Study on the Influencing Factors of Oil Bearing and Mobility of Shale Reservoirs in the Fourth Member of the Shahejie Formation in the Liaohe Western Depression

Abstract

Oil content and the movability of shale oil are important indicators for the evaluation of continental shale oil. In recent years, the sandwiched shale oil in the fourth member of the Shahejie Formation in the Liaohe Western Depression area of the Bohai Bay Basin has shown great exploration potential, while the understanding of shale oil content and the movability of shale oil is weak. In this study, through a combination of core observations and experiments, we clarified the shale lithofacies types in the fourth member of the Shahejie Formation in the Liaohe Western Depression and explored the influencing factors of the characteristics in the oil-bearing and movability of shales in different lithofacies. The results of the study show that the organic matter content of the shale is high (TOC = 2.2–4.3%), but the maturity of thermal evolution is low (R_o = 0.38–0.55%), and the mineral component is dominated by clay minerals (30.3–72.7%), with quartz, feldspar, and other feldspar minerals developing secondarily. According to the content of organic matter, the mineral component, and the sedimentary structure, five types of lithofacies can be classified: organic-rich laminated clay-bearing felsic shale lithofacies (LS1), organic-rich laminated clay felsic mixed shale lithofacies (LS2), organic-rich layered clay felsic mixed shale lithofacies (LS3), organic-containing massive felsic-bearing clay shale lithofacies (LS4), and organic-containing massive clay felsic mixed shale lithofacies (LS5). The oil content of shale is mainly affected by the organic matter. The rate of increase in oil content of shale is fastest when the organic matter content is between 2 and 4%. The movability of shale oil is mainly controlled by the sedimentary structure, mineral component, and microscopic pore structure; the more the shale laminae is developed, the lower the clay content is, and the more the pore space is developed, the better the movability of shale oil is. Combined with the results of the shale oil content and mobility analysis in the study area, LS2 and LS3 are the dominant lithofacies in the fourth member of the Shahejie Formation in the study area, followed by LS1 >LS5 >LS4, so shale oil exploration should focus on the development of LS2 and LS3.

1. Introduction

China’s continental shale oil resources are abundant and widely distributed, and important breakthroughs have been made in the exploration and development of several sets of continental lake basin oil and gas-bearing formations, such as the Permian (Luchaogou Formation and Fengcheng Formation) in the Junggar Basin, the Triassic Yanchang Formation in the Ordos Basin, the Cretaceous Qingshangkou Formation in the Songliao Basin, the Paleoproterozoic Shaxiangjie Formation in the Bohai Basin, and the Jurassic Duanzhai section in the Sichuan Basin, showing that China’s continental shale oil has a good prospect for exploration [1,2,3]. Compared with marine shale, continental shale is non-homogeneous, with features such as rapid sedimentary phase change, frequent intercalation interactions, diverse mineral components, low organic matter evolution, and high viscosity and density of hydrocarbon fluids [4], which is not conducive to determining the dominant shale oil phase zone. Therefore, clarifying the characterization methods of shale oil content and movability and their influencing factors are of great theoretical and practical significance for continental shale oil exploration and development [5,6,7].

In recent years, many scholars have carried out a large number of studies around the oil content and mobility of shale, and its characterization method has been a hot spot of research. Shale oil content characterization methods mainly include Rock-Eval pyrolysis, solvent extraction, and physical simulation to measure oil saturation [8,9]. In Rock-Eval pyrolysis, due to the loss of light hydrocarbons at room temperature and during the experimental process [10], the S₁ obtained cannot reflect the content of the heavy part of the oil, and the chloroform asphalt “A” obtained by the extraction method does not reflect the content of C₁₄ hydrocarbons, and both of them have low observational values, which cannot be used as a criterion for the direct characterization of shale oil in the free and adsorbed states Based on digital core, nuclear magnetic resonance (NMR), and well logging data and other means, the oil saturation of the core is measured by establishing an oil saturation model and selecting preferred parameters, and the oil saturation measured by this method has a high accuracy; however, due to the complexity of the analytical process and the strong heterogeneity of continental shale, it does not have a good universality [11]. Regarding the movable shale oil, there are various methods to characterize the movable shale oil [12], and the traditional Rock-Eval pyrolysis S₁ and extraction methods are able to achieve the separation of the soluble organic matter of different fugitive states to a certain degree, but the loss of light hydrocarbons during the experimental process leads to the reduction of the movable oil volume [13]. The multi-temperature step pyrolysis method obtains S_1-1 light oil and S_1-2 light–medium oil based on experiments, and the sum of S_1-1 and S_1-2 characterizes the amount of movable oil in shale, but the method is mainly used for shale samples of high maturity and is not suitable for measuring samples of low maturity [14]. According to Jarvie et al., the oil saturation index (OSI=S₁/TOC) characterization of shale oil movability is effective, and many scholars have agreed with this [15,16], but there is uncertainty in the judgement criteria for different regions. The NMR method is an important method to obtain movable oil saturation due to the non-destructive and rapid experimental process and is often used in quantitative characterization of the movable oil volume. The T_2cutoff value calibration method, area difference subtraction method, and so on [17], with the characteristics of small measurement error and high precision, show better research prospects. On the basis of shale oil content and movability characterization methods, it is of great significance to clarify the influencing factors for shale reservoir evaluation in the study area.

The results of previous studies show that the influencing factors of shale oil content include organic carbon content, the development degree of pore seams, the sedimentary structure, and other aspects. Among them, organic carbon content is the key factor affecting the oil content of shale; With similar maturity levels, the higher the organic matter, the better the oil content in the same shale lithofacies [18]. Oil content increases significantly with the increase in pore volume, and the pore-seam system for shale oil transport provides a good storage space and channel, which is conducive to the flow of petroleum and storage [19]. Sedimentary structures are usually developed in semi-deep–deep lake environments where sedimentary waters are quiet, organic matter enrichment is strong, hydrocarbon potential is high, and shale is oil-bearing [20,21]. It was previously believed that shale oil movability is mainly controlled by several factors, such as the sedimentary structure, mineral components, and microscopic pore structure. Laminar development provides a large number of microfractures, resulting in low resistance when oil and gas flow along the direction of the laminar joints, and thus, the movability of shale oil becomes better [22]. Clay minerals have an important limiting effect on the movability of shale oil; due to the strong adsorption capacity of clay minerals, the increase in clay mineral content is conducive to adsorption of state shale oil endowment, which results in shale mobility becoming poorer [23]. Macropores provide a passageway for the shale oil seepage, and the porosity connectivity is better, which is conducive to shale oil seepage, while the small pore size has a certain adsorption effect on shale oil, with strong binding capacity, leading to the deterioration of the movability of shale oil [24]. Therefore, an in-depth study of shale oil content and mobility is of great significance to enrich the theory of continental shale oil exploration in China.

In recent years, many scholars have carried out a large number of studies on the sedimentary characteristics, reservoir characteristics, reservoir conditions, and hydrocarbon resource evaluation of the Shahejie Formation in the Liaohe Western Depression of the Bohai Bay Basin [25,26]. The previous studies were mainly focused on the spreading characteristics of the sandstone segments of the reservoir, but there were fewer studies on the characteristics of the shale reservoirs, and especially, there is a lack of understanding of the oil content and mobility of shale and the factors involved. Therefore, we took the fourth member of the Shahejie Formation in the Liaohe Western Depression of the Bohai Bay Basin as the research object and carried out shale lithofacies delineation according to the mineral components, sedimentary structure, and organic carbon content by combining core observation, experimental analysis test, and geological analysis, which revealed the differences in the oil-bearing and mobility of the different shale lithofacies and defined the oil-bearing and movability characteristics of the shale. We also clarify the influencing factors of shale oil content and movability, providing reference for the selection of development layers and prediction of favorable exploration zones for continental shale oil in the Liaohe Western Depression.

2. Geological Setting

The Liaohe Depression is located in the northeastern part of the Bohai Bay Basin, and the study area is located in the Liaohe Western Depression, which is a long, narrow, north-east spreading mini-shape. The characteristics are high and narrow in the north, low and wide in the south, slow in the west, and steep in the east (Figure 1a). The Paleocene system of the Liaohe Western Depression consists of the Shahejie Formation and the Dongying Formation from the bottom up, and the Shahejie Formation is segmented into the first member, the second member, the third member, and the fourth member of the Shahejie Formation [27] (Figure 1b). The lithological characteristics of the fourth member of the Shahejie Formation are dominated by dark, thick-bedded shales interbedded with thin-bedded sandstones and dolomitic shales, and the cumulative thickness of the shales ranges from 68 to 80.2 m, with a generally thick distribution in the northeast and thin in the southwest [28]. The types of sedimentary facies are mainly lake sedimentary facies and fan delta sedimentary facies.

3. Samples and Experimental Methods

3.1. Samples

The shale core samples in this study were all from the fourth member of Shahejie Formation in the Liaohe Western Depression of Bohai Bay Basin, distributed in four depth points of 2584 m, 2717.16 m, 2968.06 m, and 3101.63 m, the depth section of 3561.87–3568.17 m, with a total of 18 samples. Some routine experiments were carried out on the samples (including TOC analysis, Rock-Eval pyrolysis, Vitrinoplast reflectance measurements, X-ray diffraction, thin-section observation, FE-SEM, and so on), and the specific experimental methods were referred to the results of previous studies [30]. Nitrogen adsorption experiments, nuclear magnetic resonance experiments, and high-pressure mercury pressure experiments were carried out for the quantitative characterization of pore structure.

3.2. Low-Temperature (77.35 K) Nitrogen Adsorption (N2GA)

Experiments were carried out using ASAP2460 fully automated gas adsorption instrument to measure the experimental results, and the tests were carried out in accordance with GB/T 19587-2017, “Determination of Specific Surface Area of Solid Substances by Gas Adsorption BET Method” [31]. The samples were firstly ground to 20–50 mesh, and organic fluids were extracted from the samples using a solution of acetone and dichloromethane (1:3), and then the samples were heated in a vacuum oven at 60 °C for 12 h. During the experiments, liquid nitrogen with a purity greater than 99.99% was used as the adsorption medium, and the pressure was increased to reach saturation vapor pressure of the liquid nitrogen at the temperature of liquid nitrogen (77.35 K). Then, the pressure was gradually decreased. The adsorption–desorption curve of nitrogen was obtained by measuring the adsorption amount of the gas when the relative pressure was gradually increased and the desorption amount when the pressure was decreased. The adsorption–desorption curves of nitrogen can be used to obtain the BJH pore volume, average pore diameter, and BET specific surface area of the samples.

3.3. High-Pressure Mercury Intrusion (HPMI)

Experiments used the U.S. AutoPore IV9500 mercuric pressure instrument in Daqing city to measure the experimental results, the test implementing the standards GB/T 29172-2012 “Practices for core analysis” [32] and GB/T 29171-2012 “Rock capollary pressure measurement” [33]. Before the experimental test, the sample shape was firstly made into a cubic sample (length × width × height = 1.2 × 1.2 × 1.2 cm³), which was dried to constant weight at 105 °C and then tested in the extraction and heating state (the treatment was the same as that of conducting the N2GA) to obtain the amount of mercury fed into the sample, the amount of mercury withdrawn from the sample, and the various experimental parameters of high-pressure mercury pressure under different pressures, including porosity, average pore diameter, pore volume, mercury withdrawal efficiency, etc. The highest experimental pressure did not exceed 200 MPa.

3.4. Nuclear Magnetic Resonance (NMR)

Experiments were carried out using GeoSpec2 NMR core analyzer produced by Resonance Instruments of the UK in Daqing city, China, and the tests were conducted in accordance with China’s petroleum and natural gas industry standard SY/T 6490-2014, “Specification for Laboratory Measurement of NMR Parameters of Rock Samples” [34]. The test procedure is to extract the samples by organic solvent and vacuum heating to remove the water in the samples, then measure the T₂ signal of the dry samples and weigh them; the extracted dry samples are saturated with n-dodecane for 24 h, and the saturated samples are measured and weighed after full saturation. The samples are then centrifuged with centrifugal force of 2.916 MPa (centrifugal rotational speed of 9000 r/min), and centrifugal samples are measured and weighed after centrifugal samples are centrifuged for 1 h. The basic parameters of this experiment are 35 °C, 2 MHz, 0.2 ms echo interval, 6 s waiting time, 4096 echoes, and 32 scans.

4. Results

4.1. Organic Geochemical Characterization

According to the analysis of the 18 shale samples, the results show that the minimum value of TOC is 0.46%, and the maximum value is 7.04%; the minimum value of S₁ is 0.07 mg/g, and the maximum value is 4.34 mg/g; while the minimum value of chloroform asphalt “A” is 0.02%, and the maximum value is 1.04%. The values of S₁, chloroform asphalt “A”, and TOC have a similar trend (

Table 1. The TOC, S1, S2, “A”, and R_o of shale samples.

Sample Number	Depth (m)	TOC (%)	S1 (mg/g)	S2 (mg/g)	“A” (%)	Ro (%)
L1	3561.87	3.41	2.06	13.61	0.43	0.48
L2	3562.67	3.48	1.42	16.48	0.29	0.57
L3	3563.77	4.66	3.46	24.47	0.79	0.53
L4	3563.27	4.14	3.05	19.17	0.63	0.46
L5	3565.87	3.34	2.58	17.51	0.77	0.48
L6	3566.87	3.22	2.74	17.12	0.59	0.51
L7	3567.87	3.27	2.78	16.06	0.66	0.61
L8	2584	0.47	0.07	0.85	0.02	0.37
L9	2717.16	2.46	0.57	9.91	0.23	0.45
L10	2968.06	0.46	0.11	0.75	0.02	0.49
L11	3564.37	4.33	3.31	21.5	0.76	0.46
L12	3562.17	3.88	1.82	18.35	0.33	0.60
L13	3564.17	4.17	4.07	19.14	1.04	0.58
L14	3565.47	4.92	4.34	26.25	1.03	0.47
L15	3566.27	3.97	2.8	22.16	0.72	0.54
L16	3567.37	3.22	2.64	16	0.53	0.63
L17	3568.17	2.78	1.8	13.33	0.53	0.68
L18	3101.63	2.72	0.7	15.56	0.26	0.51

). When the TOC < 2%, the growth rate is slower, when the TOC is between 2 and 4%, the growth rate is obviously faster, and when the TOC > 4%, the growth rate gradually slows down (Figure 2). R_o is considered a better index to discriminate the maturity of OM. It is difficult to measure the value of R_o, because the shale samples have a lot of algae and lack of vitrinite in the study area. The samples are basically in a hydrogen-rich environment (algae fluorescence is strong, most of the vitrinite are also weakly fluorescent), the maturity of hydrogen-rich vitrinite is inhibited, and the measurement value of vitrinite will be suppressed to a certain extent and become lower [35,36]. The minimum value of R_o was measured as 0.37%, the maximum value was 0.68%, the maturity of the thermal evolution was relatively low, and the hydrocarbon generation threshold for shale oil was basically reached [37].

4.2. Characteristics of Mineral Components

Quantitative analysis of whole-rock minerals using whole-rock mineral X-diffraction experiments on shale samples from the fourth member of the Shahejie Formation in the Liaohe Western Depression (Figure 3). The results show that the mineral components of shale are dominated by clay minerals, with a content of 30.3–72.7%; quartz, feldspars, and other feldspathic minerals are developed secondly, with a content of 17.2–62.7%. The carbonate mineral contents are lower, mainly calcite and pyrite, with contents of 1–22.8%; some samples contain other minerals such as square zeolite, barite, and hornblende, with contents of 0.3–6.8%; meanwhile, the pyrite content is 0.4–5%. The content of major minerals (e.g., quartz, clay, and calcite) varies in different shale samples, reflecting the strong non-homogeneity of continental shale.

4.3. Characteristics of Reservoir Space

4.3.1. Type of Reservoir Space

Scholars at home and abroad have proposed different division schemes for the development characteristics of pore throats in continental shale reservoirs, in which they are divided into intragranular pore, intercrystalline pore, organic matter pore, and micro-fracture according to the characteristics of the mineral structure, the composition of organic matter, diagenesis, and so on [38]. In this paper, we analyze the cores and thin sections of the fourth member of the Shahejie Formation, and with scanning electron microscope analysis, the shale reservoir space type of the fourth member of Shahejie Formation in the study area is classified into five types: intergranular pore, intercrystalline pore, dissolution pore, organic matter pore, and micro-fracture. Intergranular pores are the main types of pores in the shale of the fourth member of the Shahejie Formation in the study area, which are mostly formed by secondary intergranular pores of quartz and other brittle minerals after compaction and crushing. There are fewer primary intergranular pores, and the pore cross-section is mainly in the form of slit, wedge, or irregular (Figure 4a,b). Intercrystalline pores are formed by the inter-support of different mineral crystals [3]. There are mainly pyrite intercrystalline pores, dolomite intercrystalline pores are less-developed, and the pore morphology is mainly in the form of strawberry-shaped pyrite microsphere aggregate and irregular polygonal shape, which is often filled by organic matter (Figure 4c,d). The formation of the dissolution pores is related to the organic acid produced in the process of hydrocarbon production of organic matter and mainly develops two types of intragranular dissolution pores in the feldspar and intragranular dissolution pores in the dolomite grains, and the pore morphology is round or elliptic (Figure 4e). The organic matter pores are formed through the generation and expulsion of hydrocarbons, but the degree of thermal evolution and the development of organic matter pores are low, the pore morphology is mainly elliptical or irregular polygonal, and the honeycomb morphology is not seen (Figure 4f). The micro-fractures are more developed in the sand section but also can be seen in structural joints, interlayer joints, and laminated joints, with the width of the joints up to micrometers, and the common organic matter fills them (Figure 4g–i).

4.3.2. Pore Structure Characterization

(1)

Nitrogen adsorption experiment and high-pressure mercury injection experiment parameters.

Sample pore size-related parameters were obtained based on the BET model and the BJH model (

Table 2. The table of N₂ adsorption experimental parameters of samples.

Sample Number	Surface Area (m2/g)	Pore Volume (cm3/g)	Average Pore Size (nm)
L1	11.71	0.019	7.01
L2	6.80	0.015	8.76
L3	10.29	0.020	7.86
L4	10.21	0.020	7.91
L5	10.45	0.022	8.52
L6	7.87	0.012	6.22
L7	12.13	0.022	7.35
L8	42.21	0.040	5.59
L9	8.83	0.015	7.52
L10	31.38	0.035	5.71

), in which the BET specific surface area was distributed in the range of 6.7976 m²/g~42.2139 m²/g, with an average value of 15.1883 m²/g; the BJH pore volume was distributed in the range of 0.0122 cm³/g~0.0404 cm³/g, with an average value of 0.0221 cm³/g; and the average pore size distribution of BJH was 5.5876 nm~12.7806 nm, with an average value of 7.2447 nm.

The high-pressure mercury injection experiment is commonly used for the quantitative characterization of a reservoir’s microporous structure, and the relevant pore structure parameters obtained from the experiment have different indicative significance. In the present study, the average pore throat radius is used to characterize the size of the pore throat, the coefficient of variation is used to characterize the degree of pore throat sorting, and the expulsion pressure is used to characterize the connectivity of the pore throat. The results of the high-pressure mercury compression experiments (

Table 3. The table of mercury intrusion pore structure parameters of samples.

Sample Number	Pore-Throat Size	Degree of Pore Throat Sorting	Pore-Throat Connectivity
	Average Pore Throat Radius (μm)	Dr	Pd (Mpa)
L1	0.010	0.158	13.78
L2	0.011	0.149	15.77
L3	0.013	0.174	10.77
L4	0.012	0.135	12.26
L5	0.011	0.172	13.76
L6	0.009	0.171	18.66
L7	0.017	0.149	10.77
L8	0.026	0.096	5.48
L9	0.014	0.148	13.77
L10	0.013	0.135	11.02

) show that the average pore diameter was distributed in the range of 0.009–0.026 μm, with an average value of 0.014 μm; the coefficient of variation was distributed in the range of 0.096–0.174, with an average value of 0.149; and the expulsion pressure was distributed in the range of 5.481–18.656 Mpa, with an average value of 12.603 Mpa.

(2)

Nuclear magnetic resonance experiment.

Ten shale samples from the fourth member of the Shahejie Formation in the study area were selected to carry out NMR experiments, and the NMR T₂ spectra were plotted by the transverse relaxation time T₂ with the signal intensity of each sample in the saturated and centrifuged state. The saturated sample T₂ spectral characteristics of shale samples from the fourth member of Shahejie Formation were analyzed, and according to the number of peaks in the T₂ spectra, the T₂ spectra were classified into the three categories of single-peak type, double-peak type, and multiple-peak type (Figure 5). The single-peak pore type T₂ spectrum distribution shows that the mesopores of small pores are more developed, and the pore throat radius is medium, which can be seen in the L7 sample. The double-peak pore type T₂ spectrum distribution shows that the macropores and mesopores are more developed, and the pore throat radius is large, which can be seen in the L1–L6 and L8 samples. The multi-peak pore type T₂ spectrum distribution shows that the small pores are more developed, the mesopores and macropores are less developed, and the pore throat radius is small. At the same time, with the increase in the T₂ relaxation time, the saturated T₂ spectrum is divided into three types of samples. With the increase in T₂ relaxation time, the signal intensity of the saturated samples suddenly increases and then decreases, indicating that cracks may exist, as seen in samples L9 and L10.

5. Discussion

5.1. Lithofacies Classification of Shale

5.1.1. Principles and Bases for Classification of Lithofacies Types

Lithofacies refers to the rocks or rock assemblages formed in a certain depositional environment, which is a synthesis of rock types and sedimentary structures and is an important indicator for evaluating shale oil enrichment. At present, scholars at home and abroad have carried out a lot of research on the delineation of continental shale facies [39], but due to the strong non-homogeneity of continental shale, the understanding of different regions is different, and it is difficult to form a set of unified delineation schemes. In order to clarify the type of lithofacies in the study area, it is found by comparing the experimental data of each core sample that lithology, sedimentary structure, and organic matter abundance are the influencing factors for the lithofacies of various types of shale in the fourth member of the study area. Therefore, in this study, referring to the lithofacies delineation standards of continental shale proposed by previous researchers [40,41] and combining them with the actual situation of the study area, the lithofacies of continental shale in the fourth member of the study area are delineated based on the consideration of three main factors: organic matter content, mineral components, and sedimentary structure. Firstly, two-level rock naming zoning was carried out by using the three-terminal meta-diagrams of felsic minerals (quartz + feldspar), carbonate minerals (calcite + siderite + dolomite + ankerite), and clay minerals content. With 50% as the boundary to determine the main name of the rock, four primary lithofacies zones were divided; then, 25% of the mineral content was used as the boundary for secondary zoning, and the four lithofacies of the primary zones were subdivided into 12 lithofacies of the secondary zones, of which if none of the minerals exceeded 50%, the name was designated as a mixed lithofacies phase. Secondly, in order to reflect the difference in the degree of enrichment of organic matter in different types of shale, 2% of the TOC content was used as a demarcation line between the organic matter-containing and organic-rich phases and was used as a lithofacies name. Finally, Finally, the sedimentary structure is divided into laminated (laminae thickness < 1 mm), layered (laminae thickness 1–10 mm), and blocky (laminae thickness is not developed), to give the lithofacies classification a clearer significance as an environmental indicator (Figure 6).

5.1.2. Basic Characteristics of the Main Lithofacies Shale

On the basis of clarifying the shale facies classification criteria, the continental shale facies types in the fourth member of the Liaohe Western Depression were classified into five types by drawing triangular diagrams, and the characteristics of each type of facies are as follows (Figure 7). Organic-rich laminated clay-bearing felsic shale lithofacies (LS1): the TOC is >2%, the content of felsic minerals is >50%, the content of clay minerals is between 25% and 50%, and the content of carbonate is <25%. According to the observation of the thin section, it is found that the laminae are more developed, and under the scanning electron microscope, it is observed that the rock is more dense, the porosity is dominated by intragranular pores and intercrystalline pores, the pyrite is more developed, it is in the shape of berry globule, it is rich in organic matter, and Organic matter is mostly filled between mineral grains. Organic-rich laminated clay felsic mixed shale lithofacies (LS2): the TOC is >2%, the content of felsic and clay mineral is 25–50%, and the content of carbonate mineral is <25%. According to the observation of the thin section, it was found that the laminae were developed, the asphalt was distributed in the form of lines to fill the cracks, and the pore space was relatively dense with intergranular pores, mainly formed by the dissolution of feldspar and carbonate rock minerals. The scanning electron microscope observed that the rock was relatively dense, the pores were mainly intergranular, the dissolution pores were mainly formed by feldspar and carbonate minerals, it was rich in organic matter, and a large number of organic matter fillings were seen between the particles. Organic-rich layered clay felsic mixed shale lithofacies (LS3): the TOC is >2%, the content of felsic and clay mineral is 25–50%, the content of carbonate mineral is <25%, and the laminae are more developed. The scanning electron microscope observed that the rock is relatively dense, the pores are dominated by intergranular pores and intercrystalline pores, there is a large quantity of berry spherical pyrite, and there is common organic matter filled with mineral grains. Organic-containing massive felsic-bearing clay shale lithofacies (LS4): the TOC is <2%, the content of felsic mineral is 25–50%, the content of clay minerals is >25%, and the content of carbonate mineral is <25%. According to the thin-section observation, it was found that the laminae were not developed and some organic matter was developed. Under the scanning electron microscope, it was observed that the rock was denser and the pores were more developed, the pores were dominated by intergranular pores and intercrystalline pores, and organic matter was common in the fillings. Organic-containing massive clay felsic mixed shale lithofacies (LS5): the TOC is <2%, the content of felsic and clay mineral is 25–50%, and the content of carbonate mineral is <25%. According to the thin-section observation, it was found that mud crystal dolomite and asphalt can be seen and the laminae are not developed. Under the scanning electron microscope, it was observed that the structure of the rock was denser, the intergranular pores were more developed and most of them were in the form of slit, and, at the same time, the rock was obviously affected by the compaction.

5.2. Oil Content of Shale

5.2.1. Hydrocarbon Occurrence

The oil content correlation is crucial for the comprehensive evaluation of oil in continental shale, and the difference in oil content between different shale phases is mainly affected by organic matter content and pore structure [43]. Therefore, this study comprehensively evaluates the oil content of shale from both qualitative and quantitative aspects.

Shale oil has various occurrence states, including free state, adsorbed state, and dissolved state, mainly in the shale pores and cracks [44]. In the fourth member of Shahejie Formation in the study area, the shale oil is mainly in the free state and adsorbed state, in which the free shale oil is mainly in the inorganic mineral pores and microfractures of the shale matrix, such as the intergranular pores of chalk particles and the intergranular pores of dolomite crystals (Figure 8a,b); the adsorbed shale oil is mainly on the surface of the clay minerals, the strawberry-like pyrite binding body, and the adsorption in the pore surfaces of the organic matter (Figure 8c,d).

The incremental pore volume (dV/dD) measured by nitrogen adsorption experiments was used to reflect the pore size range of shale oil. Comparison of the experimental data before and after oil washing shows that the pore size changes are mainly concentrated in the interval of 2~100 nm, in which the pore size changes are more obvious when the pore size is from 2 nm to 5 nm. The pore size distribution curve is in the shape of multiple peaks (Figure 9), which indicates that movable oils are mainly endowed in the mesopores with smaller pore sizes.

5.2.2. Characterization of Shale Oil Content

Oil content is an important index for evaluating shale oil resource potential. S₁ is an experimental parameter commonly used to characterize the oil content of shale. However, the cores in the fourth member of the Shahejie Formation in this study have been shelved for a long time, so the light and heavy hydrocarbons of each sample tend to dissipate to a certain extent, resulting in the experimental measurement of S₁ being low. Recently, S₁ measured based on experiments was not able to accurately characterize the oil content of the samples in their original state [45]. In order to carry out the recovery of S₁ for the pyrolysis parameter, the following expression was applied (Equation (1)):

$${{\mathrm{S}}_1}^{\prime }={\mathrm{C}}_1\times ({\mathrm{S}}_1+{\mathrm{S}}_2)+{\mathrm{S}}_1+{\mathrm{C}}_2\times {\mathrm{S}}_2$$

(1)

S₁′ is the pyrolysis parameter of recovered light hydrocarbons, mg/g; C₁ is the recovery coefficient of light hydrocarbons for the pyrolysis parameter; and C₂ is the recovery coefficient of heavy hydrocarbons for the pyrolysis parameter.

Since the organic geochemical characteristics of the fourth member of the Shahejie Formation in the Dongying Depression and the Liaohe Western Depression are similar, the organic matter types are both of type II₁ and the R_o in the study area is 0.37–0.68%. The recovery coefficients of light and heavy hydrocarbons are sought on the basis of the previous study [46], where C₁ is taken to be 0.1, and C₂ is taken to be 0.3. It can be seen by the recovery of S₁ that organic-rich layered clay felsic mixed shale lithofacies (LS3) has the best oil content, with S₁′ taking the range of 5.55–7.29 mg/g and an average value of 6.34 mg/g; organic-rich laminated clay felsic mixed shale lithofacies (LS2) has better oil content, with S₁′ taking the range of 5.36–5.50 mg/g and an average value of 4.18 mg/g; the organic-rich laminated clay-bearing felsic shale lithofacies (LS1) has medium oil content, with S₁′ values ranging from 3.64–4.25 mg/g and an average value of 3.95 mg/g; organic-containing massive felsic-bearing clay shale lithofacies (LS4) has poor oil content, with S₁′ values ranging from 0.18–1.79 mg/g and an average value of 0.99 mg/g; and organic-containing massive clay felsic mixed shale lithofacies (LS5) has the worst oil content, with S₁′ averaging 0.23 mg/g.

5.2.3. Factors Influencing the Oil Content of Shale

The oil content of shale is an important index for the evaluation of shale oil’s resource potential, so establishing the relationship between each geological parameter and oil content as well as analyzing the influence of different geological factors on the oil content of shale in the fourth member of Shahejie Formation will be conducive to the fine prediction of the geological evaluation in the subsequent study area.

Organic matter content is the main influence factor of shale oil content, organic matter is the basis of shale oil enrichment, and high organic matter content is conducive to shale oil generation in large quantities. Through the establishment of the relationship between TOC and shale oil content, it can be found that the oil content of shale with different lithofacies shows a good positive correlation with TOC; with the increase of TOC content, the S₁′ content also increases (Figure 10). Combined with the previous analysis, when TOC < 2%, the chloroform asphalt “A” S₁′ content and the growth rate is slow; fewer hydrocarbons are generated by the organic matter at this stage, which cannot satisfy the adsorption needs of shale itself; and the lithofacies types are mainly LS4 and LS5. When 2% < TOC < 4%, the S₁′ content is in the stage of rapid growth, which indicates that a large number of free hydrocarbons have been generated by the organic matter at this stage, and the lithological types are mainly LS1 and LS2. When TOC > 4%, due to thermal maturation and hydrocarbon discharge, the hydrocarbon production reaches saturation [47]; all the liquid hydrocarbons generated are free oil; the corresponding S₁′ content growth rate slows down; and the lithofacies type is LS3. Regarding differences in the oil content of different lithofacies, in terms of sedimentary structure, the blocky shale (LS4, LS5) is the worst, the laminated shale (LS1, LS2) is medium, and the layered shale (LS3) is the best.

5.3. Shale Oil Movability

5.3.1. Shale Oil Movability Characterization

Mobility is another important indicator for evaluating shale oil resource potential. The mobility characteristics of shale oil are of great significance for exploration and development. Currently, NMR experiments are commonly used to calculate the movable oil volume, and methods include the T_2cutoff value method and area difference subtraction method. These methods are used to characterize the movability of shale oil with small measurement error and high accuracy [48].

The T_2cutoff method is to calculate the total signal amplitude of the NMR T₂ spectra before and after signal strength, respectively, and find a point on the T₂ spectrum before signal strength so that the total amplitude of the T₂ spectra at the points to the left of that point is equal to the total amplitude of the T₂ spectrum after signal strength; the T₂ value corresponding to that point is the T_2cutoff (Figure 11a). When the relaxation time is greater than T_2cutoff, it is considered as movable oil and vice versa for bound oil [49] (Figure 11b). Therefore, the proportion of movable oil is expressed through the ratio of movable oil volume to saturated oil volume (Equation (2)).

$${\mathrm{U}}_1={\displaystyle \frac{{\displaystyle {\int }_{{\mathrm{T}}_{2\mathrm{cutoff}}}^{{\mathrm{T}}_{2\max }}\mathrm{S}\left({\mathrm{T}}_2\right){\mathrm{dT}}_2}}{{\displaystyle {\int }_{{\mathrm{T}}_{2\min }}^{{\mathrm{T}}_{2\max }}\mathrm{S}\left({\mathrm{T}}_2\right){\mathrm{dT}}_2}}}\times 100$$

(2)

U₁ is the movable oil ratio, %; T_2min and T_2max are the T₂ minimum and T₂ maximum values, ms, respectively; T_2cuttoff is the T_2cutoff value, ms; and S(T₂) is the expression of the T₂ spectral distribution curve.

The area subtraction method uses the difference between the pre-centrifugation T₂ spectral peak area minus the post-centrifugation T₂ spectral peak area. The ratio of this difference to the saturated sample T₂ spectral peak area is the movable oil ratio (Figure 11c) ((Equation (3)):

$${\mathrm{U}}_2={\displaystyle \frac{{\mathrm{S}}_0-{\mathrm{S}}_1}{{\mathrm{S}}_0}}\times 100$$

(3)

U₂ is the proportion of movable oil, %; S₀ is the T₂ spectral area of the saturated sample; and S₁ is the T₂ spectral area of the centrifuged sample.

In order to obtain more accurate results and avoid experimental chance, the movability of shale oil was jointly characterized by the NMR T_2cutoff and area difference subtraction methods in this study (

Table 4. Movable oil ratio in different shale lithofacies.

Lithofacies	Sample Number	Movable Oil Ratio (%)
		T2cutoff Method	Area Subtraction Method	Average
LS1	L1	11.71	0.019	7.01
	L2	6.80	0.015	8.76
LS2	L5	10.29	0.020	7.86
	L7	10.21	0.020	7.91
LS3	L3	10.45	0.022	8.52
	L4	7.87	0.012	6.22
	L6	12.13	0.022	7.35
LS4	L8	42.21	0.040	5.59
	L9	8.83	0.015	7.52
LS5	L10	31.38	0.035	5.71

). According to the T_2cutoff method, the movable oil proportion obtained was from 2.5% to 39.59%, with an average value of 19.5%, and the movable oil proportion obtained from the area difference subtraction method was from 7.91% to 38.62%, with an average value of 20.02%; the average value of the two methods was taken for the joint characterization of shale movable oil proportion. The results show that LS2 has the highest percentage of movable oil, which is 30.65%, followed by LS3 with 23.05%, LS5 with 18.06%, LS1 with 12.65%, and LS4 with 10.36%. Combined with the results of shale oil-bearing and movability experiments, organic-rich laminated clay felsic mixed shale lithofacies (LS2) and organic-rich layered clay felsic mixed shale lithofacies (LS3) have the best oil-bearing and movability and are the best types of lithofacies in the fourth member of the Shahejie Formation in the study area.

5.3.2. Factors Affecting Shale Movability

According to previous researchers, the movability of shale oil is mainly affected by sedimentary structure, mineral components, and reservoir microscopic pore structure. The influencing factors of the movability of shale oil are discussed by analyzing the relationship between movable oil ratio and sedimentary structure, mineral component content, and pore structure parameters.

(1)

Sedimentary structure

Sedimentary structure is the main factor governing the movability of shale oil. From the previous conclusions, it is clear that the movability of shale oil in textured shale is better than that of laminated and massive shale. The development of textured layers leads to the transport of fluids within the rock along the direction of microfractures between the layers, and the microfractures distributed between the layers are more likely to form a complex fracture network, which increases the transverse permeability of the reservoir and the fluid diffusion paths and contributes to the enhancement of the movability of shale oil [50]. However, not all shales’ laminated formations have better movability than layered formations. The movability of organic-rich laminated clay-bearing felsic shale lithofacies (LS1) is weaker than that of organic-rich layered clay felsic mixed shale lithofacies (LS3), and the presence of more laminar joints in the LS3 samples leads to the enhancement of shale oil seepage capacity, which results in a better movability. Organic-rich laminated clay-bearing felsic shale lithofacies (LS1) and organic-rich laminated clay felsic mixed shale lithofacies (LS2) are both laminar shales, but the proportion of movable oil in LS2 is significantly higher than that in LS1, with the high number of laminae developed and the better lateral circulation within the rock due to the more developed cracks, which results in the high movability of shale oil (Figure 12). Therefore, the development of laminae can effectively improve the pore connectivity, which is conducive to increasing the movability of shale oil.

(2)

Mineral components

We establish the relationship between clay minerals, felsic minerals, and the proportion of movable oil, and it is found that the proportion of movable oil in the shale has a weak negative correlation trend with the content of clay minerals and a weak positive correlation trend with the content of felsic minerals (Figure 13). According to the results of whole-rock mineral X-ray diffraction experiments, the clay mineral content of LS2 is significantly smaller than that of LS1, because the clay minerals in the fourth member of the Shahejie Formation are dominated by illite and smectite/illite mixed layers in the form of flakes and filaments, and illite has a strong adsorption capacity for shale oil. Some intragranular pores and dissolution pores are usually developed in the smectite/illite mixed layers, which will improve the adsorption capacity of clay minerals to a certain extent [51]. Similarity, the large specific surface area of clay minerals will lead to the enhancement of the interaction between the pore throat surface and the fluid, which increases the volume of oil adsorbed on the pore wall [52]. Therefore, with the increase in clay mineral content, it is not conducive to the flow of shale oil, resulting in a decrease in the content of movable oil. Quartz and feldspar of felsic minerals are hydrophilic [53] and have a weak adsorption capacity for shale oil, which is conducive to the flow of shale oil. At the same time, when the brittle mineral content is high, it is easy to produce natural fractures, which plays a certain role in promoting the flow of shale oil. It can also be seen from Figure 13 that LS1, LS2, and LS3 are all organic-rich shales, and their mineral composition has a weak correlation with the movability of shale oil. In conclusion, the mineral composition of the fourth member of the study area has no obvious effect on the movability of shale oil. The effect of mineral components’ content on the movability of shale oil is low in the fourth member of Shahejie Formation in the study area.

(3)

Microscopic pore structure

The occurrence of microscopic pores has been investigated in the fourth member of the Shahejie Formation. The influence of microscopic pore structures on the movability of shale oil was analyzed in combination with the experimental parameters of nitrogen adsorption and high-pressure mercury pressure. In the parameters of the nitrogen adsorption experimental results, we found that the proportion of movable oil had a negative correlation trend with the specific surface area and pore volume (Figure 14a,b), and the proportion of movable oil had no correlation with the average pore diameter (Figure 14c). Due to the small pores of the fourth member of the Shahejie Formation in the study area, mainly developing micropores and mesopores with smaller pore sizes. The small pore provides the main specific surface area and pore volume, and a large specific surface area will have a certain impediment to the storage and transport of hydrocarbons [54], which is not conducive to the seepage of the shale oil, so the proportion of movable oil decreases with increase in the specific surface area. In the high-pressure mercury pressure experiment results parameters, we found that the average pore throat radius and the coefficient of variation are positively correlated with the proportion of movable oil (Figure 15a,b), and there is no significant correlation between the displacement pressure and the proportion of movable oil (Figure 15c). The size of reservoir pore throats affects its seepage capacity, and the size of pore throats is characterized by the average pore throat radius. The larger the average pore throat radius, the better the connectivity between pore throats, the stronger the seepage capacity, and the better the movability of shale oil. The pore throat sorting characteristics are characterized by the coefficient of variation; the larger the coefficient of variation, the worse the sorting of pore throats, the more the large pore space is developed, and the better the movability of shale oil. Pore throat sorting characteristics are characterized by the coefficient of variation, and the larger the coefficient of variation, the worse the sorting of the pore throat, the more developed the macropores, and the better the movability of shale oil. In summary, the smaller the specific surface area and pore volume, the larger the average pore throat radius; and the larger the coefficient of variation, the better the movability of shale oil, and the conforming petrographic types include LS2 and LS3.

6. Conclusions

A detailed study of the oil-bearing nature of shale and the movability of shale oil in the fourth member of the Shahejie Formation in the Liaohe Western Depression has been carried out, which is summarized as follows:

(1)

The fourth member of the Shahejie Formation in the Liaohe Western Depression mainly develops a set of lake sedimentary phases and fan delta sedimentary phases, and the shale phases are mainly divided into five categories based on organic carbon content, mineral components, and lithofacies types, including organic-rich laminated clay-bearing felsic shale lithofacies (LS1), organic-rich laminated clay felsic mixed shale lithofacies (LS2), organic-rich layered clay felsic mixed shale lithofacies (LS3), organic-containing massive felsic-bearing clay shale lithofacies (LS4), and organic-containing massive clay felsic mixed shale lithofacies (LS5).

(2)

Organic-rich layered clay felsic mixed shale lithofacies (LS3) has the best oil content, and the average value of S₁′ is 6.34 mg/g. The organic-rich laminated clay felsic mixed shale lithofacies (LS2) has the strongest movability, and the percentage of movable oil is 30.65%. TOC is the main influencing factor on the oil content of shale, and with the increase in TOC content, the oil content of the shale increases. The movability of shale oil is controlled by the sedimentary structure, mineral components, and microscopic pore structure; the more developed the shale laminae, the less clay content, and the more developed the large pores, the better the movability of shale oil.

(3)

It is clear that the organic-rich laminated clay felsic mixed shale lithofacies (LS2) and organic-rich layered clay felsic mixed shale lithofacies (LS3) are the dominant lithofacies in the fourth member of Shahejie Formation of the Liaohe Western Depression. In the process of the subsequent exploration and development, the dominant shale should be selected with the characteristics of a higher number of grains, a TOC of >2%, a mixed texture of clay minerals and felsic minerals ranging from 25% to 50%, and a higher degree of development of micro-fractures.