High-pressure Mercury Intrusion Research Articles

Quantitative classification evaluation model for tight sandstone reservoirs based on machine learning

Tight sandstone reservoirs are a primary focus of research on the geological exploration of petroleum. However, many reservoir classification criteria are of limited applicability due to the inherent strong heterogeneity and complex micropore structure of tight sandstone reservoirs. This investigation focused on the Chang 8 tight reservoir situated in the Jiyuan region of the Ordos Basin. High-pressure mercury intrusion experiments, casting thin sections, and scanning electron microscopy experiments were conducted. Image recognition technology was used to extract the pore shape parameters of each sample. Based on the above, through grey relational analysis (GRA), analytic hierarchy process (AHP), entropy weight method (EWM) and comprehensive weight method, the relationship index Q1 between initial productivity and high pressure mercury injection parameters and the relationship index Q2 between initial productivity and pore shape parameters are obtained by fitting. Then a dual-coupled comprehensive quantitative classification prediction model for tight sandstone reservoirs was developed based on pore structure and shape parameters. A quantitative classification study was conducted on the target reservoir, analyzing the correlation between reservoir quality and pore structure and shape parameters, leading to the proposal of favourable exploration areas. The research results showed that when Q1 ≥ 0.5 and Q2 ≥ 0.5, the reservoir was classified as type I. When Q1 > 0.7 and Q2 > 0.57, it was classified as type I1, indicating a high-yield reservoir. When 0.32 < Q1 < 0.47 and 0.44 < Q2 < 0.56, was classified as type II. When 0.1 < Q1 < 0.32 and 0.3 < Q2 < 0.44, it was classified as type III. Type I reservoirs exhibit a zigzag pattern in the northwest part of the study area. Thus, the northwest should be prioritized in actual exploration and development. Additionally, the initial productivity of tight sandstone reservoirs showed a positive correlation with the porosity, permeability, sorting coefficient, coefficient of variation, and median radius. Conversely, it demonstrated a negative correlation with the median pressure and displacement pressure. The perimeters of pores, their circularity, and the length of the major axis showed a positive correlation with the porosity, permeability, sorting coefficient, coefficient of variation, and median radius. On the other hand, they exhibited a negative correlation with the median pressure and displacement pressure. This study quantitatively constructed a new classification and evaluation system for tight sandstone reservoirs from the perspective of microscopic pore structure, achieving an overall model accuracy of 93.3%. This model effectively predicts and evaluates tight sandstone reservoirs. It provides new guidance for identifying favorable areas in the study region and other tight sandstone reservoirs.

Evolution characteristic and mechanism of microstructure, hydraulic and mechanical behaviors of sandstone treated by acid-rock reaction: Application of in-situ leaching of uranium deposits

The main difficulty in understanding the effects of chemical-physical composite stimulation for low-permeability sandstone-type uranium deposits is clarifying the influence of acidification on pore response mechanism and permeability-mechanical properties evolution during loading-deformation-failure process. Therefore, the acid-rock reaction experiment was first performed, the multiple testing methods (X-ray Diffraction, thin-section identification, high-pressure mercury intrusion porosimetry, stress-seepage coupling experiment) were then conducted, the evolution laws and mechanisms of reservoir physical characteristics after acidification were finally clarified. Results show that after the acid-rock reaction, the contents of calcite, feldspar and kaolinite of samples are decreased and the quartz content is increased, the permeabilities of samples are all promoted, the peak strength, elastic modulus, and shear modulus of samples are reduced and the Poisson’s ratio is raised. The acid-rock reaction changes the energy storage performance and promotes the plasticization of samples. It is suggested to adopt a lower sulfuric acid concentration (2 g/L) and longer reaction time (>45 d) for the ISL of uranium deposits. This work has important theoretical and practical significance for an in-depth understanding of the enhanced mining of low-permeability sandstone-type uranium deposits.

The Pore Structure Multifractal Evolution of Vibration-Affected Tectonic Coal and the Gas Diffusion Response Characteristics

Vibrations caused by downhole operations often induce coal and gas outburst accidents in tectonic zone coal seams. To clarify how vibration affects the pore structure, gas desorption, and diffusion capacity of tectonic coal, isothermal adsorption-desorption experiments under different vibration frequencies were carried out. In this study, high-pressure mercury intrusion experiments and low-pressure liquid nitrogen adsorption experiments were conducted to determine the pore structures of tectonic coal before and after vibration. The pore distribution of vibration-affected tectonic coal, including local concentration, heterogeneity, and connectivity, was analyzed using multifractal theory. Further, a correlation analysis was performed between the desorption diffusion characteristic parameters and the pore fractal characteristic parameters to derive the intrinsic relationship between the pore fractal evolution characteristics and the desorption diffusion characteristics. The results showed that the vibration increased the pore volume of the tectonic coal, and the pore volume increased as the vibration frequency increased in the 50 Hz range. The pore structure of the vibration-affected tectonic coal showed multifractal characteristics, and the multifractal parameters affected the gas desorption and diffusion capacity by reflecting the density, uniformity, and connectivity of the pore distribution in the coal. The increases in the desorption amount (Q), initial desorption velocity (V0), initial diffusion coefficient (D0), and initial effective diffusion coefficient (De) of the tectonic coal due to vibration indicated that the gas desorption and diffusion capacity of the tectonic coal were improved at the initial desorption stage. Q, V0, D0, and De had significant positive correlations with pore volume and the Hurst index, and V0, D0, and De had negative correlations with the Hausdorff dimension. To a certain extent, vibration reduced the local density regarding the pore distribution in the coal. As a result, the pore size distribution was more uniform, and the pore connectivity was improved, thereby enhancing the gas desorption and diffusion capacity of the coal.

Microscopic Mechanism of CO2 Displacement Oil in Different Pore Throat Radius Segments of Tight Sandstone Reservoirs.

The micropore structure of tight sandstone affects the efficiency of CO2 displacement of crude oil. As the pressure changes, the oil displacement efficiency (E d) in segments with different pore radii changes, and the asphaltene precipitation in the pores causes alterations in the pore structure and wettability, which constrain E d. Ten samples of tight sandstone from the Yanchang Formation in the Ordos Basin were selected for this study. A variety of methods, including X-ray diffraction (XRD), casting thin sections (CTS), scanning electron microscopy (SEM), high-pressure mercury intrusion (HPMI), CT scanning, and nuclear magnetic resonance (NMR) combined with CO2 displacement, were used to study the efficiency of crude oil utilization and the amount of asphaltene deposited at different pore-throat radii, and then the impacts of pressure, pore structure, and wettability changes on E d were discussed. The findings indicate that samples have three types: macropore-fine throats (MF), medium pore-tiny throats (MT), and small pore-microthroats (SM). The MT exhibits a favorable configuration. The pore-throat radius of each sample can be divided into two segments, namely, large pore segments (PL) and small pore segments (PS), and the PL has a significant E d. The E d of the MF-type PS is constrained by pressure. The E d of PL is significantly affected by the pressure sensitivity for the MT, while the E d of PL for the SM structure is more affected by pressure. Changes in wettability and the precipitation of asphaltene are the results of the reaction between crude oil and CO2. In the MF, asphaltene precipitates from the PL, while in the MT and SM, asphaltene precipitates both from the PL and PS. The amount of asphaltene precipitation strongly affects the E d in PS. The oil wettability increases more obviously with better pore-throat configurations. This study offers a reference and foundational understanding for evaluating CO2 displacement in tight sandstone reservoirs.

Applicability of a Fractal Model for Sandstone Pore-Fracture Structure Heterogeneity by Using High-Pressure Mercury Intrusion Tests

Pore structure heterogeneity affects the porosity and permeability variation of tight sandstone, thereby restricting sandstone gas production. In total, 11 sandstone samples were taken as a target in the northwest margin of the Junggar Basin. Then, scanning electron microscope and high-pressure mercury injection tests are used to study the distribution of a pore and fracture system in the target sandstone. On this basis, single and multifractal models are used to quantitatively characterize the heterogeneity of pore structure, and the applicability of the classification model in characterizing the heterogeneity of the pore-fracture structure is explored. The results are as follows. (1) The target samples are divided into two types, with the mercury removal efficiency of type A samples ranging from 44.6 to 51.8%, pore size mainly distributed between 100 and 1000 nm, and pore volume percentage ranging from 43 to 69%. The mercury removal efficiency of type B samples ranges from 14 to 28%, and pore diameter distribution is relatively uniform. (2) Different fractal models represent different physical meanings. The calculation results of sponge and thermodynamic fractal models indicate that the heterogeneity of pore structure distribution in the type B sample is significantly stronger than that in type A, which is inconsistent with the conclusions of the Sierpinski model. This is because the aforementioned two models characterize the complexity of pore surface area, while the Sierpinski model characterizes the roughness of pore volume. The comparison shows that there is a significant correlation between the thermal dimensionality value DT and the volume percentage of macropores and mesopores. Therefore, the thermodynamic model can better quantitatively characterize the heterogeneity of macropore and mesoporous pore distribution. (3) The results indicate that higher pore volume range is mainly influenced by mesopores and macropores. From the relationship curve between mercury removal efficiency and single fractal dimension, it can be seen that mercury removal efficiency is greatly affected by distribution heterogeneity of the lower value area of pore volume, and it has no obvious relationship with distribution heterogeneity in the lower value area of the pore volume.

Shale pore characteristics and their impact on the gas-bearing properties of the Longmaxi Formation in the Luzhou area

Deep shale has the characteristics of large burial depth, rapid changes in reservoir properties, complex pore types and structures, and unstable production. The whole-rock X-ray diffraction (XRD) analysis, reservoir physical property parameter testing, scanning electron microscopy (SEM) analysis, high-pressure mercury intrusion testing, CO2 adsorption experimentation, and low-temperature nitrogen adsorption–desorption testing were performed to study the pore structure characteristics of marine shale reservoirs in the southern Sichuan Basin. The results show that the deep shale of the Wufeng Formation Longyi1 sub-member in the Luzhou area is superior to that of the Weiyuan area in terms of factors controlling shale gas enrichment, such as organic matter abundance, physical properties, gas-bearing properties, and shale reservoir thickness. SEM is utilized to identify six types of pores (mainly organic matter pores). The porosities of the pyrobitumen pores reach 21.04–31.65%, while the porosities of the solid kerogen pores, siliceous mineral dissolution pores, and carbonate dissolution pores are low at 0.48–1.80%. The pores of shale reservoirs are mainly micropores and mesopores, with a small amount of macropores. The total pore volume ranges from 22.0 to 36.40 μL/g, with an average of 27.46 μL/g, the total pore specific surface area ranges from 34.27 to 50.39 m2/g, with an average of 41.12 m2/g. The pore volume and specific surface area of deep shale gas are positively correlated with TOC content, siliceous minerals, and clay minerals. The key period for shale gas enrichment, which matches the evolution process of shale hydrocarbon generation, reservoir capacity, and direct and indirect cap rocks, is from the Middle to Late Triassic to the present. Areas with late structural uplift, small uplift amplitude, and high formation pressure coefficient characteristics favor preserving shale gas with high gas content and production levels.

Pore Size Distribution and Fractal Characteristics of Deep Coal in the Daning-Jixian Block on the Eastern Margin of the Ordos Basin.

Important breakthroughs have recently been achieved in deep coalbed methane (CBM) exploration and development in regions such as the eastern margin of the Ordos Basin, China. Investigating the development characteristics of various-scale pores in deep coalbeds is of great significance for resource assessment and selection of favorable zones for CBM exploration. Herein, six deep coal samples were selected from the Shanxi and Taiyuan Formations in the Daning-Jixian block on the eastern margin of the Ordos Basin. Low-pressure CO2/N2 adsorption (LP-CO2/N2GA) and high-pressure mercury intrusion (HPMI) methods were employed to analyze pore volume, specific surface area, and pore size distribution, thereby evaluating the full-scale pore characteristics. Furthermore, the fractal dimension characteristics of deep coal rock pores were elucidated, revealing the influence of pore structure, burial depth, and coal composition. The results indicate that micropores in deep coal rocks have the highest volume and specific surface area proportions, while mesopores have the smallest volume proportion, and macropores make the least contribution to the total specific surface area. The V-S, Frenkel-Halsey-Hill, and Sierpinski models were suitable for calculating the fractal dimensions of micropores, mesopores, and macropores with LP-CO2GA, LP-N2GA, and HPMI experimental data, respectively. Other than the relatively smaller mesopore fractal dimension of samples 20-8 and 20-10, the micropore, mesopore, and macropore fractal dimensions successively increased in the other four samples. The comprehensive fractal dimension, which exhibited a decreasing trend with increasing pore volume and specific surface area, was negatively correlated with burial depth, mineral and moisture contents, and ash and volatile component yields, while it was positively correlated with vitrinite and fixed carbon contents.

Quantitative Characterization of Pore–Fracture Structures in Coal Reservoirs by Using Mercury Injection–Removal Curves and Permeability Variation under Their Constraints

Pore and fracture structure heterogeneity is the basis for coalbed methane production capacity. In this paper, high-pressure mercury intrusion test curves of 16 coal samples from the Taiyuan Formation in the Linxing area are studied. Based on the fractal dimension values of mercury intrusion and retreat curves, the correlation between the two different fractal parameters is studied. Then, the permeability variation of different types of coal samples is studied using overlying pressure pore permeability tests. The correlation between the permeability variation of coal samples and dimension values is explored, and the results are as follows. (1) Based on porosity and mercury removal efficiency, all coal samples can be divided into three types, that is, types A, B, and C. Among them, Type A samples are characterized by lower total pore volume, with pore volume percentages ranging from 1000 to 10,000 nm not exceeding 15%. (2) During the mercury injection stage, both the M-model and S-model can reflect the heterogeneity of seepage pore distribution. In the mercury removal stage, the M-model cannot characterize the heterogeneity of pore size distribution in each stage, which is slightly different from the mercury injection stage. (3) The permeability of Type A samples is most sensitive to pressure, with a permeability loss rate of up to 96%. The original pore and fracture structure of this type of coal sample is relatively developed, resulting in a high initial permeability. (4) There is no significant relationship between compressibility and fractal dimension of mercury injection and mercury removal, which may be due to the comprehensive influence of pore structure on the compressibility of the sample.

Effect of reservoir composition and structure on spontaneous imbibition: a case study of Shahejie Formation shale in Zhanhua Sag, Bohai Bay Basin

Spontaneous imbibition has a certain impact on the oil and gas recovery of shale reservoirs. However, the current research on the influence of mineral composition and pore structure on spontaneous imbibition is not sufficiently comprehensive and lacks quantitative evaluation. Therefore, this study employed experimental methods combining X-ray diffraction, scanning electron microscopy, high-pressure mercury intrusion, nuclear magnetic resonance, and spontaneous imbibition to qualitatively and quantitatively characterize the influence of mineral composition, content, and pore structure characteristics on spontaneous imbibition. The results indicate that the relationship between quartz, calcite, and clay minerals and the imbibition slope exhibits a two-stage distribution (with critical values of 25%, 40%, and 20%, respectively). With the increase in mineral content, the imbibition slope first increases and then decreases. Additionally, pore structure parameters such as average pore throat radius, sorting coefficient, and structural coefficient show a positive correlation with the imbibition slope. Furthermore, small pores contribute significantly during the early imbibition stage, while medium to large pores serve as the main flow channels during the diffusion stage. This study quantitatively evaluates the relationship between fluids and minerals, providing a theoretical basis for understanding the complex interaction between fluids and minerals.

Research on the Diagenetic Facies Division and Pore Structure Characteristics of the Chang 63 Member in the Huaqing Oilfield, Ordos Basin.

In tight sandstone reservoirs, diagenesis has a significant impact on the development of reservoirs and pore structures. To clarify the effect of diagenesis on the pore structure of tight sandstone, 12 samples of the Yanchang Formation in the basin were studied based on experiments such as high-pressure mercury intrusion and low-temperature nitrogen adsorption. The diagenetic facies in the study area are divided into two categories: strong cementation facies of carbonate minerals and strong compaction facies of soft component minerals, which are relatively unfavorable diagenetic facies, and stable facies of felsic minerals and strong dissolution facies of feldspar minerals, which are dominant diagenetic facies. The pore structure of the Chang 63 reservoir in the study area has obvious fractal characteristics, with a fractal dimension D 1 greater than D 2 and a greater heterogeneity of large pore throats. Compared to compaction and cementation, dissolution has a stronger controlling effect on the pore structure of reservoirs. In tight sandstone reservoirs with low porosity and permeability, dissolution has a more important impact on reservoir transformation and development. The intensity of different types of diagenesis in the Chang 63 reservoir affects reservoir heterogeneity, and the level of the reservoir heterogeneity affects the complexity of reservoir pore structure. In tight sandstone reservoirs, cementation has a stronger controlling effect on the structural complexity of large pores, while dissolution has a stronger controlling effect on the structural complexity of small pores. The dissolution has a strong control effect on the physical properties of the reservoir. This study provides insights into the relationships among the diagenetic facies, reservoir quality, and pore structure of tight sandstone reservoirs. This study has reference significance for the exploration and development of tight oil in the research area.

Porosity and pore structure evolution during the weathering of black shale

Pore type and pore structure evolves systematically across continuous black shale weathering profile. However, the extend and process of pore structure change is still an enigma. In this study, we try to unveil the pore structure evolution during weathering process through studying Cambrian Hetang shales in southern China. Fourteen shale samples, from protolith zone (PZ), fractured and weathered shale zone (FWZ), and saprolite zone (SZ), were collected to elucidate how porosity and pore structure develop during black shale weathering under subtropical condition. Through low pressure argon (Ar) gas adsorption (LP-ArGA), high pressure mercury intrusion (HPMI), nuclear magnetic resonance(NMR) and field emission scanning electron microscope (FESEM) observation, the results reveal significant differences in physical properties and pore structures among the PZ, FWZ, and SZ samples. Specifically, compared to PZ, FWZ and SZ samples are characterized by higher clay mineral content, lower organic matter (OM), and the absence of carbonates and pyrite. Total porosity, determined through HPMI and NMR, exhibits a gradual increase from PZ (6.70 % and 6.41 %) to FWZ (20.47 % and 13.45 %) and SZ (23.22 % and 12.48 %). Ar adsorption isotherms indicate a change in pore type from predominantly ink-bottle and slit-shaped in the PZ to mainly slit-shaped in FWZ and SZ. Integrated analysis of LP-ArGA, HPMI, NMR and SEM observation suggests a substantial decrease in the contribution of micropores to total pore volume (PV) and a concurrent increase in larger pores (meso-macropores) with the increase of weathering intensity. This results in smoother surfaces of micro-transition pores but rougher surfaces of macropores. Changes in mineralogy composition during weathering play a crucial role in influencing pore structure of shales and further accelerating the release and migration of toxic elements in black shale. Our study provides the essential theoretical foundation for the remediation of soil and water environmental pollution caused by black shale weathering.

Porosity Characteristics of Coal Seams and the Control Mechanisms of Coal Petrology in the Xishanyao Formation in the Western Part of the Southern Junggar Basin

The porosity characteristics of coal seams serve as a pivotal factor in assessing the development potential of coalbed methane (CBM) resources, significantly influencing the adsorption and permeability capabilities of coal reservoirs, as well as the accumulation, entrapment, and preservation of CBM. In this study, we focused on the coal seams of the Xishanyao Formation in the western part of the southern Junggar Basin (NW China). By leveraging the complementarity of nuclear magnetic resonance (NMR), low-temperature liquid nitrogen experiments, and high-pressure mercury intrusion porosimetry (MIP) in spatial exploration range and precision, we conducted a comprehensive analysis to achieve a fine description of porosity characteristics. Furthermore, we explored the coal petrology factors controlling the pore characteristics of the Xishanyao Formation, aiming to provide geological evidence for the selection of favorable areas and the development potential evaluation of CBM in the study area. The results indicate the following: (1) The total pore volume of the coal samples is 6.318 × 10−3 cm3/g on average, and the micropore volume accounts for a relatively high proportion (averaging 44.17%), followed by the fine pores (averaging 39.41%). The average porosity is approximately 3.87%, indicating good gas storage and connectivity of the coal seams, albeit with some heterogeneity. The coal reservoir is dominated by micropores and fine pores with diameters less than 100 nm, and the pore structure is characterized by low pore volume and high pore area. (2) The pore structure is influenced by both the coalification degree and the coal maceral. Within the range of low coalification, porosity increases with the increase in coalification degree. Building upon this, an increase in the vitrinite content promotes the development of micropores and fine pores, while an increase in the inertinite content promotes the development of meso–macropores. The clay mineral content exhibits a negative correlation with the adsorption pore volume ratio and a positive correlation with the seepage pore volume ratio.

Quantitative Description of Pore and Fracture Distribution Heterogeneity Using Mercury Removal Curve and Applicability of Fractal Models

Many studies have used fractal theory to characterize pore structure distribution heterogeneity through mercury intake curves. However, there is relatively little research on the fractal model calculation of mercury removal curves. In this study, a high-pressure mercury intrusion test is used to describe the pore and fracture distribution heterogeneity (PFDH). The fractal physical meaning of the mercury removal curve was determined by calculating the change in the curve’s fractal dimension value. The results are as follows. (1) According to mercury removal efficiency and porosity, samples can be divided into types A (mercury removal efficiency above 35%) and B (mercury removal efficiency below 35%). In general, type A sample belongs to micro-pore-developed types, and type B samples belong to the macro-pore-developed type. (2) The Menger model (M) represents the complexity of a specific surface area, while the Sierpinski model (S) represents the roughness of the pore volume. Among all the samples, the lower-pore-volume region controls PFDH. (3) According to the calculation results of the single fractal model, it can be seen that the PFDH of type B is stronger than that of type A, which is similar to the results of mercury intrusion. According to the calculation structure of the multifractal model, it can be seen that the volume distribution heterogeneity of type B under various pores is significantly stronger than that of type A. This is opposite to the result of mercury injection. (4) DM has a relationship with the pore volume percentage at different stages, so the M model at the mercury inlet stage can better characterize PFDH at the mercury inlet stage.

Influence of coal rock on tight sandstone reservoirs in coal seam roofs: A case study of the lower jurassic in the Taibei sag, Turpan-Hami Basin, China

After shale gas, coalbed methane and gas hydrate, coal measure gas has become an important new unconventional resource, for which exploration to depths of >3000 m are taking place in China. However, owing to unusual geological conditions and as yet inadequate exploration technology the current level of exploration is low. The acidic water medium in coal-bearing strata affects the diagenesis of adjacent tight sandstone reservoirs, thereby influencing reservoir quality. However, the current understanding of the impact mechanism of coal seams on neighboring tight reservoirs is insufficient, constraining the further exploration of coal measure gas. In order to reveal the influence of coal rock on a tight sandstone reservoir in its roof, we study the coal-bearing strata of the Xishanyao Formation in the Taibei Sag of the Turpan-Hami Basin using cast thin sections, physical property tests, XRD analysis, carbon and oxygen isotopes, high-pressure mercury intrusion and low-temperature N2 adsorption. The carbonate cement in the sandstone reservoir of the coal seam roof was formed by the decarboxylation of organic acid. The organic acid, containing CO2 generated by coal rock hydrocarbon generation, has modified the tight sandstone reservoir of the coal seam roof via dissolution. This has improved the physical properties and pore throat structure of the tight sandstone reservoir close to the coal-sandstone interface. The amount of improvement extends to about 2 m into the sandstone. During the upward transport of fluid, the pre-existing carbonate cement dissolves and then precipitates, which causes the CO2 generated by the organic acid decarboxylation to exchange carbon with the carbon isotopes in the pre-existing carbonate cement. Due to the slow upward diffusion rate and limited diffusion distance of the CO2-bearing fluids, the carbonate cement exhibits gradually heavier δ13CPDB values with increasing distance from the coal-sandstone interface.

Pore Structure Characteristics and Reservoir Classification of Tight Sandstones within the Upper Permian Longtan Formation in the Laoshan Uplift, South Yellow Sea Basin: Implications for Hydrocarbon Exploration

The Upper Permian Longtan Formation in the Laoshan Uplift of the South Yellow Sea Basin hosts thick and distinctive tight sandstones. However, a comprehensive understanding of its pore structure and reservoir classification remains lacking. This study investigates the fully cored well, CSDP-2, utilizing thin section analysis, scanning electron microscopy, energy spectrum analysis, X-ray diffraction, high-pressure mercury intrusion, and nuclear magnetic resonance to characterize its petrophysical properties, pore space, and movable fluid characteristics. Additionally, fractal principles are further employed to examine reservoir heterogeneity and conduct a quantitative assessment, considering the complexity of tight sandstone pore structures. The findings reveal that the sandstones predominantly comprise feldspathic litharenites, with an average porosity of 1.567% and permeability of 0.099 mD, primarily containing intragranular pores. Two distinct sets of pores with significantly different sizes (r &lt; 2 μm; r &gt; 6 μm) were identified, displaying relatively high fractal dimensions and discrete distribution. Movable fluids primarily occupy pores with radii &gt; 0.019 μm, reflecting pronounced overall heterogeneity. The reservoir was classified into three categories utilizing permeability, median radius, and movable fluid saturation as key evaluation parameters, with Class I representing a relatively high-quality reservoir. These findings advance our understanding of the pore development mechanism of tight sandstone reservoirs and provide geological evidence for further hydrocarbon exploration in this study area.

Pore structure characterization and its influence on aqueous phase trapping damage in tight gas sandstone reservoirs.

Aqueous phase trapping (APT), which is one of the most prominent damages, seriously restricts the natural gas production in tight gas sandstone with low permeability. Pore size and microscopic pore structures are the most important factors to determine the water blocking damage. In this paper, 9 core samples from tight gas sandstone with various physical properties were employed, and the pore size distribution (PSD) of the core samples were investigated by high pressure mercury intrusion tests (HPMI). Results showed that the porosity of core samples ranges from 5.68% to 13.7%, and the permeability ranges from 0.00456 to 7.86 mD, which is a typical tight reservoir with strong heterogeneity. According to the HPMI capillary curve, the cores can be divided into two types: Type I and Type II, and the pore sizes of type I are larger than that of type II. Fractal distributions were obtained using HPMI data to further determine the pore structure characteristics of tight reservoirs. The pore structures of tight sandstones display the multifractal fractal feature: D1 corresponding to macro-pores, and D2 corresponding to fractal dimension of micro-pores. Furthermore, APT damage was determined by the permeability recovery ratios (Kr) after gas flooding tests. The correlation of Kr and PSD and fractal dimensions were jointly analyzed in tight gas sandstone. Although positive correlations between pore size parameters and the permeability recovery ratios were observed with relatively weak correlations, for those core samples with very close permeability, pore size parameters (both permeability and PSD) is inadequate in clarifying this damage. The fractal dimension can well describe the complexity and heterogeneity of flow channels in pores, which can become the determining factor to distinguish the flow capacity of tight sandstone. The D2 for samples of type I and type II exhibited a good negative relation with Kr with a correlation coefficient of 0.9878 and 0.7723, respectively. The significance of this finding is that for tight gas sandstone, fractal dimensions, especially the small pore fractal dimension (D2), can be used to predict the possible APT damage very well.

Full-Scale Pore and Microfracture Characterization of Deep Coal Reservoirs: A Case Study of the Benxi Formation Coal in the Daning–Jixian Block, China

The pore-fracture structure of deep coal reservoirs is highly important for evaluating, exploring, and developing coalbed methane (CBM) resources. This study considers three coal samples from the DJ57 well in the Benxi Formation in the Daning–Jixian block on the eastern margin of the Ordos Basin as the research object. Based on the coal quality parameters of the coal samples, field emission scanning electron microscopy (FE-SEM), gas adsorption experiments, high-pressure mercury intrusion porosimetry (MIP), and microcomputed tomography (micro-CT) scanning were used to quantitatively characterize the nanoscale pores and microscale fractures in deep coal reservoirs and to evaluate the pore-fracture structure at different scales. The results reveal that the pore types in the Benxi Formation coal samples are diverse and include mainly organic matter (OM) pores, inorganic pores (intraparticle and interparticle pores), and microfractures. The organic pores are diverse in shape and mainly exhibit round, oval, and wedge shapes, while the microfractures exhibit slender stripes or serrated curves. The multiscale quantitative characterization of deep coal reservoir pores and fractures is based on a variety of pore characterization methods, and the pore and fracture volume distributions are mainly U-shaped, revealing the coexistence of micropores and microfractures. The volumes of micropores (0.3–2 nm), mesopores (2–50 nm), macropores (50 nm to 10 μm), and microfractures (&gt;10 μm) account for 78.00%, 6.78%, 2.08%, and 13.14%, respectively, of the total pore volume (PV). Based on a full-scale pore-fracture splicing calculation, the total permeability of the Benxi Formation coal samples ranges from 5.77 to 28.22 mD. The observation results indicate that the microfractures are connected to each other, forming a network structure with strong connectivity. The microfractures are mainly associated with pore diameters&gt;100 μm, accounting for approximately 95% of the total permeability. Moreover, micropores in deep coal reservoirs provide a large space for CBM adsorption, and microfractures enhance the seepage capacity of CBM.

Pore throat distributions and movable fluid occurrences in different diagenetic facies of tight sandstone reservoirs in the Triassic Chang 6 reservoirs, Wuqi Area, Ordos Basin, China

The 6th member of the Triassic Yanchang Formation, hereafter referred to as Chang 6 reservoir, in the Wuqi area of the Ordos Basin presents formidable obstacles for efficient tight oil development. This reservoir is known for its tight lithology, strong heterogeneity, inadequate oil saturation, and abnormally low reservoir pressure, which collectively contribute to the highly differentiated mobility of tight oil within the formation. To overcome these challenges, a comprehensive understanding of the factors influencing oil mobility is essential. This study investigates the occurrence characteristics of movable fluids in different diagenetic facies and the corresponding influential factors by employing various microscopic experiments, including high-pressure mercury intrusion, constant-rate mercury intrusion, nuclear magnetic resonance test, scanning electron microscopy, pore-casted thin section analysis, and X-ray diffraction measurement. There is a weaker correlation between the pore-throat radius ratio and the movable fluid saturation in reservoirs of various diagenetic facies (R2 = 0.6104), whereas there is a stronger correlation between movable fluid saturation and throat radius (R2 = 0.9415). Among the seven types of diagenetic facies, chlorite membrane cementation-intergranular pore facies (Facies I) and chlorite and illite membrane cementation-intergranular pore facies (Facies II) have the best-developed throats and the highest coordination number. Illite cementation-intergranular pore facies (Facies III) and illite and chlorite membrane cementation-dissolution facies (Facies IV) demonstrate smaller pore-throat radii and moderate to poor reservoir connectivity. The other three facies, namely illite cementation-dissolution facies (Facies V), illite cementation facies (Facies VI), and carbonate tight cementation facies (Facies VII) exhibit underdeveloped pore structures and lower recovery rates. Pore-throat radius emerges as the principal factor influencing reservoir permeability and storage capacity. The distribution of favorable diagenetic facies is influenced by depositional environments, diagenetic processes, and microscopic pore-throat characteristics. This study significantly enhances our understanding of the differential occurrence characteristics of fluids in different diagenetic facies in the Chang 6 reservoir, providing valuable insights for future exploration and production endeavors aimed at optimizing oil recovery in tight sandstone reservoirs.

Influences of lithofacies on fluid mobility in mixed sedimentary rocks: Insights from NMR analysis of the middle Permian Lucaogou Formation, Junggar Basin

The multi-source mixed sedimentation resulted in a unique series of mixed fine-grained sedimentary rocks evolved within the Permian Lucaogou Formation in the Jimusar Sag, located in the southeastern Junggar Basin, China. The variety of lithofacies within this series resulted in pronounced heterogeneity of pore structures, complicating the analysis of fluid occurrence space and state within reservoirs. As a result, the impact of lithofacies on fluid mobility remains ambiguous. In this study, we employed qualitative methods, such as field emission scanning electron microscopy (FE-SEM) and thin section observation, and quantitative analyses, including X-ray diffraction (XRD), total organic carbon (TOC), vitrinite reflectance (Ro), high-pressure mercury intrusion (HPMI) porosimetry, and nuclear magnetic resonance (NMR), along with linear and grey correlation analyses. This approach helped delineate the effective pore characteristics and principal factors influencing movable fluids in the fine-grained mixed rocks of the Lucaogou Formation in the Jimusar Sag, Junggar Basin. The findings indicate the development of three fundamental lithologies within the Lucaogou Formation: fine sandstone, siltstone, and mudstone. Siltstones exhibit the highest movable fluid saturation (MFS), followed by fine sandstones and mudstones sequentially. Fluid mobility is predominantly governed by the content of brittle minerals, the sorting coefficient (Sc), effective pore connectivity (EPC), and the fractal dimension (D2). High content of brittle minerals favors the preservation of intergranular pores and the generation of microcracks, thus offering more occurrence space for movable fluids. A moderate Sc indicates the presence of larger connecting throats between pores, enhancing fluid mobility. Elevated EPC suggests more interconnected pore throat spaces, facilitating fluid movement. A higher D2 implies a more intricate effective pore structure, increasing the surface area of the rough pores and thereby impeding fluid mobility. Ultimately, this study developed a conceptual model that illustrates fluid distribution patterns across different reservoirs in the Lucaogou Formation, incorporating sedimentary contexts. This model also serves as a theoretical framework for assessing fluid mobility and devising engineering strategies for hydrocarbon exploitation in mixed fine-grained sedimentary rocks.

Coevolutionary Diagenesis in Tight Sandstone and Shale Reservoirs within Lacustrine-Delta Systems: A Case Study from the Lianggaoshan Formation in the Eastern Sichuan Basin, Southwest China

Tight sandstone and shale oil and gas are the key targets of unconventional oil and gas exploration in the lake-delta sedimentary systems of China. Understanding the coevolutionary diagenesis of sandstone and shale reservoirs is crucial for the prediction of reservoir quality, ahead of drilling, in such systems. Thin-section description, scanning electron microscopy (SEM), X-ray diffraction (XRD), fluid inclusion analysis, porosity and permeability tests, high-pressure mercury intrusion (HPMI) measurements and nuclear magnetic resonance tests (NMR) were used to reveal the coevolutionary diagenetic mechanisms of a sandstone and shale reservoir in the Lianggaoshan Formation of the Eastern Sichuan Basin, China. The thermally mature, organic-matter-rich, dark shale of layer3 is the most important source rock within the Lianggaoshan Formation. It started to generate abundant organic acids at the early stage of mesodiagenesis and produced abundant hydrocarbons in the early Cretaceous. Porewater with high concentrations of Ca2+ and CO32− entered the sandstone reservoir from dark shale as the shale was compacted during burial. Potassium feldspar dissolution at the boundary of the sandstone was more pervasive than at the center of the sandstone. The K+ released by potassium feldspar dissolution migrated from the sandstone into mudstone. Grain-rimming chlorite coats occurred mainly in the center of the sandstone. Some silica exported from the shale was imported by the sandstone boundary and precipitated close to the shale/sandstone boundary. Some intergranular dissolution pores and intercrystal pores were formed in the shale due to dissolution during the early stages of mesodiagenesis. Chlorite coats, which precipitated during eodiagenesis, were beneficial to the protection of primary pore space in the sandstone. Calcite cement, which preferentially precipitated at the boundary of sandstone, was not conducive to reservoir development. Dissolution mainly occurred at the early stage of mesodiagenesis due to organic acids derived from the dark shale. Calcite cement could also protect some primary pores from compaction and release pore space following dissolution. The porosity of sandstone and shale was mainly controlled by the thickness of sandstone and dark shale.