymer flooding, the heterogeneity between different layers intensifies, forming intricate seepage channels and fluid diversions, which results in decreased circulation efficiency and lower recovery rates, leaving a significant amount of residual oil trapped within the reservoir. Understanding the characteristics of residual oil occurrence is crucial for enhancing oil recovery post-polymer flooding. This study focused on sandstone reservoirs with varying permeability in the Saertu block of the Daqing oilfield. Using cryosectioning and laser scanning confocal microscopy, the occurrence characteristics of the residual oil in these sandstone reservoirs post-polymer flooding were investigated. Additionally, micro-CT and scanning electron microscopy were employed to analyze the impact of the pore structure on the distribution characteristics of the residual oil. The results indicate that laser scanning confocal images reveal that post-polymer flooding, the residual oil in high- and low-permeability sandstone reservoirs predominantly exists in a bound state (average > 47%), mostly as particle-adsorbed oil. In contrast, the residual oil in medium-permeability reservoirs is primarily in a free state (average > 49%), mostly as intergranular-adsorbed oil. In high-permeability sandstone reservoirs, heavy oil components are mainly in a particle-adsorbed form; in medium-permeability sandstone reservoirs, residual oil predominantly consists of heavy components, with most light components occurring in a clustered form; in low-permeability sandstone reservoirs, clustered residual oil exists in a balanced coexistence of light and heavy components, while the heavy components primarily exist in a particle-adsorbed form. Post-polymer flooding, the large pore-throat structure in high-permeability sandstone reservoirs results in effective displacement and less free residual oil; medium-permeability sandstone reservoirs, with medium-large pores and throats, have preferential channels and fine particles blocking the throats, leading to some unswept pores and more free residual oil; low-permeability sandstone reservoirs, with small pores and throats, exhibit weak displacement forces and poor mobility, resulting in more bound residual oil. The distribution and content of clay particles and clay minerals, along with the complex microscopic pore structure, are the main factors causing the differences in the residual oil occurrence states in sandstones with varying permeability.

Combined effect of silica nanoparticles and binary surfactants in enhancing oil recovery: An experimental investigation

Modern oil fields extensively utilize enhanced oil recovery (EOR) techniques to optimize production. This investigation evaluates the potential of silica (SiO2) nanoparticles (NPs) when combined with the SDS-TX100/xanthan gum (XG) binary surfactant/polymer mixture for enhancing oil recovery. The study focuses on examining the synergistic effects of the SDS-TX100 + XG combination and SiO2 NPs on reducing interfacial tension (IFT), altering wettability, and improving viscosity. Core flooding experiments were conducted on low-permeability San Saba sandstone cores. The dispersion and stability of SiO2 NPs in the SDS-TX100 surfactant mixture were evaluated through stability analysis, dynamic light scattering (DLS), Ultraviolet–visible spectroscopy (UV–VIS), and turbidity meter. Notably, the NPs exhibited a significant reduction in IFT between the SDS-TX100 surfactant mixture and crude oil, while the addition of the SDS-TX100 surfactant mixture improved the stability of nanofluids. Core flooding experiments revealed a synergistic effect of SiO2 NPs with the SDS-TX100 + XG mixture, leading to higher incremental oil recovery compared to the SDS-TX100 + XG mixture alone. The study elucidates various mechanisms contributing to oil recovery, including wettability alteration and IFT reduction. The flooding outcomes indicate that injecting SiO2 NPs with the SDS-TX100 + XG mixture increases oil recovery by up to 16 % of the original oil in place (OIIP) after conventional water flooding. This research contributes to a comprehensive understanding of the application of SiO2 NPs with binary surfactant and polymer as a chemical-EOR (CEOR) agent and assists in identifying sandstone reservoirs where nanofluids could be effectively deployed.

Pore structure characterization and permeability prediction of uranium-bearing sandstone based on digital core

The permeability of the ore-bearing layer is an important indicator affecting the in-situ leaching (ISL) of uranium-bearing sandstone, which is related to various factors such as pore shape, distribution, and size. In order to study the effect of pore structure on seepage in low-permeability uranium-bearing sandstone, CT scanning tests were conducted to create a 3D digital core based on scanning images and to calculate the fractal dimension using the box counting dimension method, which integrated fractal theory to define the core samples' pore structure. The permeability prediction was realized based on the porosity-permeability model and the fractal theory model. Results indicated that this type of sandstone is obviously characterized by pore connectivity, large differences in distribution, and strong microscopic inhomogeneity. The pores are dominated by micro- and nano-pores, as well as small pores, accounting for 90 %; macropores are few in number, but the diameters of their single pores are large. The distribution of pore structure in this type of sandstone exhibits a good fractal characteristic; the three-dimensional fractal dimensionality is 2.044–2.310. The porosity-permeability model was established, and permeability prediction was realized by combining the fractal theory to provide theoretical support for determining the values of well field parameters in ISL.

Progress on enhancing seepage-leaching mass-transfer research for in-situ leaching mining of low-permeability uranium-bearing sandstone: a review

Progress on enhancing seepage-leaching mass-transfer research for in-situ leaching mining of low-permeability uranium-bearing sandstone: a review

Evolution of CO2 Storage Mechanisms in Low-Permeability Tight Sandstone Reservoirs

Understanding the storage mechanisms in CO2 flooding is crucial, as many carbon capture, utilization, and storage (CCUS) projects are related to enhanced oil recovery (EOR). CO2 storage in reservoirs across large timescales undergoes the two storage stages of oil displacement and well shut-in, which cover multiple replacement processes of injection–production synchronization, injection only with no production, and injection–production stoppage. Because the controlling mechanism of CO2 storage in different stages is unknown, the evolution of CO2 storage mechanisms over large timescales is not understood. A mathematical model for the evaluation of CO2 storage, including stratigraphic, residual, solubility, and mineral trapping in low-permeability tight sandstone reservoirs, was established using experimental and theoretical analyses. Based on a detailed geological model of the Huaziping oilfield, calibrated with reservoir permeability and fracture characteristic parameters obtained from well test results, a dynamic simulation of CO2 storage for the entire reservoir life cycle under two scenarios of continuous injection and water–gas alternation were considered. The results show that CO2 storage exhibits the significant stage characteristics of complete storage, dynamic storage, and stable storage. The CO2 storage capacity and storage rate under the continuous gas injection scenario (scenario 1) were 6.34 × 104 t and 61%, while those under the water–gas alternation scenario (scenario 2) were 4.62 × 104 t and 46%. The proportions of storage capacity under scenarios 1 and 2 for structural or stratigraphic, residual, solubility, and mineral trapping were 33.36%, 33.96%, 32.43%, and 0.25%; and 15.09%, 38.65%, 45.77%, and 0.49%, respectively. The evolution of the CO2 storage mechanism showed an overall trend: stratigraphic and residual trapping first increased and then decreased, whereas solubility trapping gradually decreased, and mineral trapping continuously increased. Based on these results, an evolution diagram of the CO2 storage mechanism of low-permeability tight sandstone reservoirs across large timescales was established.

Research on the influence of mineral heterogeneity under different CO2 injection schemes in low permeability reservoirs

In the pursuit of sustainable oil and gas resource extraction, the innovative integration of carbon capture, utilization, and storage (CCUS) technology has emerged as the most promising approach. During the CCUS process, intricate physicochemical interactions between the injected CO2, facilitated through various injection strategies (Water Alternative Gas: WAG/Continue Gas Injection: CGI) and the formation fluids and heterogeneous mineral assemblages within the reservoir trigger alterations in mineral structures, consequently impacting permeability and recovery factors, constituting a pivotal aspect. Precisely delineating and quantifying these interactions is paramount for optimizing process design and evaluating reservoir dynamics in the successful implementation of CCUS operations. This study has carried out qualitative and quantitative characterization of mineral heterogeneity, different pore types, and mineral combination characteristics from a low-permeability sandstone reservoir. Additionally, the effect on the physical properties of minerals from different development methods (WAG/CGI) was investigated using numerical simulation for CCUS applications. The results indicate that the saturated CO2 fluid selectively dissolves the potassium feldspar (orthoclase) in intergranular pores, while the intergranular pores are filled with illite and secondary precipitated clay minerals. It initially dissolves the sensitive mineral (ankerite) in the intergranular pores. The decrease of ankerite and increase of illite result from the prolonged contact period between saturated CO2 and minerals, which changes the mineral cementation to argillaceous type, thus affecting permeability in the context of CCUS. The spatial impact on reservoir physical properties depends on the spatial heterogeneity of the original sensitive minerals (ankerite, anorthite, illite, etc.) distributed in the study area. In the WAG scheme, the physicochemical interaction between saturated CO2 and reservoir minerals is more intense than in the CGI scheme for CCUS operations, significantly impacting cumulative production.