Pore Structure Characteristics and Controlling Factors of an Interbedded Shale Oil Reservoir—A Case Study of Chang 7 in the HSN Area of the Ordos Basin

Abstract

The geological structure of interbedded shale oil reservoirs is complex, later characterized by high reservoir heterogeneity and diverse reservoir spaces. These distinctive features are primarily attributed to their unique source–storage configuration. This paper comprehensively investigates the pore structure characteristics and controlling factors, which are beneficial for realizing efficient and sustainable resource utilization. The pore structure characteristics and main control factors of interbedded shale oil in the Heshuinan (HSN) area of the Ordos Basin are studied by analyzing thin sections and scanning them under an electron microscope, and using XRD analysis, a high-pressure mercury injection, a constant-rate mercury injection, and a nitrogen adsorption method. The influence of sedimentation and diagenesis on the pore structure is analyzed. Research shows that the interbedded shale oil reservoirs of the Triassic Chang 7 in the HSN area have an average porosity of 8.47% and an average permeability of 0.74 × 10⁻³ μm². The reservoirs are classified as typical ultra-low porosity, ultra-low permeability reservoirs. The various pore types in the study area are mainly residual intergranular pores and feldspar dissolution pores. The pores are mostly in the shape of parallel slits and ink-bottle-shaped. The pore-throat radii range from 0.02 μm to 200 μm. Sedimentation and diagenesis jointly control the pore structure in the study area. Sedimentation determines the material foundation of the study area. Diagenesis affects later pore development. Early compaction greatly reduces the intergranular pores, but the chlorite envelope reduces the influence of compaction to some extent. The compacted residual intergranular pores are further reduced by clay minerals, carbonate minerals, and siliceous minerals. Late dissolution promotes pore enlargement, which is the key to the formation of high-quality reservoirs. Furthermore, on this basis, this paper outlines the genetic mechanism of the Chang 7 high-quality reservoir in the HSN area to provide guidance for the exploration and development of interbedded shale oil and gas.

1. Introduction

With the development of the global economy and population growth, the demand for oil resources is increasing. Chang 7 in the HSN area of the Ordos Basin is a high-quality interbedded shale oil reservoir with proven reserves of 20 × 10⁸ t [1,2,3,4,5], which enables strategic support for meeting the needs of the energy provision. Furthermore, the strategic development of mezzanine shale oil presents dual advantages in energy sustainability: its primary significance lies in its capacity to address growing energy demands while simultaneously mitigating the depletion pressures of conventional petroleum resources [6,7,8]. Broadly speaking, interbedded shale oil reservoirs of the Chang 7 reservoir in the HSN area have developed a typical source reservoir interbedded configuration. The interlayering between shale layers in the study area is sandstone, which has a significant impact on the formation, preservation, and later exploitation of shale oil [9,10]. Chang 7 interbedded shale oil reservoir in the HSN area underwent complex diagenesis. Compared to conventional reservoirs, it has lower porosity and permeability [11]. The pores are in the shape of parallel slits and ink bottles. The mechanical properties of rocks are influenced by pore structure, such as Young’s modulus, Poisson’s ratio, etc., and the brittle shale with developed pore structure is more clearly fractured using CO₂ fracturing fluid [12,13]. Furthermore, the pore structure control of the physical properties of the reservoir directly restricts the development of the next step [14,15]. Therefore, it is of urgency to characterize the pore structure and identify the controlling factors to guide exploration and development.

Pore structure refers to the spatial distribution, size, shape, and interconnectivity of pores in rocks. The size of the pores determines the porosity, and the distribution, shape, and connectivity determine the permeability. In addition, the porosity and permeability determine the physical properties of the reservoir [16,17]. There are two ways to study pore structures. Firstly, the direct observation method uses a high-resolution scanning electron microscope, X-ray energy spectrum, and CT scanning core to analyze the particle contact relationship, pore size, distribution, and pore shape [18]. Secondly, the indirect measurement method is conducted using low-temperature gas isothermal adsorption, constant-rate mercury injection, high-pressure mercury injection, and numerical simulation, combined with the BET isothermal equation, the Washburn equation, and hysteresis morphology analysis of pore size, shape, and distribution. Previous studies on the Chang 7 reservoir in the Ordos Basin mainly focused on sedimentological and paleoclimatic characteristics, diagenesis, and reservoir space of the reservoir, as well as the oil and gas migration mechanism, and high-quality area distribution [19,20]. The research on the pore structure and master control factors of the Chang 7 reservoir focuses on the pore basin and the Longdong area. However, research on pore structure and main controlling factors of reservoirs with a small study area, with strong heterogeneity, complex source and storage relationship, and strong diagenesis in the study area, is relatively lacking. The pore structure of the Chang 7 interbedded shale oil reservoir in the Ordos Basin is studied through a casting sheet approach, scanning electron microscopy, and mercury pressure experiments. It shows that the Chang 7 reservoir in the Longdong area of the Ordos Basin is mainly controlled by compaction and dissolution, and their effects are roughly the same. In the late stage of diagenesis, this involves filling pores with ferrocalcite and ankerite. The pore structure features of Chang 7 reservoir are influenced by diagenesis. They are also influenced by the sequence of the diagenetic evolution [21]. Strong compaction, weak cementation, and strong dissolution are the key factors for the formation of high-quality reservoirs. The sedimentary sandstone and physical properties of the reservoir in the HSN area are similar to those in the Longdong area and other areas [14], but the oil–water relationship is complex. The pore structure has an obvious control over the distribution of oil and water. At present, the pore structure and main control factors of the Chang 7 interbedded shale oil reservoir are unclear, which restricts the efficient further development of shale oil and gas in the HSN area.

On the basis of detailed core description, this study determines the characteristics and distribution of Chang 7. The pore structure characteristics and main controlling factors of the Chang 7 interbedded shale oil reservoir in the HSN area are clarified by the casting sheet, SEM, XRD analysis, CT scan, high-pressure mercury, constant-speed pressure mercury, nitrogen adsorption, etc.

2. Geological Background

The Ordos Basin is the second largest continental sedimentary lake basin in China, located in central and western China, spanning five provinces: Gansu, Shaanxi, Inner Mongolia, Shanxi, and Ningxia, with a total area of 37 × 10⁴ km² [22,23]. It developed a river-dominated delta–lacustrine sedimentary system. The Triassic Yanchang Formation of deposition is the focus of shale oil and gas exploration and development, among which the Chang 7 section is one of the key target layers. The Yanchang Formation was deposited in 10 strata from bottom to top, comprising 10 well-developed sections; the Chang 7 deposits reached a peak and the sedimentation of the Yanchang Formation concluded at the end of the Triassic [24,25].

The study area is located in Heshui County, Qingyang City, Gansu Province, in the southwest region of the Yishan slope (Figure 1a). The target layer is Chang 7 segments, whose main sedimentary stage is the formation and transformation of sandy debris flow and turbidity current sand bodies. Formed in a semi-deep to deep lake sedimentary environment, a deep-water gravity flow sedimentary system triggered gravity collapse, providing terrestrial debris. According to the sedimentary characteristics and the sequence stratigraphy method, Chang 7 is divided into three sublayers, respectively, Chang 7₁, Chang 7₂, and Chang 7₃. The Chang 7 section of the HSN area was deposited in a semi-deep to deep lake sedimentary environment. The sandy debris flow, turbidity current, and deep lake mudstone deposition are present. Two sub-layers, Chang 7₁ and Chang 7₂, mainly consist of gray and gray–black sand debris flow and turbidity current, which are the high-quality reservoirs in the study area. Chang 7₃ small layers developed a set of high-quality hydrocarbon source rocks, mainly black deep lake mudstone with thin siltstone interbeds. Two sets of high-quality reservoirs of Chang 7₁ and Chang 7₂ are directly superimposed on the source rock of Chang 7₃, forming a good source–storage relationship [26] (Figure 1b).

The grain of the rock is a fine-grained Chang 7 interbedded shale oil reservoir in the HSN area. The most developed aspects are fine sandstone, siltstone, pelitic siltstone, and silty mudstone. The major rock types are feldspathic litharenite and lithic arkose. The main mineral components are quartz and feldspar. The filling material is mainly composed of clay minerals. The cement is composed of iron-bearing calcite cement and iron-bearing dolomite cement. Overall, the quartz content is relatively low, which presents low component maturity; the illite and chlorite have relatively high contents [21,22].

3. Experiments and Methods

3.1. Samples

The study samples were obtained from the Triassic Series. A total of 10 samples were collected for petrographic observation, XRD analysis, CT scan, high-pressure mercury injection (HPMI), rate-constant speed pressure mercury injection (RCMI), and low-temperature nitrogen adsorption (LTNA).

3.2. Petrographic Observation

In total, 40 thin sections were observed petrographically; 10 of them were from collected core samples, and the remaining 30 were from the China National Petroleum Corporation (CNPC) Exploration and Development Research Institute of Changqing Oilfield. Polarized microscope (PM) and scanning electron microscope (SEM) observations, combined with X-ray diffraction (XRD) and computer tomography (CT) scans, were used to analyze the reservoir mineral type, particle size, contact relationship, pore type and morphology, and pore and throat connectivity characteristics. The microscopic photos and XRD and CT analysis data were obtained from the Experimental Center of Daqing Exploration and Development Research Institute in Heilongjiang Province.

3.3. Experimental Measurement

LTNA experiments were carried out on 10 collected samples. According to the nitrogen adsorption volume and relative pressure in the process of nitrogen adsorption and desorption, the pore morphology was analyzed through hysteresis characterization. HPMI technology was used to identify the pore structure and pore size distribution of 10 samples, following the testing standards GB/T29172-2012 [27] Core Analysis Method and GB/T29171-2012 Determination of Rock Capillary Pressure Curve. The test used corelab CMS300 (Core Laboratories, Holland, Amsterdam) and an AutoPore IV 9500 (Micromeritics, Norcross, GA, USA) mercury press with a maximum experimental pressure of about 200 MPa. Mercury does not wet the rock surface. When the injection pressure is higher than the capillary pressure corresponding to the pore throat, mercury enters the pores. At this stage, the injection pressure is equivalent to the capillary pressure, and the corresponding capillary radius is the pore-throat radius (

Table 1. Parameters of the pore-throat structure of the studied samples derived from HPMI test.

Test Method	Sample	Enter Pressure (MPa)	Average Radius (µm)	Maximum Mercury Saturation (%)	Maximum Mercury Removal Efficiency (%)
HPMI	N140 1622 m	0.465	0.428	82.585	22.103
	N143 1626 m	0.675	0.278	84.989	17.123
	N143 1648 m	0.675	0.209	83.891	15.334
	L27 1637 m	0.674	0.245	82.892	15.461
	N23 1605 m	5.501	0.040	74.294	30.556
	N23 1613.2 m	1.364	0.162	78.259	9.275
	N27 1568.5 m	1.361	0.125	83.752	30.890
	N27 1572.6 m	0.675	0.189	87.058	22.570
	N142 1712 m	2.047	0.114	84.767	22.901
	N142 1792 m	0.671	0.244	83.553	12.539

).

We calculate the pore radius according to the Washburn formula (Equation (1)):

$$\mathit{Pc}={\displaystyle \frac{2\sigma cos\theta }{r}}$$

(1)

In this equation, Pc—capillary pressure, MPa; σ—interface tension to air, σ = 480 dyn/cm; θ—wetting angle of mercury to rock, θ = 140, cos θ = 0.765; r—pore radius, μm.

The pore and throat size distribution of four samples were analyzed by RCMI. Tests were conducted following GB/T29172-2012 and using the ASPE-730 (Cordx Union, Atlanta, GA, USA) constant speed pressure mercury instrument with constant mercury intake speed (0.00005 mL/min). At a very low constant velocity, the process of the capillary pressure process within the system can be observed. Operating at a low constant speed, the mercury intake process can be approximated as a quasi-static process. In that case, according to the natural pressure fluctuations that occur when passing through different microscopic pore shapes the microstructure of the pores can be determined. The technical feature is the ability to distinguish the throat from the pore. It can measure the pore radius distribution and the throat radius distribution separately (

Table 2. Parameters of the pore-throat structure of the studied samples derived from RCMI test.

Test Method	Sample	Enter Pressure (MPa)	Average Pore Radius (µm)	Average Pore-Throat Radius (µm)	Maximum Mercury Saturation (%)
RCMI	N140 1622 m	0.433	158.992	1.331	71.956
	N143 1626 m	0.406	151.311	0.998	67.922
	N143 1648 m	0.585	155.251	1.245	63.620
	L27 1637 m	0.610	159.674	0.722	65.138

).

4. Results

4.1. Pore Type and Pore Shape

Various types of pores develop in the Chang 7 reservoir of the HSN area, and under microscopy, we can see a large number of residual intergranular pores, dissolution pores, and intercrystalline pores, and a small number of microcracks. The residual intergranular pores are formed mainly through compaction and cementation, and the dissolution pores are mainly formed from feldspar and debris dissolution. The study area experienced strong cementation, and the compaction-reduced intergranular pores are relatively less retained. Microscopy reveals a clear boundary without cement between particles (Figure 2a). Most of them are cemented residual intergranular pores, and the residual pores of authigenic quartz mineral cemented pores can be seen under the microscope (Figure 2b). The dissolution direction of the feldspar dissolution pore is mostly along the cleavage. The rock debris dissolution pores are formed by the dissolution of debris with high concentration of soluble components, with irregular pore distribution. When the particles are completely dissolved, the mold pores are formed (Figure 2c–e). Intercrystalline pores mainly refer to the intercrystalline pores of clay minerals. Accordion-shaped interstitial pores of kaolinite, and bridging-shaped and honeycomb-shaped interstitial pores of illite can be seen from SEM and PM (Figure 2f–h), with certain levels of connectivity. A small number of developed microfractures are mainly due to uneven tectonic activity (Figure 2i).

The temperature is 77.3 K (liquid nitrogen temperature) and the relative pressure is 0.010~0.095 MPa in the LTNA experiment. Nitrogen was used as the adsorption medium to determine the nitrogen adsorption amount of the sample. From this, the nitrogen can be obtained using the nitrogen adsorption–desorption isotherm of the sample. In the process of nitrogen adsorption and desorption the hysteresis occurs, and, according to the morphology of the hysteresis, we can effectively judge the pore shape [28]. According to the IUPAC classification of hysteresis [29], most of the hysteresis types in the study area belong to the H3–H4 compound, a small amount of the H2–H3 transition type. The hysteresis is narrow and the N2 adsorption amount is small, indicating that the pore shape is mainly parallel slits and ink-bottle-type pores, which is consistent with that observed under SEM (Figure 3).

4.2. Pore Structure and Pore Radius

The distribution characteristics of the pore throat in the interbedded shale oil reservoir in the HSN area were studied using HPMI. According to the morphology of the mercury pressure curve, the development characteristics of the pore throat can be judged. Moving along the direction of the arrow shows a gradual decrease in the discharge pressure and increasing maximum mercury saturation, indicating that the structure of the rock pore is improving (Figure 4a). The experimental results show that the maximum mercury saturation of the interbedded shale oil reservoir in the HSN area is 34.12–93.26%, with an average of 80.9%; the displacement pressure is 0.57–26.37 MPa, with an average of 3.09 MPa; and the mercury withdrawal efficiency is mostly lower than 40% (Figure 4b,c). High-pressure mercury experiments show that the pore structure fundamentally controls the physical properties of the interbedded shale oil reservoir. The greater the displacement pressure, the smaller the reservoir permeability. The greater the maximum mercury saturation, the greater the reservoir porosity and permeability (Figure 4d,e).

CT can more intuitively show the microscopic heterogeneous characteristics of interbedded shale oil reservoirs. The CT results of the samples show that the Chang 7 interbedded shale oil reservoir had strong heterogeneity, with uneven distribution of pores at all scales, and with pores developed from dozens of microns to nanometer scale. The more single the color (red, yellow), the larger the pores and the better the physical property (Figure 5). According to CT, the number of holes and pores, average pores, and throat radius of the N143 well are larger than those of the LY18 well. Rock samples from N143 have a porosity of 9.9% and a permeability of 0.1 mD, while samples from LY18 show 7.1% porosity and 0.04 mD permeability, according to HPMI data (

Table 3. Parameters of the pore-throat structure of the studied samples derived from CT.

Sample	Pore Number	Throat Number	Average Pore Radius (um)	Average Throat Radius (um)	Pore Main Peak Distribution (um)	Average Pore Volume (um3)
N143 1648.8 m	10,349	958	2.11	1.68	0~2	181.15
LY18 1682.5 m	6030	464	1.78	1.67	0~2	145

). The pore structure and physical properties of the N143 well are significantly better than those of the LY18 well, indicating that the physical property of the reservoir is directly controlled by pore-throat size and connectivity.

HPMI can measure a wide range of pore radius distribution, but it is not accurate enough for non-circular pore measurements, and cannot distinguish between pore and throat. RCMI can accurately measure non-circular pores, and can effectively distinguish the pores and throat, but the measured pore radius range is limited [30,31]. Therefore, we combine HPMI and RCMI experiments to obtain the full pore size distribution characteristics of the interbedded shale oil reservoir. The throat radius of the reservoir pore is mainly 0.02–200 μm, the pore radius is mainly 30–200 μm, and the throat radius is mainly 0.3–2 μm. Along the direction of the arrow, the throat radius gradually decreases, and the permeability also decreases along this direction. This indicates that the permeability of the rock is determined by the throat radius; the larger the throat, the better the reservoir property (Figure 6).

5. Discussion

5.1. Control of Pore Structure by Sedimentation

On the basis of previous studies, according to the classification of typical and atypical gravity flows proposed by Bauma and Walker, we provide a detailed observation of the Chang 7 core in the HSN area. It is believed that the Chang 7 reservoir in the HSN area is the result of deep-water gravity flow. The sediments mainly consist of sand debris flows and turbidity currents. The sand debris flow deposits have fine particle sizes, good sorting and rounding, low matrix content, and good physical properties. The mainly developed massive oily fine sandstone and parallel bedding and irregular mud debris can be seen in the sandstone (Figure 7a–c). The deposition of the turbidity current is very fine-grained, with a high matrix content and poor physical properties. It is a non-Newtonian fluid. It mainly contains muddy siltstone or silty mudstone, showing the Bouma sequence sections B and C, flame structures, and groove cast in the core (Figure 7d–f).

The sedimentary environment and material basis of the reservoir control the pore structure. Under the background of gravity flow deposition, the sediment underwent rapid accumulation and the particle arrangement was non-directional, causing less pore formation between particles. The target layer was deposited in the semi-deep lake–deep lake deposition environment where the deposited water was deep and the sediment was far from the source. After long distance transport, the sediment had fine grain size, good sorting, high mud content, and small reservoir original pores. Sandy debris flow develops in a high-energy sedimentary environment, and turbidity current deposition develops in a relatively low-energy sedimentary environment. Compared with the turbidity current deposition, the sandy debris flow has larger grain size, mainly fine sandstone, and pores are relatively developed (Figure 8a). Under the PM, the pore development of sand debris flow is better than that of the turbid current. The average particle size and face rate show significant positive correlation, confirming the influence of deposition environment on the pore (Figure 8b). The sediment size and matrix content determine the original porosity and permeability of the reservoir. The sandy debris flow has large sediment size, less matrix, and high original porosity and permeability. The turbidity current sediment has small grain size, high matrix, and low original porosity and permeability. The statistical results confirm that the porosity and permeability of sand debris flow deposits are significantly better than those of the turbidity current deposits (Figure 8c,d).

5.2. Control of Pore Structure by Diagenesis

5.2.1. Diagenesis

Compaction

Under the background of gravity flow deposition, the deposit of the sediment has fine sizes, high matrix content, fast deposition, and poor rock compressional strength, which leads to strong compaction during later diagenesis. The compaction strength of the reservoir increases with burial depth. The interparticle contact relationship changes from the original point-line contact to line contact, and further progresses to concave–convex contact or even suture-like contact (Figure 9a). Under PM and SEM observation, plastic particles such as mica and clay debris can be deformed under compression and be rearranged (Figure 9b). Rigid particles such as quartz and feldspar can be fractured (Figure 9c).

Cementation

Various types of interbedded shale oil reservoirs are developed in the HSN area. Based on XRD analysis in the study area, clay minerals are predominant, followed by carbonate cement. Affected by the strong compaction, the reservoir pores are greatly reduced, with pore types mainly consisting of small pore throats. Fluids in small pore throats are prone to semi-permeable membrane effects, causing strong carbonate cementation and clay cementation and resulting in the reservoir suffering from strong cementation. Cementation, through a series of physicochemical interactions, fills intergranular pores and accompanies various stages of the diagenesis period. This is another important factor leading to pore reduction in the reservoir.

(1)

Carbonate cementation

The carbonate cementation was dominated by late ferrocalcite and ankerite, which were widely distributed in the study area with an average volume fraction of 4.3%. Multi-stage carbonate cementation can be seen under the PM and SEM. Early carbonate cements are mostly without iron minerals, with poor crystallization and small crystal particle size. Self-shaped rhomboid dolomite fills the pores (Figure 9d). Late carbonate cements are mostly iron minerals, with good crystallinity and large crystal particle size. Under the PM, dark red ferrocalcite and light blue ankerite stained with potassium ferrocyanide and alizarin red can be observed. This filling of pores by porosity type cementation is shown (Figure 9e).

(2)

Clay cementation

The average volume fraction of self-generated clay minerals in the Chang 7 interbedded shale oil reservoir in the HSN region is 5.7%. Under the PM and SEM, we can see illite, chlorite, kaolinite, montmorillonite, and an illite/smectite mixed layer, mainly illite and chlorite, and other clay minerals are relatively less developed. There are bridging-shaped and honeycomb-shaped interstitial pores of illite (Figure 2f,g). They mainly originate from the montmorillonite formed during early diagenesis and are widely distributed on the surfaces of feldspar, debris, and other particles. The clay cement in the study area is mainly illite, with an average mass fraction of 39.8%, which greatly reduces the compaction residue intergranular pores of the reservoir. Chlorite occupies a relatively low proportion of clay cement, averaging 21.5%, and exhibits filamentous morphology under the microscope (Figure 9f). Chlorite is present in the pore mainly in two forms. When the chlorite content is low, chlorite mainly attaches to the surface of particles. On the one hand, it can reinforce the pores to increase the compaction resistance of the pores. On the other hand, it can effectively inhibit the secondary increase in mineral particles, which is conducive to the preservation of the pores. When the content of chlorite is high, a small amount of the chlorite attaches to the surface of particles, while the rest directly fills the pores, which is not conducive to pore preservation. The chlorite is relatively developed in the study area, which can increase the anti-compaction ability of the reservoir, inhibit the secondary growth of minerals, and be conducive to the preservation of the reservoir pores.

Dissolution

The reservoir is subjected to strong compaction and strong cementation, resulting in a highly tight reservoir. The intensity of the dissolution effect is the key to the formation of high-quality reservoirs. Microscopic observation showed that the dissolved pores in the study area are mainly feldspar and rock debris dissolution pores (Figure 2c–e). The dissolved pore radius was extracted, and we calculated the areal percentage of the cast thin section using the convex hull method [32,33]. The blue region shows the extracted dissolved pores, and the red region represents the extracted primary pores (Figure 10c,g). The dissolution degree of different samples varied significantly (Figure 10d,h). In the core sample from well N11 at 1141 m depth, dissolution pores are relatively numerous, with a total areal percentage of 6.03%, of which dissolved pores account for 5.31%. In contrast, the core sample from well N11 at 1147 m contains fewer dissolution pores, showing a total areal percentage of 2.83%, with dissolved pores accounting for 2.1% (Figure 10c,g).

In the process of diagenesis evolution, the dissolution of potassium feldspar will produce a large number of potassium ions. Potassium ions can effectively promote montmorillonite illitization. However, a large number of sodium ions will be produced in the process of illitization to form a dissolution barrier on the surface of the plagioclase to inhibit plagioclase dissolution. The widely developed illite cement in the study area indicates the presence of potassium feldspar massive dissolution. XRD analysis showed that the average content of plagioclase in the reservoir was three times that of potassium feldspar, confirming that the dissolution pores mainly originate from the potassium feldspar.

5.3. Advantageous Reservoir Forming Mechanism

The diagenetic evolutionary sequence of interbedded shale oil reservoirs is compaction → quartz increasing → chlorite, illite, calcite cementation → feldspar, debris, and calcite dissolution → ferrocalcite, ankerite cementation [14]. According to the different formation processes of sand bodies, the reservoirs can be classified into three types:

Type I reservoir: Strong compaction leading. This kind of reservoir is mostly turbidite current with high plastic debris content and low rigid mineral content. These reservoirs have undergone strong compaction, strong cementation, and weak dissolution (Figure 11(I)). The reservoir porosity < 5%, and permeability < 0.05 mD, with very small pore radial distribution around 10 nm, and maximum mercury saturation < 30%. Dissolution features are poorly developed (Figure 4a Z306 well rock sample).

Type II reservoir: Medium compaction, medium cementation leading. This kind of reservoir has increased rigid particles, and anti-compaction ability is enhanced. It also suffers weak dissolution (Figure 11(II)). The reservoir porosity is 5~8%, permeability is 0.05~0.1 mD, the pore radius is small, averaging around 50 nm, the maximum mercury saturation is 30~70%, and both cementation and dissolution are relatively well developed (Figure 4a N23 well rock sample).

Type III reservoir: Medium compaction, medium cementation, medium dissolution leading. This kind of reservoir is mostly composed of sandy debris flows, with strong compaction resistance, large pores, and many soluble substances such as feldspar and debris (Figure 11(III)). Well-developed dissolved pores can be observed under the PM. The reservoir porosity > 8%, permeability > 0.1 mD, with pore radius distributed around 1 μm, maximum mercury injection saturation > 70%, and strong dissolution development (Figure 4a N143 well rock sample).

6. Conclusions

(1)

The Chang 7 interbedded shale oil reservoir in the HSN area has extremely strong heterogeneity and extremely low porosity and permeability. The pore types are diverse, mainly feldspar and debris dissolution pores, residual intergranular pores, and a small number of microcracks are developed.

(2)

The pore shapes are mainly parallel-slit and ink-bottle shapes. The pore radius is mainly distributed in the range of 30 to 200 µm, and the throat radius is mainly distributed in the range of 0.3 to 2 µm.

(3)

The pore structure of interbedded shale oil reservoirs in the HSN area is controlled by sedimentation and diagenesis. Sedimentation determines the material basis of fine size and high matrix clay content. Compaction and cementation are the main factors for reducing pores in the study area. The effect of sand debris flow is reduced by cementation. The effect of turbidity current is reduced by compaction. The strength of dissolution is the key to the development of high-quality reservoirs.

(4)

We established the formation mode of the high-quality reservoir of the Chang 7 interbedded shale in the HSN area. The formation of the sandy debris flow is attributed to medium compaction, medium cementation, and medium dissolution, which results in good physical properties and large pore sizes. It is the main factor for high-quality reservoirs in the study area.