Pore Classification and Structural Characteristics of Oligocene–Pliocene Shale Reservoirs in the Western Qaidam Depression

Abstract

Oligocene–Pliocene shale reservoirs in the Western Qaidam Depression represent typical mixed shale deposits characterized by moderate organic matter (OM) abundance and sufficient OM maturity, indicating substantial shale-oil resource potential. Here, a comprehensive study was conducted to analyze the reservoir characteristics of different shale types, including the Upper Xiaganchaigou (late Oligocene), Shangganchaigou (Miocene), and Xiayoushashan (early Pliocene) Formations in the Western Qaidam Depression. Our analysis focused on the pore structural characteristics of shale reservoirs, employing X-ray diffraction, casting thin sections, scanning electron microscopy, low-temperature nitrogen adsorption, and nuclear magnetic resonance (NMR) as investigative techniques. Our results show that (1) the study area comprises five typical shale types: lime shale, argillaceous shale, limestone, argillaceous limestone, and mudstone. The best hydrocarbon source rock conditions are found in the lime shale and argillaceous shale. (2) Inorganic pores, including dissolution pores, intergranular pores, bedding fractures, structural fractures, and intraparticle pores in clay minerals, are the main pore types found in the studied samples and constitute the primary reservoir space for shale oil. On the basis of fractal dimensions obtained through NMR, the pores can be classified as micropores (<100 nm), mesopores (100–1000 nm), or macropores (>1000 nm). Mesopores are the main contributors to porosity. (3) The development of micropores is positively correlated with clay mineral content. The development of mesopores and macropores is influenced by the quartz, feldspar, dolomite, and calcite contents. Calcite content exhibits a negative correlation with porosity, suggesting that later-stage pore cementation hinders shale reservoir development. (4) The five typical shale reservoirs in the study area can be categorized into three types. Type I reservoir lithologies include lime shale and argillaceous shale; type II reservoir lithologies include limestone and argillaceous limestone; and type III reservoirs comprise mudstone. Type I and II reservoirs are of better quality than type III.

1. Introduction

With the success of the North American shale-oil revolution, the global direction of oil and gas exploration has gradually shifted from conventional to unconventional resources.¹⁻⁴ China ranks third globally after Russia and the United States in terms of shale-oil reserves.⁵⁻⁷ Abundant shale-oil resources are widely distributed across various basins in China; examples include the Lucaogou Formation in the Junggar Basin, Shahejie Formation in the Bohai Bay Basin, and Qingshankou Formation in the Songliao Basin. The Qaidam Basin stands out as the only large-scale Cenozoic oil-bearing basin in western China,⁸⁻¹⁰ forming a distinctive saline lake basin oil–gas system.¹¹ Several oil-bearing layers have been identified in the Western Qaidam Depression, spanning the Upper Xiaganchaigou to Xiayoushashan Formations.^12,13

Previous studies have shown that source rocks with low organic matter (OM) abundance spanning the Upper Xiaganchaigou to Xiayoushashan Formations are pivotal to the Cenozoic hydrocarbon system in the Qaidam Basin.^14,15 As a sedimentary system in a saline lake basin, these source rocks exhibit optimal conditions for preserving soluble OM, which can generate large amounts of hydrocarbons during the low maturity stage.¹⁶⁻¹⁸ In recent years, there has been marked progress in shale-oil exploration in the Yingxiongling area, underscoring the immense exploration potential of oil and gas resources in the Western Qaidam Depression.¹⁵

Shale pores play a crucial role in shale reservoirs, holding paramount importance for shale-oil exploration and development. Previous studies on shale pores in the Qaidam Basin have primarily focused on pore type, pore connectivity, and mechanisms of pore structure development and evolution.¹⁹⁻²¹ However, the heterogeneity resulting from multiple shale types in the Oligocene–Pliocene layers remains a challenge. Moreover, limited attention has been paid to studying the differences and influencing factors of pores in various shale types.

In this study, we used mineral composition, rock structure, and OM content to classify different shale types. Subsequently, the micropore development characteristics and differences among these shale types were quantitatively analyzed through casting thin sections, scanning electron microscopy (SEM), low-temperature nitrogen adsorption (LTNA), nuclear magnetic resonance (NMR), and X-ray diffraction (XRD). This enabled us to reveal the influencing factors of pore development in different shale reservoirs and categorize reservoirs, providing a theoretical basis for assessing shale-oil resource potential and guiding exploration efforts in the Western Qaidam Depression.

2. Geological Setting

The Qaidam Basin, situated on the northern Tibetan Plateau in northwestern China about 120 × 10³ km²,²² is characterized by complex topography and high-altitude arid conditions. Bounded by the East Kunlun Mountains to the south, Qilian Mountains to the north, and Altun Mountains to the west,^23,24 it stands as one of the largest inland sedimentary basins in China. The basin has an irregular rhomboid shape, wider in the west and narrower in the east²⁵ (Figure 1), owing to the influence of plateau uplift and surrounding strike-slip tectonics. Originating in the middle–late Mesozoic it has undergone multiple evolutionary stages since the middle–late Jurassic, encompassing collisional orogenesis, tectonic burial, and subsequent uplift and subsidence. This prolonged geological history has led to the deposition of a diverse series of sediments in the region, forming a robust material foundation for shale-oil reservoirs. According to variations in structural deformation and geophysical characteristics, the Qaidam Basin can be divided into four first-order tectonic units, namely, the Western Qaidam Depression, Eastern Qaidam Depression, Northern Qaidam Depression, Altun Slope, as well as 25 s-order tectonic units.²⁶

Figure 1.

Geological setting of the Qaidam Basin. (a) Tectonic map showing the Qaidam Basin composed of the Western Qaidam Depression, Eastern Qaidam Depression, Northern Qaidam Depression, and Altun Slope. (b) Sketch map of the study area location [marked with a red rectangle in (a)].

Located in the southwestern part of the basin, the Western Qaidam Depression comprises nine sets of strata from bottom to top: the Jurassic basement; Paleogene Lullehe Formation; Oligocene Lower Xiaganchaigou and Upper Xiaganchaigou Formations; Miocene Shangganchaigou Formation; Pliocene Lower Youshashan, Upper Youshashan, and Shizigou Formations; and Quaternary Qigequan Formation.²⁷⁻²⁹ The Upper Xiaganchaigou Formation is particularly noteworthy for containing the primary source rocks in this area.

3. Samples and Methods

3.1. Samples

Shale is widely distributed across the Western Qaidam Depression. To ensure the universal applicability of our experimental results, a total of 47 core samples were collected from the four areas of Ganchaigou, Yingxi, Xiaoliangshan, and Zahaquan; the collection layers were all within the Upper Xiaganchaigou, Shangganchaigou, and Lower Youshashan Formations, with 34 samples collected from the Upper Xiaganchaigou Formation, nine samples from the Shangganchaigou Formation, and four samples from the Lower Youshashan Formation. The depth distribution of the samples was 2045–4174 m, and the lithologies were mainly calcareous shale, argillaceous shale, carbonate rocks, and mudstone. All geochemical analyses were carried out at the Hubei Key Laboratory of Petroleum Geochemistry and Environment, Yangtze University.

3.2. Geochemical Analyses

Total organic carbon (TOC) content was determined using a LECO-230 carbon sulfur analyzer, referring to the Chinese national standard GB/T19145-2003. Prior to analysis, each sample was powdered to 100 mesh, dilute hydrochloric acid was added to remove inorganic carbon, and then each sample was dried at room temperature for >24 h.

Rock-Eval analysis was carried out using an OGE-VI instrument, referring to the GB/T 18602-2012 standard. Each 80 mg sample was ground to a 100 mesh, before being heated to 300 °C and held at a constant temperature for 3 min to obtain the content of S₁ (free hydrocarbons). Each sample was then heated from 300 to 550 °C at a rate of 25 °C/min, before being held at a constant temperature for 1 min, where the S₂ (pyrolysis hydrocarbon) content and T_max (maximum peak temperature of pyrolysis) value were obtained.

Analysis of microscopic organic components was carried out using a Leica DMRXP microscope with a 50× oil immersion objective lens. Each rock sample was cut in the longitudinal section, fixed with epoxy resin, and polished to obtain a light-transparent sheet. The organic components were then identified under reflected light and fluorescence, referring to the SY/T6414-2014 standard.

3.3. Mineral Composition Analysis

The mineral composition of shale samples was quantitatively analyzed using an Ultima IV X-ray diffractometer, referring to the standard SY/T5163-2018. Each 3 g sample was crushed to below 300 mesh, soaked with ethanol, and ground; the detection temperature was 20 °C, humidity was 40%, and scanning speed was 4 °C/min.

3.4. Reservoir Characterization Analysis

SEM was carried out using a ZEISS MERLIN compact field emission scanning electron microscope with a resolution of 0.8 nm and magnification range of 12–2,000,000 times. To more clearly observe the pore characteristics, each sample was first ground into a square shape with a length of 6 mm, width of 4 mm, and thickness of 2 mm using sandpaper; each sample was then polished using an argon ion polishing instrument.

LTNA experiments were carried out using a Micromeritics ASAP 2020 automatic gas adsorption instrument manufactured in the United States. Prior to analysis, each rock sample was crushed to 40–60 mesh and degassed at 110 °C in vacuum for >12 h to remove volatile impurities. At the temperature of liquid nitrogen (77 K), the pressure was increased to reach the saturated vapor pressure of liquid nitrogen; the pressure was then gradually reduced, and the isothermal adsorption–desorption curve with a relative pressure of 0.01–0.993 was obtained. The pore size distribution, specific surface area, and other pore parameters were obtained using the Brunauer–Emmett–Teller and Barrett–Joyner–Halenda (BJH) models. The range of pore sizes of the characterized samples was below 100 nm.

NMR analysis was carried out using a MesoMR23-060H-I NMR analyzer and imager, in three parts: original sample, saturated oil sample, and dry sample. Each rock sample was drilled using an emery wire cutter with a diameter of 25 mm and length of 50 mm.

4. Results and Discussion

4.1. Mineralogical Compositions and Geochemical Characteristics of Different Shale Types

XRD analysis showed that the mineral composition of the samples predominantly comprised quartz, feldspar, calcite, and clay minerals; some samples had a high dolomite content, while others contained minerals such as pyrite, gypsum, and anhydrite (Figure 2), indicating a typical mixed shale deposit. On the basis of mineral composition and rock structure characteristics (Tables 1 and 2), the samples in the study area were classified into five types: lime shale, argillaceous shale, limestone, argillaceous limestone, and mudstone.

Figure 2.

Composition characteristics of different types of shales. (a) Through XRD analysis, the shale samples were classified into five types according to their mineral composition. (b,c) Lime shale. Well YH106X, 3358.7 m, core. (d,e) Argillaceous shale. Well NQ3-1S, 2095.8 m, core. (f,g) Limestone. Well C2-4, 2823.8 m, core. (h,i) Argillaceous limestone. Well C906, 3237.0 m, core. (j,k) Mudstone. Well C2-4, 2811.3 m, core.

Table 1. Lithologies and Mineral Compositions of Shale Samples.

sample	well	depth (m)	lithology	mineral composition (wt %)
				quartz	feldspar	calcite	dolomite	pyrite	gypsum and anhydrite	clay
2	C10	2329.6	lime shale	12.10	7.56	13.10	50.60	3.83	0.71	12.10
4	NQ25-16S	3431.5	lime shale	21.50	14.80	33.20	6.80	1.00	1.20	21.50
6	NQ3-1S	2278.3	lime shale	16.90	17.20	11.10	31.10	5.30	0.70	17.70
7	G11	4112.0	lime shale	20.00	18.00	18.90	8.10	2.70	0.90	31.40
8	G6	4104.0	lime shale	23.82	11.56	23.32	6.73	0.90	0.70	32.96
9	L8	4050.3	lime shale	17.21	22.00	21.89	9.98	3.46	0.00	25.46
10	YH106X	3352.9	lime shale	28.72	20.70	18.37	2.64	4.86	1.58	23.13
11	YH106X	3358.7	lime shale	15.38	7.53	31.89	11.97	4.44	0.00	28.79
14	YH106X	3373.9	lime shale	14.88	20.92	14.78	19.04	5.31	0.00	25.08
15	S41-6-1	3849.8	lime shale	21.00	28.20	25.50	0.00	3.00	5.00	17.30
16	NQ3-1S	2095.8	lime shale	10.70	16.80	6.00	47.00	5.10	1.40	13.00
18	C2-4	2821.0	argillaceous shale	20.30	10.20	16.60	10.60	5.10	3.20	34.00
19	C2-4	2821.4	argillaceous shale	21.44	19.41	13.35	3.24	4.85	4.15	33.57
20	C10	2343.3	argillaceous shale	16.80	9.30	11.70	24.00	7.70	0.00	30.50
21	NQ25-16S	3440.3	argillaceous shale	16.13	21.47	21.98	6.25	2.72	0.81	30.65
23	L8	4040.4	argillaceous shale	13.78	17.71	6.54	37.83	1.81	0.00	22.33
24	L8	4040.9	argillaceous shale	19.98	23.83	21.40	8.22	3.35	0.71	22.52
25	ZT1	2762.8	argillaceous shale	11.97	17.34	13.18	31.03	5.17	0.00	21.30
26	ZT1	2763.3	argillaceous shale	11.45	15.70	14.59	33.74	3.95	1.22	19.35
27	C906	3237.0	argillaceous shale	19.10	22.81	13.77	10.75	4.02	0.00	29.55
28	S41-6-1	3851.9	argillaceous shale	22.70	24.30	24.90	5.00	2.60	6.90	13.60
30	C906	3237.4	limestone	10.50	15.20	53.80	2.60	2.80	0.00	15.10
31	NQ25-16S	3425.8	limestone	13.90	12.00	47.40	10.90	1.90	0.00	13.90
32	ZT1	3956.6	limestone	4.13	7.26	34.88	46.67	3.23	0.40	3.43
33	C2-4	2845.0	limestone	8.80	8.00	66.20	10.10	2.00	0.00	4.90
34	G11	4127.0	limestone	6.40	11.60	6.70	64.70	3.50	0.30	6.80
36	S41-6-1	3867.1	argillaceous limestone	11.60	21.00	44.60	5.90	3.10	3.80	10.00
37	C2-4	2823.8	argillaceous limestone	8.60	6.50	75.70	0.40	0.80	1.00	7.00
38	NQ25-16S	3425.5	argillaceous limestone	17.60	19.00	35.20	6.70	2.50	0.60	18.40
39	G11	3861.3	argillaceous limestone	24.42	17.39	27.24	5.13	1.31	0.70	23.82
40	G5	4174.5	argillaceous limestone	15.40	8.20	15.60	29.90	0.00	1.10	29.80
41	C10	2337.1	argillaceous limestone	16.16	14.98	45.99	2.48	2.48	0.00	17.92
43	NQ25-16S	3425.6	mudstone	14.46	15.86	33.33	10.04	3.61	1.00	21.69
44	NQ3-1S	2045.1	mudstone	18.02	17.92	18.96	15.94	3.33	0.73	25.10
45	G11	3866.5	mudstone	24.39	16.91	12.91	5.64	2.87	0.72	36.58
46	G11	3867.0	mudstone	22.55	18.71	11.12	5.56	2.63	0.00	39.43

Table 2. Organic Geochemical Characteristics of Shale Samples^a.

sample	well	depth (m)	lithology	geochemical characteristics
				TOC (%)	S1 (mg/g)	S2 (mg/g)	Tmax (°C)	HI (mg/g)
1	C10	2322.1	lime shale	1.22	0.70	7.15	431	586.1
2	C10	2329.6	lime shale	1.17	0.85	5.44	436	465.0
3	S41-6-1	3858.2	lime shale	1.46	1.19	6.55	435	448.6
4	NQ25-16S	3431.5	lime shale	0.56	0.22	0.81	437	143.6
5	NQ3-1S	2106.8	lime shale	0.71	0.34	2.16	448	306.4
6	NQ3-1S	2278.3	lime shale	0.83	0.75	3.00	433	361.9
7	G11	4112.0	lime shale	1.56	0.42	5.97	437	382.7
8	G6	4104.0	lime shale		0.10	0.24	432
9	L8	4050.3	lime shale	1.93	2.02	10.47	433	542.7
10	YH106X	3352.9	lime shale	0.59	0.83	1.29	440	217.7
11	YH106X	3358.7	lime shale	0.62	0.48	1.91	451	306.1
12	YH106X	3364.3	lime shale	1.81	2.04	9.56	448	528.2
13	YH106X	3366.0	lime shale	2.11	2.59	9.51	429	450.6
14	YH106X	3373.9	lime shale	1.83	1.36	7.62	430	416.5
15	S41-6-1	3849.8	lime shale	1.50	0.67	8.97	444	598.0
16	NQ3-1S	2095.8	lime shale	0.93	0.30	3.49	448	375.3
17	C2-4	2813.4	argillaceous shale	2.11	2.62	10.90	433	516.6
18	C2-4	2821.0	argillaceous shale	1.59	2.75	6.54	432	411.4
19	C2-4	2821.4	argillaceous shale	2.09	3.12	13.18	439	630.5
20	C10	2343.3	argillaceous shale	1.76	1.22	11.71	458	665.2
21	NQ25-16S	3440.3	argillaceous shale	0.86	0.51	1.43	447	166.1
22	NQ3-1S	2094.0	argillaceous shale	0.77	0.39	2.80	438	363.2
23	L8	4040.4	argillaceous shale	1.48	1.77	5.65	424	382.0
24	L8	4040.9	argillaceous shale	1.19	0.54	6.88	433	578.3
25	ZT1	2762.8	argillaceous shale	1.61	1.65	7.74	438	480.7
26	ZT1	2763.3	argillaceous shale	1.32	1.35	6.61	441	500.8
27	C906	3237.0	argillaceous shale	1.40	0.45	8.36	448	597.1
28	S41-6-1	3851.9	argillaceous shale		0.99	9.37	449	554.4
29	G11	4110.3	argillaceous shale	0.90	0.34	3.85	442	428.3
30	C906	3237.4	limestone	1.03	0.51	4.00	441	388.3
31	NQ25-16S	3425.8	limestone	1.45	0.38	2.57	446	177.2
32	ZT1	3956.6	limestone	0.65	0.74	1.57	450	241.5
33	C2-4	2845.0	limestone	1.51	1.41	8.83	435	584.8
34	G11	4127.0	limestone	1.31	1.11	3.46	441	264.1
35	YH106X	3365.0	limestone	1.18	1.41	4.65	448	394.2
36	S41-6-1	3867.1	argillaceous limestone	1.29	0.61	7.00	445	542.6
37	C2-4	2823.8	argillaceous limestone	1.26	1.17	6.92	437	548.9
38	NQ25-16S	3425.5	argillaceous limestone	0.89	0.40	1.52	443	170.8
39	G11	3861.3	argillaceous limestone	0.79	0.08	3.52	444	443.9
40	G5	4174.5	argillaceous limestone	0.33	0.19	0.76	448	227.5
41	C10	2337.1	argillaceous limestone		0.91	8.11	438	579.3
42	C906	3225.6	mudstone	1.22	2.25	4.46	443	365.2
43	NQ25-16S	3425.6	mudstone		0.26	4.93	437	300.6
44	NQ3-1S	2045.1	mudstone	0.32	0.33	0.73	439	225.3
45	G11	3866.5	mudstone	0.67	0.21	2.75	439	408.0
46	G11	3867.0	mudstone	0.58	0.19	1.99	432	343.7
47	ZT1	3957.9	mudstone		4.12	4.77	460	305.6

^aTOC: total organic carbon, T_max: maximum temperature, HI: hydrogen index.

Lime shale was identified as the main shale-oil layer, distinguished by a predominant laminar structure (Figure 2j,k), featuring distinct micrometer-scale laminae, alternating between carbonate and clay minerals. The contents of carbonate and clay minerals were relatively high, with average values of 37 and 23%, respectively.

Argillaceous shale was mainly characterized by sand–clay lamination (Figure 2h,i), with a relatively high clay mineral content of between 14 and 34% (average of 26%).

Limestone was common and characterized by a centimeter-scale thick layered structure or blocky structure (Figure 2f,g). The mineral components were dominated by carbonate minerals, with contents exceeding 50% (average of 69%).

Argillaceous limestone was also widely distributed within the shale unit, characterized by a blocky structure and lack of bedding (Figure 2d,e). The carbonate mineral content was slightly lower than that of limestone, ranging from 32 to 76% (average of 49%), while the clay mineral content remained relatively low.

Mudstone was predominantly blocky or layered (Figure 2b,c), with a relatively high clay mineral content (average of 28%) and a lower carbonate mineral content compared with other shale types.

Through the analysis of TOC and rock pyrolysis data from various samples (Figure 3), statistics showed that the TOC distribution ranged from 0.32 to 2.11 wt %, and the S₁ + S₂ distribution ranged from 0.95 to 16.30 mg/g TOC. The OM abundance showed little variation among different types, primarily falling into the “good” to “high quality” grades. Lime shale and argillaceous shale samples had the highest OM abundance, with TOC content ranges of 0.56–2.11 wt % and 0.77–2.11 wt %, respectively, and source rock grades ranked as “good” to “high quality”. These were followed by limestone and argillaceous limestone samples with TOC contents of 0.65–1.51 wt % and 0.33–1.29 wt %, respectively. Mudstone exhibited the lowest OM abundance, with TOC contents ranging from 0.32 to 1.22 wt %.

Figure 3.

Intersection diagram of TOC and hydrocarbon generation index (S₁ + S₂). Lime shale and argillaceous shale comprise the best quality source rocks, followed by limestone and argillaceous shale, and finally mudstone.

The maximum temperature (T_max) and HI of rock-eval data are often used to classify OM types, while microscopic organic composition analysis can also identify the type of OM. The HI values of different types of shale in the study area were distributed between 100 and 700 mg/g, while the T_max values were mainly distributed within the range of 420–460 °C. From these data, the OM predominantly falls into the range of type I–type II₂ (Figure 4a). Among the different samples, lime shale and argillaceous shale exhibited the highest-quality OM types, primarily classified as types I–II₁. The microscopic components of the hydrocarbon source rocks mainly comprised lamalginite, sporophytes, amorphous solids, and solid bitumen, with vitrinite and inertinite being less common (Figure 4b–g), indicating OM dominated by types I–II₁ derived from lower aquatic organisms.

Figure 4.

Distribution characteristics of OM types. (a) Diagram of maximum temperature (T_max) versus HI showing that the OM mainly falls into the range of type I–type II₂. (b–g) Using fluorescent and transmitted light, the microscopic components of the source rocks were mainly found to be lamalginite, sporophytes, amorphous solids, and solid bitumen, indicating that the OM was mainly types I–II₁.

The vitrinite reflectance (Ro) of kerogen is an important indicator of the maturity of source rocks, but the maceral group of the source rocks in the study area was rarely vitrinite; hence, T_max was used to evaluate the maturity of the source rocks. The T_max value increases with the thermal evolution of a given source rock. According to our rock-eval data (Figure 5), the OM of the source rock system is mainly in the mature stage, corresponding to Ro values ranging from 0.5 to 1.3%.

Figure 5.

Variation in maximum temperature (T_max) of hydrocarbon source rocks with depth. The OM of the source rock system is mainly in the mature stage.

4.2. Pore Structure Characteristics

4.2.1. Pore Types

On the basis of observations using thin sections and SEM (Figure 6), reservoir spaces identified in the shale reservoirs included dissolution pores, intergranular pores, bedding fractures, structural fractures, intraparticle pores in clay minerals, and OM pores.

Figure 6.

Thin section and SEM images of shale rocks. (a) Well NQ25-16S, 2278.3 m, dissolution pores developed. (b) Well NQ25-16S, 2278.3 m, dissolution pores developed. (c) Well S41-6-1, 3867.1 m, intergranular pores developed. (d) Well ZT1, 3956.6 m, structural fractures developed. (e) Well C2-4, 2821.4 m, bedding fractures developed. (f) Well C906, 3237.4 m, bedding fractures developed. (g) Well L8, 4050.32 m, intraparticle dissolution pores developed. (h) Well C2-4, 2821.4 m, interparticle dissolution pores, OM pores, and intergranular pores developed. (i) Well S41-6-1, 3858.2 m, interparticle dissolution pores developed. (j) Well S41-6-1, 3858.2 m, structural fractures developed. (k) Well L8, 4050.32 m, intraparticle pores in clay minerals developed. (l) Well ZT1, 2762.8 m, OM pores developed.

Dissolution pores (Figure 6a,b) are formed by the dissolution of unstable components (feldspar, dolomite, and debris) when exposed to acidic fluids. The pore size distribution was wide in the studied samples, ranging from tens of nanometers to several micrometers.

Intraparticle dissolution pores (Figure 6g) were observed within feldspar grains, comprising densely distributed honeycomb-like pores that easily interconnect to form microfractures. Where the clay mineral content was relatively high, intraparticle pores formed within the clay minerals (Figure 6k), having a complex pore morphology, including both slender wedges and irregular serrations.

Interparticle dissolution pores (Figure 6h,i) originate from intergranular dissolution and extend into the interior of grains, forming irregular harbor shapes, usually associated with residual intergranular pores. Intergranular pores (Figure 6c,h) occurred between mineral crystals (e.g., quartz, dolomite, and clay), with diameters mainly distributed in the range of 1–10 μm. These small individual pores were widely developed in limestone, where they were densely distributed in contiguous layers, and are considered important in shale-oil reservoirs.

Fractures were widely developed in the studied rocks, with the main types including bedding fractures (Figure 6e,f) and structural fractures (Figure 6d,j). Fracture widths were mainly distributed in the range of 1–20 μm, markedly enhancing reservoir permeability.

OM pores (Figure 6h,l) were also observed under SEM, with a pore size of approximately 10–100 nm. These pore shapes were mainly narrow and elliptical. Owing to the overall low maturity of the OM, the number of OM pores was relatively small, mainly comprising OM edge shrinkage fractures, which were scattered with poor connectivity, and were unable to form an effective pore grid.

4.2.2. Full-Scale Pore Characteristics Based on NMR Analysis

NMR is often employed to characterize the full-scale pore characteristics of shale,³⁰ wherein a large T₂ value corresponds to a large pore size, and a small T₂ value corresponds to a small pore size.³¹ In this study, a total of 26 samples from five different shale types were selected for analysis. To facilitate a more intuitive comparison of pore characteristics across different types of shale, the signal amplitude of the T₂ spectrum was converted into porosity components, resulting in typical three-peak distributions, as illustrated in Figure 7. The distributions signify the presence of at least three types of pores, with peaks distributed at <1, 1–10, and >10 ms, respectively. The P1 and P2 peaks of the T₂ spectrum of the lime shale samples did not develop independently, and the P1 + P2 peak was larger than the P3 peak (Figure 7a). In the argillaceous shale, the P1 and P2 peaks of some samples did not develop independently (nos. 22, 26, and 29), and in these samples, the P1 + P2 peak was larger than the P3 peak; the three peaks of the other argillaceous shale samples developed independently, with the P2 peak > P3 peak > P1 peak (Figure 7b). The three peaks of the limestone and argillaceous limestone samples were distributed independently (Figure 7c,d). Except for sample no. 34, samples of limestone exhibited the largest P3 peak. In argillaceous limestone samples, the P2 peak > P3 peak > P1 peak. Among the mudstone samples, the P1 and P2 peaks of sample no. 43 did not develop independently and the P1 + P2 peak was larger than the P3 peak; the P3 peaks of the other mudstone samples were smaller than the P1 and P2 peaks (Figure 7e).

Figure 7.

NMR T₂ spectra of different types of shale reservoirs. (a) Nine samples of lime shale, in which the P1 and P2 peaks were not independently distributed and were higher than the P3 peak. (b) Seven samples of argillaceous shale, in which the P1 and P2 peaks of samples 22, 26, and 29 were not independently distributed. (c) Four samples of limestone, in which the P2 peak was highest in sample 34, and the P3 peak was highest in the rest of the samples. (d) Three samples of argillaceous limestone, in which the peak sizes were ordered P2 > P3 > P1. (e) Three samples of mudstone, in which the P1 and P2 peaks of sample 43 were not independently distributed and the P1 + P2 peak was higher than the P3 peak, while the P3 peaks of the other samples were smaller than the P1 and P2 peaks.

4.2.3. Pore Size Classification Based on Fractal Dimension

In 1972, the International Union of Pure and Applied Chemistry (IUPAC) classified the pores of shale-gas reservoirs according to pore size, categorizing pores as either micropores (<2 nm), mesopores (2–50 nm), or macropores (>50 nm).³² However, this classification scheme may not be directly applicable to shale-oil reservoirs because these reservoirs frequently contain a substantial number of pores with sizes exceeding 100 nm, often reaching the micrometer level. On this basis, a number of scholars have proposed alternative classifications for shale-oil reservoir pores, drawing on experimental techniques such as high-pressure mercury intrusion, NMR, and SEM.^33,34 The fractal dimension, calculated using NMR data, is one method used to determine a classification scheme for shale pore characterization.^35,36 The calculation equation is as follows

1

where S denotes the cumulative porosity (%), D is the fractal dimension, and T_2max denotes the maximum T₂ value (ms).

Regression analysis on logarithmic scale graphs resulted in significant correlations, and the slopes of the fitted lines, combined with eq 1, were utilized to calculate the fractal dimensions of the samples. Intersection graphs of lg(S) and lg(T₂) for different types of shale samples were plotted using this method, as shown in Figure 8. Comparative analysis revealed that the correlation coefficients of the curve fittings were all >0.8, indicating pronounced fractal characteristics in the reservoir pores of the study area.

Figure 8.

Fractal dimension characteristics of different types of shales. (a) Well C10, lime shale, D1 = 0.507, D2 = 2.451, and D3 = 2.925. (b) Well NQ3-1S, argillaceous shale, D1 = 0.464, D2 = 2.478, and D3 = 2.969. (c) Well YH106X, limestone, D1 = 1.337, D2 = 1.999, and D3 = 2.820. (d) Well C10, argillaceous limestone, D1 = 0.726, D2 = 2.439, and D3 = 2.908. (e) Well ZT1, mudstone, D1 = 1.214, D2 = 2.775, and D3 = 2.978.

All samples exhibited three linear segments with two turning points (T_2l and T_2r). The distribution of these inflection points remained stable, with a tendency to cluster around 1 and 10 ms. The two turning points divided the shale pores into micropores (T₂ < T_2l), mesopores (T_2l < T₂ < T_2r), and macropores (T₂ > T_2r). The relaxation times of T₂ spectrum data can be transformed into pore diameter values through mathematical expressions. Combined with the fractal dimensions, the three peaks in each T₂ spectrum (Figure 7) correspond precisely to micropores with pore sizes <100 nm, mesopores with pore sizes between 100 and 1000 nm, and macropores with pore sizes > 1000 nm.

The fractal dimensions of micropores, mesopores, and macropores are represented by D1, D2, and D3, respectively, as shown in Table 3. Values of D1 ranged from 0.026 to 1.361, with an average of 0.931. Micropores predominantly exhibited adsorption characteristics with a relatively uniform pore structure. Values of D2 ranged from 1.880 to 2.841, with an average of 2.352. Values of D3 ranged from 2.820 to 2.994, with an average of 2.942; this was larger than the average D2 value, indicating a higher complexity of pore structure in macropores compared with mesopores.

Table 3. Fractal Dimensions and Porosity Calculated from NMR Data.

sample	lithology	porosity (%)	fractal dimension			porosity component (%)
			D1	D2	D3	micro	meso	macro
1	lime shale	8.29	0.803	2.282	2.946	0.97	5.23	2.08
2	lime shale	11.42	0.507	2.451	2.925	1.84	5.85	3.72
3	lime shale	8.90	0.998	2.065	2.911	0.51	5.08	3.31
5	lime shale	8.49	1.297	1.880	2.929	0.37	5.52	2.60
7	lime shale	6.76	0.914	2.096	2.965	0.52	5.19	1.06
12	lime shale	13.09	1.172	1.994	2.976	0.84	10.90	1.35
13	lime shale	15.35	1.033	1.972	2.977	0.96	12.76	1.63
15	lime shale	8.49	1.129	2.125	2.916	0.58	4.83	3.09
16	lime shale	6.80	0.461	2.225	2.971	0.81	5.06	0.92
17	argillaceous shale	6.06	0.716	2.602	2.994	2.16	3.72	0.19
19	argillaceous shale	7.19	1.186	2.475	2.930	1.31	3.68	2.21
22	argillaceous shale	7.25	0.464	2.478	2.969	1.53	4.60	1.12
26	argillaceous shale	7.49	0.616	2.432	2.977	1.53	5.13	0.83
27	argillaceous shale	4.38	1.092	2.497	2.923	0.79	2.08	1.51
28	argillaceous shale	9.15	1.181	2.841	2.923	3.80	2.22	3.13
29	argillaceous shale	6.28	0.026	2.609	2.990	2.08	3.79	0.41
32	limestone	1.26	0.750	2.350	2.879	0.07	0.50	0.70
33	limestone	2.38	1.245	2.396	2.900	0.23	1.09	1.06
34	limestone	10.95	1.361	2.259	2.952	1.40	7.06	2.49
35	limestone	2.06	1.337	1.999	2.820	0.04	0.70	1.32
36	argillaceous limestone	3.92	0.917	2.429	2.950	0.59	2.32	1.01
37	argillaceous limestone	2.43	1.286	2.456	2.944	0.40	1.38	0.64
41	argillaceous limestone	4.26	0.726	2.439	2.908	0.56	1.97	1.73
42	mudstone	2.82	1.138	2.311	2.962	0.41	1.89	0.51
43	mudstone	1.66	0.637	2.727	2.969	0.66	0.73	0.27
47	mudstone	4.36	1.214	2.775	2.978	2.17	1.72	0.47

Additionally, the full-scale pore size distribution characteristics of the samples are illustrated in Figure 9. The highest overall porosities were observed in lime shale and argillaceous shale, with averages of 9.73 and 6.83%, respectively. The porosity distribution in limestone and argillaceous limestone samples was uneven, with some samples having high porosity, but the average porosities were relatively low at 4.16 and 3.53%, respectively. Mudstone exhibited an average porosity of 2.95%, lower than that of limestone and argillaceous limestone. The meso-porosity component was the highest in all samples, and the microporosity component was the lowest, except for the argillaceous shale and mudstone samples, where microporosity was slightly higher than macro-porosity.

Figure 9.

Pore size distribution box plots of shale reservoirs with different types based on NMR data. Lime shale and argillaceous shale show the highest porosity, followed by limestone and argillaceous limestone, and finally mudstone. Except for the argillaceous shale and mudstone, the microporosity of some samples of a given lithology is slightly higher than the macro-porosity, with the porosity of the other samples ordered meso-porosity > macro-porosity > microporosity.

4.2.4. Characteristics of Micropores Based on LTNA

LTNA technology has commonly been employed to characterize micropore morphology and pore size distribution characteristics for pores <100 nm in size. In this study, 35 samples of different shale types were selected for nitrogen adsorption analysis, in which the isothermal adsorption–desorption curves exhibited inverse S-shapes (Figure 10). Isotherms in the front section of each curve rose slowly and had a slightly convex upward pattern. The rate of increase in the middle section of each curve became more rapid and approximately linear and in the rear section, rose sharply. Adsorption saturation occurred even when the equilibrium pressure approached the saturation vapor pressure.

Figure 10.

Isothermal adsorption–desorption curves of shale reservoirs with different types (STP: standard temperature and pressure). Hysteresis loops of (a) lime shale, (c) limestone, and (e) mudstone comprise both H2–H3 and H3 types. Hysteresis loops of (b) argillaceous shale and (d) argillaceous limestone are only H2–H3 type.

The adsorption capacity varied among different shale types, ranging from 1.8 to 18.0 cm³/g. Lime shale and argillaceous shale exhibited the highest adsorption capacities, ranging from 5.0 to 18.0 cm³/g. Argillaceous limestone and mudstone followed, with some of these samples exhibiting a maximum adsorption capacity > 5.0 cm³/g and the remaining samples ranging between 1.8 and 5.3 cm³/g. The adsorption capacity of limestone was the lowest, with maximum adsorption capacities of only 3.0–4.3 cm³/g. Isothermal adsorption–desorption curves showed evident hysteresis loops in the higher pressure parts; previous studies have shown that the morphology of hysteresis loops is related to the shape of micropores (2015, IUPAC).^19,37

Two types of hysteresis loops (H3 and H2–H3 transition) were observed in samples from the study area (Figure 10), indicating that the pore structure in the shale reservoirs mainly exhibits “ink bottle”–parallel plate structure pores. The hysteresis loops of the lime shale samples were mainly of the H2–H3 type, with only a few samples showing the H3 type, indicating that lime shale is mainly composed of transition pores with “ink bottle”—parallel plate structure, with some parallel plate-shaped pores. Only the transition pores of H2–H3 “ink bottle”—parallel plate structure were present by H2–H3 type in the argillaceous shale and argillaceous limestone samples. In limestone samples, both the H2–H3 transition and H3 types of hysteresis loop were present, indicating that the pore morphology is mainly characterized by “ink bottle”—parallel plate structure transition pores and parallel plate-shaped pores. Mudstone samples exhibited both H3 and H2–H3 type hysteresis loops, with the H2–H3 type being predominant.

Table 4 shows the average pore diameter, specific surface area, pore volume, and porosity of shale micropores obtained through the BJH model. According to the BJH pore size distribution, shale reservoirs of different types in the study area had micropore size widths mainly distributed between 5 and 70 nm (Figure 11). Each type of lithology exhibited a unique pore size distribution. All samples demonstrated two prominent peak regions, with the first peak at approximately 20 nm, second peak at approximately 40 nm, and the latter being higher than the former. Lime shale and argillaceous shale displayed the largest total micropore volumes. The pore size width distribution of lime shale was similar to that of argillaceous shale, and the proportions of micropores in these samples within the pore size range of 25–60 nm were relatively high. The maximum micropore volume of lime shale reached 0.04 cm³/g and that of argillaceous shale reached 0.03 cm³/g. In addition, the volume of micropores in some samples varied frequently with pore size, showing a serrated multipeak feature, suggesting that the heterogeneity of micropores in these samples is relatively large. The volume of micropores in argillaceous limestone and mudstone reached a maximum value (approximately 0.01 cm³/g) at a size of approximately 40 nm. The pore sizes of limestone were mainly distributed between 20 and 100 nm, and the contribution of micropore volume was relatively low. The highest micropore volume (0.01 cm³/g) occurred at a pore size of 40 nm. In general, argillaceous limestone and mudstone exhibited slightly higher levels of micropore development than did limestone. With a reduction in type H2–H3 hysteresis loops, the microporous volume also decreased; we infer that type H2–H3 hysteresis is more favorable for micropore development.

Table 4. Pore Structure Parameters of Studied Shale Samples Obtained via LTNA Analysis^a.

sample	lithology	APD (nm)	SSA (m2/g)	PV (cm3/g)	LTNA porosity (%)
4	lime shale	12.1	3.51	0.0071	1.83
6	lime shale	13.8	3.30	0.0073	1.89
7	lime shale	10.3	4.07	0.0088	2.29
8	lime shale	5.7	7.21	0.0098	2.56
9	lime shale	10.6	3.42	0.0075	1.95
10	lime shale	14.3	6.23	0.0145	3.77
11	lime shale	14.6	4.81	0.0114	2.96
14	lime shale	12.1	5.70	0.0135	3.50
15	lime shale	17.3	1.61	0.0040	1.04
16	lime shale	12.5	2.92	0.0062	1.62
18	argillaceous shale	10.2	1.82	0.0038	0.98
19	argillaceous shale	10.6	2.12	0.0048	1.25
20	argillaceous shale	9.5	2.25	0.0050	1.29
21	argillaceous shale	7.7	2.56	0.0051	1.32
23	argillaceous shale	8.9	2.41	0.0053	1.37
24	argillaceous shale	9.7	3.17	0.0065	1.69
25	argillaceous shale	9.3	3.68	0.0086	2.24
26	argillaceous shale	10.4	5.42	0.0119	3.10
27	argillaceous shale	12.0	1.19	0.0024	0.63
28	argillaceous shale	11.7	1.24	0.0028	0.72
30	limestone	8.0	1.76	0.0035	0.91
31	limestone	6.0	2.24	0.0034	0.89
32	limestone	10.1	0.96	0.0022	0.57
33	limestone	20.8	0.86	0.0021	0.54
34	limestone	14.1	1.13	0.0027	0.70
36	argillaceous limestone	10.0	1.04	0.0026	0.68
37	argillaceous limestone	10.1	1.10	0.0025	0.66
38	argillaceous limestone	9.5	2.24	0.0048	1.25
39	argillaceous limestone	7.4	3.11	0.0048	1.25
40	argillaceous limestone	6.3	6.83	0.0106	2.76
41	argillaceous limestone	10.0	1.82	0.0042	1.09
43	mudstone	12.3	0.62	0.0012	0.31
44	mudstone	15.1	0.72	0.0018	0.47
45	mudstone	7.0	4.31	0.0061	1.58
46	mudstone	6.5	5.65	0.0079	2.05

^aAPD: average pore diameter, SSA: specific surface area, PV: pore volume.

Figure 11.

BJH pore size distributions of shale reservoirs with different types. Samples of (a) lime shale and (b) argillaceous shale had the highest micropore volume, followed by (d) argillaceous limestone, (e) mudstone, and finally (c) limestone.

4.3. Shale Reservoir Controlling Factors and Classification

4.3.1. Controlling Factors of Shale Reservoir Pores

The proportion of different pore sizes comprising the total porosity, obtained through NMR, reveals that mesopores are the main contributor to porosity, followed by macropores, and finally micropores (Figure 12).

Figure 12.

Distributions of the proportions of porosity made up by different pore sizes in shale reservoirs of different lithological types, obtained via NMR analysis. Mesopores are the major contributor to porosity.

In this study, we obtained the specific surface area of micropores through LTNA and BJH calculation models. The specific surface area of lime shale was the highest, distributed between 1.61 and 7.21 cm²/g, with an average of 4.28 cm²/g; next came argillaceous shale, argillaceous limestone, and mudstone, with averages of 2.59, 2.69, and 2.83 cm²/g, respectively; last, was limestone, with an average of 1.39 cm²/g. Notably, no significant correlations were found between the TOC content and specific surface area, or TOC content and total pore volume, in samples of all lithological types (Figure 13a,b), indicating that the contribution of OM to specific surface area and micropore volume is not prominent. The OM is primarily in the mature stage (Ro = 0.5%–1.3%), forming shrinkage OM pores with a low contribution to microporosity.³⁸

Figure 13.

Correlation analysis of specific surface area, pore volume, porosity, TOC, and clay minerals of micropores based on LTNA data. (a) TOC versus specific surface area showing no correlation. (b) TOC versus pore volume showing no correlation. (c) Clay mineral content versus specific surface area showing a positive correlation. (d) Specific surface area versus LTNA porosity showing a positive correlation.

The specific surface area of samples of different shale types was linearly correlated with the clay mineral content (Figure 13c), with a higher clay mineral content corresponding to a larger specific surface area. Additionally, a good linear correlation was observed between the specific surface area and LTNA porosity (Figure 13d), indicating that the development of micropores in shale reservoirs is primarily controlled by the clay mineral content,³⁹ with intraparticle pores in clay minerals being the main micropore type.

SEM images revealed that the layered structure of clay minerals can create adsorption sites between clay crystals. In areas where clay minerals were distributed in patches, numerous pores were developed, primarily at the nanoscale, existing between clay minerals in an adsorption state. However, owing to the long-term compaction experienced by clay minerals during diagenesis, there was poor connectivity between these pores, which may impact permeability.

The mesopores and macropores of the studied shale reservoirs mainly comprise dissolution pores, intergranular pores, and microfractures. The relationships between NMR porosity and TOC content, as well as different mineral components, show that as TOC content increases, porosity tends to increase (Figure 14a), and brittle minerals show significant positive correlations with total porosity, mesopore porosity, and macropore porosity (Figure 14b). A higher shale OM content means that it is easier for organic acids to be generated during hydrocarbon generation,⁴⁰ while quartz and feldspar are prone to dissolution in acidic environments, forming secondary corrosion pores. In addition, owing to the generally large grain size and better compressive strength of brittle minerals, residual intergranular pores can be fully preserved under compaction, providing channels for acidic fluids to enter and dissolution products to be discharged.

Figure 14.

Correlation analysis of NMR porosity with TOC and different mineral components (n = 26). (a) TOC versus NMR porosity showing a positive correlation. (b) Brittle mineral content versus NMR porosity showing a positive correlation. (c) Dolomite content versus NMR porosity showing a positive correlation. (d) Calcite content versus NMR porosity showing a negative correlation.

In addition to brittle minerals, carbonate minerals also account for a large proportion of the mineral composition of the studied shale samples. Dolomite crystals have a rhombic morphology, and intergranular pores easily develop between the crystals (Figure 6g). Moreover, during the process of dolomitization, volume shrinkage caused by ion exchange in the lattice can also form a reservoir space.⁴¹ Microfractures are generally formed owing to the contrasting brittleness of different lithologies, especially in areas of concentrated tectonic stress. Previous studies have shown that microfracture development is highly influenced by dolomite content, with a higher dolomite content leading to increased microfracture development. Therefore, there is a good positive correlation between dolomite content and NMR porosity (Figure 14c). During diagenesis, the strength of cementation will lead to differences in reservoir properties. As cement content increases, the cementation method gradually changes from contact cementation to substrate pore cementation or continuous crystal cementation, causing damage to the original intergranular pores. The cement in the research area is mainly composed of calcite,⁴² with a low content of anhydrite that has negligible impact. Calcite cement is mainly found as mosaic shapes between grains or as metasomatic inclusions within feldspar particles, reducing reservoir porosity.^43,44 An increasing calcite content equates to a decreasing trend in porosity (Figure 14d).

4.3.2. Shale Reservoir Classification

Combining the mineral composition, pore distribution, and quantitative characterization of different types of samples, shale reservoirs in the Western Qaidam Depression can be divided into three categories: type I reservoirs composed of lime shale and argillaceous shale; type II reservoirs composed of limestone and argillaceous limestone; and type III reservoirs composed of mudstone.

In type I reservoirs, the content of brittle minerals, such as quartz and feldspar, as well as clay minerals, is relatively high. Therefore, brittle mineral dissolution pores and intraparticle pores in clay minerals are the main pore types in this type of reservoir; in some samples, the content of dolomite is relatively high, and intergranular pores and microfractures are also relatively well developed. Overall, type I reservoir pores mainly comprise mesopores, accounting for 24–83% of the total porosity, followed by macropores, and a relatively low proportion of micropores. The proportion of micropores in argillaceous shale is higher than that in lime shale, while the proportion of macropores is lower than that in lime shale. The porosity content of type I reservoir samples is mainly controlled by the quartz and feldspar mineral content, and dissolution pores are the main contributors to porosity. Owing to the small size (<100 nm) of intraparticle pores in clay minerals, their contribution to porosity is relatively low, so the argillaceous shale reservoir is of a slightly poorer quality than the lime shale reservoir.

The mineral composition of type II reservoir samples mainly comprise carbonate minerals; porosity is mainly dominated by intergranular pores and microfractures controlled by dolomite content, followed by brittle mineral dissolution pores, with a lower level of development of intraparticle pores in clay minerals. The proportion of meso-porosity in this type of reservoir is lower than that in type I reservoirs, ranging from 34 to 64%, while the macro-porosity is higher, ranging from 23 to 55%; the microporosity is very low. However, owing to the high calcite content, which has a negative impact on pore development, the overall porosity of this type of reservoir is lower than that of type I reservoirs.

In type III reservoir samples, the content of clay minerals is relatively high, with the main pore type being intraparticle pores in clay minerals. Meanwhile, dissolution pores and intergranular pores are also well developed, and microfractures are relatively poorly developed. The proportions of meso- and macro-porosity are lower than those in the other types of reservoirs. The proportion of microporosity is relatively high, being 15–50%. The clay mineral content is the main influencing factor of porosity in this type of reservoir. Owing to the small pore size and poor connectivity, the overall porosity is lower than that in the other reservoir types, resulting in poorer reservoir quality.

5. Conclusions

In the shale reservoirs in the Upper Xiaganchaigou, Shangganchaigou, and Xiayoushashan Formations of the Western Qaidam Depression, a total of five sample types were identified: lime shale, argillaceous shale, limestone, argillaceous limestone, and mudstone. Among them, lime shale and argillaceous shale possessed the highest OM abundance. Inorganic pores and fractures dominate the reservoir space, and content of OM pores is low. According to calculation results of fractal dimensions based on NMR data, the shale pores were classified into three categories: micropores (<100 nm), mesopores (100–1000 nm), and macropores (>1000 nm), with mesopores being the main contributors to porosity.

The micropores are dominated by the intraparticle pores in clay minerals, and the development is controlled by the content of clay minerals. Dissolution pores, intergranular pores, and microfractures constitute mesopores and macropores, with their development controlled by the content of brittle minerals and carbonate minerals. Quartz and feldspar can be dissolved in an acidic environment to form secondary dissolution pores. The rhombic morphology of dolomite favors the formation of intergranular pores, and the high content of dolomite facilitates the development of microfractures. Calcite is filled between the particles in the form of cement, which destroys the original intergranular pores.

On the basis of mineral composition and pore distribution characteristics, the shale reservoirs in the study area were categorized into three types. Type I reservoirs are composed of lime shale and argillaceous shale, the pores are mainly dissolution pores in brittle minerals and intraparticle pores in clay minerals, the dissolution pores are the main contributors to porosity, and the porosity is mainly controlled by quartz and feldspar mineral content. Type II reservoirs are composed of limestone and argillaceous limestone, which mainly develop intergranular pores and microfractures. The porosity content is mainly controlled by dolomite mineral content. However, due to the high content of calcite, which has an adverse effect on pore development, the overall porosity is lower than that of type I reservoirs. Type III reservoirs, comprising mudstone, show the lowest porosity, primarily influenced by the clay mineral content. Among the three types of reservoirs, type I is superior to type II, which, in turn, is superior to type III.

The authors declare no competing financial interest.