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Article

Differential Diagenesis and Hydrocarbon Charge of the Tight-Sandstone Reservoir: A Case Study from Low-Permeable Sandstone Reservoirs in the Ninth Member of the Upper Triassic Yanchang Formation, Ordos Basin, China

by
Caizhi Hu
1,
Likuan Zhang
2,*,
Yuhong Lei
2,
Lan Yu
3,
Jing Qin
1 and
Xiaotao Zhang
1
1
National Research Center for Geo-Analysis, Chinese Academy of Geological Sciences, Beijing 100037, China
2
Key Laboratory of Deep Petroleum Intelligent Exploration and Development, Institute of Geology and Geophysics, Chinese Academy of Sciences, Beijing 100029, China
3
SINOPEC Exploration & Production Research Institute, Beijing 102206, China
*
Author to whom correspondence should be addressed.
Minerals 2025, 15(5), 544; https://doi.org/10.3390/min15050544
Submission received: 3 April 2025 / Revised: 8 May 2025 / Accepted: 9 May 2025 / Published: 20 May 2025
(This article belongs to the Topic Recent Advances in Diagenesis and Reservoir 3D Modeling)
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Abstract

:
Studies of hydrocarbon migration and enhanced oil recovery focus on the effects of reservoir heterogeneity on subsurface fluid flow and distribution. Differential diagenesis in clastic rock reservoirs is an important factor of internal-reservoir heterogeneity and its relationship to hydrocarbon charges is a key scientific issue for understanding hydrocarbon accumulation mechanisms in tight-sandstone reservoirs. This paper focuses on the ninth member of the Upper Triassic Yanchang Formation (Chang 9), located in the central and western Ordos Basin, China. The aims of the paper are to examine the differential diagenesis of sandstone reservoirs and to illustrate the process of organic/inorganic fluid–rock interaction using an integrated method of petrography, UV fluorescence spectra, fluid inclusion, and basin modeling analyses. The Chang 9 reservoir comprises four sandstone types: mechanically compacted sandstone, calcite-cemented sandstone, water-bearing sandstone, and oil-bearing sandstone. These four types of sandstone experience contrasting diagenetic evolutions. During early diagenesis, mechanically compacted sandstone and calcite-cemented sandstone undergo strong deformation and cementation, respectively. The water-bearing and oil-bearing sandstones experience similar diagenetic evolutions, but significantly different from those two tight sandstones in fluid activity and diagenesis magnitude. Three types of porous bitumen were identified in the oil-bearing sandstone, whereas no bitumen was identified in the water-bearing sandstone. According to the contact relationship between bitumen, cements, and dissolution pores, the related diagenesis sequence of the oil-bearing sandstones of Chang 9 was reconstructed. Three phases of fluid flow occurred in turn, with hydrocarbon charging in the process, but no hydrocarbon charging occurred in the water-bearing sandstones. The research findings, in terms of organic and/or inorganic fluid–rock interaction, can be used as a reference for the differential diagenesis and process of fluid–rock interaction in low-permeability sandstone reservoirs with a highly heterogeneous internal reservoir framework. Furthermore, this study could help in understanding the internal heterogeneity characteristics of a fluvial sandstone reservoir and its relationship with hydrocarbon charging.

1. Introduction

The spatial variability of the reservoir system property that affects the fluid flow within the reservoir is namely reservoir heterogeneity [1,2,3,4]. Pore structure, permeability, and porosity are the typical properties that change across the reservoir and cause this phenomenon [5]. Reservoir heterogeneity impacts fluid-flow styles and distribution in reservoirs [5,6]. Studying reservoir heterogeneity is very important in locating lithological hydrocarbon accumulations, predicting residual oil distribution, and enhancing oil recovery [4,7,8]. Large amounts of systematical knowledge about macro-scale reservoir heterogeneity have been gained [8,9,10]. Different scales of heterogeneity caused by sedimentation and lithology are well defined [11,12]. Different reservoir heterogeneities vary greatly at different scales in reservoir rocks, influenced primarily by sedimentary environments, structural evolution, and diagenesis [5,13]. According to meso-scale reservoir theory, the internal flow within reservoir rock can be divided into various flow units by compartments that extend far enough inside the reservoir to cause fluid flow differentially. It is generally accepted that a flow unit is homogeneous statistically, but there are obvious heterogeneous rocks within the same flow unit resulting from diagenesis heterogeneity [5,10,14].
Numerous studies have indicated that different diagenesis types and intensities strongly complicate the original reservoir heterogeneity resulting from the depositional environment [15]. Diagenesis often results in tight-sandstone belts or concretions, such as calcite-cemented sand belts or abnormally high-dissolution pore belts, forming different types of barrier layers and a “sweet spot” within the reservoir. The distribution of barrier layers with different diagenetic origins causes the non-uniform distribution of porosity and permeability within thick sandstone layers [3,6,16]. Most of these studies focused on the genesis and distribution of different types of interlayers in thick-bed sandstone and their influence on reservoir quality and secondary pore genesis and distribution [17,18]. Few references are made to illuminate the hydrocarbon–water–rock interaction during the diagenetic evolution of the reservoir [19,20].
The systematic observation and testing of differential diagenesis have illustrated that differential diagenesis at the micro-scale creates significant heterogeneity (where oil-bearing sandstone, water-bearing sandstone, and non-permeable sandstone can coexist within a flow unit) and interlayers are not limited to mudstones or calcareous concretions. Strong internal-reservoir heterogeneity and complex oil–water distribution characteristics suggest that different sandstone components experience diverse diagenesis [21,22]. In addition, this has been recognized that compaction, cementation, dissolution, and other diagenetic factors are ongoing before the completion of the tightening of a tight-sandstone reservoir regardless of when hydrocarbon charging occurs [23,24,25,26]. It is possible to make more interesting discoveries about the hydrocarbon accumulation mechanisms of tight-sandstone reservoirs by studying the diagenetic evolution of oil-bearing sandstones under a strongly heterogeneous internal-reservoir framework from the viewpoint of organic and/or inorganic fluid–rock interaction [19,21].
The aims of this paper are to examine the differential diagenesis of tight-sandstone reservoirs and to understand the process of fluid–rock interaction using an integrated method of petrography, UV fluorescence spectra, fluid inclusion, and basin modeling analyses. In this study, the Upper Triassic ninth member of the Yanchang Formation (Chang 9), located in the central and western Ordos Basin, China, was used as a case study reservoir. Different types of sandstones within the same oil-bearing reservoir were sampled to analyze the reservoir’s diagenetic characteristics and clarify the evolution of differential diagenetic and hydrocarbon charge processes to determine the internal heterogeneity characteristics of a fluvial sandstone reservoir and its relationship with hydrocarbon charging.

2. Geological Setting

As the second largest sedimentary basin in China, the Ordos Basin can be divided into six main tectonic units: the Western Margin Thrust Belt, Tianhuan Depression, Shanbei Slope Belt, Jinxi Fold Belt, Yimeng Uplift, and Weibei Uplift (Figure 1). The Shanbei Slope Belt, which is a result of weak tectonic deformation, forms the majority of the basin in the study area. It is inclined to the west, where it forms a single slope with an incline angle of only 2°. During the early Mesozoic, a lacustrine sedimentary basin formed on the Cretaceous and Permian marine–continental transition facies basement [10]. During the late Triassic, the stable subsidence of the sedimentary basin formed a typical fluvial lacustrine clastic sediment series, represented by multiple sediment sources, multiple river systems, and obvious sediment debris zonation. During the late Triassic, late middle Jurassic, and the end of the late Jurassic, the basin was briefly uplifted and partly eroded. Since the late Cretaceous, the basin has continued to be uplifted while undergoing a diversified transformation [27].
The Upper Triassic Yanchang Formation is the first oil source rock and reservoir created in the basin after the formation of the lacustrine sedimentary basin and has been the main exploration target in the basin [29]. It can be divided into ten members, from Chang 1 downward to Chang 10. During the Chang 9 sedimentation period, the basin was rapidly subsiding. Significant primary reservoir heterogeneity was created during this period through the development of a northeast meandering river delta, a southeast braided river delta, a central fluvial delta, and a deep to semi-deep lacustrine facies, which created vertical inter-stacking and multiple lateral contiguous sedimentation patterns, including various microfacies of subaqueous distributary channels, subaqueous levees, river mouth bars, distal bars, and a distributary bay [29]. The recent exploration of the lower Yanchang Formation has illustrated that the Chang 9 member potentially contains a large amount of petroleum resources and has thereby become an important potential reservoir [28,29].
The published literature indicates that the sandstones in the Chang 9 reservoir have low porosity and ultralow permeability [29]; a complex oil–water relationship; a wide range of oil saturation values in the oil-bearing formation [28]; and oil, water, and dry layers that are difficult to recognize using well log data. These challenges have severely affected the understanding of the hydrocarbon accumulation mechanisms in the Chang 9 oil reservoir, the choice of exploration targets, and the development of a production strategy. The authors believe that the heterogeneity and various types of non-oil-bearing sandstones in the Chang 9 member may be the main reasons for these difficulties in resource exploitation.

3. Samples and Methods

This study utilized 132 Chang 9 core samples from 23 wells, representing the different lithologies, oil saturations, petrophysical properties, and sedimentary microfacies.
All samples were impregnated with blue epoxy resin to indicate porosity before preparing thin sections. Thin sections were stained with Alizarin Red S and K-ferricyanide to identify carbonate cements. The composition and pore plane ratio of the sandstones were quantified by point counting at 300 points per thin section using a polarizing light microscope. A scanning electron microscope (SEM) (Zeiss LEO 1450VP, Carl Zeiss Microscopy Deutschland GmbH, Oberkochen, Germany), equipped with energy dispersive spectroscopy (Oxford Inca Energy 300, Oxford Instruments plc, Tubney Woods, Abingdon, UK), was used to examine the pore geometry and morphology of diagenetic minerals. Cathodoluminescence (CITL CL8200 MK5-2, Cambridge Image Technology Ltd., Hertfordshire, UK) analysis was used to identify debris fabrics and the multiphase cementation of carbonate, quartz, and feldspar cements. A high-pressure mercury meter was selected to measure the porosity and permeability of the sandstones.
Ultraviolet (UV) fluorescence spectrometry with Raman microspectrometry (Renishaw LabRam-010, Renishaw plc, New Mills, UK) was conducted to observe the characteristics of asphaltene in pores and hydrocarbon fluid inclusions and their relationships with authigenic minerals within 37 0.08 mm-thick doubly polished thin sections. From the authigenic minerals such as quartz overgrowths, carbonate cement, and healed fractures, 96 fluid inclusions, including 42 hydrocarbon fluid inclusions and 54 saline fluid inclusions synchronous with the hydrocarbon inclusions, were selected from 16 thin section samples from 14 wells. The homogenization temperatures of the saline inclusions were measured using a heating–cooling stage (Linkam THMSG600, Linkam Scientific Instruments, Salfords, UK), connected to a microscope (Nikon Eclipse 80i, Nikon Instruments Inc., Tokyo, Japan) with an instrumental precision of ±0.1 °C. All observations and testing were carried out at the Key Laboratory of Petroleum Resource Research, Chinese Academy of Sciences.
The core analysis data included measurements of the porosity, permeability, and grain density of the 132 samples and the wireline logs of 23 wells.

4. Results

4.1. Macro-Scale Observations and Statistical Characterization

The Chang 9 reservoir contains various sedimentary structures and different levels of oil saturation (Figure 2). Gray-green fine-grained sandstone and dark gray siltstone or mudstone were frequently observed to be vertically interbedded. Block bedding, parallel bedding, and scouring structures were often observed at the base of the sandstone beds, and the upward fining of the grain size accompanied wedge-shaped or plate-shaped staggered bedding.
The oil-bearing sandstones were dark brown to brown (Figure 2a) and characterized by the slow permeation of a drop of water on a freshly fractured surface. The oil-free sandstones included three types. Type I is dark gray to gray and exhibits a blocky or staggered bedding structure. Type II exhibits large amounts of gray conglomeration growing along laminar surfaces, characterized by a strong reaction to a drop of acid on freshly fractured surfaces. Type III is a dark-gray fine-grained sandstone distributed as thin laminar with sand-grain bedding and horizontal bedding. In general, the oil-bearing sandstone and the oil-free sandstone overlapped each other, and the oil–water surface was clearly recognized because of frequent changes in the sedimentary structure.
One hundred and thirty-two porosity and permeability measurements from different types of sandstones are shown in Figure 2b. The Chang 9 member sandstones exhibited low or ultralow porosity and permeability. The physical properties of the tight sandstones were the least favorable, with a maximum porosity of <10% and a maximum permeability of <0.1 × 10−3 μm2. The porosity of all the oil-bearing sandstone samples ranged from 0.3% to 16.8%, with an average value of 6.29%, and the permeability varied from 0.02 to 2.3 × 10−3 μm2, with an average value of 0.38 × 10−3 μm2. For the relatively highly saturated oil-bearing sandstones, the average porosity (9.4%) and average permeability (0.66 × 10−3 μm2) were higher than the relatively slightly saturated oil-bearing sandstones, with an average porosity of 5.88% and an average permeability of 0.24 × 10−3 μm2. In addition, the physical properties of the oil-free sandstones varied over a larger interval, i.e., the porosity ranged from 0.1% to 15.2% and the permeability ranged from 0.04 to 1.04 × 10−3 μm2.

4.2. Sandstone Petrology

The Chang 9 reservoir sandstone is dominated by light gray-green medium-fine-grained lithic arkose, with a small amount of arkose and arkose lithic sandstone [30]. There was no significant difference between the oil-bearing and the oil-free sandstones in detrital components (Figure 3). The quartz content varies between 20% and 35%, with an average of 30%. The feldspar content ranges from 25% to 40%, with an average value of 30.5%. The lithic fragment content falls between 15% and 25%, with an average value of 20.6%. The Chang 9 sandstones exhibited moderate compositional maturity, moderate-to-poor sorting, angular-to-subangular roundness, and low textual maturity.
The oil-bearing and oil-free sandstones in the Chang 9 reservoir differ in their content of rock fragments and cements. The statistical relationship between cement and thin section porosity is illustrated in Figure 4 and Table 1. The average thin section porosity of the oil-bearing sandstone was ~4.55% and the cements were mainly less than 15%, with an average of ~8.8%. The porosity reduction resulting from cementation was about 5%–40%. The average value of the thin section porosity of water-bearing sandstones was about 3.16% and the cement ranged from ~5% to 20%, with an average value of 10.4%. The cementation and mechanical compaction porosity reduction have similar degrees to oil-bearing sandstones, with values of 12%–40% and 50%–75%, respectively (Figure 4). In addition, another type of tight sandstones had the lowest thin section porosity, mainly lower than 1%, with an average value of 0.35% (Table 1). The distribution of cement contents in the tight sandstones exhibits a bimodal pattern, with a lower peak of less than 10% and a higher peak exceeding 20%. The former with a lower cement content had mean ductile lithic fragment (Dl) contents of 16.17% and mean rigid lithic fragment (Rl) contents of 8.7%, while the latter with a higher cement content had 8.3% and 11.4%, respectively. Cementation causes 10%–25% of the original porosity loss and compaction causes 70%–75% of the original porosity loss in the former tight sandstones, while cementation and compaction causes 65%–90% and 35% of original porosity loss in the latter tight sandstones, respectively. These features were in good agreement with the core observations. Sandstones with a high ductile debris content had low cement contents and low intergranular porosity. Calcite-cemented sandstones had a high calcite cement content and low intergranular porosity.
The core observations, physical statistics, and microfabric features clearly demonstrated that the Chang 9 reservoir sandstones can be roughly divided into four types: oil-bearing sandstones, water-bearing sandstones, mechanically compacted sandstones rich in ductile debris, and calcite-cemented sandstones.

4.3. Diagenesis of the Oil-Bearing Sandstone

4.3.1. Cementation

Most of the oil-bearing sandstones were rich in quartz overgrowths, calcite, chlorite, and kaolinitic cement, as well as large amounts of dark brown–black asphalt remaining on the edges of the pores. As illustrated in Figure 5b, two single quartz crystals continued to grow on the surface of the particles coated by a hydrocarbon-infiltrated chlorite membrane. After the first phase of quartz overgrowth precipitation, thin chlorite coatings, representing an alkaline environment, precipitated on the surface of the first-phase quartz overgrowth. The chlorite coating was followed by the second-phase quartz overgrowth, representing a weakly acidic environment. The calcite cement in the remaining intergranular pores indicated that it had formed after the second phase of quartz overgrowth. The irregular edges of the calcite cement indicated that another phase of dissolution occurred after the precipitation (Figure 5c). The formation of the calcite cement in the oil-bearing sandstones also exhibited multiple phases. As shown in Figure 5d, the calcite is a micro-calcite, representing early precipitation, and occupied by large intergranular pores, and the sparry calcite, representing late precipitation, occupied little porosity.

4.3.2. Fluorescence of the Pore Asphalt and Hydrocarbon-Bearing Fluid Inclusions

The main feature of the oil-bearing sandstones was that hydrocarbon charging had occurred in multiple phases during the diagenetic process: the samples contained different types of asphalt and hydrocarbon fluid inclusions (HFIs). The oil-bearing sandstones exhibit strong fluorescence under UV light, with at least two colors. Under transmitted light, the pore asphalt was opaque and dark brown to black, while under UV light, it showed two distinct characteristics (Figure 6a). Most of the edges of carbonaceous bitumen were irregular and exhibited light-yellow fluorescence (Figure 6b), possibly resulting from the dissolution of oil asphalt. This phenomenon is common in the Chang 9 oil-bearing sandstones. A large amount of authigenic kaolinite filling was common in the intergranular pores of some of the oil-bearing sandstones. The authigenic kaolinite contaminated by hydrocarbons in the center of the intergranular pores was light brown under transitional light and bright blue under UV light, while at the interface with particles, it was dark brown under transitional light and light-yellow under UV light (Figure 6c). Membrane-like dry asphalt in intergranular pores, observed using SEM, forms dry shrinkage fractures that expose impregnated chlorite aggregates (Figure 6d) and provide nuclei for cementation minerals such as calcite and kaolinite.
The HFIs are mostly dark orange, yellowish green to light yellow, and blue to bright blue under UV light irradiation (Figure 6e), with peak wavelengths (λmax) of 596.68, 538.24, and 470.46 nm, respectively. Differently fluorescing HFIs, corresponding to different porous asphalts (i.e., carboniferous pitch, yellow-fluorescence porous asphalt, and blue-fluorescence porous asphalt), usually appearing in cementation minerals or healed cracks with different phases, reflected three hydrocarbon charging events. The light-yellow fluorescing HFI (λmax = 536.33 nm), shown in Figure 6f, grew in the contact between the quartz grains and quartz overgrowths, while the HFI in the sealed microfractures cross-cutting the quartz grains, and quartz overgrowths fluoresced blue (λmax = 468.28 nm). It was concluded that the hydrocarbon charge represented by the light-yellow fluorescent porous asphalt occurred before the quartz overgrowth, while the blue-fluorescent porous asphalt occurred after the quartz overgrowth.

4.4. Diagenesis of the Oil-Free Sandstone

The oil-free sandstones differ from oil-bearing sandstones because no hydrocarbon charges occurred in diagenetic evolution and their components and structures differed from each other.

4.4.1. Mechanically Compacted Sandstone

The mechanically compacted sandstones contained large volumes of ductile debris (such as mudstone, volcanic tuff, phyllite, schist, and mica) or mud matrices. These components mainly exhibited ductile deformation, being in linear or concavo-convex contact with rigid grains such as quartz and feldspars, as well as forming pseudo-matrices after squeezing into intergranular pores (Figure 7a,b). A lack of UV light fluorescence indicated that they had not been charged by hydrocarbons.

4.4.2. Calcite-Cemented Sandstone

The calcite-cemented sandstone was cemented by calcite during the diagenetic process and did not dissolve after this. The calcite was of two types, microcrystalline calcite (Figure 7c) and sparry calcite (Figure 7d).
The microcrystalline calcite often occurs in fine-grained or silty sandstones, where detrital grains are in point contact with each other (Figure 7c). Longman (1980) [31] stated that large volumes of microcrystalline calcite form during the syngenesis or early diagenesis stage, which causes the rapid tightening of sandstones.
Sparry calcite can recrystallize from microcrystalline calcite (Figure 7c) and precipitate directly from pore water (Figure 7d). The resulting cementation is porous or suspended. The contact between the sparry calcite cement and the detrital grains was irregular (zigzag), which indicated that the dissolution occurred before the cementation (Figure 7d). In addition, a single-phase quartz overgrowth had precipitated between the detrital grains and the calcite cement in a small number of samples. There were no asphaltene residues or fluorescence displayed in calcite-cemented sandstones; therefore, the diagenetic sequence of the calcite-cemented sandstone was determined as follows: compaction, microcrystalline calcite cementation, quartz overgrowth cementation, and sparry calcite cementation.

4.4.3. Water-Bearing Sandstone

The water-bearing sandstone had relatively good porosity and permeability and had undergone a relatively complicated diagenetic process. It was commonly observed that the multiphase of quartz overgrowths had interactively grown with chlorite films in most of the water-bearing sandstones (Figure 8a–d), indicating that the water-bearing sandstone had undergone cyclical acidic and alkaline fluid environments. As shown in Figure 8a, the first phase of quartz overgrowths precipitated around the edges of detrital quartz grains during the diagenetic process. The quartz overgrowths were in linear contact with adjacent detrital grains during compaction. When the pore water became alkaline, chlorite precipitated as a film in the pores. When the pore water then became weakly acidic, quartz cement re-precipitated in the pores from a sufficiently siliceous source and appropriate nucleation conditions. This was the second phase of quartz overgrowths to precipitate on the chlorite coating of the detrital grains, as shown in Figure 8b. Calcite cemented the pores outside of the second phase of quartz overgrowth, suggesting a third pore-fluid condition conversion. Figure 8c reflects the contact relationship between the different phases of quartz overgrowth and other authigenic minerals more comprehensively. There were three phases of quartz overgrowth precipitated out of order along the surface of the grains with “dust lines”, which were confirmed by SEM to be authigenic chlorite between the different quartz overgrowths (Figure 8d). After the precipitation of the three phases of quartz overgrowth, one phase of calcite precipitated in the remaining intergranular pores until the pores were completely cemented.
As part of a reservoir, water-bearing sandstones commonly experience similar multiphase diagenetics to oil-bearing sandstones. No asphaltene residues were observed in the thin sections and no fluorescence was displayed under UV light, which indicated that no hydrocarbon charging had occurred.

4.5. Petrography and Homogenization Temperatures of the Fluid Inclusions

The detailed observation of secondary fluid inclusions in 16 inclusion-bearing thin sections belonging to the four types of sandstone indicated that there were no secondary fluid inclusions in the mechanically compacted sandstone; only saline-bearing fluid inclusions were present in the water-bearing sandstone and calcite-cemented sandstone; and both saline-bearing fluid inclusions and hydrocarbon-bearing fluid inclusions were present in the oil-bearing sandstone. The homogenization temperatures of 54 saline-bearing fluid inclusions, located in the cements (quartz overgrowth and calcite) and healed cracks, formed simultaneously with hydrocarbon charging, clearly showed that there were three peak intervals of ~75 °C–85 °C, ~100 °C–110 °C, and ~125 °C–140 °C in the oil-bearing sandstones (Table 2 and Figure 9), corresponding to HFIs with dark orange, yellowish green to light yellow, and bright blue under UV light irradiation, respectively. Similarly, in the water-bearing sandstones, three peak intervals were observed: ~65 °C–75 °C, ~90 °C–100 °C, and ~125 °C–140 °C. Saline-bearing fluid inclusions in the calcite-cemented sandstones mainly occurred in calcite cement and a small amount of quartz overgrowth cement. The results showed that the homogenization temperatures were mainly between ~56.3 °C and 84.6 °C, and especially between ~56.3 °C and 78.3 °C for the saline-bearing fluid inclusions in calcite cement.

5. Discussion

5.1. Theoretical Basis for Dividing the Diagenesis by the Hydrocarbon Charging Events

According to the principle of material balance, in a relatively closed diagenetic system, after a first-phase fluid enters the rocks, there must be both the dissolution of debris particles and the precipitation of authigenic minerals [1,32]. The precipitation and dissolution of minerals, including the original debris and cementation minerals, will occur simultaneously [32]. Fluid properties in different parts of the same rock layer can be quite different and the number of exchanges of formation fluids in the reservoir and the possible diagenesis events are innumerable and difficult to distinguish. Differences in sandstone fabrics can also lead to strong diagenetic heterogeneity and processes at different scales [8,33]. Therefore, for complicated diagenetic processes, it is obviously difficult to restore the diagenesis and hydrocarbon charging processes at the internal scale of the reservoir based on the authigenic minerals and their contact with surrounding minerals.
The duration and spacious distribution of hydrocarbon generation, migration, and accumulation in a basin are often extremely limited, and there are significant differences between hydrocarbons in each period [25,34]. After a reservoir is destroyed by various geological processes, a large amount of residual oil remains in the reservoir [35]. Some hydrocarbon components, adsorbed and encapsulated in the pore asphaltene and less affected by the later evolution of the reservoir, can contain important organic geochemical information [36]. The addition of late low-molecular-weight hydrocarbons to the crude-oil system will cause the precipitation and re-dissolution of crude asphaltenes but will not change the molecular structure of the asphaltenes [37]. A large amount of research has proved that hydrocarbon charging will not completely prevent diagenesis but only slows the diagenetic rate and that hydrocarbon charging and diagenesis can be alternated [25,38]. Therefore, the authors used pore asphaltenes and hydrocarbon inclusions in oil-bearing sandstones as the divisional markers for fluid activity, differentiated diagenesis, and hydrocarbon charging during reservoir compaction, controlled by the regional structure, sedimentary background, and heterogeneous intralayer structures.

5.2. The Process of Diagenesis and the Hydrocarbon Charge According to the Basin Uplift and Subsidence Events

Previous studies of the Ordos Basin’s burial and thermal history have shown that the basin experienced four uplift and subsidence events after the Triassic [39,40] (Figure 10). Four uplifts occurred as follows: the early Jurassic (~202.5–200 Ma and ~85–175 Ma), the middle and late Jurassic (~150–155 Ma), and the Paleogene (~20–30 Ma). The Chang 9 reservoir was correspondingly uplifted to 800, 1200, 1800, and 2500 m from the surface. During the sedimentation process, the Chang 9 reservoir reached a maximum depth of about 3500 m at the end of the early Cretaceous (~100 Ma).
The homogenization temperature data of 32 brine-filled fluid inclusions (Table 2), formed during the same period of hydrocarbon charging in the oil-bearing sandstones, indicated that the peak homogenization temperature of the first period of hydrocarbon charging was ~75 °C–85 °C, corresponding to the late Jurassic (~160–150 Ma) when the basin experienced the third subsidence event. Both the second and third hydrocarbon charges occurred during rapid subsidence in the early Cretaceous (Figure 10), and the corresponding peak homogeneous temperatures were ~100 °C–110 °C and ~120 °C–140 °C, respectively.
Therefore, using hydrocarbon charging as a marker, combined with the burial history and contact relationships between the pore asphaltene, the hydrocarbon fluid inclusions, and the authigenic cement, the diagenetic evolution of the oil-bearing sandstone was divided into three phases. Prior to the first phase of hydrocarbon charging, the oil-bearing sandstone underwent a two-stage subsidence-uplift process. The organic acid expelled from the source rock before the generation of hydrocarbons during this period tended to charge relatively high-quality reservoirs, causing the extensive dissolution of feldspar debris, calcite cement, etc., and the formation of large-volume pores favorable for hydrocarbon accumulation. The latter two phases of hydrocarbon charging occurred during the rapid subsidence of the basin during the early Cretaceous. The dissolution that occurred before the second stage of hydrocarbon charging was partly due to changes in the fluid environment caused by the third stage of basin uplift. The third stage of dissolution was caused entirely by the organic acid discharged from the source rocks before the third stage of hydrocarbon expulsion. All three stages of hydrocarbon charging began with broad dissolution, which was followed by alternating acidic and alkaline fluids and the formation of various characteristic minerals. Until the end of the hydrocarbon filling, the oil saturation reached its highest, causing the rate of cement precipitation to gradually decrease or even stop.
Before the first phase of hydrocarbon charging, the burial depth of the Chang 9 reservoir was nearly 2000 m (Figure 10). Pittman and Larese (1991) [41] stated that the maximum burial depth of the sandstones rich in rigid debris at the stage of rapid compaction and pore reduction was 2000 m and that the sandstones with a higher plastic debris content were located at a much shallower depth. The average pore reduction rate resulting from the compaction of the Chang 9 reservoir in the Ordos Basin is greater than 25% [42,43], and because the reservoir contains abundant plastic debris with an extremely high stress sensitivity, such as siltstones, phyllites, schist, and volcanic tuff, this should be much larger than average [44]. Furthermore, in the current study, microscopic observations showed that there was no evidence of cementation, dissolution, or hydrocarbon residue in sandstones with high levels of plastic debris, indicating that this type of sandstone was tightly mechanically compacted before the first phase of hydrocarbon charging.
Early carbonate cement usually develops in high-permeability layers of sandstone or in the groundwater flow direction. Since the permeability of sandy sediments mainly depends on the size and sorting of the particles, carbonate cement will preferentially develop along sandstones with a coarser grain size, better sorting, and better original permeability [16]. The greater negative cement porosity and the point-like and suspended contact of the clastic particles in the calcite-cemented sandstone of the study area indicated that the sandstone had good physical properties and had not reached the maximum depth when the cementation diagenesis occurred. In addition, no forms of hydrocarbon residue or fluorescent display were observed in the fluorescence analysis, indicating that hydrocarbon charging did not occur when the cementation occurred. Carbon and oxygen isotopes in the carbonate cements of the Yanchang Formation in the study area also proved that the formation of such cements was related to the weak HCO3− alkaline environment formed by atmospheric water [45]. Therefore, there was ample evidence that the formation of the calcite-cemented sandstone occurred earlier than the first phase of the hydrocarbon charging.
The water-bearing sandstone was exposed to fluid activity similar to that of the oil-bearing sandstones, as determined by the comparative analysis of the vitrinite reflectance, the montmorillonite content index in the illite/smectite mixed layer, and the homogenization temperatures of the fluid inclusions in similarly produced cement. These diagenetic characteristics are closely related to the uplift and subsidence of the basin, with each stage of uplift resulting in fluid exchange and the diagenetic environment of the reservoir changing to a large extent. The oil-bearing sandstone evolved relatively slowly and retained relatively high porosity and permeability due to the retardation of the diagenesis by the charged hydrocarbons, while most of the water-bearing sandstones were densified through sufficient iron exchange but no hydrocarbon charge. Due to the isolation of the interlayer, only a small portion of the water-bearing sandstone may still maintain relatively high porosity [26,46].
Therefore, the basin’s evolutionary background combined with the detailed analysis of the diagenetic events of the four types of sandstones, the differential diagenesis, and the hydrocarbon charging process of the Chang 9 reservoir sandstones was essentially clarified (Figure 10).
Under the influence of the Yanshan movement, the strongly heterogeneous Chang 9 reservoir experienced two periods of tectonic uplift. During this process, the mechanically compacted sandstone in the Chang 9 reservoir underwent a small amount of siliceous cementation and debris erosion in the early stage due to better pore penetration conditions, but it rapidly densified as the compaction increased. Simultaneously, some sandstones with good porosity and permeability were gradually cemented by calcium during the two uplifting-subsidence processes, and all were cemented when the basin was buried for the third time, retaining a high negative cement porosity.
When the basin was buried to ~2000 m for the third time, the source rock began to produce hydrocarbons and charge the reservoir. The hydrocarbon migration path and local accumulation spots were extremely non-uniform due to the reservoir’s heterogeneity [25,26]. With increasing filling by hydrocarbons, the diagenetic rate of the oil-bearing sandstones along the migration pathways gradually slowed, thus maintaining relatively high porosity and permeability and simultaneously transforming some of the wettable mineralogy into oleophilic surfaced minerals [25]. The diagenesis of the water-bearing sandstone not on the migration pathways continued, and the porosity and permeability continued to decrease. The basin began its third overall uplift ~150 Ma due to tectonic movement. During this process, the reservoirs that had originally been concentrated in the relatively high-porosity sandstone began to adjust and destruct, leaving dark brown–black carbonaceous asphalt in pores, and the pore fluid gradually changed into an inorganic fluid through frequent ion exchange.
The latter Yanshan movement changed the overall uplift tectonic pattern of the basin, and the basin began its fourth rapid subsidence in the early Cretaceous. During this burial process, the porosity of the oil-bearing and water-bearing sandstones gradually deteriorated under the influence of various diagenetic processes. During the period of ~125–140 Ma, a second period of hydrocarbon generation peaked, and the rapidly sinking Chang 9 oil-bearing sandstones began to be continuously charged. At this time, the oil-bearing sandstones were the dominant channel for hydrocarbon charging due to their relatively good physical properties and the oil wettability of some minerals. Only a small amount of water-bearing sandstone with relatively good porosity and permeability was filled with hydrocarbons during the second phase. The continuous subsidence of the basin made the oil-bearing sandstones and water-bearing sandstones denser.
The third stage of hydrocarbon expulsion was weak. During this period, the depth of the Chang 9 reservoir exceeded 3000 m. Various sandstones exhibited low porosity and low permeability [47], but the oil-bearing sandstone maintained relatively good porosity and oil wetting, thus becoming the main target of the hydrocarbon charging.

6. Conclusions

The Chang 9 reservoir in the Ordos Basin is highly heterogeneous and comprises mechanically compacted sandstone, calcite-cemented sandstone, water-bearing sandstone, and oil-bearing sandstone according to the petrology and diagenetic characteristics of the reservoir. The first two types of sandstone strongly influenced the fluid flow, distribution, and diagenesis of the reservoir.
Different types of sandstones in the same reservoir underwent different diagenetic processes. The mechanically compacted sandstone was only affected by compaction and rapidly densified in the early stage of diagenesis. Calcite-cemented sandstone underwent a wide range of pore-type and even base-type cementations under these conditions, with a sufficient supply of calcite and good porosity and permeability in the early stage, and the densification was completed before the first phase of hydrocarbon charging. Water-bearing sandstone and oil-bearing sandstone underwent similar multi-stage diagenetic processes, but the hydrocarbon charge into the oil-bearing sandstone slowed the rate of diagenesis (mainly cementation), maintained relatively good porosity and permeability, and changed the wettability of some minerals, which made it more conducive to the migration and accumulation of hydrocarbons in the later stage compared with the water-bearing sandstone.
The diagenesis of the oil-bearing sandstone can be divided into three phases using the three hydrocarbon charging events. Each phase of the hydrocarbon-filled front (organic acid) formed a large range of acidic fluid environments, which produced a large number of dissolved pores. As the hydrocarbon charging continued, the supply and delivery conditions of mineral ions gradually deteriorated, and the growth of authigenic minerals was inhibited until it ceased. After the completion of the first phase of the hydrocarbon charging or the uplift of the basin’s structure, the reservoir adjusted, the activity of the inorganic pore fluid was enhanced, a new diagenesis started, and the diagenesis and hydrocarbon charging alternated.

Author Contributions

Conceptualization, C.H. and L.Z.; methodology, Y.L.; software, Y.L.; validation, L.Z., Y.L. and L.Y.; formal analysis, J.Q.; investigation, L.Y.; resources, L.Z.; data curation, X.Z.; writing—original draft preparation, C.H.; writing—review and editing, L.Z.; visualization, C.H., L.Z., Y.L. and L.Y.; supervision, L.Z.; project administration, L.Z.; funding acquisition, L.Z. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by the National Natural Science Foundation of China (42030808), the Provincial Natural Science Foundation of Heilongjiang (QC2018042), and the Fundamental Research Funds of Chinese Academy of Geological Sciences (CSJ-2021-04).

Data Availability Statement

Data are contained within the article.

Conflicts of Interest

The authors declare no conflict of interest.

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Figure 1. Tectonic outline map of the study area and stratigraphic column (modified from [27,28]).
Figure 1. Tectonic outline map of the study area and stratigraphic column (modified from [27,28]).
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Figure 2. Structural sedimentary feature and the relationship between porosity and permeability for the different oil-saturated sandstones. (a) Chang 9 core sandstone characteristics (~2110.00–2114.32 m, well F10). (b) Porosity and permeability scatter diagram and histogram.
Figure 2. Structural sedimentary feature and the relationship between porosity and permeability for the different oil-saturated sandstones. (a) Chang 9 core sandstone characteristics (~2110.00–2114.32 m, well F10). (b) Porosity and permeability scatter diagram and histogram.
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Figure 3. Petrology of the Chang 9 member. I—quartz sandstone, II—arkose quartz sandstone, III—lithic quartz sandstone, IV—arkose, V—lithic arkose, VI—arkose lithic sandstone, and VII—lithic sandstone.
Figure 3. Petrology of the Chang 9 member. I—quartz sandstone, II—arkose quartz sandstone, III—lithic quartz sandstone, IV—arkose, V—lithic arkose, VI—arkose lithic sandstone, and VII—lithic sandstone.
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Figure 4. Correlation between cement content, intergranular volume, and porosity of the Chang 9 member.
Figure 4. Correlation between cement content, intergranular volume, and porosity of the Chang 9 member.
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Figure 5. Diagenetic characterization of Chang 9 oil-bearing sandstone (well ZC47) from ~2186 m. (a) Carbonaceous bitumen left in the solution pores of the sandstone (7.5× magnification). (b) Common relative diagenetic sequence of chlorite growth, oil charge (carbonaceous bitumen), and quartz overgrowth (30× magnification). (c) Large amounts of cement and solution pores observed in the sandstones and the relative diagenesis sequence: bitumen, quartz overgrowth I, chlorite growth, quartz overgrowth II, calcite growth, and dissolution (30× magnification, 2676.5 m, well DZ3251). (d) The relative diagenetic sequence is micro-calcite, quartz overgrowth, and sparry calcite. Note: Qog = quartz overgrowth, Cal = calcite, Chl = chlorite, and Bit = porous bitumen.
Figure 5. Diagenetic characterization of Chang 9 oil-bearing sandstone (well ZC47) from ~2186 m. (a) Carbonaceous bitumen left in the solution pores of the sandstone (7.5× magnification). (b) Common relative diagenetic sequence of chlorite growth, oil charge (carbonaceous bitumen), and quartz overgrowth (30× magnification). (c) Large amounts of cement and solution pores observed in the sandstones and the relative diagenesis sequence: bitumen, quartz overgrowth I, chlorite growth, quartz overgrowth II, calcite growth, and dissolution (30× magnification, 2676.5 m, well DZ3251). (d) The relative diagenetic sequence is micro-calcite, quartz overgrowth, and sparry calcite. Note: Qog = quartz overgrowth, Cal = calcite, Chl = chlorite, and Bit = porous bitumen.
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Figure 6. Fluorescence spectrum characteristics of pore bitumen and an oil-bearing fluid inclusion in Chang 9 oil-bearing sandstone. (a) The black to dark-brown bitumen remaining in the pores represents the two phases of oil charging, a counterpart to the black (first-phase oil charging) and yellow-brown color (second-phase oil charging), and (b) as seen under UV light (20× magnification, 2227.7 m, well ZC48). (c) Another type of bitumen remaining in the kaolinitic inter-crystal porosity appearing light blue under UV light (50× magnification, 2053.7 m, well JT564). (d) SEM of an oil film covering cracked chlorite aggregates forming microfractures (1843.26 m, well Y190). (e) Oil-bearing fluid inclusions containing two different phases of sealed fractures (50× magnification, 2113.44 m, well F10) appearing yellow brown (the earlier oil) and light blue (the later oil) under UV light. (f) Oil-bearing fluid inclusions in a quartz overgrowth appearing (g) as a faint yellow color (50× magnification, 2663.46 m, well D3217). (h) Oil-bearing fluid inclusions contained in a sealed fracture cutting through a quartz overgrowth and appearing light blue under UV light. Note: Q = quartz, Qog = quartz overgrowth, Bit = porous bitumen, Chl = chlorite, and Kln = kaolinite.
Figure 6. Fluorescence spectrum characteristics of pore bitumen and an oil-bearing fluid inclusion in Chang 9 oil-bearing sandstone. (a) The black to dark-brown bitumen remaining in the pores represents the two phases of oil charging, a counterpart to the black (first-phase oil charging) and yellow-brown color (second-phase oil charging), and (b) as seen under UV light (20× magnification, 2227.7 m, well ZC48). (c) Another type of bitumen remaining in the kaolinitic inter-crystal porosity appearing light blue under UV light (50× magnification, 2053.7 m, well JT564). (d) SEM of an oil film covering cracked chlorite aggregates forming microfractures (1843.26 m, well Y190). (e) Oil-bearing fluid inclusions containing two different phases of sealed fractures (50× magnification, 2113.44 m, well F10) appearing yellow brown (the earlier oil) and light blue (the later oil) under UV light. (f) Oil-bearing fluid inclusions in a quartz overgrowth appearing (g) as a faint yellow color (50× magnification, 2663.46 m, well D3217). (h) Oil-bearing fluid inclusions contained in a sealed fracture cutting through a quartz overgrowth and appearing light blue under UV light. Note: Q = quartz, Qog = quartz overgrowth, Bit = porous bitumen, Chl = chlorite, and Kln = kaolinite.
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Figure 7. Diagenesis of the tight Chang 9 sandstone resulting from compaction and calcite cementation. (a,b) Phyllite debris plastically deformed by compaction exhibiting a concavo-convex contact with rigid debris and a false mixed base (5× and 20× magnification, respectively; 2191.1 m; well ZC47). (c) A commonly observed micro-calcite edge from an intergranular pore partially recrystallized to sparry calcite (20× magnification, 2071.9 m, well C109). (d) Dissolved pores cemented by sparry calcite (15× magnification, 2114.87 m, well DT6529).
Figure 7. Diagenesis of the tight Chang 9 sandstone resulting from compaction and calcite cementation. (a,b) Phyllite debris plastically deformed by compaction exhibiting a concavo-convex contact with rigid debris and a false mixed base (5× and 20× magnification, respectively; 2191.1 m; well ZC47). (c) A commonly observed micro-calcite edge from an intergranular pore partially recrystallized to sparry calcite (20× magnification, 2071.9 m, well C109). (d) Dissolved pores cemented by sparry calcite (15× magnification, 2114.87 m, well DT6529).
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Figure 8. Diagenesis of water-bearing Chang 9 sandstone. (a) The relative multiphase diagenesis sequence is quartz overgrowth I, chlorite, and quartz overgrowth II (20× magnification), and calcite cementing intergranular pores with a relative diagenetic sequence of chlorite, quartz overgrowth, and calcite (40× magnification, 2087.71 m, well JT322). (b) Three-phase quartz overgrowths occurring adjacent to debris with clay minerals appearing between two different phases of quartz overgrowths, and (c) calcite cementing the residual intergranular pores (20× magnification, 2210.44 m, well D209). (d) Numerous chlorite minerals covering a quartz overgrowth observed with SEM (2373.26 m, well JT805). Note: Qog = quartz overgrowth, Chl = chlorite, and Cal = calcite.
Figure 8. Diagenesis of water-bearing Chang 9 sandstone. (a) The relative multiphase diagenesis sequence is quartz overgrowth I, chlorite, and quartz overgrowth II (20× magnification), and calcite cementing intergranular pores with a relative diagenetic sequence of chlorite, quartz overgrowth, and calcite (40× magnification, 2087.71 m, well JT322). (b) Three-phase quartz overgrowths occurring adjacent to debris with clay minerals appearing between two different phases of quartz overgrowths, and (c) calcite cementing the residual intergranular pores (20× magnification, 2210.44 m, well D209). (d) Numerous chlorite minerals covering a quartz overgrowth observed with SEM (2373.26 m, well JT805). Note: Qog = quartz overgrowth, Chl = chlorite, and Cal = calcite.
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Figure 9. Homogenization temperatures of saline-bearing fluid inclusions from the three types of Chang 9 sandstones.
Figure 9. Homogenization temperatures of saline-bearing fluid inclusions from the three types of Chang 9 sandstones.
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Figure 10. Interaction of diagenesis and oil charging in different types of Chang 9 sandstones. Burial history data and paleo-geothermal gradient data cited from [39,40].
Figure 10. Interaction of diagenesis and oil charging in different types of Chang 9 sandstones. Burial history data and paleo-geothermal gradient data cited from [39,40].
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Table 1. Chang 9 sandstone compositions and fabrics.
Table 1. Chang 9 sandstone compositions and fabrics.
Sandstone TypesValueQ/%F/%Rl/%Dl/%C/%Pp/%IGV/%
Oil-bearing sandstonemaximum46.139.919.719.923.09.728.3
minimum25.021.46.13.51.01.411.8
mean31.130.211.98.38.84.518.1
Water-bearing sandstonemaximum36.042.918.515.726.07.429.8
minimum21.827.44.02.10.00.57.6
mean30.633.610.88.310.43.216.4
Non-permeable sandstoneImaximum35.045.011.124.312.01.525.2
minimum20.018.74.27.20.00.010.0
mean29.331.38.316.16.80.414.6
IImaximum31.729.617.214.235.01.535.0
minimum18.218.96.23.420.00.021.3
mean25.725.211.48.726.80.328.7
Note: Q = quartz, F = feldspar, Rl = rigid lithic debris, Dl = ductile lithic debris, C = cement, Pp = pore plane ratio, and IGV = intergranular volume.
Table 2. Fluid-inclusion characteristics and homogenization temperatures for the different types of Chang 9 sandstones.
Table 2. Fluid-inclusion characteristics and homogenization temperatures for the different types of Chang 9 sandstones.
WellDepth (m)Sandstone TypesHost Cement MineralHomogeneous Temperature (°C)Hydrocarbon Color During the Same Period
Y1901843.26Oil-bearing sandstoneQog105.2Light yellow
Qog87.6Yellow brown
Qog102.5Light yellow
Qog142.7blue
Cal98.5Yellow brown
Fe-Cal104.9Light yellow
Fe-Cal132.6blue
Z5001865.17Oil-bearing sandstoneQog102.5Yellow green
Qog101.6Light yellow
Qog93.3Yellow brown
Qog90.7Yellow brown
ZC472227.7Oil-bearing sandstoneQog123.9blue
Cal97.2Yellow brown
Fe-Cal110.1Light yellow
Fe-Cal126.3blue
SMC135blue
DT17382234.16Oil-bearing sandstoneFe-Cal125.9blue
SMC116.7Light yellow
SMC138.2blue
Z5421894.37Oil-bearing sandstoneSMC136.8blue
DZ32512672.2Oil bearing sandstoneSMC83.6Yellow brown
Qog78.8Yellow brown
Qog75.1Yellow brown
Qog81.7Yellow brown
DZ32512676.5Oil-bearing sandstoneQog101.1Yellow green
Qog103Light yellow
40892222.9Oil-bearing sandstoneQog108.4Light yellow
Qog121.5blue
Qog131blue
Cal107.3Yellow green
Cal77.1Yellow brown
SMC131.9blue
JT3222087.71Water-bearing sandstoneQog67.9None HFI
Qog103.7None HFI
Cal92.7None HFI
Fe-Cal143.4None HFI
W802281.9Water-bearing sandstoneQog74.9None HFI
Cal66.1None HFI
Cal105.4None HFI
Fe-Cal130.2None HFI
SMC139.7None HFI
JT6481967.34Water-bearing sandstoneQog127.5None HFI
Fe-Cal90.4None HFI
SMC132.5None HFI
JT3221947.28Water-bearing sandstoneFe-Cal117.6None HFI
ST242124.5Calcite-cemented sandstoneQog73.2None HFI
Cal76.7None HFI
DT65292114.87Calcite-cemented sandstoneCal74.3None HFI
Cal64.1None HFI
Cal78.3None HFI
D132691.24Calcite-cemented sandstoneCal56.3None HFI
ZC942182.28Calcite-cemented sandstoneQog84.6None HFI
Qog68.4None HFI
Cal68.5None HFI
Note: Qog = quartz overgrowth, Cal = calcite cement, Fe-Cal = ferrous calcite cement, and SMC = sealed microcrack.
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MDPI and ACS Style

Hu, C.; Zhang, L.; Lei, Y.; Yu, L.; Qin, J.; Zhang, X. Differential Diagenesis and Hydrocarbon Charge of the Tight-Sandstone Reservoir: A Case Study from Low-Permeable Sandstone Reservoirs in the Ninth Member of the Upper Triassic Yanchang Formation, Ordos Basin, China. Minerals 2025, 15, 544. https://doi.org/10.3390/min15050544

AMA Style

Hu C, Zhang L, Lei Y, Yu L, Qin J, Zhang X. Differential Diagenesis and Hydrocarbon Charge of the Tight-Sandstone Reservoir: A Case Study from Low-Permeable Sandstone Reservoirs in the Ninth Member of the Upper Triassic Yanchang Formation, Ordos Basin, China. Minerals. 2025; 15(5):544. https://doi.org/10.3390/min15050544

Chicago/Turabian Style

Hu, Caizhi, Likuan Zhang, Yuhong Lei, Lan Yu, Jing Qin, and Xiaotao Zhang. 2025. "Differential Diagenesis and Hydrocarbon Charge of the Tight-Sandstone Reservoir: A Case Study from Low-Permeable Sandstone Reservoirs in the Ninth Member of the Upper Triassic Yanchang Formation, Ordos Basin, China" Minerals 15, no. 5: 544. https://doi.org/10.3390/min15050544

APA Style

Hu, C., Zhang, L., Lei, Y., Yu, L., Qin, J., & Zhang, X. (2025). Differential Diagenesis and Hydrocarbon Charge of the Tight-Sandstone Reservoir: A Case Study from Low-Permeable Sandstone Reservoirs in the Ninth Member of the Upper Triassic Yanchang Formation, Ordos Basin, China. Minerals, 15(5), 544. https://doi.org/10.3390/min15050544

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