Diagenetic Facies Controls on Differential Reservoir-Forming Patterns of Mixed Shale Oil Sequences in the Saline Lacustrine Basin

Abstract

The Permian Lucaogou Formation has developed mixed shale reservoirs, but there are few studies on the diagenetic facies, and the control effect of differential diagenesis on the reservoir capacity of shale oil reservoirs in this area is not clear. Therefore, shale samples of the Lucaogou Formation were systematically selected in this study, and through cast thin sections, field emission scanning electron microscopy, XRD mineral analysis, low-temperature nitrogen adsorption and high-pressure mercury injection experiments, the reservoir capacity of the shale oil reservoirs was evaluated from the perspective of diagenetic evolution. The results show that the shale oil reservoir of the Lucaogou Formation in Jimsar Sag is in the middle diagenetic stage A. The diagenetic evolution sequence is compaction—chlorite cementation—silica cementation—first-stage carbonate cementation—first-stage dissolution of authentic albite—illite/smectite mixed layer cementation—second-stage carbonate cementation—second-stage dissolution. The shale reservoirs are divided into five diagenetic facies: tuffaceous–feldspar dissolution facies, mixed cementation dissolution facies, chlorite thin-membrane facies, carbonate cementation facies and mixed cementation compact facies. Among them, the former two diagenetic facies have strong dissolution and weak cementation and are high-quality diagenetic facies, mainly characterized by large pore volume and good pore connectivity, with relatively low D₂ values defined as the fractal dimension of mesopores. On the basis of the above research, three different control models of Lucaogou Formation shale oil reservoirs are proposed, including dissolution to increase pores, chlorite cementation to preserve pores, and strong compaction cementation to reduce pores. The quality of reservoirs developed in this model is successively high, medium, and low. This work can provide guidance for the fine characterization and grading evaluation of mixed shale oil reservoirs in saline lake basins and has important theoretical and practical significance for the prediction of shale oil “sweet spot” distribution.

1. Introduction

In recent years, shale reservoirs have become a hot spot in the exploration and development of unconventional reservoirs [1,2]. Shale oil in China is mainly distributed in continental shale strata [3,4], including the Paleogene Shahejie Formation in Bohai Bay Basin, Chang 7 Member of the Triassic Yanchang Formation in the Ordos Basin, and the Permian Lucaogou Formation in the Junggar Basin [5,6,7]. Compared with conventional reservoirs, shale oil reservoirs mainly develop micro-nano pore-throats, and shale oil is mainly enriched in micro-nano pore-throats with pore size ranging from 10 nm to 1 μm, which are characterized by low porosity and low permeability [3,8]. The pore structure varies greatly due to its complex connectivity and late diagenesis and has strong heterogeneity [9,10].

From the perspective of a diagenetic environment, diagenesis can be divided into alkaline diagenesis and acid diagenesis [11,12,13,14,15]. Differences in diagenetic environment have derived their corresponding typical diagenetic types, among which quartz particle dissolution, carbonate cementation metasomatism, and authigenic albite and zeolite precipitation are typical for alkaline diagenesis [11,12,13], while acid diagenesis is dominated by dissolution such as feldspar and rock debris [15]. The type and intensity of reservoir diagenesis is often influenced by a variety of factors, such as the composition of original rock debris, which determines the strength of compaction to a certain extent [16,17,18]. The salinity of the formation fluid affects the strength of cementation, and the reservoirs in the saline lake sedimentary background often have strong cementation [19,20,21]. In addition, the evolution of organic matter affects the reservoir performance of shale oil reservoirs, and it has been found that the dissolved pores are usually the main reservoir space for shale oil [22,23,24]. The products of various diagenesis superimposed on sediments are diagenetic facies [25,26]. For the division of diagenetic facies, different scholars have considered different factors, with different bases of division, resulting in a variety of diagenetic facies division schemes [26,27,28,29,30,31]. Some of them take the diagenetic stage as the main basis for division and combine this with diagenetic events to divide diagenetic facies [27,28], some divide diagenetic facies according to the characteristics of pore-throat development and diagenesis [29,30], and others quantitatively characterize the intensity of diagenesis through various parameters and name diagenetic facies based on the intensity of diagenesis [26,31]. Among them, the classification of diagenetic facies based on diagenetic events is simple, convenient, and more common.

Different types of diagenetic reformation have significantly different influences on reservoir space [32,33]. Different types of rocks differ significantly due to mineral content, particle size, and sorting, which in turn lead to different rock types experiencing different diagenesis types. Because of the position relationship between the same type of rocks and the source rocks in the strata, whether there is acid fluid filling or not will lead to differential diagenetic evolution processes. The reservoirs dominated by constructive diagenesis have stronger reservoir performance, and their corresponding intervals have better physical conditions and more abundant reservoir space, such as feldspar particles or carbonate cements that can form secondary pores through dissolution, which further enhances the ability of hydrocarbon enrichment [34,35]. Compared with reservoirs formed by constructive diagenesis, the reservoirs dominated by destructive diagenesis have poor reservoir capacity, for example, the large pores within the reservoir become small pores through compaction or become smaller or even disappear through cementation of calcite and clay minerals, resulting in smaller reservoir space in the reservoir [36,37,38]. These studies have deepened the understanding of how diagenesis affects reservoir quality. However, the research on the classification and grading evaluation of saline lake shale oil reservoirs from the perspective of diagenetic evolution is relatively weak.

The Lucaogou Formation in Jimusar Sag, Junggar Basin is a set of fine-grained mixed rocks with multiple provenances and compositions, and their diagenesis types are complex [12,36]. Some scholars have comprehensively analyzed the role of dissolution in the shale oil sweet-spot reservoir in the Lucaogou Formation through typical well logging data, logging data, core data, and analysis and test data [39,40]. Other scholars have analyzed the influence of diagenesis on the shale oil reservoir in the Lucaogou Formation in Jimusar Sag through routine experiments [12,41]. However, there have been no in-depth investigation on the mechanism of pore development of the shale oil reservoir under differential diagenesis in the Lucaogou Formation. Therefore, the mixed shale oil reservoirs of the Lucaogou Formation in the Jimusar Sag are discussed systematically. A combined methodical approach mainly utilizing XRD, cast thin sections, scanning electron microscopy, low-temperature nitrogen adsorption, and high-pressure mercury injection experiments was adopted to compare the pore structures of various diagenetic facies in the mixed shale oil reservoirs, revealing the genetic mechanisms of pore development in the shale oil reservoir under differential diagenesis. These results are of great theoretical and practical significance to guide the evaluation and optimization of a mixed shale oil “sweet spot”.

2. Geological Setting

The Junggar Basin, located in the northwest of China (Figure 1a), is an essential hydrocarbon-bearing basin with huge oil and gas resources and exploration potential [42,43]. The Jimsar Sag is located in the southeast of Junggar Basin (Figure 1b) with a total area of about 1278 km². The north boundary is Jimsar Fault, the south boundary is Santai Fault, the west boundary is Laozhuangwan Fault and Xidi Fault, and the east gradually transitions to the Guxi Uplift (Figure 1c) [36,44]. The Jimsar Sag as a whole is high in the east and low in the west; it is a dustpan-shaped depression that is broken in the west and overtaken in the east, with no obvious internal faults. The Jimsar Sag has undergone multiple stage tectonic movements such as Hercynian, Indo-China, Yanshan, and Himalayan [45,46], depositing the Carboniferous, Permian, Triassic, Jurassic, Cretaceous, Paleocene, Neoproterozoic, and Quaternary systems, and the thickness of the strata gradually decrease from west to east [44,47]. Three sets of formations, including Jiangjunmiao Formation (P₂j), Lucaogou Formation (P₂l), and Wutonggou Formation (P₃wt), are developed from bottom to top in the Permian system within the depression, among which the Lucaogou Formation is the main target stratum for shale oil exploration and development [48,49]. This formation has high organic matter content and great hydrocarbon generation potential, with a thickness of 200–350 m and a favorable area of 806 km² [36]. The Lucaogou Formation can be divided into two members from bottom to top, namely, the first members of the Lucaogou Formation (P₂l₁) and the second members of the Lucaogou Formation (P₂l₂) (Figure 1d). The main reservoirs are the upper and lower “sweet spots” with an average thickness of 38 m and 44 m, respectively [50]. The sedimentary environment of the upper sweet spot (P₂l₂²) is shallow lake and shallow lake-semi-deep lake, and the lithology is mainly siltstone, sandy dolomite, and dark dolomitic mudstone. The sedimentary environment of the lower sweet spot (P₂l₂¹) is delta front, shallow lake, shallow lake-semi-deep lake, and semi-deep lake. The lithology is mainly dolomitic siltstone, dolomite, and dark mudstone, with frequent alternation in the lithology longitudinally [12,51].

3. Samples and Methods

3.1. Samples

In this study, 60 shale oil reservoir samples were collected from the Permian Lucaogou Formation in 4 typical wells (J10012, J10014, J10016 and J10025) to estimate their petrophysical properties, and a total of 20 samples were selected to process during measurements. The mineral contents were determined through measurements of powder samples.

3.2. Experimental Methods and Theories

3.2.1. Thin Section Observation

Thin section analysis is a straightforward, effective, and repeatable method for estimating rock pore systems and mineralogy [43,52]. Blue epoxy was injected into each thin section to better identify pores and microcracks clearly, and alizarin red dye was used to identify calcite, iron calcite, and iron dolomite. Then, using a polarizing microscope, we observed the characteristics of the thin section under plane-polarized light (PPL) and cross-polarized light (XPL).

3.2.2. Field Emission-Scanning Electron Microscopy (FE-SEM)

The block samples were polished with argon ion along the vertical bedding plane before the experiment, and then plated with carbon to enhance their electrical conductivity. Next, the surface of the sample was scanned using a Merlin type field emission scanning electron microscope, State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing, China). The working voltage was 10~15 kV, the working distance was 8~10 mm, and the energy spectrometer was an EDAX ternary integrated system to amplify the image of the sample surface.

3.2.3. XRD Analysis

X-ray diffraction (XRD) analysis was conducted for analyses of mineral compositions quantitatively. The samples used for the XRD experiments were powders with grain size less than 40 μm. XRD experiments were performed on a Bruker D8 instrument using 45 kV Co Ka-ray, and with the main steps of determination of the mineral components referring to the Core Analysis Method (GB/T 29172-2012). Quantification of mineralogical compositions followed the calculation criterion of the integrated area through Jade 5.0 software. The software jade 5.0 was developed by Materials Data Ltd. (MDI) in California (CA), USA.

3.2.4. Low-Temperature N₂ Adsorption

The low-temperature N₂ adsorption method was introduced into the study of shale pore structure due to the need for micro- and nano-pore size study of shale in recent years [53,54,55]. Low-temperature N₂ adsorption experiments were performed using Quanta Chromium autosorb-iq3 to analyze and measure the pore size distribution. Prior to analysis, the shale samples were crushed into 60–80 mesh-sized particles (180–250 um), dried in an oven at 60 °C for 24 h, and then degassed under high vacuum (<10 mm Hg) for 12 h. During nitrogen adsorption, the temperature of the sample chamber was set at −196 °C (77 K) to obtain the adsorption and desorption analysis data.

3.2.5. HPMI Analysis

The high-pressure mercury injection experiment (HPMI) was completed at the Key Laboratory of Tectonics and Petroleum Resources Ministry of Education, China University of Geosciences (Wuhan, China). HPMI was performed with a mercury injection porosity (AutoPore IV 9510) manufactured by Mack Instruments in Norcross, Georgia (GA), USA, with a maximum working pressure of 60,000 psi (413 MPa), which is suitable for the measurement of connected pores with pore throat diameters ranging from 2.8 nm to 50.0 μm. Firstly, the samples were dried and vacuumed, and then the prepared samples were placed in the sample chamber. Then mercury was injected into the dilatometer and the pressure level was gradually increased to atmospheric pressure. The observed relationship between the external pressure and the aperture satisfied the Washburn equation.

3.2.6. Fractal Theory

Fractal theory is commonly used to study complex bodies in nature with self-similarity in non-integer dimensional filled space. Due to the statistical self-similarity of pore throat characteristics in rocks, fractal theory has been widely used to quantitatively characterize the pore structure of rocks [56,57]. Objects with fractal characteristics can be expressed by the fractal dimension D. Generally, the fractal dimension of porous rock ranges from 2 to 3, and the closer the fractal dimension is to 2, the stronger the reservoir homogeneity is. The closer the fractal dimension is to 3, the more complex the pore structure of the reservoir is [58,59]. The fractal dimension model for calculating pore structure based on the mercury injection method is calculated as follows [60,61]:

$$S_{Hg}=1-{\left(\frac{P_c}{P_{c min}}\right)}^{D_f-3}$$

(1)

Taking the logarithm of both sides yields:

$$l_g\left(1-S_{Hg}\right)=\left(D_f-3\right)l_g{P}_c+\left(3-D_f\right)l_g{P}_{c min}$$

(2)

where P_c is the capillary pressure, MPa; P_{c min} is the minimum capillary pressure corresponding to the maximum pore size of the sample, MPa; S_Hg is the into mercury saturation at the capillary pressure of P_c, %; and D_f is the fractal dimension, dimensionless variable.

The fractal dimension (D_f) can be expressed through the pore interval fitting straight slope K deriving, namely:

$$D_f=K+3$$

(3)

4. Results

4.1. Petrological Characteristics

4.1.1. Mineral Composition

From the perspective of mineral composition, the shale samples of the Lucaogou Formation as a whole are dominated by feldspar, quartz, and carbonate minerals (Figure 2). The content of feldspar mainly ranges from 6.8% to 33.2%, with an average content of 17.2%, among which the plagioclase content is higher, ranging from 5.0% to 28.3%. Quartz content ranges from 4.6% to 42.2%, with an average content of 15.5%. Calcite content ranges from 0% to 35.1%, with an average content of 11.1%. The dolomite content of different samples varies greatly, ranging from 0% to 58.5%. The clay mineral content is low overall, with an average content of 6.6%.

4.1.2. Lithologic Characteristics

According to the core and cast thin section data, the lithology of the Lucaogou Formation can be divided into three main types: silty sandstones, mudstones, and carbonates. Among them, the siltstones include lithic feldspar silty sandstone, dolomitic sandstone, and dolomitic siltstone (Figure 3a–c). The carbonates mainly include dolarenite and micritic dolomite (Figure 3d,e), and the mudstones include mudstone and dolomitic mudstone (Figure 3f).

The results of cast thin section and XRD show that the lithic feldspar silty sandstones have coarser grain size and simple mineral composition (Figure 3a), in which the content of feldspar is relatively high, followed by the content of quartz. The carbonate minerals are mainly calcite, and the content of clay minerals is low (Figure 2). The dolomitic sandstones and dolomitic siltstones are transitional rocks with coarser grain size and a visible mixed distribution of sandy debris, dolomite, and felsic (Figure 3b,c). Their mineral composition is relatively complex, and the content of dolomite increases obviously (Figure 2). The dolomitic siltstones are usually developed within a mudstone interlayer, forming obvious light and dark streaks (Figure 3c). The dolarenites have fine grain size, the sandy debris masses are cemented by dolosparite (Figure 3d), and the mineral composition is relatively simple, mainly dolomite (Figure 2). The micritic dolomites are fine-grained (Figure 3e), with calcite and dolomite content over 70% (Figure 2). The dolomitic mudstones have developed bedding (Figure 3f) and have a high content of clay minerals (Figure 2).

4.2. Type of Diagenesis

4.2.1. Compaction

Microscopy found that the shale oil reservoirs of the Lucaogou Formation are significantly reduced in porosity, which is due to the fact that they have generally undergone chemical and mechanical compaction of moderate intensity [37,62]. The micritic dolomites are homogeneous in composition, with obvious stylolite (Figure 4a), indicating relatively strong compaction [36,37]. The dolomitic siltstones have a high content of brittle minerals such as feldspar and quartz, and the mineral particles are in linear contact (Figure 4b), indicating strong compaction resistance. Plastic mineral bending deformation is visible in the dolomitic sandstone (Figure 4c), indicating strong compaction. The particles in the dolarenites are relatively intact, indicating that micritic cladding at the edge of sandy debris reduces the influence of compaction on the reservoir to some extent (Figure 4d) [63].

4.2.2. Cementation

Microscopy found that shale oil reservoir cementation in Lucaogou Formation includes carbonate cementation, siliceous cementation, and clay mineral cementation (Figure 4e,f,i,j). The main types of carbonate cements are calcite, dolomite, and iron dolomite [64,65]. Calcite cementation is evident in the dolomitic siltstone, mainly in the form of pore-filled cemented clastic particles (Figure 4e). The dolomite in the dolarenite has an obvious mist core and bright edge structure (Figure 4f). According to the energy spectrum, the Fe content in the dolomite “mist core” is significantly lower than that in the “bright edge” (Figure 4g,h), indicating that the iron dolomite metasomatized the dolomite along the grain edges, which is consistent with previous conclusions [63].

The siliceous cementation of the shale oil reservoir in the Lucaogou Formation is dominated by quartz overgrowth. In the micrite, dolomite, and dolarenite, quartz overgrowth is less developed. In the lithic feldspar silty sandstone and sandy sandstones, quartz overgrowths are poorly developed and only grow along the narrow edges of quartz and other mineral grains (Figure 4i,j), because the Si⁴⁺ provided by the transformation of minerals is relatively limited [66].

The results of clay mineral XRD show that the clay minerals in the Lucaogou Formation are mainly composed of illite, an illite/smectite mixed layer, kaolinite, chlorite, and a chlorite/smectite mixed layer. Illite content is the first (27.80%), followed by the illite/smectite mixed layer (20.70%), and the content of kaolinite is the lowest (8.07%) (Figure 5). The main type of clay cementation is chlorite cementation, and chlorite is attached to the surface of debris particles in a thin membrane form (Figure 6a), showing a double-layer structure (Figure 6b). The illite is the product of late stages of diagenesis and is mostly flaky, growing along the pore walls [49]. The content of the illite/smectite mixed layer is high, and its irregular occurrence often occupies the pore space (Figure 6c), which may reduce the reservoir storage and percolation capacity [49,51]. Through field emission scanning electron microscopy, it was found that a small number of cements such as pyrite and authigenic albite developed in the shale oil reservoir of Lucaogou Formation. Pyrite often exists in the pores as spherical aggregates, and the clay mineral–pyrite assemblage formed by some pyrite and clay minerals fills the pore space (Figure 6d), reducing the reservoir space.

4.2.3. Dissolution

The shale oil reservoir of the Lucaogou Formation has strong dissolution, and all kinds of rocks are dissolved to different degrees, which greatly improves the reservoir’s performance. Under the action of acidic fluid, some of the soluble components, such as feldspar and tuffaceous, were dissolved to form intragranular dissolved pores or all dissolved to form cast membrane pores (Figure 6e,g,h), and short columnar authigenic albite was found in some of the dissolved pores (Figure 6f), while a few of the dissolved pores were filled with crude oil (Figure 6h), indicating that feldspar developed two stages of dissolution. In the dolarenite, intergranular pores formed by dolomite dissolution can be seen (Figure 6i). The micritic dolomite has a single composition, the strongest denseness, and weak dissolution. The dolomitic mudstone is similar to micritic dolomite, and basically no dissolution occurs.

4.3. Diagenetic Stages and Evolutionary Sequences

4.3.1. Diagenetic Stages

Based on the research results of Wang Jian et al., (2020) [12], and combined with the characteristics of authigenic minerals, particle contact relationship, and dissolution characteristics under a microscope, as well as according to the oil and gas industry standard (2003) [67], the diagenetic stages of the Lucaogou Formation reservoir were comprehensively identified and divided. The authigenic minerals are mainly carbonate minerals, including calcite, dolomite, and iron-bearing dolomite, followed by authigenic quartz and various clay minerals. Microscopically, quartz overgrowths are common (Figure 4i,j); dolomite, calcite and other carbonate minerals exist in the form of sparry (Figure 4e,j); and a large number of iron-bearing dolomite cements appear (Figure 4f). In addition, the dissolution of feldspar and rock debris is developed, with less carbonate dissolution, and some of the dissolution of feldspar is converted to albite (Figure 6f). According to the observation of the cast thin section, the contact relationship of rock particles in the Lucaogou Formation is mainly linear contact, and concave–convex contact can be seen locally (Figure 4b). XRD clay mineral analysis results show that clay minerals are mainly an illite/smectite mixed layer, illite, and chlorite (Figure 5). Combining all the above indicators, it was judged that the diagenetic stage of the Lucaogou Formation reservoir is in the middle diagenetic stage A (Figure 7).

4.3.2. Diagenetic Evolutionary Sequence

Based on the aforementioned studies on the characteristics of diagenesis, through the identification result of cast thin sections and scanning electron microscopy and combined with the research achievements of our predecessors [63,66], we determined the sequence of siliceous cement (stage I), clay mineral cement (stage II), carbonate cement (stage II), and dissolution (stage II) to lay the foundation for the establishment of diagenetic sequences. In the early diagenetic stage, mineral particles gradually change from loose state to point contact (Figure 4a), indicating that compaction occurred in the Lucaogou Formation reservoir. Combined FE-SEM and casting thin section identification show that the chlorite thin membranes are attached to the pore walls of the primary intergranular pores (Figure 6a), while quartz overgrowths are not seen in the grains wrapped by chlorite ring edges (Figure 4j) [68], indicating that chlorite cementation occurred before siliceous cementation. Calcites (the first-stage carbonate cement) are distributed around the quartz overgrowths (Figure 4e), which is attributed to the high concentration of Ca²⁺ in pore water as the source of the first-stage calcite cement [66], indicating that the formation time of the first-stage carbonate cementation was later than that of siliceous cementation. In the middle stage of diagenesis, organic matter generates hydrocarbon and releases organic acids, and feldspar and tuffaceous dissolve in the action of acidic fluid. It can be seen that albite grows inward along the edge of the dissolved pores of feldspar [65,69], so the formation of albite was later than the dissolution of feldspar (Figure 6f). At the edge of the feldspar dissolved pores, the illite/smectite mixed layer can be seen (Figure 6e), indicating that the illite/smectite mixed layer cementation occurred after the first stage dissolution. The transformation of clay minerals provided a Ca²⁺ source for calcite and dolomite cementation in stage II [69,70], indicating that carbonate cementation in stage II followed the transformation of clay minerals. As the burial depth increases, the stratigraphic temperature rises, the organic matter continues to generate hydrocarbons to discharge large amounts of organic acids, the feldspar filled with carbonate cements begins to dissolve, and the dissolved pores are filled with crude oil (Figure 6h), indicating that second-stage dissolution was the most recent diagenesis. In summary, the overall diagenetic evolution sequence of the Lucaogou Formation is as follows: compaction—chlorite cementation—silica cementation—first-stage carbonate cementation—first-stage dissolution authentic albite—illite/smectite mixed layer cementation—second-stage carbonate cementation—second-stage dissolution.

4.4. Types and Characteristics of Diagenetic Facies

In this paper, the diagenetic facies of shale oil reservoir in Lucaogou Formation in the study area are divided based on XRD, cast thin sections, and scanning electron microscopy data, the previous diagenetic facies classification methods are used for reference, and diagenetic events are used as the basis for classification (

Table 1. Types and characteristics of diagenetic facies of Lucaogou Formation shale oil reservoir in Jimsar Sag.

Diagenetic Facies Type	Tuffaceous-Feldspar Dissolution Facies	Mixed Cementation Dissolution Facies	Chlorite Thin Membrane Facies	Carbonate Cementation Facies	Mixed Cementation Compact Facies
Original lithologies	Lithic feldspar silty sandstones Dolomitic siltstones Dolomitic sandstones	Lithic feldspar silty sandstones Dolomitic siltstones Dolomitic sandstones Dolarenites	Dolomitic siltstones Dolomitic sandstones	Dolarenites Micrite dolomites	Dolomitic siltstones Dolomitic sandstones Dolomitic mudstones
Major diagenesis	Compaction Feldspar dissolution Tuffaceous dissolution	Compaction Feldspar dissolution Calcite cementation Chlorite cementation	Compaction Chlorite cementation	Compaction Calcite cementation Dolomite cementation Iron dolomite cementation	Compaction Illite/smectite mixed layer Quartz overgrowth Calcite cementation
Secondary diagenesis	Quartz overgrowth Calcite cementation Authigenic albite Illite/smectite mixed layer	Quartz overgrowth Authigenic albite Dolomite cementation Iron dolomite cementation Illite/smectite mixed layer	Quartz overgrowth Illite/smectite mixed layer Feldspar dissolution	Illite/smectite mixed layer Pyrite Carbonate dissolution	Dolomite cementation Pyrite
Particle contact relationship	Line contact	Line contact	Line contact	Concavo–convex contact	Concavo–convex contact

).

4.4.1. Tuffaceous-Feldspar Dissolution Facies

The casting thin section identification shows that feldspar and tuffaceous dissolution can be seen in lithic feldspar silty sandstones, dolomitic sandstones, and dolomitic siltstones, calcite cementation is rarely seen, and quartz overgrowths are common. After feldspar particles and tuffaceous component are dissolved by acidic fluid, a large number of secondary dissolved pores are formed, and some residual intergranular pores exist (Figure 8a,b). Most of the feldspar dissolved pores are regular and polygonal in shape, and some particles are completely dissolved to form cast membrane pores (Figure 8a), indicating that these rocks belong to the tuffaceous–feldspar dissolution facies.

4.4.2. Mixed Cementation Dissolution Facies

Through scanning electron microscope observation and casting thin section identification, calcite cementation can be seen in the dolomitic siltstones and dolomitic sandstones, and the cementation is usually porphyritic, with narrow quartz overgrowths at the grain edges. However, due to the high content of soluble components such as feldspar and tuff, the internal dissolution is strong. The residual intergranular pores are more angular, but less developed overall (Figure 8c). Some of the intergranular pores of the clay minerals are elongated and tabular, and organic matter is occasionally seen (Figure 8d), indicating that these rocks belong to the mixed cementation dissolution facies.

4.4.3. Chlorite Thin Membrane Facies

Combined FE-SEM and casting thin section identification show that chlorite cementation can be seen in the dolomitic siltstones and dolomitic sandstones, accompanied by feldspar dissolution and a small amount of siliceous cementation. The common residual intergranular pores and the development of a small number of feldspar dissolved pores (Figure 8e) indicate that these rocks belong to the chlorite thin membrane facies.

4.4.4. Carbonate Cementation Facies

According to field emission scanning electron microscope observation, calcite, dolomite, and iron dolomite carbonate cements can be seen in the dolarenites and micrite dolomites. The contact relationships between the particles are concave–convex and linear contact. The calcite and dolomite are fine grains distributed in the particle gap or filled in the dissolved pores. Only a few small pore intergranular pores of dolomite and few clay mineral intergranular pores between dolomite crystals can be seen (Figure 8f,g), indicating that these rocks belong to the carbonate cementation facies.

4.4.5. Mixed Cementation Compact Facies

Through scanning electron microscope observation and casting thin section identification, it is found that the contact relationship between particles in the dolomitic mudstones and a small part of the dolomitic siltstones and dolomitic sandstones is concave–convex contact, and the cementation of calcite and dolomite is strong. All kinds of pores are not developed (Figure 8h), and only a small number of dissolved pores in feldspar grains are visible (Figure 8i), indicating that these rocks belong to the mixed cementation compact facies.

5. Discussion

5.1. Micropore Heterogeneity of Shale Oil Reservoirs with Different Diagenetic Facies

5.1.1. Differences in Pore Structure Characteristics

Due to the different sedimentary environment and diagenesis, the pore structure parameters of different diagenetic facies are different, which leads to the differences in the isothermal adsorption cure morphology, capillary pressure curve morphology, displacement pressure characteristics, and pore size distribution characteristics of each diagenetic facies [71,72]. Therefore, a low-temperature nitrogen adsorption experiment and a high-pressure mercury injection experiment were combined to jointly characterize the microscopic pore structure of the shale oil reservoir.

As shown in Figure 9, the hysteresis loops of the mud shale samples of the Lucaogou Formation in Jimsar Sag are mainly H3 type, with H4 type characteristics, indicating that the pores are mainly composed of slit-like pores and fissure-like pores. The mercury inlet curve of a high-pressure mercury injection experiment can reflect the pore-throat connectivity and pore-throat distribution characteristics. According to the mercury inlet curves of five typical samples from the Lucaogou Formation in the study area (Figure 9), the mercury inlet curves of the samples of each diagenetic facies are different in shape. The mercury inlet curves of the tuffaceous–feldspar dissolution facies and the mixed cementation dissolution facies are platform-like, with low displacement pressure, both less than 3.0 MPa, corresponding to the maximum pore throat radius of 24.5 nm. The mercury inlet curve of the chlorite thin membrane facies is an inverted L shape, and the displacement pressure is 30 MPa. The mercury inlet curves of the carbonate cementation facies and the mixed cementation compact facies present a steep line, and the displacement pressure is large while the mercury withdrawal efficiency is high, which may be related to the high brittleness and fracture development of the samples. It can be seen from

Table 2. High-pressure mercury injection parameters of typical samples of different diagenetic facies in Lucaogou Formation, Jimsar Sag.

Diagenetic Facies	Representative Samples ID	Displacement Pressure/MPa	The Maximum Pore Throat Radius/nm	The Maximum Mercury Inlet Saturation/%	Total Pore Volume/mL
Tuffaceous–feldspar dissolution facies	J25-13	2.9	25.3	85.39	0.0265
Mixed cementation dissolution facies	J25-16	3.0	24.5	78.09	0.0288
Chlorite thin-membrane facies	J14-2	30	2.5	62.70	0.0185
Carbonate cementation facies	J25-4	25	2.9	40.94	0.0065
Mixed cementation compact facies	J12-2	68	1.1	26.26	0.0082

that the tuffaceous–feldspar dissolution facies and mixed cementation dissolution facies have the highest mercury inlet saturation, indicating that their pore connectivity is better than other diagenetic facies.

According to the difference between the range of pore size and the accuracy of pore size characterized using the two experimental methods, the low-temperature nitrogen adsorption experiment was used to characterize the shale oil reservoir micropores (<50 nm), high-pressure mercury injection was used to characterize mesopores (50~1000 nm) and macropores (>1000 nm) [73,74], and the average was obtained using the weighted average method for the duplicated part of the characterization interval [75,76]. The pore size distribution curves of the samples of each diagenetic facies are unimodal, but the main peaks are different. The peak value of the tuffaceous–feldspar dissolution facies is concentrated around 50~800 nm, indicating that the diagenetic facies mainly develops mesopores, which is related to its strong dissolution [42]. The peak value of the mixed cementation dissolution facies is between 50~300 nm, indicating that the medium strength of cementation inhibits the development of pores. The peaks of the other diagenetic facies are less than 50 nm and the pores are less developed.

Comparing the pore structure characteristics of different diagenetic phases, it can be seen that the tuffaceous–feldspar dissolution facies and mixed cementation dissolution facies have good pore connectivity and larger pore volume, and the range of main peak is much larger than other diagenetic phases because of strong feldspar solution, medium cementation, and weak compaction.

5.1.2. Microscopic Heterogeneity of Reservoir under Differential Diagenesis

The fractal dimension model of the pore structure was calculated based on the high-pressure mercury method [59,61], and the scatter plots of the wetting phase saturation 1-S_Hg and capillary pressure P_c in double logarithmic coordinates were established based on the results of high-pressure mercury injection experiment (Figure 10).

As shown in Figure 10, each diagenetic facies of the Lucaogou Formation has a good-fitting relationship in the three pore intervals of macropores (>1000 nm), mesopores (50~1000 nm), and micropores (<50 nm), and the R² is generally high, indicating that the pores of different scales in each diagenetic facies of the Lucaogou Formation have fractal characteristics. However, the slope of the fitted linear relationship of each section of the curve differs due to the difference in the influence of differential diagenesis on the heterogeneity of the reservoir.

The results of the fractal dimension in different aperture ranges are shown in

Table 3. Fractal dimension of high-pressure mercury injection of representative samples in different diagenetic facies of Lucaogou Formation, Jimsar Sag.

Diagenetic Facies	Representative Samples ID	Micropores		Mesopores		Macropores
		D1	R2	D2	R2	D3	R2
Tuffaceous–feldspar dissolution facies	J25-13	2.8867	0.7894	1.9809	0.943	2.9881	0.9774
Mixed cementation dissolution facies	J25-16	2.9575	0.6359	2.5840	0.9643	2.9983	0.7707
Chlorite thin-membrane facies	J14-2	2.7770	0.9706	2.9946	0.9224	2.9963	0.9027
Carbonate cementation facies	J25-4	2.8605	0.9716	2.9873	0.9357	2.9842	0.9265
Mixed cementation compact facies	J12-2	2.8725	0.8919	2.9962	0.8456	2.9874	0.9507
Average value	-	2.8708	-	2.7086	-	2.9909	-

. The fractal dimension of micropores (D₁) ranges from 2.777 to 2.9575, with an average value of 2.8708. The fractal dimension of mesopores (D₂) ranges from 1.9809 to 2.9962, with an average value of 2.7086. The fractal dimension of macropores (D₃) ranges from 2.9842 to 2.9983, with an average value of 2.9909. As a whole, the fractal dimensions of macropores, micropores, and mesopores in the Lucaogou Formation reservoirs decrease in turn, indicating that the macropores have the strongest heterogeneity while the mesoporous heterogeneity is the weakest, which further indicates that the development of macropores will enhance the heterogeneity of shale oil reservoirs in the Lucaogou Formation.

The differences in the fractal dimension on the pore scale of the different diagenetic facies of the reservoir in the Lucaogou Formation in the study area indicate significant differences in the complexity of the micropores, mesopores, and macropores developed within the shale oil reservoir, indicating that the more complex the pore structure of a shale oil reservoir, the worse its reservoir capacity [42,77,78]. The fractal dimension of the mesopores differs greatly among different diagenetic facies, while the fractal dimension of the macropores differs little. Therefore, the mesopore fractal dimension will be used to discuss the complexity of pore structure of each diagenetic facies. Except for chlorite thin-membrane facies, the fractal dimension of mesopores in the tuffaceous–feldspar dissolution facies, mixed cementation dissolution facies, carbonate cementation facies, and mixed cementation compact facies increases successively, indicating that the heterogeneity of the diagenetic facies increases successively and the reservoir capacity decreases successively. However, the micropore fractal dimension of the chlorite thin-membrane facies is the smallest (2.777), and the heterogeneity of the micropores is weak. The reservoir space is dominated by residual intergranular pores with small pore size (Figure 8e), indicating that the micropores of the diagenetic facies are the main place for shale oil enrichment. These interpretations for the fractal dimension of pore structure reflecting the reservoir capacity of shale oil can also be supported by the study of the Middle Permian Lucaogou Formation. To be more specific, fractal dimension can comprehensively reflect reservoir properties and mineral composition, thus controlling shale oil accumulation [42,43].

5.2. Different Diagenetic Facies Control Reservoir Mechanism

The difference in diagenetic type and intensity leads to significant differences in pore types, pore size distribution, and pore structure heterogeneity of different diagenetic facies in the original sedimentary reservoir [30,79,80].

Regarding the tuffaceous–feldspar dissolution facies, in the middle diagenetic stage B, the transformation between smectite and illite provides large amounts of Si⁴⁺ for siliceous cementation due to the increase in burial depth and formation temperature, but the lower temperature at this stage leads to limited mineral reactions, which inhibits siliceous cementation, and weaker siliceous cementation facilitates the preservation of reservoir pores (Figure 4i,j) [66]. At this time, the lithic feldspar silty sandstones and dolomitic sandstones are conducive to the development of the diagenetic facies. At the late stage of middle diagenesis, organic matter generates hydrocarbon and discharges a large number of organic acids [81,82], and the feldspar and tuffaceous begin to dissolve under the action of acidic fluid [42,83,84], forming dissolved pores within the feldspar grains (Figure 8a,b). These dissolved pores are connected with primary intergranular pores to form a pore network with good pore connectivity (Figure 9a). The distribution range of the pore diameter of the main peak is large (50~800 nm) and the pore structure heterogeneity is weak (D₂ is 1.9809), which greatly enhances the reservoir capacity and comprises the high-quality diagenetic facies of the target layer.

The mixed cementation dissolution facies are affected by compaction in the early stage of diagenesis, and the primary pore space is reduced [42,85]. In the early diagenetic stage B, siliceous cements appear, further reducing the primary pore space. Formation water with a high concentration of Ca²⁺ provides an ion source for early calcite cementation, and with increasing burial depth, Mg²⁺ concentration in the pore water increases [86], which forms dolomite, and Fe²⁺ readily enters the lattice of minerals, which in turn forms iron dolomite cementation (Figure 4f) [87,88], at which time the dolarenites favor the development of this diagenetic facies. In the late diagenetic stage, the dissolution degree of the calcite and other cements is very low after contact with acidic fluid, but the feldspar dissolution is stronger. On the whole, the dissolution degree of carbonate is lower than that of feldspar and rock debris. This is because the chemical reaction equilibrium constant of dissolution of the carbonate minerals is much lower than that of the feldspar minerals, and the pH value required for the dissolution of carbonate minerals in a water–rock system is lower than that of feldspar minerals [69,89]. From the whole process, dissolution of this diagenetic facies is stronger than cementation, and dissolved pores and residual intergranular pores are developed (Figure 8c), with good pore connectivity (Figure 9b); the pore size distribution of the main peak is large (50~300 nm) and the pore structure heterogeneity is weak (D₂ is 2.584), which enhances the reservoir capacity and comprises a better diagenetic facies for the target layer.

The chlorite thin-membrane facies are affected by compaction in the early diagenetic stage, and the primary pore space gradually decreases. In the late stage of early diagenesis, the chlorite begins to cement, usually adhering to the particle surface in the form of a thin membrane, resisting to some extent the destruction of the reservoir by compaction, allowing the reservoir to retain a small portion of primary intergranular pores [25]. On the other hand, the chlorite itself occupies part of the pore space and plays a certain role in reducing the primary intergranular pores. At the same time, the chlorite membrane physically blocks the contact between acidic fluid and feldspar, thus obstructing the development of feldspar dissolution pores [66,90]. On the whole, this diagenetic facies has relatively little pore development (Figure 8e) and general pore connectivity (Figure 9c), but its microporous structure heterogeneity is the weakest (D₁ is 2.777) and its reservoir capacity is moderate, making it a more favorable diagenetic facies for the target layer.

The carbonate cementation facies are subject to compaction in the early diagenetic stage, and the reservoir space decreases rapidly. In the early diagenetic stage B, due to a strong cementation degree of dolomite, calcite and other carbonates, the grains are basically filled with cementation, which makes the pore throat radius narrow and the storage space decrease [82,91]. Very few dolomites undergo dissolution under the action of more acidic diagenetic fluids [83,92], forming intergranular dissolved pores (Figure 8f,g), but with little gain to the reservoir space. Overall, this diagenetic facies have less developed pores, poor pore connectivity (Figure 9d), strong pore structure heterogeneity (D₂ is 2.9873), relatively poor reservoir capacity, and is generally not used as a favorable diagenetic facies for the target layer.

The mixed cementation compact facies forms calcite cementation from a high concentration of Ca²⁺ precipitates in pore water in the early diagenetic stage [87], then dolomite cementation begins to appear, and the reservoir space continues to decrease (Figure 8h). In the middle diagenetic stage, the overlying pressure continues to compact the formation, and the reservoir space of rocks is further reduced. Subsequently, the illite/smectite mixed layer appears and the pore space is further reduced (Figure 6c). On the whole, the pore space of this diagenetic facies is not developed, and the pore connectivity is extremely poor (Figure 9e). The pore structure heterogeneity is strong (D₂ is 2.9962) and the reservoir capacity is poor, usually existing in the form of compartments and interlayers.

5.3. Different Diagenetic Facies Control Different Reservoir Models

With differential diagenesis as the main factor controlling reservoir quality, the development model of the shale oil reservoir in the Lucaogou Formation under differential diagenesis is summarized as follows (Figure 11) by comparing the characteristics of the diagenetic facies and reservoir space.

(1)

Pore-increasing model: This model is more common in the rock strata where tuffaceous–feldspar dissolution facies and mixed cementation dissolution facies are developed (Figure 11a). In the tuffaceous–feldspar dissolution facies and mixed cementation dissolution facies, the dissolution is strong and the cementation is moderate, and the dissolved pores and residual intergranular pores are visible. In this model, the reservoir is of the best quality, usually with large pore volume, mesopore development, and relatively low heterogeneity.

(2)

Pore-preserving model: This model is more common in the rock strata where chlorite thin-membrane facies are developed (Figure 11b). The chlorite cementation in the chlorite membrane is moderate, the dissolution is weak, and residual intergranular pores are visible. The reservoirs formed in this model are of medium quality, usually with micropore development and the weakest heterogeneity.

(3)

Pore-reducing model: This model is more common in the rock strata where carbonate cementation facies and mixed cementation compact facies are developed (Figure 11c). The carbonate cementation facies and mixed cementation compact facies have strong compaction, moderate cementation, almost no dissolution, and undeveloped nano-pores under the microscope. The reservoirs formed in this model are of poor quality, usually with small pore volume, poor pore throat connectivity, and strong heterogeneity.

6. Conclusions

(1)

The diagenetic stage of the Lucaogou Formation shale oil reservoir in Jimusar Sag is in the middle diagenetic stage A, and the diagenetic evolution sequence of the reservoir is compaction—chlorite cementation—silica cementation—first-stage carbonate cementation—first-stage dissolution of authentic albite—illite/smectite mixed layer cementation—second-stage carbonate cementation—second-stage dissolution. The diagenetic facies of the shale oil reservoir in the Lucaogou Formation in the study area can be divided into five categories.

(2)

The characteristics of pore type, pore size distribution, and pore structure heterogeneity of the different diagenetic facies are obviously different. The tuffaceous–feldspar dissolution facies is dominated by the dissolved pores, with the widest pore size distribution range, and the main peaks are concentrated in 50~800 nm. The mesopores are the main reservoir space, and the maximum mercury saturation reaches 85.39%, reflecting good pore connectivity, as well as the lowest D₂ value of 1.9809, making it the optimal diagenetic facies for the target layer. The mixed cementation dissolution facies developed dissolved pores and residual intergranular pores, and the main peaks are concentrated in 50~300 nm. Compared with the tuffaceous–feldspar dissolution facies, the maximum mercury saturation reaches 78.09% and the D₂ value is slightly higher at 2.5840, which make it a better diagenetic facies for the target layer. The chlorite thin membrane facies is mainly composed of residual intergranular pores with small pore size, with relatively developed micropores and the lowest D₁ value of 2.7770, which make it a favorable diagenetic facies for the target layer. The carbonate cementation facies and mixed cementation compact facies have poor pore development, and their main peak pore size is concentrated in 30~50 nm, with lower mercury saturation and higher D₂ value, which make them usually not studied as favorable diagenetic facies.

(3)

According to the diagenetic facies differential control mechanism, the reservoir can be divided into three types. The high-quality reservoir consists of rocks developed by the tuffaceous–feldspar dissolution facies and mixed cementation dissolution facies, mainly developing dissolved pores and residual intergranular pores, with large pore volume, good pore connectivity, weak pore structure heterogeneity, and good reservoir capacity. The medium reservoir consists of rocks developed by the chlorite thin-membrane facies, mainly developing chlorite residual intergranular pores, with large pore volume, good pore connectivity, weak pore structure heterogeneity, and medium reservoir capacity. The poor reservoir consists of rocks developed by the carbonate cementation facies and mixed cementation compact facies, with undeveloped pores, poor pore connectivity, strong pore structure heterogeneity, and poor reservoir capacity.

(4)

The reservoir control model under differential compaction, differential cementation and differential dissolution of shale oil reservoirs is summarized, that is, dissolution increases pores, chlorite cementation preserves pores, and compaction cementation reduces pores. This model can provide reference value for the evaluation of saline lake mixed shale oil reservoir classification.