Mercury Intrusion Capillary Pressure Research Articles

Quantifying Organic Matter and Its Pore Structure of Wufeng–Longmaxi Deep Shales by Small-Angle X-ray Scattering, Mercury Intrusion Capillary Pressure, and Field-Emission Scanning Electron Microscope

Quantifying Organic Matter and Its Pore Structure of Wufeng–Longmaxi Deep Shales by Small-Angle X-ray Scattering, Mercury Intrusion Capillary Pressure, and Field-Emission Scanning Electron Microscope

Diagenesis as a control on the tight sandstone reservoir quality of the upper Carboniferous strata in the northeastern Ordos basin, China

The upper Carboniferous tight sandstone strata are considered the most promising targets for gas exploration in the northeastern Ordos Basin. Reservoir quality is critical for the successful commercial exploration and development of tight sandstone gas. Reservoir quality of deeply buried tight sandstones is controlled by diagenesis, yet there is sparse systematic documentation on upper Carboniferous tight sandstone reservoir quality and its diagenetic link. In this study, we utilized core analysis and wireline log data, and core samples were studied using X-ray diffraction, optical light microscopy, scanning electron microscopy, porosity–permeability, mercury intrusion capillary pressure and nuclear magnetic resonance measurements. Dolomite, siderite, quartz, kaolinite, and illite are the main diagenetic cements. The upper Carboniferous sandstones pore system consists of residual intergranular pores, intragranular dissolution pores associated with feldspar grains and micropores mainly related to diagenetic minerals. Due to differences in diagenetic alterations, sandstones have significant differences in pore types and pore-filling components, ultimately leading to differences in reservoir quality. The residual intergranular porosity is closely related to the reservoir quality. Quartz cement and authigenic clay minerals lead to reduced residual intergranular porosity, but their impact on reservoir quality is relatively limited due to their relatively low content. The most significant factors contributing to reservoir quality deterioration are ductile (clay-rich) grain-influenced compaction and pervasive pore-filling carbonate cement. When sandstone contains large numbers of ductile grains, it loses a large amount of intergranular porosity due to compaction, and the pore space contains only a small number of dissolution pores and micropores, resulting in reservoir quality deterioration. Similarly, when a large amount of carbonate cement is developed in sandstone, it leads to intergranular porosity loss. The best reservoir quality sandstones preserve a percentage of intergranular porosity because they (i) have few ductile grains, resulting in low compaction, and (ii) do not have significant amounts of carbonate cements. Finally, the diagenetic variations were successfully correlated with wireline logs to evaluate the reservoir quality of subsurface upper Carboniferous sandstones. The data sets provided in this research offer insights to better evaluate and predict reservoir quality in the northeastern Ordos Basin.

Effect of X‐Ray Computed Tomography Imaging Parameters on Quantification of Petrophysical Properties

AbstractThree‐dimensional (3D) X‐ray computed tomography (X‐ray CT) imaging has emerged as a nondestructive means of microstructural characterization. However, obtaining and processing high‐quality and high‐resolution images is time‐consuming and often requires high‐performance computing, particularly with a high number of projections. This work evaluates the effect of 3D X‐ray CT imaging parameters on pore connectivity and surface area quantification in sandstone samples of varied composition. Samples from Bentheimer and Torrey Buff formations are imaged via 3D X‐ray CT imaging at resolutions ranging from 1.25 to 15 μm, bin sizes 1, 2, and 4, and number of projections from 400 to 4,500. Collected images are processed and analyzed using ImageJ and MATLAB to discern petrophysical properties and the results are compared with each other and Mercury Intrusion Capillary Pressure (MICP) results. Overall, little variation in bulk porosity with changing scanning parameters is observed. However, for low resolution and projection numbers, connected porosity is lower compared to bulk porosity due to a failure to capture microfeatures. Overall, mineral surface area is observed to decrease with increasing bin size, voxel size, and projection numbers, except an observed increase with projection numbers for Torrey Buff. The Torrey Buff samples contains comparatively more clays and even the highest resolution (1.25 μm) fails to separate the micrograins, which is reflected in the pore size distribution. Identifying these variations are helpful as discrepancies in imaged pore connectivity and surface area can largely impact assessments of fluid flow and transport in reactive transport simulations informed by this data.

Pore connectivity and microfracture characteristics of Longmaxi shale in the Fuling gas field: Insights from mercury intrusion capillary pressure analysis

Assessing the connectivity of pores and the characteristics of microfractures is essential for comprehending gas migration mechanisms and effectively implementing development strategies in deep shale gas plays. The Fuling gas field, a prominent shale gas reservoir in China, holds promise for deep shale development. This requires a better understanding of variations in pore connectivity among shale samples from different depths of the Fuling gas field. To achieve this goal, this study employs innovative methodologies based on mercury intrusion capillary pressure (MICP), a recognized technique for evaluating material pore structures. In this research, we conducted MICP tests on shale samples of varying sizes to examine variations in pore structure and quantify inaccessible pores. Additionally, repeated MICP tests were performed on the same sample to investigate the spatial distribution of residual mercury and distinguish different pore types associated with flow conduits and storage spaces. Furthermore, a directional MICP experiment was carried out to quantitatively characterize the degree of pore development and anisotropy of microfractures by considering the direction of mercury intruding the sample (parallel or perpendicular to lamination). Our findings revealed that deep shale samples exhibited a higher proportion of inaccessible pores compared to mid-deep ones. Regarding accessible pores, a greater proportion of connected pores was observed in the deep shale samples, while the mid-deep shale samples exhibited a lower proportion. The results from the directional MICP experiment indicated that samples with anisotropy in mercury intrusion volume possessed finer and denser microfractures. However, no evidence was found to correlate the ratio of dead-end and connected pores with sample anisotropy. Overall, this study presents a novel approach for experimentally evaluating pore connectivity and microfracture characteristics in shale reservoirs using MICP. The outcomes contribute to enhancing our understanding of shale gas migration mechanisms, particularly in deep ultra-low-permeability reservoirs, and hold significant implications for future developments in the field.

The importance of pore-fracture connectivity in overmature marine shale for methane occurrence and transportation

Pore-fracture connectivity is a critical factor in gas occurrence and transportation in shale plays. To investigate the limiting factors of multiscale pore-fracture connectivity, which might control methane occurrence and transportation in shale reservoirs, small-angle neutron scattering (SANS) under vacuum and high-pressure conditions incorporated with repeated mercury intrusion capillary pressure (MICP), and field emission-scanning electron microscopy (FE-SEM) imaging after Wood's metal (WM) impregnation were performed on overmature marine shale samples of the Wufeng-Longmaxi and Niutitang Formations from south China. Based on the electron micrographs of the WM-injected samples, it was found that the sealing of the pore system by brittle minerals is the root cause for a reduction in overall pore connectivity within the shale matrix. Aside from being favorable to the preservation of organic and clay mineral pores, brittle minerals however, resulted in the closure of pore network, thus, forming an isolated pore system. The novel approach of integrating repeated MICP measurement and FE-SEM imaging after WM impregnation provides a new evaluation method for pore-fracture connectivity of shale. The minimum fraction of pores within the overmature shales accessible to methane was at 38% and 78% within 100 nm. Moreover, because of confinement effects, the density of methane in a pore space less than 20 nm under high pressure was greater than that of an ideal gas under the same pressure conditions which even increased with decreasing of pore size to several times of its inert state and formed nanoscale methane clusters. The combination of contrast-matching SANS (CM-SANS) and repeated MICP measurements can effectively reveal the connectivity of pores within the matrix and the connectivity between such pores and microfractures, which helps to evaluate the distribution of closed pores and dominant transport spaces of gas in shale reservoirs. Overall, the pore-fracture connectivity in overmature marine shale controls the amount of gas that is supplied from matrix pores into fracture systems and also affects the density of the gas in pore spaces within the matrix.

Effects of Supercritical CO2 on the Pore Structure Complexity of High-Rank Coal with Water Participation and the Implications for CO2 ECBM.

To reveal how mineral changes affect a coal pore structure in the presence of water, an autoclave was used to carry out the supercritical CO2 (ScCO2)-H2O-coal interaction process. To reveal the changes in pore complexity, mercury intrusion capillary pressure (MICP), low-pressure nitrogen adsorption, CO2 adsorption, and field emission scanning electron microscopy (FESEM) experiments were combined with fractal theory. The experimental data of MICP show that the MICP data are meaningful only for the pore fractal dimension with pore sizes >150 nm. Therefore, the pores were classified into the classes >150, 2-150, and <2 nm. The results show that the pore volume and specific surface area of the coal increased significantly after the reaction. ScCO2-H2O can cause the formation of many new pores and fractures in the coal. The presence of H2O may increase the potential for the injection of CO2 into the coal seam. The complete dissolution of calcite surfaces caused a significant increase in the pore volume and specific surface area of the pores >150 nm. The morphologies of these pores are controlled by the morphologies of the complete dissolution carbonate particles. The pore morphologies were relatively uniform, and the fractal dimensions decreased. However, the incomplete dissolution of calcite leads to irregular variations in the morphologies for the pores in the 2-150 nm pore size range. The pore morphologies that are produced by incompletely dissolved calcite particles are more complex, which increases the fractal dimensions after the reaction. The fractal dimensions of the pores <2 nm decreased after the reaction, indicating that the newly generated micropores were more uniform and had regular pore morphologies.

Characterizations of Middle–Lower Triassic Reservoir Quality and Gas Accumulations in the Northeastern Margin of the Ordos Basin, China

New Middle–Lower Triassic gas reservoirs were found in the eastern margin of the Ordos Basin, which provides new possibilities for gas exploration in the Ordos Basin. However, there are few relevant studies on these gas reservoirs. In this study, we use porosity–permeability measurements, optical light microscopy, scanning electron microscopy, mercury intrusion capillary pressure experiments, core-scale low-field nuclear magnetic resonance experiments, fluid inclusion analysis, burial history reconstruction, organic geochemistry data, and wireline log data to systematically investigate the reservoir quality and accumulation pattern of Middle–Lower Triassic gas reservoirs. The Middle–Lower Triassic sandstones are mostly lithic arkose, with a small amount of feldspathic litharenite. In comparison to the upper Paleozoic tight sandstone, the Middle–Lower Triassic sandstones exhibit a superior pore structure and increased porosity and permeability. A significant portion of the Middle–Lower Triassic sandstones can be referred to as “conventional sandstones” (porosities >12% and permeabilities >1 mD). The source rocks of the Middle–Lower Triassic gas reservoirs are most likely the upper Paleozoic coal and organic-rich mudstone, and the accumulation of natural gas occurred in the Early Jurassic to Late Cretaceous. The gas accumulation in the sandstones of the Middle–Lower Triassic reservoirs was mainly driven by buoyancy. The initiation and extension of vertical faults with small displacement in the northeast margin of the Ordos Basin enabled gas to move through the faults from the deep upper Paleozoic source rocks to the Middle–Lower Triassic reservoirs. Since gas accumulation relies on buoyancy, conventional sandstone layers with good reservoir properties are more likely to reach high gas saturation and are the primary targets for exploration and development.

Pore Distribution Characteristics of Different Lithofacies Shales: Evidence from Scanning Electron Microscopy

To disclose the pore distribution characteristics of different lithofacies lacustrine shales, ten samples collected from the Shahejie Formation, Dongying Sag, Bohai Bay Basin, China, were examined using argon ion beam milling–scanning electron microscopy (SEM). A quantitative method was adopted to characterize shale pore distributions based on the SEM images. Mercury intrusion capillary pressure was employed to determine the pore throat size distributions of the shales. The SEM images indicated that in shale reservoirs, interparticle pores at the edges of brittle particles and intraparticle pores in clay mineral aggregates primarily contribute to the reservoir spaces and that in calcite-rich shales, dissolution pores provide secondary reservoir space. Among the morphologies of dissolution, intraparticle, and interparticle pores, the morphology of the dissolution pores is the simplest, followed by those of intraparticle and interparticle pores in that order. Clay and felsic minerals primarily control the shale pore sizes and the larger the clay mineral content in the shales, the smaller their pore size; the felsic minerals demonstrate the opposite behavior. The image-based point counting data indicate that shale pore sizes are mostly between 20 nm and 2 μm. In contrast, most pore throats are less than 20 nm in diameter, implying that the pores in the nanometer to micrometer scales are connected by tiny throats. Among the four lithofacies shales, felsic-rich shales are favorable for shale oil accumulation and seepage because of their large pore sizes and throats their ability to form intercalated shale oil adjacent to organic-rich shales. Calcareous shales with a large number of dissolution pores and a large content of organic matter could produce self-generation and self-storage matrix shale oil and would typically develop fractures, thereby creating a seepage channel for shale oil. This study presents the micro-distributions of different lithofacies of shale pores, which would help in understanding the occurrence and seepage of oil in shale reservoirs.

Lithofacies and Diagenetic Controls on Tight Silty and Sandy Upper Triassic Reservoirs of the Heshui Oil Field (Ordos Basin, North China)

Summary Tight oil, present in reservoirs of low porosity and permeability, can be regarded as a kind of unconventional resource. The tightening process in this kind of reservoir is controlled by the lithology and diagenetic history of the host formation. Upper Triassic Yanchang Formation siltstones and sandstones are the main reservoirs for hydrocarbon accumulation in the Heshui Oil Field (HOF), southwestern Ordos Basin. The reservoirs exhibit low porosity, low permeability, and strong heterogeneity. In recent years, numerous drillcores have been recovered from these units, but the porosity-permeability characteristics and burial history of these silty and sandy reservoirs have not yet been reported in detail. In this study, an integrated analysis of the lithofacies, diagenesis, and reservoir characteristics of the siltstones and sandstones was achieved using a combination of core and thin section, grain size, scanning electron microscopy (SEM), X-ray diffraction (XRD), δ13C and δ18O, mercury intrusion capillary pressure (MICP), and porosity and permeability data. Our primary goals were to quantify the porosity-permeability characteristics of these silty and sandy reservoirs, restore their diagenetic histories, and examine the paragenetic relationship of reservoir tightness to hydrocarbon accumulation. The silty and sandy reservoirs represent braided river delta facies consisting of compositionally and texturally immature sediments. In the burial environment, they underwent complex diagenetic processes that reduced porosity from an initial average of ~38% to the present ~8%. Porosity-destructive processes included compaction (~ –12.5%) and cementation (~ –21%), with increases in porosity related to grain dissolution (~ +2.2%) and tectonic fractures (~ +1.1%). The reservoirs underwent four diagenetic stages: (1) Penesyngenetic and Eogenetic A Stage (Late Triassic-Early Jurassic); (2) Eogenetic B Stage (Late Jurassic); (3) Early Mesogenetic A Stage (Early Cretaceous); and (4) Late Mesogenetic A Stage (Late Cretaceous to recent). Hydrocarbon charging of these reservoirs occurred in three pulses. Existing pore space was partly filled by hydrocarbons during the Eogenetic B Stage. A second hydrocarbon charging event occurred during the Early Mesogenetic A Stage, when residual primary intergranular pores and secondary dissolution pores were filled. A third hydrocarbon charging event occurred during the Late Mesogenetic A Stage, when the reservoirs were tight. Siltstone beds deposited in delta front environments are the main future exploration targets in the Chang 6 to 8 members. The results of this study provide a useful reference framework for future exploration of hydrocarbon resources in the Upper Triassic Yanchang Formation of the HOF, as well as potential insights into the evolution of similarly tight reservoirs in other basins.

Impact of sedimentation and diagenesis on deeply buried sandy conglomerate reservoirs quality in nearshore sublacustrine fan: A case study of lower Member of the Eocene Shahejie Formation in Dongying Sag, Bohai Bay Basin (East China)

The sandy conglomerates of the lower member of Shahejie (Es4x) in the north of Dongying Sag, Bohai Bay Basin, were investigated to understand the formation mechanism of the good reservoir and controlling factors in deeply buried strata. This research is based on seismic, logging, and core data and comprehensively utilizes methods such as core description, petrographic analysis, cathodoluminescence image analysis, SEM-EDS analysis, and mercury intrusion. The sandy conglomerates are predominantly lithic arkose and litharenite. The reservoirs in the Es4x have experienced three diagenetic processes, compaction, dissolution, and cementation. Compaction remains the major factor affecting the reservoir quality, mainly in the progradation sequence, and cementation has a destructive effect on reservoirs, principally in the retrogradation sequence. The quantification of the compaction by the compaction index revealed that mechanical compaction is higher in the progradation sequence (0.68) than in the retrogradation sequences (0.59). Compaction is suppressed by carbonate cementation, but the extensive cementation significantly degrades the reservoir quality, especially in the retrogradation sequence. Dissolution of different rock fragments, feldspar, and the whole dissolution, in general, enhance the reservoir's quality in both intervals but more in the progradation sequence. Three types of reservoirs representing type I, type II, and Type III mercury intrusion capillary pressure curves were encountered in the Es4x. The braided channels in the progradation and retrogradation sets encompass the greatest reservoir quality and are characterized by type I and II reservoirs with good petrophysical properties. The preeminent reservoirs appear in the braided channels of the progradation set. The development of high-quality reservoirs is governed by the depositional subfacies, compaction, and dissolution in the Es4x. This study will contribute to comprehending the origin of the genesis mechanism of high-quality in deep sublacustrine sandy conglomerate and will help the exploration and pre-drill for favorable reservoirs in similar basins around the world.

Genesis of authigenic clay minerals and their impacts on reservoir quality in tight conglomerate reservoirs of the Triassic Baikouquan formation in the Mahu Sag, Junggar Basin, Western China

Authigenic clay minerals are widely distributed and considerably affect the reservoir quality of the conglomerate reservoirs in the Triassic Baikouquan Formation (BF), Mahu Sag, Junggar Basin, Western China. Their occurrences, origins, and impacts on reservoir quality were investigated utilizing petrographical analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM), Mercury intrusion capillary pressure (MICP), and fractal analysis. Pore-lining chlorite coatings (Ch1) and pore-filling chlorite aggregates (Ch2), respectively, originate from smectite precursors and directly precipitate from pore water. The first-stage kaolinite (K1) formed by plagioclase dissolution appears as flake-shaped single crystals, whereas the second-stage kaolinite (K2) formed by K-feldspar particle dissolution appears as complete false-hexagonal single crystals and vermiform-shaped aggregates. Smectite transformation produces first-stage illite (I1) with honeycomb-like shaped aggregates. The second-stage illite (I2) displaying a flake-shaped occurrence with a directional arrangement is attributed to the transformation of K-feldspar. Based on the burial history, contact relationship of diagenetic minerals, and hydrocarbon charging period, the paragenetic sequence of the conglomerate reservoir is summarized.Afterward, Neimark's fractal model is employed to calculate the fractal dimensions (Fd) of the reservoir with different dominant clay minerals. It is revealed that pore-lining chlorites have the smallest Fd values (<2.5) and their pore size reached 0.6 μm, whereas pore-filling chlorites possessed the greatest heterogeneity with the narrowest pore size distribution. Illite and kaolinite affect reservoir quality in both favorable and detrimental ways. Eventually, the pore evolution within different lithofacies was analyzed. The first promising reservoirs are well-sorted fine-grained conglomerates that have experienced two phases of oil charging, wherein well-developed primary intergranular apertures, secondary dissolution apertures, and kaolinite are commonly observed. Medium-grained conglomerate reservoirs with high clay amounts and poor sorting have been subjected to rapid and intense compaction, resulting in the worst reservoir quality while no dissolution occurred. This work may provide a useful reference for hydrocarbon exploitation of reservoirs which formed under similar geological conditions.

Characterization of crude oil charging of Xiaoerbulake dolomite in the Tarim basin: Insights from bitumen distribution

Understanding hydrocarbon charging mechanisms is essential for reservoir quality evaluation. In this study, a systematic investigation of micro-nano scale oil charging characteristics in the Lower Cambrian Xiaoerbulake Formation of the Tarim Basin was performed via mercury intrusion capillary pressure (MICP) on samples of four types of dolomitic lithofacies before and after bitumen removal. Additionally, to determine the pore structure and space that was occupied by the bitumen, a series of observations using both optical and field-emission scanning electron microscopy (FE-SEM), along with micro-computed tomography (micro-CT) were conducted. A combination of these micro-CT and MICP techniques enabled us to determine how bitumen is distributed in micro-nano pore space of the bulk sample. Imaging results show that three types of pores (intergranular pores, intercrystalline pores and intragranular pores) and microfractures are developed within these lithofacies and confirmed that bitumen has occupied pores >20 nm in diameters. Furthermore, a relationship between pore-throat threshold and charging force was established under the reservoir conditions. It was found that the oil charging force and pore-throat threshold are different for each lithofacies with the microbial dolomites demonstrating the highest charging force and smallest pore throat threshold; as a consequence, they are the most favorable lithofacies for the accumulation and migration of oil and gas which should be considered for future exploration efforts in dolomitic reservoirs.

Evaluating the sedimentological and diagenetic impacts on terrestrial lacustrine fan delta sandy conglomerates reservoir quality: Insights from the Triassic Baikouquan Formation in the Mahu sag, Junggar Basin, Western China

The terrestrial lacustrine fan delta conglomerate reservoirs in the Triassic Baikouquan Formation (BF) are the primary hydrocarbon exploration targets in the Mahu sag, Junggar Basin, Western China. However, the varying lithofacies and complex diagenesis controlling the reservoir quality remain poorly understood. For the sake of revealing how reservoir quality is associated with sedimentary processes and diagenetic alterations, we used integrated approaches like petrographical analysis, cores description, wireline, X-ray diffraction (XRD), scanning electron microscopy (SEM), mercury intrusion capillary pressure (MICP) and measured petrophysical properties. The results showed that sedimentary processes have considerable control over facies distribution, grain size, and clay content, causing spatial variation of reservoir quality within the fan delta deposits. The coarser grain and high clay content fraction at the base of gravity flow will first settle in the fan delta plain near provenance, whereas the finer grains at the top of flows progressively deposit in the fan delta front areas. From proximal to distal fan delta, a progressive conversion from cohesive muddy debris flow into traction current can be inferred from the variations of lithofacies associations. A total of 8 types of microfacies were identified where the conglomerates of the BF were deposited. The grayish-green fine-grained conglomerates concentrated in the subaqueous distributary channels provide the best reservoir performance, whereas debris flow deposits dominated primarily by muddy debrites occupy the worst reservoir quality because of their highest clay content and coarsest grain size.The dominant diagenetic events include mechanical compaction that continued throughout the entire burial, two phases of quartz cementation, dissolution of unstable components, early and late carbonate cementation, precipitation of authigenic clay minerals, and two phases of hydrocarbon charging. It is unveiled that compaction is the predominant mechanism negatively affecting reservoir quality in the fan delta complex, while the effect of cementation on pore reduction of the conglomerate reservoir is weaker than compaction. Simultaneously, a complex relationship exists between reservoir petrophysical properties within different clay minerals. Dissolution does not significantly improve the permeability of the reservoir because of the partial dissolution which primarily generated intragranular pores with strong heterogeneity and poor connectivity. The most favorable reservoirs occur primarily in the subaqueous distributary channels in the fan delta front, which comprise well-sorted fine-grained conglomerates with well-developed residual intergranular pores and secondary dissolution pores and have undergone two phases of oil charge. This work may provide a useful reference for hydrocarbon exploration of the fan delta systems and regions which have encountered similar sedimentary and diagenetic processes.

Reservoir characteristics and factors influencing shahejie marl in the shulu sag, bohai bay basin, eastern China

Shahejie marl in the Shulu Sag is a crucial resource for unconventional hydrocarbon exploration in China. Although breakthroughs have been made in tight oil exploration in this area, the mechanisms underlying the formation of this marl reservoir and factors controlling its ‘sweet spots’ have not been thoroughly studied. To understand the pore structure characteristics and factors influencing the marl reservoir, we analyzed core samples from Wells ST1 and ST3. A series of experiments was conducted on the samples, such as X-ray diffraction, focused ion beam scanning electron microscopy, micro-CT, and total organic carbon test. Additionally, the physical properties of different marl rock fabrics were studied with auxiliary tests, such as mercury intrusion capillary pressure analyses, nuclear magnetic resonance, porosity and permeability tests, and thin-section observation. The results revealed that the marl reservoir is characterized by low porosity (1.61%) and low permeability (2.56mD). The porosity and permeability (1.61% and 3.26mD) of laminated marl were better than those (0.92% and 1.68mD) of massive marl. Clay minerals and quartz content in laminated (11.8 and 8.2%) was less than in massive marl (16.2 and 13.3%). The marl pores include intercrystalline pores, dissolution pores, and microfractures. Additionally, the laminated marl pores were primarily distributed along the dark lamina, with good connectivity. A few isolated and uniform holes were observed in the massive marl. Influenced by rock fabric and mineral composition, layered fractures were mainly developed in the laminated marl, while structural fractures were the main type of microfractures in the massive marl. The primary sedimentary mechanism was the main geological action underlying the differences in marl rock fabric; this mechanism affects the physical properties of the marl reservoir, which are key factors to be considered when searching for the marl reservoir ‘sweet spots’. Particular attention should be paid to these factors during tight oil exploration and development in similar sedimentary basins.

Coal pore structure changes in upper protective seam after mining: Pingdingshan Shenma Group, Henan Province, China

Protective layer mining is a safe and effective method of gas control in coal mining; we should pay more attention to changes in the pore structure of coal in protected layers, but there is less research in this aspect. We analyzed the characteristics of different-size pores in coal samples affected and unaffected by a protective layer at a distance of 900 m from the open-off cut of the protected layer. The pore morphology, type, size, and distribution in the coal seams affected and unaffected by the protective layer were qualitatively studied via field-emission scanning electron microscopy. Mercury intrusion capillary pressure testing was applied to analyze differences in pores of the same size between coal seams affected and unaffected by the protective layer. Protective layer mining increases the pore sizes of irregular pores. The protective layer has a large effect on various pores at different distances from the open-off cut. Within 100–700 m of the open-off cut of the protected layer, the upper protective layer mining promotes the conversion of 1–10 μm pores to 8–200 μm pores. When the distance from the open-off cut is less than 100 m, the upper protective layer mining facilitates the transformation of 10–100-nm pores into 100 nm to 10 μm pores. At distances of 100–900 m from the open-off cut, the porosity of pores with sizes from 10 nm to 200 μm increases markedly (with a maximum increase of 14%). The results of this study provide a theoretical foundation for designing a protective layer, evaluating its effect, and the research of gas seepage law and gas emission.

Development characteristics of deepwater gravity flows and tight sandstone reservoir characteristics in Chang 6 in the Huaqing area, Ordos Basin, China

The tight sandstone reservoirs have become the focus of today's oil and gas exploration. To clarify the microscopic characteristics of the tight sandstone reservoirs of the Chang 63 deep water gravity flow origin in the Huaqing area, the Chang 63 gravity flow origin reservoirs in the study area are divided into three categories. They are the formation reservoir of sandy clastic flow (FROSF), formation reservoir of muddy debris flow deposits and turbidites (FROMT) and formation reservoir of slides and slumps (FROSS). In this study, core and logging data, thin sections, field emission scanning electron microscopy (FE‐SEM), and mercury intrusion capillary pressure (MICP) were combined to investigate the rock composition and pore‐throat characteristics of tight sandstone reservoirs with different types of gravity flow origins. The reservoir micro‐heterogeneity is also investigated in this paper. The results show that the reservoirs with different gravity flow origins are similar in lithology and are mainly composed of feldspar lithic sandstone and lithic feldspar sandstone. The pore types are mainly intergranular pores and feldspar‐dissolved pores. There are significant differences in the porosity, permeability, microscopic pore‐throat characteristics and microscopic heterogeneity of the reservoirs. From FROSF to FROMT and FROSS, the porosity, permeability, mercury inlet saturation, discharge pressure, median pressure and mercury removal efficiency gradually decrease. The tightness of the reservoir gradually increases. The storage capacity is gradually reduced. The disparity between the throat radius and pore radius gradually increases. The pore‐throat structure becomes more complex, and the microscopic heterogeneity of the reservoir gradually increases.

Fractal Characteristics of Pore-Throats Structure and Quality Evaluation of Carbonate Reservoirs in Eastern Margin of Pre-Caspian Basin

The Carboniferous reservoir KT-II layer in the Eastern margin of the Pre-Caspian Basin was formed in the open platform sedimentary environment and marked by a complicated pore-throats structure. Understanding the main controls on the carbonate reservoir quality is of great significance for reservoir classification and a relevant production prediction. This study focuses on revealing reservoir pore-throats structure’s fractal characteristics by analyzing the mercury intrusion capillary pressure (MICP), with the integration of the pore-throats radius’ distribution data. The relationship between fractal dimensions and reservoir parameters such as physical properties, mercury median saturation pressure (Pc50) and the proportion of large-size (radius &gt; 0.1 μm) pores demonstrate that the lower fractal dimension corresponds not only to core plug samples with higher permeability, but also to lower Pc50 and a higher proportion of large pore-throats. Three classes of carbonate reservoir with different qualities were defined according to their fractal dimensions, petrophysical properties and photomicrograph features, et al. Combined with flow profiles from Production Log Tool tests, the relationship between the carbonate reservoir type and production behavior was revealed, thus providing suggestions on the middle and late stage of the water flooding production adjustment strategy. This work provides a typical case study for the further comprehensive evaluation and classification of a carbonate reservoir and it is quite meaningful for production efficiency optimization.

Effects of Carbonic Acid-Rock Interactions on CO2/Brine Multiphase Flow Properties in the Upper Minnelusa Sandstones

SummaryCarbon dioxide (CO2) injection into a deep saline aquifer can dissolve into formation brine and generate carbonic acid. The resulting acid can drive fluid-rock geochemical reactions. The impact of these fluid-rock geochemical reactions on porosity, permeability, and multiphase flow responses is relevant to the determination of CO2 storage capacity of deep saline aquifers. In this research, carbonic acid flooding experiments were performed on core samples consisting of poorly sorted, quartz-rich sand with laminated bedding from a possible CO2 storage target in northwest Wyoming. Complementary pre- and post-injection porosity and permeability, thin-section, Brunauer-Emmett-Teller (BET) surface area, mercury intrusion capillary pressure (MICP), and time-domain nuclear magnetic resonance (TD-NMR) measurements were conducted. Overall, both core porosity and permeability increased after a 7-day carbonic acid injection, from 6.2 to 8.4% and 1.6 to 3.7 md, respectively. We attributed these changes to carbonate mineral dissolution, which was evidenced by the effluent brine geochemistry, pore-throat size distribution (PTSD), and BET surface area. To be more specific, within the more-permeable section of core samples containing larger pore size, the permeability increment is apparent due to dolomite mineral grains and cements dissolution. However, for the lower-permeability section corresponding to the smaller pore size, mineral precipitation possibly lessened dissolution effects, leading to insignificant petrophysical properties changes. Consequently, the observed heterogeneous carbonic acid-rock interactions resulted in alterations of CO2/brine relative permeability (i.e., the initial CO2 saturation decreased and the CO2 flow capacity was enhanced). This research provides a fundamental understanding regarding effects of fluid-rock reactions on changes in static and multiphase flow properties of eolian sandstones, which lays the foundation for more accurate prediction/simulation of CO2 injection into deep saline aquifers.

Study of Fractal and Multifractal Features of Pore Structure in Tight Sandstone Reservoirs of the Permian Lucaogou Formation, Jimsar Sag, Junggar Basin, Northwest China.

The primary factor impacting the tight sandstone reservoirs and fluid flow capacity represents the pore-throat structure. On the basis of petrophysical characteristics test, scanning electron microscopy (SEM), and casting thin-section examination of tight sandstone reservoir specimens from the Permian Lucaogou Formation in Jimsar Sag, Junggar Basin., the full-size pore-throat parameters and distribution characteristics were determined by constant-rate mercury injection (CRMI) analysis. Using fractal theory and multifractal theory, the pore architectures of sandstone pores are analyzed. Mercury intrusion capillary pressure (MICP) is used to compute the dimensions of fractals using various fractal models and multifractal characteristics. Analysis is done on the relationships between tight sandstone pore architectures and fractal and multifractal characteristics. According to the research, a network of tightly packed sandstone pores may be assessed using the dimensions of fractals computed from a 3D capillary model. When displacement pressure is increased, the dimensions of fractals rise; when permeability, pore-throat diameter, and variable coefficient are increased, it falls. Tight sandstone pores exhibit multifractal features, according to the multifractal analysis, and multifractal parameters may depict the size, concentration, and asymmetry of the pore size distribution (PSD). Sandstone’s PSD is comparable when its multifractal parameters (Δα, Δf, α0, α1, α2) are identical. Pore diameters of tight sandstone are positively connected with information dimensions D1 and correlation dimensions D2, and information dimensions D1 have a greater impact on PSD than correlation dimensions D2. Additionally, the 3D capillary model’s dimensions of fractals and D1 exhibit a substantial negative association. These findings play a significant guiding role in the quantitative characterization of unconventional reservoir pore structures. The multifractal technique is effective to define the heterogeneity of the sandstone pore system and to differentiate between distinct PSD in heterogeneity.

Using Nano-XRM and High-Contrast Imaging to Inform Micro-Porosity Permeability During Stokes–Brinkman Single and Two-Phase Flow Simulations on Micro-CT Images

Carbonate rocks have multiscale pore systems that are weakly understood. In this study, we use combined experimental, modeling, and pore space generation methods to tackle the impact of microporosity on the flow properties of Estaillades limestone. First, a nano-core from a microporous grain of Estaillades limestone was scanned using nanotomography (nano-XRM). The information from the nano-XRM scan was then used as input into an object-based pore network generator, on which permeability fields were simulated for a range of porosities, creating a synthetic Kozeny–Carman porosity–permeability relationship targeted for the specific microporous system present in Estaillades. We found a good match between the experimental and simulated Mercury Intrusion Capillary Pressure (MICP) range in the imaged geometry and a good match between the imaged and object-generated permeabilities and MICP. A micro-core of Estaillades was then scanned using X-ray microtomography (μCT), the differential pressure was measured during single-phase flow, and the rock was flooded with doped brine. The contrast between the images was used to assign a porosity to each voxel of connected microporosity. The flow through the pore space was solved using the Stokes–Brinkman (S–B) and Stokes-only solvers, and the differences between the measured permeability and computed permeabilities were evaluated. An agreement was seen between the computed permeability of the Stokes and S–B simulation with the measured permeability. However, the velocity fields with the S–B simulation captured stagnant regions of the pore space that were not present in the Stokes simulations. Additionally, we investigated the implications of including microporosity in the estimation of relative permeability. Nitrogen was experimentally co-injected through the core with doped brine at a 50% fractional flow and imaged to capture the two-phase effective permeability and was compared with the simulated numerical permeability. The Stokes simulation was not able to predict relative permeability with this method due to the major flow paths in the macroporosity being impeded by the injected non-wetting phase. The S–B simulations, however, allowed flow in the microporous regions around these blocked flow paths and were able to achieve a relative permeability prediction that was a reasonable match to the experimental measurement.