Intercrystalline Pores Research Articles

Pore and fracture characteristics of Cretaceous tight reservoir and its control effect on hydrocarbon accumulation in the Liuhe Basin

Tight oil and gas in the Cretaceous has been found in the Liuhe Basin, but the rules of tight reservoir and oil and gas accumulation are not clear. This paper discusses the developmental characteristics and evolution law of pores and fractures in the Cretaceous tight reservoir in the Liuhe Basin, and reveals its controlling effect on tight oil and gas accumulation. The results show that intercrystalline pores, intergranular pores and dissolution pores are scattered and only developed in shallow tight reservoirs, while microfractures are developed in both shallow and deep layers, which are the main type of reservoir space in the study area. The results of mercury intrusion porosimetry and nitrogen gas adsorption show that with the increase of depth, the proportion of macropores (microcracks) increases, while the proportion of micropores decreases. There are two stages of microfractures developed in the study area, corresponding to the initial fault depression stage from late Jurassic to early late Cretaceous and compressional uplift at the end of late Cretaceous. According to the principle of “inversion and back-stripping method”, combined with the data of optical microscopy and inclusions, the time of each key diagenesis and its contribution to porosity are revealed, and the porosity evolution history of reservoirs in different diagenetic stages is quantitatively restored. The porosity reduction rate of compaction can reach more than 80%, which is the main reason for reservoir densification. The relationship between pore evolution history and oil and gas accumulation history reveals that during the oil and gas filling period of the Xiahuapidianzi Formation (90–85 Ma), the reservoir porosity is only 1.15%, but the development of microfractures in the first stage of the reservoir is conducive to oil and gas accumulation.

Petrographic, Rare Earth Elemental and Isotopic Constraints on the Dolomite Origin: A Case Study from the Middle-Upper Cambrian Xixiangchi Formation in Eastern Sichuan Basin, Southwest China

The Middle-Upper Cambrian Xixiangchi Formation in the Sichuan Basin is regarded as an important reservoir with great potential for hydrocarbon exploration. It is previously indicated that the Xixiangchi carbonates have experienced extensive dolomitization, however, the origin of dolomitizing fluids and the dolomitization mechanism still remain uncertain. In this study, a set of petrographic and geochemical examinations, including rare earth elements (REE) and isotopic (C, O, and Sr) compositions were used to trace the origins of dolomitizing fluids and associated diagenetic processes. The petrographic examination revealed three types of matrix dolomites (D1, D2, D3) and one cement saddle dolomite (SD). These phases have crystal size ranges of less than 30 μm (very fine to fine crystals, D1), 30–100 μm (fine to medium crystals, D2), 100–300 μm (medium to coarsely crystalline dolomite, D3), and 0.3–4 mm (fracture filling cements, SD), respectively. D1 is characterized by non to very weak luminescence, weakly negative Ce anomalies (Ce/Ce* = 0.84 ± 0.02), strongly negative Eu anomalies (Eu/Eu* = 0.65 ± 0.03), and high 87Sr/86Sr ratios (0.71062 ± 0.00122). In combination with δ13C (−1.5‰ ± 0.2‰) and δ18O (−9.7‰ ± 0.5‰) compositions, D1 is interpreted to be formed by penecontemporaneous dolomitization in the near-surface environment with seawater as the dolomitizing fluid. In contrast, D2 is characterized by intercrystalline pores, dirty crystal surfaces, similar δ13C (−1.4‰ ± 0.4‰) compositions but higher δ18O (−8.9‰ ± 0.7‰) compositions, and lower 87Sr/86Sr ratios (0.70992 ± 0.00035), similar Ce anomalies (Ce/Ce* = 0.87 ± 0.04) and higher Eu anomalies (Eu/Eu* = 0.85 ± 0.04). The coarser D2 is regarded to be formed by the post-penecontemporaneous seepage-reflux dolomitization or by recrystallization of D1 dolomite in a near-surface or shallow burial environment. D3 is distinguished by a cloudy core with clear rims, showing slightly higher Eu anomalies (Eu/Eu* = 0.88 ± 0.02) and similar Ce anomalies (Ce/Ce* = 0.88 ± 0.02) than those of D1 and D2. Combined with the δ18O compositions (−10.4‰ ± 0.4‰) and 87Sr/86Sr ratios (0.70989 ± 0.00048), D3 is thought to be formed by the overgrowth or recrystallization of D1 and D2 dolomites in a shallow to moderate burial environment. The fractures filling SD dolomite consists of nonplanar and much coarser crystals with undulatory extinctions and brighter red luminescence. The lower δ18O (−11.1‰ ± 0.3‰) compositions, lower negative Eu anomalies (Eu/Eu* = 0.70 ± 0.01) of SD than the matrix dolomites, and similar Ce anomalies (Ce/Ce* = 0.83 ± 0.01) are indicative of hydrothermal dolomitization, with possible fluids associated with the magma during the period of Emei taphrogenic movement. In addition, the 87Sr/86Sr ratios (0.70941 ± 0.00003) of SD suggest probable origin from the coeval seawater partially. Therefore, SD dolomite is interpreted to be formed by hydrothermal dolomitization with mixed dolomitizing fluid of seawater and hydrothermal fluids. In summary, all the matrix dolomites have almost the same ΣREE concentrations and exhibit similar near-flat REE partition patterns with weak LREE enrichments, weakly negative Ce anomalies, and negative Eu anomalies. Such characteristics of REE compositions are indicative of similar evolved dolomitizing fluid, such as seawater or seawater- derived fluids. By contrast, SD dolomites have a different REE partition pattern with left-leaning characteristics, LREE depletions, and negative Eu anomalies, thus suggesting a different dolomitizing fluid source from the matrix dolomites. In addition, the development of intercrystalline pores associated with D2 dolomite makes it more likely to be a potential reservoir, indicating that the dolomitizing history of carbonate has a strong influence on the quality of potential dolomite reservoirs.

Pore Size Distribution Characterization by Joint Interpretation of MICP and NMR: A Case Study of Chang 7 Tight Sandstone in the Ordos Basin

Pore size distribution characterization of unconventional tight reservoirs is extremely significant for an optimized extraction of petroleum from such reservoirs. In the present study, mercury injection capillary pressure (MICP) and low-field nuclear magnetic resonance (NMR) are integrated to evaluate the pore size distribution of the Chang 7 tight sandstone reservoir. The results show that the Chang 7 tight sandstones are characterized by high clay mineral content and fine grain size. They feature complex micro-nano-pore network system, mainly composed of regular primary intergranular pores, dissolved pores, inter-crystalline pores, and micro-fractures. Compared to the porosity obtained from MICP, the NMR porosity is closer to the gas-measured porosity (core analysis), and thus can more accurately describe the total pore space of the tight sandstone reservoirs. The pore throat distribution (PTD) from MICP presents a centralized distribution with high amplitude, while the pore size distribution (PSD) derived from NMR shows a unimodal distribution or bimodal distribution with low amplitude. It is notable that the difference between the PSD and the PTD is always related to the pore network composed of large pores connecting with narrow throats. The PSD always coincides very well with the PTD in the very tight non-reservoirs with a much lower porosity and permeability, probably due to the pore geometry that is dominated by the cylindrical pores. However, a significant inconsistency between the PSD and PTD in tight reservoirs of relatively high porosity and low permeability is usually associated with the pore network that is dominated by the sphere-cylindrical pores. Additionally, Euclidean distance between PSD and PTD shows a good positive correlation with pore throat ratio (PTR), further indicating that the greater difference of pore bodies and pore throats, the more obvious differentiation of two distributions. In summary, the MICP and NMR techniques imply the different profiles of pore structure, which has an important implication for deep insight into pore structure and accurate evaluation of petrophysical properties in the tight sandstone reservoir.

Geochemical transformation of tuffaceous materials in tight sandstone and its significance for reservoir reconstruction: A case study from the Taiyuan and Shihezi Formation in Dingbei area, Ordos Basin

Combined with thin sections and electronic probe microanalyzer (EPMA) analysis, we studied the effect of the chemical composition of tuffaceous materials on the quality of sandstone reservoir in the Dingbei area. Analysis of 100 thin sections from five drilled wells indicates that the tuffaceous materials in sandstones from the Taiyuan and Shihezi Formation are common due to the volcanic eruptions. There are three types of tuffaceous materials in the sandstone: intermediate-basic type, intermediate-acid type, and mixed type. Seven thin sections were selected to analyze the chemical elements of tuffaceous materials by EPMA, with 3–8 test points on each thin section. The results indicate a clear decline in most major elements except for SiO2 and Al2O3. The elemental differentiation of tuffaceous sandstone is largely controlled by the activity of the diagenetic system. Under the slow-moving fluid, the active elements such as K, Na, Ca, Mg, and Fe are lost, and Si and Al are enriched. The SiO2 contents of EPMA results are up to 42%. Under the strong-flow fluid, Si and Al can be transferred to precipitate the kaolinites. In the closed diagenetic system, the contents of active elements such as Na and K are high. Dissolution or alteration of tuffaceous materials with different types under the acid fluid is one of the reasons for the generation of heterogeneous reservoirs. The intermediate-acid tuffaceous materials with high SiO2 content experience transformation without dissolution. The mixed tuffaceous materials are mainly transformed into kaolinite to form intercrystalline pores. Due to a large number of soluble components in the intermediate-basic tuffaceous materials, a large number of secondary pores are developed.

Occurrence Characteristics and Threshold Pore Throat Radius of Movable Fluids for Dolomite Intercrystalline Pores of Lacustrine Carbonate Rocks

The reservoir evaluation and classification are restrained by the progress of research on the pore structure and fluid occurrence in dolomite intercrystalline pores of the Paleogene lacustrine carbonate rock in the western Qaidam Basin. The experimental method adopted to investigate the fluid occurrence of the lacustrine carbonate rock in the study area can be used as a reference for studying tight reservoirs. By integrating technical approaches such as the thin-section petrographic analysis, SEM, electron probe, mercury injection test, and NMR test, this research studies the petrology, pore type and distribution, and pore structure of the reservoir. Moreover, the pore fluid distribution and threshold pore throat radius for the distribution of movable fluids are investigated by integrating the centrifuging treatment and NMR characterization. Results show that pores of samples in the study area are dolomite intercrystalline pores, intercrystalline dissolved pores, framework dissolved pores of algal limestone (dolostone), dissolved pores of saline minerals, and interlayer fractures, among which dolomite intercrystalline pores and intercrystalline dissolved pores are found with the highest proportions (60%). The dolomite intercrystalline pores and intercrystalline dissolved pores are nano-micropore throats with a narrow distribution. Their capillary pressure curve is characterized by a high plateau and negative skewness, while the NMR relaxation time spectrum is left-skewed and presents higher bond water saturation (over 65%). For intercrystalline pores and intercrystalline dissolved pores, the main storage space for movable fluids is provided by small and medium pores (corresponding to the NMR relaxation time of 1–10 ms and 10–100 ms, respectively), and the experimentally determined threshold pore throat radius for movable fluids is 47 nm. The reservoir is hydrophilic and therefore movable fluids mainly occur in the centers of pores. The samples with higher proportions of coarse pores and pore connectivity are associated with higher proportions of movable fluids. Our analysis shows the dolomite intercrystalline pore has a certain storage capacity and yet inferior connectivity; the proportion of movable fluids that can effectively flow is key to evaluating the effectiveness of reservoirs with dolomite intercrystalline pores.

Pore structure characterization for coal measure shales of the Xiashihezi Formation in the Sunan Syncline block, southern North China basin

To characterize the coal measure shale pore structure of the Xiashihezi Formation in the Sunan Syncline block, a series of experiments were conducted. Results show that the main components of the shales are clay minerals and quartz, and organic matter, fluid escaping, interlayer, intercrystalline and interparticle pores are well-developed. The shale pore specific surface area (SSA) is concentrated in the pores with the size of <50 nm and is significantly higher in the pores with the size of < 5 nm, indicating that these pores have an important effect on gas adsorption. The shale pore volume is mainly concentrated near the pore size of 10 nm, followed by 10,000–100,000 nm, indicating that in addition to the fractures, the matrix pores with a size of about 10 nm contribute the most to pore volume and free gas accumulation. The volume and SSA of the micropore, small pore, and mesopore increase with the TOC content when it is lower than 6%, leading to higher porosity and total pore SSA of the shales. However, this positive correlation disappears under the compaction effect when the TOC content is higher than 6%. The clay mineral content has negative correlations with the volume and SSA of the mesopore and macropore under the compaction and pore blockage effects, but it correlates poorly with those of the micropore and small pore, causing a decrease in the shale porosity as it increases, while the brittle mineral can promote mesopore and macropore development and is conducive to micropore and small pore maintenance when its content is higher than 45%. As a result, the shale porosity tends to increase with the brittle mineral content. This study is helpful in clarifying the coal measure shale gas enrichment law in the block and in providing fundamental support for coal measure gas efficient development.

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.

Experimental evaluation of microscopic pore structure and fluid migration characteristics of coal-measure sandstone reservoirs

Research on the microscopic migration characteristics of fluids in coal measure sandstone has always been a hot spot in the evaluation of reservoir properties. In this study, taking the Yan’an Formation sandstone reservoirs in the Block A of the Ordos Basin as an example, the pore structures and fluid migration characteristics of coal-measure sandstones are systematically studied using a large number of thin sections, SEM (Scanning Electron Microscope), NMR (Nuclear Magnetic Resonance), relative permeability and water-flooding test results. The results show that the Jurassic sandstones in the target layer mainly develop lithic quartz sandstone, and the main pore types are intergranular and dissolution pores, followed by a small amount of intercrystalline pores. The surface porosity of the target sandstones mainly ranges from 7.90 to 10.79%, with an average value of 8.78%. The good correlation between porosity and permeability indicates that the target layer is a pore-type reservoir. The T2 relaxation time of the target layer is mainly distributed within 100 ms. Moreover, the reservoir of the Yan’an Formation has a high saturation of movable fluids, which is mainly distributed in 43.17–71.24%, with an average value of 56.90%. Meanwhile, samples with fractures have higher movable fluid saturations. In addition, the average irreducible water saturation of the Yan’an Formation sandstone reservoir is 35.14%, and the final oil displacement efficiency is 51.14% on average. There is a good positive correlation between the oil displacement efficiency and the co-permeability zone. As the co-permeability zone range increased from 15 to 55%, the oil displacement efficiency increased from 30 to 65%. When the cores develop fractures, they have characteristics of high permeability, high oil recovery rate, high oil displacement efficiency in the anhydrous period, low irreducible water saturation and low residual oil saturation.

Characterization of ultra-low permeability tight sandstone reservoir properties and criteria for hydrocarbon accumulation in Chang 6 member, Huaqing area, Ordos basin

How to accurately predict hydrocarbon enrichment and high-yield areas in ultra-low permeability sandstone reservoirs is a hot spot in petroleum geology. Taking the Chang 6 Member of the Yanchang Formation in the Huaqing Area, Ordos Basin as an example, the quantitative characterization and classification criteria of ultra-low permeability sandstone reservoir properties are systematically studied. The research results show that the seismic reflection characteristics of the Chang 6 Member show multi-stage wedge progradation characteristics, reflecting the sedimentary characteristics of the end of the delta front. The maturity of the minerals in the Chang 6 Member sandstones in the study area is very low, it indicates a low degree of transformation of sediments. Three types of sand bodies, namely sandy debris flow, turbidite, and slump rock sand bodies, were identified in the Chang 6 Member of the Yanchang Formation. The pore types of the Chang 6 Member in the study area include intergranular pores, dissolution pores (feldspar, detrital dissolution pores), and intercrystalline pores. Among them, the intergranular pores and feldspar dissolution pores are the most important storage spaces. The study also found that the test oil production is highly correlated with the cumulative thickness of the massive sandstone segments. Therefore, massive sandstone (sand debris flow) is the main contributor to oil well production, and its distribution directly controls the accumulation of oil reservoirs and the high production of oil wells. In addition, geological parameters affecting reservoir enrichment evaluation were analyzed, which include permeability, oil layer thickness, resistivity, and reservoir penetration rate. Finally, the evaluation criteria for hydrocarbon enrichment in the Chang 6 Member were formulated by the analysis of dominant facies, lithologic assemblages and electrical properties.

The reservoir characteristics research of Devonian Jinbaoshi Formation, Northwest Sichuan Basin, SW China

A great breakthrough was achieved on the Middle Devonian's oil-gas exploration in the Longmenshan area in northwestern Sichuan. However, only the Guanwushan Formation was researched in detail. The underlying formation - Jinbaoshi Formation as a set of the potential well reservoir and its reservoir characteristics have not been discussed. Based on the section's fine description, thin section analysis, and core borehole logging, combined with petrophysical analysis, the reservoir characteristics, controlling factors, and evolution process of the Jinbaoshi Formation reservoir in the Longmenshan area are deeply studied in this paper. The results showed that the Jinbaoshi Formation has developed a set of sand-shale interbedding deposit of terrigenous clastic and carbonate rocks. The reservoir lithology is mainly quartz sandstone and calcareous quartz sandstone. The quartz sandstone reservoir has good physical properties, but the calcareous quartz sandstone has the characteristics of strong heterogeneity, low porosity, and permeability. Residual intergranular pores are mainly developed in the reservoir space. And the development of intercrystalline pores and intergranular dissolved pores can also be seen, but the development frequency is low, and the scale is small. Among them, the Devonian Jinbaoshi Formation quartz sandstone's average porosity is about 8%, and the highest is 18.43%. The main diagenesis types of the Jinbaoshi Formation are compaction, recrystalization, and dissolution. Compaction is the main reason for the destruction of original pores, and dissolution is the main driving force for later porosity and permeability improvement. Rock fragments, calcareous silty clasts, and bioclastic grains are the main dissolution objects. The formation of intergranular dissolved pores significantly improves the physical properties of the reservoir. Therefore, the reservoir development of the Jinbaoshi Formation is mainly controlled both by favourable sedimentary facies and diagenesis. Quartz sandstone and calcareous sandstone of the Jinbaoshi Formation were controlled by early sedimentary facies in the syngenetic rock stage and developed more early intergranular pores; in the early diagenesis stage, compaction-pressure solution and cementation resulted in residual intergranular pores. In the middle-late diagenesis stage, the calcareous cement is dissolved, and more pores were formed.

Effect of saline sedimentary environment on pore throats of shale

Shale pore throat is one of the key factors affecting shale oil and gas exploitation. In order to study the effect of saline on shale pore throat in the continental lacustrine basin, the paleo-salinity of the lacustrine basin was analyzed using the Couth and Sr/Ba methods, and the pore throat characteristics of shale were observed by thin section and scanning electron microscope. The saline stage is divided into five stages: freshwater (0.5‰–1‰), brackish water (1‰–5‰), brackish water (5‰–15‰), brackish water (15‰–30‰), and high saltwater (>30‰). Shale is mainly reserved in micropores (organic, intercrystalline, and intergranular pores) and microcracks (along-layer, high pressure, structural, and mineral shrinkage cracks). Paleosalinity affects the pore throat characteristics of shale by controlling the mineral composition, rock combination type, and texture. Carbonate minerals tend to dissolve and form dissolution pores, resulting in pore throat enlargement and better physical properties. When salinity is low, the content of carbonate minerals increases with the increase in salinity. However, in the case of high salinity, the content of carbonate minerals gradually decreases, but that of sulfate and gypsum increases with the increase in salinity. The texture is conducive to the development of microcracks. With the increase in salinity, the number of textures first increases and then decreases. When the content is 15 ‰–30‰, there are most abundant textures, making it most likely to form microcracks. The results of this study play an important role in promoting the study of shale in the continental lacustrine basin.

Characteristics, formation mechanism and evolution model of Ordovician carbonate fault-controlled reservoirs in the Shunnan area of the Shuntuogole lower uplift, Tarim Basin, China

The Ordovician carbonate fault-controlled reservoir in the Shunnan area is substantially different from the typical karst reservoir closely related to an unconformity. The development of fault-controlled reservoirs is controlled by the deep and large strike-slip fault in the Middle Caledonian period. The characteristics, diagenesis types, diagenetic fluid evolution characteristics, fluid-rock interactions, and reservoir response of fault-controlled reservoirs were investigated systematically by analyzing 3D seismic, logging, and drilling core data. Production data, reservoir petrology, and chemical filling geochemistry were also used. The formation and evolution of fault-controlled reservoirs are affected by the coupling of the structure, lithofacies, and fluid. The dolomitization in the quasi-syngenetic period in the early stage of Episode I in the Middle Caledonian provided the material basis for the development of fault-controlled reservoirs. The Mg-rich high-salinity thermal fluid in the late Caledonian and the Early Hercynian provided a constructive transformation for the development of fault-controlled reservoirs. In contrast, the transformation of reservoirs by the Si-rich magmatic thermal fluid in the late Hercynian was mainly destructive, and the action range of the deep thermal fluid was strongly controlled by strike-slip fault zones. The releasing bend and superimposed parts of different structural styles in the fault zone have high activity intensity. These are areas where dissolution and transformation of the fluid occur preferentially. Dolomite is often more conducive to the development of fault fracture zones and promotes the dissolution and transformation of the deep thermal fluid. Therefore, the strike-slip fault cutting through the basement causes the hydrothermal fluid to enter the fault, dissolving carbonate minerals and forming a hydrothermal-modified fault-controlled reservoir composed of fractures, dissolution pores, and dolomite intercrystalline pores. The results provide a new approach and direction for the study of different types of deep and ultra-deep carbonate reservoirs.

Shale Lithofacies and Its Effect on Reservoir Formation in Lower Permian Alkaline Lacustrine Fengcheng Formation, Junggar Basin, NW China

Lower Permian Fengcheng Formation is considered to be a high-quality alkaline lacustrine shale oil resource in the Junggar Basin, NW China. Based on core and thin section observation, X-ray diffraction, scanning electron microscope, low-pressure N2 adsorption, and high-pressure mercury intrusion porosimetry, different shale lithofacies, and pore structures were examined. According to the mineral composition, shales in well My 1 are divided into five types: dolomitic mudstone, calcareous mudstone, siliceous mudstone, tuffaceous mudstone, and argillaceous mudstone, each of which shows its pore structure distribution. Intragranular pores, inter-crystalline pores associated with clays and pyrites, dissolution pores, and microfractures were commonly observed. There are three segments of pore structures including <50 nm, 50 nm-4 μm, and >4 μm. Clay minerals mainly contribute to mesopores, especially in argillaceous mudstones. The dissolution of carbonate minerals and feldspars is significant for macropores predominantly in dolomitic mudstones and tuffaceous mudstones, respectively. Micron-scale microfractures associated with laminae dominate in dolomitic mudstones. Therefore, the dolomitic mudstones, especially with lamination, and tuffaceous mudstones are proposed to be favored shale lithofacies with great exploration potential in the Mahu Sag.

Study on Micro-Nano Pore Characteristics and Classification of Tight Sandstone Reservoir Based on Q-Cluster

To realize the quantitative classification and comprehensive evaluation of the tight oil reservoir in the 4th of Quantou Formation in Songliao Basin, the pore structure of tight oil reservoir was quantitatively analyzed. In this study, experiments based on the constant-speed mercury injection, nuclear magnetic resonance, and micron CT are based on the observation of cast thin sections, and scanning electron microscope is conducted. The result shows that a tight oil reservoir space is mainly composed of the intergranular dissolved pore, residual intergranular pore, and intragranular dissolve pore. There are few intercrystalline pore and fracture at the same time. The average pore radius is 1.28~4.58 μm, and the average throat radius is 0.52~1.27 μm. Hence, there is a typical micro-nano throat combination with micropores. The pore throat composition and pore structure of reservoirs differ in reservoir with different physical properties. The reservoir quality depends on pore structure especially the throat radius. And the microthroat is a critical factor for permeability. Based on Q-cluster analysis, tight oil reservoirs are classified into three types. The analysis was based on the data such as max throat radius, average throat radius, displacement pressure, median pressure, and permeability. Finally, the reservoirs in the study area are mainly II and I types.

Characteristics and Genesis of Alkaline Lacustrine Tight Oil Reservoirs in the Permian Fengcheng Formation in the Mahu Sag, Junggar Basin, NW China

Through optical microscopic examination, scanning electron microscope analysis, whole rock X-ray diffraction analysis, X-ray fluorescence spectrum analysis, carbon and oxygen isotope analysis, and temperature measurement of fluid inclusions, the characteristics and formation mechanism of the alkaline lacustrine tight oil reservoirs of the Permian Fengcheng Formation in the Mahu Sag of the Junggar Basin have been systematically studied, and a genetic model has been proposed. Porosity of tight oil reservoirs of the Fengcheng Formation in the Mahu Sag is mostly less than 4%, with permeability mostly less than 0.1 mD. The lithology of the Fengcheng Formation in the Mahu Sag is mainly tuff, and the authigenic minerals mainly consist of feldspar, quartz, dolomite, and salt minerals (e.g., shortite, trona). The authigenic feldspar and quartz of the Fengcheng Formation in the Mahu Sag mainly originate from devitrification of volcanic glass in pyroclastic rocks. Reservoir space is dominated by dissolution pores of feldspar and salt minerals, followed by intercrystalline pores among feldspar, quartz, and other minerals formed by devitrification. Fractures are mainly comprised of shrinkage fractures, structural fractures, and bedding seans. The Permian Fengcheng Formation was mainly formed in an alkaline lake in the Mahu Sag, and the alkaline lacustrine sedimentary setting plays a decisive role in the formation of the tight oil reservoirs of the Fengcheng Formation. Volcanic glass in the tight oil reservoirs was generally devitrified within the alkaline lacustrine diagenetic fluid in the early diagenetic stage, and the devitrified micropores become an important reservoir space. Feldspars and salt minerals were mainly dissolved by acidic fluids generated by burial thermal evolution of the alkaline lacustrine source rocks of the Fengcheng Formation in the Mahu Sag, which produces the most developed dissolution pores in the tight oil reservoir. The abnormal high pressure formed by the early hydrocarbon generation and expulsion of the alkaline lacustrine source rocks in the Fengcheng Formation is one of the main reasons for porosity preservation. In the alkaline lake sedimentary environment of the Fengcheng Formation, widespread dolomitization and precipitation of a large number of salt minerals in the early diagenetic stage resisted partial compaction, which not only effectively protected early porosity, but also provided material conditions for dissolution porosity enhancement.

The Study on Diagenetic Characteristics of Coal Measures Sandstone Reservoir in Xishanyao Formation, Southern Margin of the Junggar Basin

The reservoir physical properties, pore types, diagenetic characteristics and reservoir quality controlling effect of the Xishanyao formation coal measure sandstone in the southern margin of the Junggar basin were discussed in this study based on thin section observation, high pressure mercury injection, low-temperature nitrogen adsorption and scanning electron microscope observation. The result shows that the porosity and permeability of the sandstone are generally low with a medium-high texture maturity and low compositional maturity. The sandstone storage space is mainly composed of residual intergranular pores, secondary dissolution pores, inter-crystalline pores and micro-fractures. The diagenetic stage of coal measure sandstone is in the mesodiagenesis A1-A2 stage, and their diagenetic interaction types mainly include compaction, cementation and dissolution. The reservoir quality of the coal measure sandstone deteriorates by compaction due to high matrix content and plastic debris content. Because of the large amounts of organic acids generated during the thermal evolution of the coal measure source rock, the coal measure sandstone suffers from strong dissolution. The secondary dissolution pores formed by the massive dissolution of feldspar, lithic fragments and early carbonate cementation in the sandstone significantly improved the reservoir quality. In the coal measure sandstone, clay mineral cementation is the most developed cementation form, followed by quartz cementation and carbonate cementation. Although kaolinite cementation and dolomite cementation can generate a small number of inter-crystalline pores, cementation deteriorates the reservoir quality. The Xishanyao formation coal measure sandstone formed in a lacustrine-delta environment, and its composition and texture make it susceptible to the influence of compaction and dissolution during diagenesis.

Classification and Evaluation of Shale Oil Reservoirs of the Chang 71-2 Sub-Member in the Longdong Area

Establishing a suitable classification and evaluation scheme is crucial for sweet spot prediction and efficient development of shale oil in the Chang 71-2 sub-member of the Longdong area. In this paper, a series of experiments, such as casting thin sections (CTS), scanning electron microscopy (SEM), low-temperature nitrogen adsorption (LTNA), high-pressure mercury intrusion porosimetry (HMIP), and nuclear magnetic resonance (NMR), were integrated to classify the pore throats and shale oil reservoirs in the study area. Moreover, the pore structure characteristics of different types of reservoirs and their contributions to productivity were revealed. The results show that the pore-throat system can be divided into four parts: large pore throats (>0.2 μm), medium pore throats (0.08~0.2 μm), small pore throats (0.03~0.08 μm), and micropore throats (<0.03 μm). Based on the development degree of various pore throats, the reservoir is divided into four types: type I (Φ ≥ 10%, K > 0.1 mD), type II (Φ ≥ 8%, 0.05 mD < K < 0.1 mD), type III (Φ ≥ 5%, 0.02 mD < K < 0.05 mD) and type IV (Φ < 5% or K < 0.02 mD). From type I to IV reservoirs, the proportion of dissolved pores and intergranular pores gradually decreases, and the proportion of intercrystalline pores increases. The proportion of large pore throats gradually decreases, and the proportions of medium pore throats and small pore throats increase initially and then decrease, while the proportion of micropore throats increases successively. The NMR pore size distribution changes from the right peak to the left peak. The developed section of the type I reservoir corresponds to the oil layer, and the developed section of the type I and II reservoirs corresponds to the poor oil layer. In contrast, the developed section of the type III and IV reservoirs corresponds to the dry layer. The daily production from single wells is primarily attributable to type I and II reservoirs.

Constrains of physical properties and geochemical characteristics of country rock on skarn tungsten mineralization: a case study of the Longjiaoshan-Fujiashan skarn tungsten deposit in the Middle-Lower Yangtze River Metallogenic Belt

Previous research on skarn tungsten deposits has mainly focused on causative rocks and skarn minerals. The effect of the physical and mechanical properties and geochemical characteristics of the country rock on the mineralization of skarn tungsten deposits urgently needs to be further studied. A new skarn deposit, Longjiaoshan-Fujiashan, was discovered in the Edong orefield of the Middle-Lower Yangtze River Metallogenic Belt in the contact zone between the causative intrusive rock and the country rocks. The Longjiaoshan-Fujiashan deposit is an ideal research object for the influence of country rock on skarn mineralization. Based on rich ore-hosting and lean ore-hosting strata in the Longjiaoshan-Fujiashan deposit, we conducted analyses of major and trace elements and organic carbon content, specific surface area, porosity, and permeability. Combined with previous studies, we concluded that the difference among the levels of major and trace elements and organic carbon of the strata could be negligible. The conclusion demonstrates that the influence of geochemical properties of limestones on mineralization is small, whereas the physical properties of limestones are likely the main factor influencing mineralization. The pore-type of rich ore-hosting strata (Qixia Formation and Maokou Formation) are fractured pores and organic pores, whereas those of the lean ore-hosting strata (Huanglong Formation and Dabu Formation) are intercrystalline and intercrystalline pores. The average specific surface areas of the rich ore-hosting and lean ore-hosting strata of the limestone samples were 0.1575 and 0.0167 m2/g, respectively. The lower specific surface area is probably not conducive to the adsorption of gas in the ore-forming hydrothermal fluid, which reduces the reaction rate. Similarly, a high pore volume is conducive to the full reaction of the ore-forming hydrothermal fluid with the country rock and the formation of the orebody. The pore diameter of the rich ore-hosting limestone strata in the Longjiaoshan-Fujiashan deposit was in the range of 40–110 μm, and showed “multiple peaks with one main peak and multiple secondary peaks.” The country rock with the reported pore size characteristics is likely to benefit from ore formation. The alteration scale of high porosity and high permeability country rock (i.e., rich ore-hosting strata: 9.0989 MDarcy; lean ore-hosting strata: 2.9699 MDarcy) are conducive to the formation of large skarn-type mineralization. In conclusion, compared with the geochemical properties of the country rock (major and trace elements and organic carbon content), the physical properties of the country rock (specific surface area, porosity, and permeability) have an obvious influence on the mineralization. Determining the influence of different physical property parameters of the country rock on the mineralization process of skarn is of great research value.

The Occurrence of Adsorbed Tight Oil and Its Effect on Porosity and Permeability Reduction of Triassic Lacustrine Sandstone Reservoir

The adsorption of crude oil in the tight sandstone reservoir is significant. Occurrence states of adsorbed tight oil and its pore and throat reduction effect are two significant directions in tight oil exploration and development. In this paper, the occurrence state of adsorbed tight oil and its porosity and permeability reduction effect is systematically analyzed based on a detailed description and discussion of occurrence space, states, changes of porosity and permeability, and its controlling factors. Five occurrence states are recognized based on the differences in spatial location and morphology of adsorbed tight oil. Adsorbed oil is distributed in all kinds of reservoir spaces and primarily concentrated in the pore − throat radius < 0.25 μm. The distribution characteristics of reservoir spaces control the occurrence states of adsorbed tight oil. The emulsion form, cluster form, throat form, thin film form, and isolation form are mainly stored in intergranular pores, feldspar dissolved pores, throats, the surface of minerals, and intercrystalline pores, respectively. The massive development of quartz, feldspar, and illite is conducive to the distribution of emulsion form, cluster form, and the throat form of tight oil, while the abundance of clay, especially chlorite, controls the distribution of the thin film form and isolated form of tight oil. The adsorption of tight oil causes clogging in the pore network, resulting in reservoir damage. The adsorption of tight oil in the reservoir leads to increased reservoir density by 0.290 g/cm3 and the reduction of porosity and permeability by 3.14% and 0.321 × 10 − 3 μm2, respectively. And the damage of adsorbed oil to permeability (30.79%) is more severe than that of porosity (19.96%). The effect of pore and throat reduction is more evident in reservoirs with higher content of quartz and feldspar. However, the strong adsorption of clay makes it difficult to separate the tight oil adsorbed on its surface. The nature of adsorbed oil in different occurrence states also can determine the separation efficiency in the extraction process. The adsorbed tight oil with emulsion, cluster, and throat forms is easier to desorb than the isolation and thin film forms. The research results can provide a basis for analyzing the occurrence characteristics and reasonably formulating the development method of tight oil. In addition, it can even provide a new understanding and basis for the densification process of reservoir permeability under different conditions.

Hydrothermal silicification and its impact on Lower–Middle Ordovician carbonates in Shunnan area, Tarim Basin, NW China

The Shunnan area is a newly discovered hydrocarbon field in Shuntuoguole lower uplift, in which the host rocks are Lower–Middle Ordovician carbonates. The carbonate reservoirs are well affected by hydrothermal silicification with well‐preserved intercrystalline pore of replacement quartz and megaquartz cements. Based on the petrography, pore types, and diagenetic processes, this research evaluated the reservoir quality and re‐constructed the porosity evolution in different diagenetic stages. Samples are collected from 7‐cored wells distributed along NNE‐ or ENE‐trending sinistral strike‐slip faults. Nine types of lithofacies were identified in the study area, including mudstone, bioclast wackestone, peloidal bioclast packstone, boundstone, peloidal grainstone, ooid grainstone, slightly silicified limestone (silica less than 25%), strongly silicified limestone (silica around 50%), and chert. Chert has better porosity (average 21.3%) and permeability (average 44.7 mD) than other lithofacies. The main reservoir pores are mainly developed in forms of fractures, intercrystalline replacement quartz and dissolved vugs. The porosity evolution shows that the primary porosity was limited due to cementation and compaction, and the earlier secondary porosity was occlusive as a result of coarse calcite cementation. Therefore, the precursor limestones may be tight, and the reservoir quality of the Lower–Middle Ordovician carbonates was controlled by hydrothermal silicification. During the hydrothermal silicification event, the burial depth of the Lower–Middle Ordovician carbonates was more than 3,000 m and their stratum temperature was higher than 120°C, representing a deep burial condition. The statistical data of porosity‐depth/temperature trends for carbonates suggest that the early secondary pores would be significantly reduced when the burial temperature reaches 100°C (or depth of strata reaches 3,000 m). Therefore, the dissolved vugs in strongly silicified limestone or hydrothermal chert are caused by hydrothermal silicification and not inherited from precursor carbonate rocks.