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Accumulation mechanism of multi-type unconventional oil and gas reservoirs in Northern China: Taking Hari Sag of the Yin’e Basin as an example

  • Chao Ding , Zhijun Chen EMAIL logo , Lan Guo , Shun Guo , Xunqing Su and Xiaoyin Bai
Published/Copyright: June 11, 2024
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Open Geosciences
From the journal Open Geosciences Volume 16 Issue 1

Abstract

Many multi-types of unconventional oil and gas reservoirs have been found in some faulted basins in northern China, showing good exploration potential. However, the hydrocarbon accumulation mechanism in these areas is still unclear, which limits the understanding of the distribution of oil and gas. In this study, we took Hari Sag in Yin’e Basin as an example, conducted a systematic analysis on various types unconventional oil and gas reservoirs, and revealed its characteristics and accumulation mechanisms. The study showed that there were many types of unconventional oil and gas reservoirs in Hari Sag, such as biogas reservoirs, shale gas reservoirs, shale oil reservoirs, tight sandstone oil reservoirs, tight sandstone gas reservoirs, and volcanic gas reservoirs. These reservoirs generally had characteristics of “near/within source rocks accumulation,” “coexistence of oil reservoirs and gas reservoirs,” “shallow oil and deep gas,” and so on. Research on the mechanism of hydrocarbon accumulation showed that: the lack of effective hydrocarbon migration pathway was the main reason for “near/within source rocks accumulation” of oil and gas reservoirs; the differences in the thermal evolution degree of the main source rocks at different structural positions in the sag made the distribution characteristics of hydrocarbon as “coexistence of oil reservoirs and gas reservoirs” and “shallow oil and deep gas”; and the joint development of multi-type effective unconventional reservoirs created the situation of “coexistence of multi-type unconventional oil and gas reservoirs.” It is predicted that six types of unconventional oil and gas reservoirs have a cumulative area of 381 km2, indicating that the Hari Sag has great potential for unconventional oil and gas exploration. The research results can not only guide the unconventional oil and gas exploration in Hari Sag but also provide a theoretical basis for exploration research in similar blocks.

Keywords: characteristics of unconventional oil and gas reservoirs; hydrocarbon accumulation mechanism; small-scale fault basin; Yin’e Basin

1 Introduction

As the field of oil and gas exploration and development has seen advancements in theory and technology, unconventional oil and gas exploration has been paid more and more attention, accounting for an increasing proportion of total oil and gas production [1,2,3]. Taking 2022 as an example, global oil production amounted to 43.5 × 108 t, where unconventional oil represented roughly 15% [4,5]; the global gas production was 4.25 × 1012 m3, of which unconventional hydrocarbon gas accounts for about 25% [4,5]. The Mesozoic faulted basins in northern China predominantly feature numerous small- and medium-scale sags, such as the Erlian Basin, which comprises 50 sags, and the Yin’e Basin, which comprises 31 sags [6,7]. These sags are characterized by a similar sedimentary and tectonic evolutionary history, coupled with comparable hydrocarbon generation, migration, and accumulation traits [6,8]. Additionally, many of these sags have been successful in discovering commercial oil and gas reservoirs, contributing large-scale oil and gas reserves, and have thus become key regions for oil and gas exploration and development [9,10]. Several types of unconventional oil and gas reservoirs have been found in some sags, highlighting the promising potential for unconventional oil and gas exploration in these regions [11,12]. However, the geological conditions of oil and gas in these sags are complex, especially the lack of understanding of the symbiotic characteristics of multi-type unconventional oil and gas reservoirs and their accumulation mechanism, which limits the understanding of oil and gas distribution.

The Hari Sag of Yin’e Basin is a typical representative of these sags. Well HC1 in the middle of the sag obtained a high-yield shale gas flow with a daily output of 9 × 104 m3 in 2015, realizing a major breakthrough in the exploration process of Yin’e Basin [13,14]. Subsequent exploration has successively discovered shale oil reservoirs, tight oil reservoirs, volcanic gas reservoirs, and other types. The diversity of unconventional oil and gas reservoir types within the Hari Sag is remarkable for a small-scale sag, reinforcing the notion that the area holds significant promise for unconventional oil and gas exploration [13,15]. However, the geological conditions of oil and gas in Hari Sag are extremely complex, and the hydrocarbon distribution pattern remains obscure, significantly impeding the progress of oil and gas exploration in the region. The main reason for the lack of understanding of the hydrocarbon distribution patter is that the symbiotic characteristics of multi-type unconventional reservoirs are unclear, and the mechanism of hydrocarbon accumulation is ambiguous; these questions cannot be scientifically answered, and the law of oil and gas distribution will not be scientifically predicted.

Based on the analysis of various types of unconventional oil and gas reservoirs, this article clarifies the characteristics of multi-type unconventional oil and gas reservoirs, discusses their formation mechanism, and predicts the distribution of unconventional oil and gas. The aim is to support further research into the distribution of oil and gas within Hari Sag and to provide a theoretical basis for the exploration of similar geological blocks.

2 Geological setting

The Mesozoic fault basin in northern China is located in the middle-east section of the Central Asian Orogenic Belt (Figure 1a), represented by the Yin’e Basin and the Erlian Basin. These basins share a comparable history of sedimentary and tectonic evolution, with various sags within the same basin exhibiting analogous characteristics in hydrocarbon generation, expulsion, and accumulation [16,17,18,19]. The regional structure of Yin’e Basin is located at the junction of the four plates of Tarim, Kazakhstan-Junggar, Siberia, and North China. It is a Mesozoic-Cenozoic sedimentary basin developed on the basis of the Precambrian crystalline block and Paleozoic fold basement [21,22,23,24]. Since the Late Paleozoic, the basin has experienced four tectonic evolution stages: Carboniferous-Permian rift, Late Permian-Triassic squeeze uplift, Jurassic-Early Cretaceous fault depression, and Late Cretaceous-Tertiary depression. The current structure can be divided into 12 secondary tectonic units of “seven depressions and five uplifts” [21,22,23,24] (Figure 1b). Hari Sag is located in the north of Yin’e Basin, a sub-tectonic unit in the west of Suhongtu Depression, with the Babula Sea uplift in the east, Zongnai Mountain uplift in the south, Hongjier Mountain in the west, and Mongolia in the north. The sag presents a dustpan-like structure with an area of about 1,000 km2, and it can be divided into three sub-tectonic units: the western slope belt, the central sag belt, and the eastern steep slope belt [25] (Figure 1c and d). Drilling results indicate that the sedimentary layers within Hari Sag span from the Permian to the Cenozoic, with the most significant Cretaceous layers further subdivided into the Lower Cretaceous (K1) and Upper Cretaceous (K2) sequences [26]. The Lower Cretaceous can be divided into the first member of Bayingobi Formation (K1b1), the second member of Bayingobi Formation (K1b2), and the third member of Bayingobi Formation (K1b3), Suhongtu Formation (K1s) and Yingen Formation (K1y) from bottom to top, while there is only Wulansuhai Formation (K2w) in the Upper Cretaceous (Figure 1e). The Cretaceous period predominantly featured the development of lake, fan delta, nearshore subaqueous fan, and volcanic sedimentary systems, which collectively created favorable conditions for hydrocarbon accumulation [15,25] (Figure 1e).

Figure 1 Regional location map (a), basin structural location map (b), structural unit division (c), seismic profile (d), and stratigraphic column (e) of the Hari Sag, based on references [19,24].
Figure 1

Regional location map (a), basin structural location map (b), structural unit division (c), seismic profile (d), and stratigraphic column (e) of the Hari Sag, based on references [19,24].

3 Samples and methods

To study the characteristics of unconventional oil and gas accumulation mechanism in this area, samples such as drilling cores and reservoir fluids (crude oil and natural gas) were collected, and the following test analysis was carried out. The test analysis was completed by the laboratory of Yangtze University.

3.1 Source rock geochemical testing

A total of 69 source rock samples were collected, including mudstone, dolomitic mudstone, lime mudstone, tuffaceous mudstone, and dolomitic shale. Among them, the number of K1b1 samples is 17, the number of K1b2 samples is 21, and the number of K1y samples is 31. The organic geochemical testing of the samples was carried out systematically. The test items included total organic carbon (TOC), rock-eval pyrolysis, chloroform bitumen “A,” carbon-hydrogen-oxygen elements of kerogen, vitrinite reflectance (R o), carbon isotope, saturated hydrocarbon gas chromatography, biomarker chromatography-mass spectrometry, etc.

3.2 Reservoir related testing

To elucidate the reservoir characteristics, a comprehensive suite of 35 samples was carefully selected from the unconventional reservoirs, encompassing lithologies such as dolomitic mudstone, mud shale, and volcanic rock. These samples underwent a rigorous program of testing and analysis, including thin-section examination, conventional physical property assessment, X-ray diffraction, cathodoluminescence imaging, scanning electron microscopy, and isothermal adsorption testing.

3.3 Oil and gas-related testing

A total of 12 natural gas samples were collected for component analysis and carbon isotope determination. A total of two crude oil samples were tested and analyzed by physical property, group composition, saturated hydrocarbon gas chromatography, biomarker chromatography–mass spectrometry, etc.

4 Unconventional oil and gas geological conditions

4.1 Characteristics of source rock

The Lower Cretaceous in Hari Sag is dominated by deep-water fine-grained sediments, and the semi-deep and deep lake facies source rocks are relatively developed. K1b1, K1b2, K1b3, K1s, and K1y have source rocks [27,28,29,30,31]. The previous hydrocarbon-source rock correlation studies show that K1b1, K1b2, and K1y source rocks are the main source rocks [13,27]. The lithology of K1b1 source rock is mainly dark gray and gray mudstone, tuffaceous mudstone, and silty mudstone. The effective source rock thickness is 5–151 m (avg. 63 m), TOC is avg. 0.89%, S 1 + S 2 (hydrocarbon production potential) is avg. 4.63 mg/g, chloroform asphalt “A” is avg. 0.073%, kerogen δ 13C is −29.1 to −24.5‰, R o is 0.60–2.01% (Table 1), and the source rocks are moderate–good in organic matter abundance, type Ⅱ1-type Ⅱ2, and mature–high mature hydrocarbon source rocks [27].

Table 1

Organic geochemical characteristics of main source rocks of the Hari Sag

Formation Thickness (m) TOC (%) (S 1 + S 2) (mg g−1) Chloroform bitumen “A” (%) Kerogen δ 13C (‰) I H (mg g–1) H/C R o (%) T max (°C)
K1b1 5–151 0.14–2.31 0.09–44.67 0.003–0.176 −29.1 to −24.5 51–1,045 0.51–1.02 0.60–2.01 379–537
63 0.89(17) 4.63(16) 0.073(10) –27.2(9) 279(10) 0.82(8) 1.10(14) 451(16)
K1b2 23–222 0.08–5.15 0.05–77.87 0.001–1.218 30.3 to −23.8 8–1,017 0.62–1.83 0.60–2.17 338–537
109 1.18(21) 7.85(20) 0.182(18) −26.7(16) 219(17) 0.96(12) 1.37(20) 468(20)
K1y 130–583 0.46–8.56 0.51–62.71 0.027–0.816 −29.9 to −23.5 21–1,020 0.17–2.35 0.41–1.31 426–480
472 3.98(31) 22.24(30) 0.233(29) −7.4(27) 537(27) 1.18(26) 0.68(31) 442(30)

TOC is total organic carbon; S 1 is the total amount of residual hydrocarbons in source rock; S 2 is the total amount of pyrolysis hydrocarbons in kerogen; S 1 + S 2 is hydrocarbon production potential; I H is hydrogen index; H/C is H/C of kerogen; R o is vitrinite reflectance; T max is the highest pyrolysis peak temper; and “5–151,63” for “min–max, average.”.

The K1b2 source rocks are mainly composed of dark gray containing lime mudstone and lime mudstone. The effective thickness of these source rocks ranges from 23 to 222 m, with an average of 109 m. The TOC content averages 1.18%, and the S 1 + S 2 value is approximately 7.85 mg/g. The chloroform asphalt “A” content averages 0.182%, and the δ 13C value of the kerogen ranges from −30.3 to −23.8‰. The R o ranges from 0.60 to 2.17% (Table 1). These source rocks are characterized by good to excellent organic matter abundance, are classified as type II1–II2, and represent mature to highly mature source rocks [27]. The K1y hydrocarbon source rocks are primarily composed of mud crystalline dolomite and dolomitic mudstone. The effective thickness of these source rocks ranges from 130 to 583 m, with an average of 472 m. The TOC content averages 3.98%, and the S 1 + S 2 value is approximately 22.24 mg/g. The chloroform asphalt “A” content averages 0.233%, and the δ 13C value of the kerogen ranges from −29.9 to −23.5‰. The R o ranges from 0.44 to 1.31% (Table 1). These source rocks are distinguished by extremely high organic matter abundance, are classified as type I–II1, and exhibit low maturity.

4.2 Reservoir and caprock characteristics

There are abundant types of unconventional reservoirs in the study area, including tight sandstone reservoirs deposited by nearshore subaqueous fan delta, fan delta, and lacustrine facies, shale (including calcareous mudstone, dolomitic mudstone, etc.) reservoirs, and volcanic rock reservoirs [14,15,32,33]. In terms of the caprock, the Mesozoic is dominated by deep-water fine-grained sediments, mudstone is relatively developed, and the caprock conditions are good. The main development is the purple-red thick-layer mudstone of the flood plain facies of the Wulansuhai Formation, the thick-layer mudstone of the lower part of the Suhongtu Formation, and the thick-layer dark mudstone of the second member of Bayingobi Formation [13,15]. The presence of favorable source rock characteristics, a variety of unconventional reservoir types, and enhanced seal rock conditions collectively contribute to the propitious accumulation of unconventional oil and gas.

5 Types of unconventional oil and gas reservoirs and their symbiotic characteristics

5.1 Unconventional reservoir types

The types of unconventional oil and gas reservoirs that have been discovered in Hari Sag include biogas reservoirs, shale gas reservoirs, shale oil reservoirs, tight sandstone oil reservoirs, tight sandstone gas reservoirs, volcanic gas reservoirs, etc. (Table 2); the diversity of unconventional oil and gas reservoir types is rare for a basin and unique for a small–medium-sized scale sag.

Table 2

Types and characteristics of unconventional oil and gas reservoirs in Hari Sag

Reservoirs types Reservoir lithology Formation Wells of production Wells of oil and gas shows Fluid characteristics Source rocks Accumulation characteristics
Biogas reservoirs Dolomitic mudstone, mud crystalline dolomite, etc. K1y HC1 HC1, H1, H3, H4, H5, H7 and H8 Dry gas From K1y Within source rocks
Shale gas reservoirs Lime mudstone, containing lime mudstone, shale, etc. Mainly K1b2, followed by K1b1 HC1 and H6 H1, HC1, H5 and H6 Humid gas From K1b1 and K1b2 Within source rocks
Shale oil reservoirs Lime mudstone, containing lime mudstone, shale, etc. K1b2 H2 H2, H3, H7 and H8 Medium crude oil From K1b2 Within source rocks
Tight sandstone oil reservoirs Siltstone, fine sandstone, etc. K1s, K1b3, K1b2 and K1b1 H3 and H4 H1, HC1, H2, H3, H4, H5, H7 and H8 Medium crude oil From K1b1 and K1b2 Near source rocks
Tight sandstone gas reservoirs Siltstone, fine sandstone, etc. K1b1 H6 H6 Humid gas From K1b1 Near source rocks
Volcanic gas reservoirs Andesite, dingite, basalt, etc. K1b1 H5 H5 Humid gas From K1b2 Near source rocks

5.1.1 Biogas reservoirs

This type of gas reservoir is developed in the Yingen Formation, the lithology is mainly dolomitic mudstone, followed by mud crystalline dolomite. The dolomitic mudstone is grayish black, mainly composed of dolomite and clay minerals, with tight lithology, and it is also marked by the development of dissolution cavities (Figure 2a). The mud crystalline dolomite bedding is developed and composed of multiple sets of layers, which mainly include organic-rich layers, mud crystalline dolomite-rich layers, and clay-rich layers, forming the unique “ternary layer” structure of lacustrine carbonate source rocks [34,35] (Figure 2b). Both the dolomitic mudstone and the mud crystalline dolomite possess an extremely high abundance of organic matter, making them suitable for high-quality hydrocarbon source rocks. Moreover, they exhibit well-developed dissolution pores and fractures, endowing them with certain oil and gas reservoir properties (Figure 2a–c).

Figure 2 Core photos of unconventional oil and gas reservoirs in Hari Sag. (a) well HC1, K1y, 437.14 m, gray gas-bearing dolomitic mudstone, with developed dissolution pores, with gas logging abnormality, with the highest total hydrocarbon value of 0.38%; (b) well HC1, K1y, 750.44 m, dark gray gas-bearing mud crystalline dolomite, with well-developed layers, with gas logging abnormality, with the highest total hydrocarbon value of 2.70%; (c) well HC1, K1y, 439.68 m, dark gray gas-bearing dolomitic mudstone, with developed fractures, with gas logging abnormality, with the highest total hydrocarbon value of 0.92%; (d) well HC1, K1b2, 2913.07 m, dark gray gas-bearing lime mudstone, developed cracks, with gas logging abnormality, with the highest total hydrocarbon value of 1.83%; (e) well H6, K1b1, 3773.46 m, dark gray gas-bearing mudstone, with developed fractures, with gas logging abnormality, total hydrocarbon value is 0.57–59.50%; (f) well H2, K1b2, 1061.14 m, gray oil-bearing lime mudstone, with crude oil seeping out from the cracks, and industrial oil flow was obtained from oil testing; (g) well H3, K1b1, 1868.83 m, oil-bearing siltstone, the obvious crude oil seepage, oil test to obtain industrial oil flow; (h) well H4, K1s, 1267.16 m, gray oil-stained dolomitic siltstone, crude oil extravasation; (i) well H6, K1b1, 3433.20 m, gray gas-bearing fine sandstone, with gas logging abnormality, total hydrocarbon value of gas logging is 0.61–11.63%, low-yield gas flow is obtained; (j) well H5, K1b1, 3178.87 m, gray gas-bearing andesite, with irregular fractures developed in a staggered manner, filled with lime, with a filling degree of about 10–50%, with gas logging abnormality, with the highest total hydrocarbon value of 4.84%; and (k) well H5, K1b1, 3175.69 m, almond-shaped gas-bearing basaltic andesite, with developed pores, abnormal gas logging, with the highest total hydrocarbon value of 1.50%.
Figure 2

Core photos of unconventional oil and gas reservoirs in Hari Sag. (a) well HC1, K1y, 437.14 m, gray gas-bearing dolomitic mudstone, with developed dissolution pores, with gas logging abnormality, with the highest total hydrocarbon value of 0.38%; (b) well HC1, K1y, 750.44 m, dark gray gas-bearing mud crystalline dolomite, with well-developed layers, with gas logging abnormality, with the highest total hydrocarbon value of 2.70%; (c) well HC1, K1y, 439.68 m, dark gray gas-bearing dolomitic mudstone, with developed fractures, with gas logging abnormality, with the highest total hydrocarbon value of 0.92%; (d) well HC1, K1b2, 2913.07 m, dark gray gas-bearing lime mudstone, developed cracks, with gas logging abnormality, with the highest total hydrocarbon value of 1.83%; (e) well H6, K1b1, 3773.46 m, dark gray gas-bearing mudstone, with developed fractures, with gas logging abnormality, total hydrocarbon value is 0.57–59.50%; (f) well H2, K1b2, 1061.14 m, gray oil-bearing lime mudstone, with crude oil seeping out from the cracks, and industrial oil flow was obtained from oil testing; (g) well H3, K1b1, 1868.83 m, oil-bearing siltstone, the obvious crude oil seepage, oil test to obtain industrial oil flow; (h) well H4, K1s, 1267.16 m, gray oil-stained dolomitic siltstone, crude oil extravasation; (i) well H6, K1b1, 3433.20 m, gray gas-bearing fine sandstone, with gas logging abnormality, total hydrocarbon value of gas logging is 0.61–11.63%, low-yield gas flow is obtained; (j) well H5, K1b1, 3178.87 m, gray gas-bearing andesite, with irregular fractures developed in a staggered manner, filled with lime, with a filling degree of about 10–50%, with gas logging abnormality, with the highest total hydrocarbon value of 4.84%; and (k) well H5, K1b1, 3175.69 m, almond-shaped gas-bearing basaltic andesite, with developed pores, abnormal gas logging, with the highest total hydrocarbon value of 1.50%.

This kind of gas reservoir has a large distribution area in Hari Sag, and wells HC1, H1, H3, H4, H5, H7, and H8 are all distributed. The thickness of the gas reservoir is 125–482 m, and the highest value of gas logging total hydrocarbon is 13.0%. The well HC1 has the best effect for gas testing, for the gas produced after gas testing was ignitable, but the flame was discontinuous and the degree of hydrocarbon gas production was low, indicating that the gas content of this type of gas reservoir was generally low. The methane content of the gas is extremely high, and the drying coefficient is 97–98% (avg. 97%), so the gas is dry gas. The non-hydrocarbon components are mainly H2 (0.00–4.04%, and avg. 0.10%) and CO2 (0.00–5.10%, and avg. 0.22%). The gas reflects the typical characteristics of “high methane content and low gas content” of biodegradable gas. The gas formed by the fermentation and synthesis of bacteria (microorganisms) in the low temperature and reducing environment of low maturity hydrocarbon source rocks with extremely high organic matter abundance in the Yingen Formation. This gas reservoir exhibits the characteristic of “within source accumulation” [36,37,38].

5.1.2 Shale gas reservoir

This type of gas reservoir is mainly formed in K1b2, followed by K1b1, its lithology is mainly lime mudstone, containing lime mudstone and shale (Figure 2d and e). Reservoir characteristics of well HC1 show that the mud content is 70–85%, the mud is mixed with microcrystalline carbonate particles, a small number of micro-cracks are found, and the mud and carbonate are mixed. The content of medium-fine sandstone fragments is 15–30%, and the fragments are mainly microcrystalline calcite, quartz, and feldspar. The porosity of the reservoir is 0.1–2.6% (avg. 0.9%). The permeability is 0.004 × 10−3–0.044 × 10−3 μm2 (avg. 0.013 × 10−3 μm2). The SEM analysis shows that the space of the reservoir is dominated by microfractures, dissolution pores, intergranular pores, intraganular pores, and other micropores, with occasional organic pores (Figure 3a–c). The results of isothermal adsorption testing and drilling field desorption testing show that the total gas content of the lime mudstone is 1.47–1.51 m3/t (avg. 1.29 m3/t), reflecting the good gas content.

Figure 3 Micropore characteristics of lime mudstone and volcanic reservoir of well HC1. (a) well HC1, K1b2, 2913.28 m, dark gray gas-bearing lime mudstone, fracture developed, casting thin section; (b) well HC1, K1b2, 2912.58 m, dark gray lime mudstone, development of dissolution pores, scanning electron microscope (SEM) (c) well HC1, K1b1, 3077.48 m, dark gray gas-bearing lime mudstone, with developed intergranular pores, some of which are filled with filamentous illite and mixed-layer aggregates of illite, SEM; (d) well H2, K1b2, 1065.37 m, dark gray grayish lime mudstone, dissolution cracks developed, casting thin section; (e) well H2, K1b2, 1063.67 m, dark gray lime mudstone, disorderly accumulation of debris particles, development of a large number of inorganic pores, SEM; (f) well H2, K1b2, 1063.67 m, dark gray lime mudstone, inorganic intergranular pores and intragranular pores are developed, the organic matter pores are also developed, SEM; (g) well H5, K1b1, 3175.80 m, gray gas-bearing basaltic andesite, filamentous clay mineral aggregate in scale-like structure, with slightly dissolved pores, SEM; (h) well H5, K1b1, 3253.00 m, gray gas-bearing basalt andesite, filamentous clay mineral aggregates filled between detrital particles and intergranular pores, SEM; and (i) well H5, K1b1, 3255.47 m, gray gas-bearing basaltic andesite, filamentous clay minerals, siliceous and dolomite crystals filled between plagioclase crystals, with intergranular dissolution micropores, SEM.
Figure 3

Micropore characteristics of lime mudstone and volcanic reservoir of well HC1. (a) well HC1, K1b2, 2913.28 m, dark gray gas-bearing lime mudstone, fracture developed, casting thin section; (b) well HC1, K1b2, 2912.58 m, dark gray lime mudstone, development of dissolution pores, scanning electron microscope (SEM) (c) well HC1, K1b1, 3077.48 m, dark gray gas-bearing lime mudstone, with developed intergranular pores, some of which are filled with filamentous illite and mixed-layer aggregates of illite, SEM; (d) well H2, K1b2, 1065.37 m, dark gray grayish lime mudstone, dissolution cracks developed, casting thin section; (e) well H2, K1b2, 1063.67 m, dark gray lime mudstone, disorderly accumulation of debris particles, development of a large number of inorganic pores, SEM; (f) well H2, K1b2, 1063.67 m, dark gray lime mudstone, inorganic intergranular pores and intragranular pores are developed, the organic matter pores are also developed, SEM; (g) well H5, K1b1, 3175.80 m, gray gas-bearing basaltic andesite, filamentous clay mineral aggregate in scale-like structure, with slightly dissolved pores, SEM; (h) well H5, K1b1, 3253.00 m, gray gas-bearing basalt andesite, filamentous clay mineral aggregates filled between detrital particles and intergranular pores, SEM; and (i) well H5, K1b1, 3255.47 m, gray gas-bearing basaltic andesite, filamentous clay minerals, siliceous and dolomite crystals filled between plagioclase crystals, with intergranular dissolution micropores, SEM.

This type of gas reservoir is mainly distributed in the central sag belt of Hari Sag. Wells H1, HC1, H5, and H6 have all been drilled. Only HC1 and H6 have been tested for this type of reservoir, well HC1 has obtained a high-yield gas flow with a daily output of 9 × 104 m3, and well H6 has obtained a low-yield gas flow. The hydrocarbon gas content is 92.38–98.43%, in which the methane content is 74.44–84.16%, and the drying coefficient is 0.81–0.86, which belongs to humid gas. The non-hydrocarbon gas is mainly N2 and CO2, the N2 content is between 1.57 and 6.18%, the CO2 content is between 0 and 0.82%, and the gas reservoir is low N2 and CO2, where it is slightly-medium sulfur-containing. The carbon isotope of methane in gas is −38.73 to −38.76‰ (avg. −38.75‰), the ethane is −26.90 to −27.12‰ (avg. −27.12‰), and the propane is −25.09 to −35.92‰ (avg. −27.59‰). According to the previous empirical formula [39], the equivalent R o of gas is calculated to be 1.55−1.65% (avg. 1.60%), and the gas belongs to high maturity gas. Based on the “Bernard” classification [40,41], the gas is thermogenic gas (Figure 4a). According to the distribution characteristics of δ 13C1, δ 13C2, and δ 13C3 (Figure 4b), referring to the relevant identification chart, the genetic type of gas tends to be oil-type gas [42,43]. The results of the gas source comparison study show that the gas in the K1b2 lime mudstone gas reservoir of well HC1 is derived from the K1b2 source rock [27], confirming that this type of gas reservoir exhibits the characteristics of “within source rocks accumulation”. Meanwhile, this type of gas reservoir is also developed in K1b1 in local areas (such as well H6 block), while the gas-source rock correlation studies cannot be carried out due to lacking of data. However, according to the characteristics of “within source rocks accumulation,” it is inferred that the gas of K1b1 lime mudstone gas reservoir comes from K1b1 source rock.

Figure 4 Identification diagram of shale gas in Hari Sag. (a) “Bernard” classification chart, classification method according to [40,41]; (b) δ 13C1 – δ 13C2 – δ 13C3 classification, classification method according to [42,43].
Figure 4

Identification diagram of shale gas in Hari Sag. (a) “Bernard” classification chart, classification method according to [40,41]; (b) δ 13C1 – δ 13C2 – δ 13C3 classification, classification method according to [42,43].

5.1.3 Shale oil reservoir

This kind of reservoir is distributed in K1b2 in the western slope zone. The reservoir type is the same as shale gas reservoir, and the lithology is mainly lime mudstone, containing lime mudstone and shale etc. (Figure 2f). However, compared with shale gas reservoir, the fractures and dissolution pores of shale reservoirs are more developed, the reservoir space is more diverse. Within the core samples, the fractures are particularly well-developed, and the crude oil is infiltrated along the fracture (Figure 2f). Dissolution cracks are seen in the casting thin section, which are branched and have a width of 0.01–0.10 mm (Figure 3d). The SEM observation shows that inorganic pores in microscopic pores are relatively developed, mainly intergranular pores, grain margin cracks, and micro-cracks, local dissolved pores are visible, and the organic pores are also relatively developed (Figure 3e–f). The porosity of the reservoir is 4.5–11.5% (avg. 9.3%), the permeability is 0.007 × 10−3–0.860 × 10−3 μm2 (avg. 0.039 × 10−3 μm2), which is significantly better than that of the shale gas reservoir.

The discovery well of this kind of reservoir is well H2, and the industrial oil flow is obtained by oil testing. Drilling revealed that wells H3, H7, and H8 also developed this type of reservoir to varying degrees. The oil has a density of 0.87 g/cm3, a viscosity of 28.94 mPa s, a freezing point of 31℃, and a wax content of 18.1%. The oil is a medium crude oil with “medium density, medium viscosity, high wax content, and no sulfur”. The oil family is mainly composed of saturated hydrocarbons, with the characteristics of “high saturated hydrocarbons, middle aromatics, low non-hydrocarbon, and asphaltene content. Based on the differences in biomarker compounds of K1b, K1s, and K1y source rocks, the relevant oil–source rock correlation study results show that the oil of K1b comes from K1b source rock [13]. However, in the current stage of fine exploration and research, it is necessary to divide K1b into three members (K1b1, K1b2, and K1b3) to carry out detailed oil–source rock correlation research. Due to the similarity of sedimentary environment, it is difficult to distinguish K1b1, K1b2, and K1b3 hydrocarbon source rocks by using biomarker compound data such as n-alkanes, steranes, and terpenes, but the aromatic hydrocarbon data have achieved good application results in the detailed oil-source correlation in the Bayingobi Formation, reflecting the superiority of aromatic hydrocarbons in related research [44,45,46]. The comparative analysis reveals that the crude oil within the K1b2 lime mudstone reservoir of well H2 shares distinct similarities in aromatic compound content with the K1b2 source rock (Figure 5). This suggests that the crude oil in the K1b2 lime mudstone reservoir originates from the K1b2 source rock, and the reservoir exhibits the characteristic of “within source rock accumulation.”

Figure 5 The component of aromatic hydrocarbon of source rocks, crude oil, and oil sand of K1b in Hari Sag.
Figure 5

The component of aromatic hydrocarbon of source rocks, crude oil, and oil sand of K1b in Hari Sag.

5.1.4 Tight sandstone oil reservoir

The tight sandstone oil reservoirs are found in K1s, K1b3, K1b2, K1b1, and other intervals and are distributed in different structural parts such as the eastern steep slope belt and the western slope belt. The lithology of the reservoir includes siltstone and fine sandstone, and the core of the reservoir is more likely to have crude oil extravasation, showing good oil content (Figure 2g–h). The reservoir in well H3 K1b1 has been systematically tested and analyzed, its lithology is mainly fine sandstone and siltstone, while other lithology is muddy sandstone and tuffaceous sandstone. Microscopic observation shows that the compositional maturity and structural maturity of the sandstone are low, and the mineral composition shows that the sandstone types are mainly feldspar lithic sandstone, lithic sandstone, and mixed sandstone. The sandstone clastic grain composition is mainly quartz, feldspar, and rock debris (quartz avg. 30.29%, feldspar avg. 9.0%, rock debris avg. 43.21%). The average content of interstitial matter is 5.12%, mainly including mica, argillaceous, iron calcite, kaolinite, etc. The reservoir porosity is 0.10–8.79% (avg. 4.6%), the permeability is 0.034 × 10−3–0.504 × 10−3 μm2(avg. 0.118 × 10−3 μm2), belonging to ultra-low porosity and ultra-low permeability tight reservoir [47,48,49,50]. The casting thin section reveals that the reservoir space is dominated by dissolution pores, developing intraprit, and intergranular dissolution pores, containing a small amount of primary pores and fissure. The SEM reveals that the intergranular micro-cracks, bedding cracks, intergranular micro-pores, and intergranular micro-cracks of the reservoir are relatively developed, the microscopic pore types are mainly intergranular pores, intergranular cracks, and interlayer cracks, the dissolved pores are locally visible, and the pore cracks are small.

The industrial oil flow was achieved during the oil test of this reservoir type in well H3, and varying degrees of oil and gas display were observed in other wells such as H1, HC1, H2, H4, H5, H7, and H8. The density of crude oil is 0.85 g/cm3, the viscosity is 29.85 mPa·s, the freezing point is 32℃, and the wax content is 18.2%. The oil is a medium-quality oil with “medium density, medium viscosity, high wax content, and no sulfur.” The oil family composition is also dominated by saturated hydrocarbon fractions, with the characteristics of “high saturated hydrocarbons, middle aromatics, low non-hydrocarbon, and asphaltene content.” The oil–source correlation analysis indicates that the crude oil within the K1b1 sandstone reservoir of well H3 originates from the adjacent K1b1 source rocks [13,14,15,16,17,18,19,20,21,22,23,24,25,26,27], thereby endowing the reservoir with the characteristic of “near source rocks accumulation.” According to its characteristics, combined with the geological conditions of the study area, it is speculated that the oils in K1s, K1b3, and K1b2 in other well areas should be K1b2 source rocks, and the K1b1 and K1b2 source rocks collectively serve as the main source rocks for such reservoirs. The whole development degree of Mesozoic sandstone reservoir in Hari Sag is poor, the single layer thickness is small, and the sandstone reservoir also exists in the form of thin layer. For example, although there are many oil layers in K1b1 sandstone reservoir of well H3, the layer thickness is thin, and the single layer thickness is generally 0.5–2.0 m. There are three layers in the K1b3 sandstone reservoir of well H7, and the thickness of the single layer is only 1.0–1.4 m.

5.1.5 Tight sandstone gas reservoir

This type of gas reservoir is only discovered in K1b1 of well H6, and the lithology is mainly fine sandstone (Figure 2i). A large amount of bubble overflow is seen in the reservoir core water immersion testing, reflecting good gas content. The sandy content of the fine sandstone is 66.7%, mainly quartz. The argillaceous content is 22.7%, mainly illite. The reservoir thickness is 3.4 m (ILD avg. 33 Ω m, LLD avg. 53 Ω m, AC avg. 227 μs/m), and the reservoir is a tight sandstone reservoir with ultra-low porosity and ultra-low permeability (porosity avg. 6.59%, permeability avg. 0.142 × 10−3 μm2). The SEM observation shows that the intergranular micro-fracture and intergranular micro-pore of the reservoir are relatively developed, the microscopic pore types are mainly intergranular pores and intergranular fractures.

This kind of gas reservoir has obtained gas output from well H6. The hydrocarbon components are mainly methane, ethane, and propane, the methane content is 81.2%, and the average drying coefficient is 0.88, which belongs to humid gas. The non-hydrocarbon gases are mainly N2, H2, and CO2, the N2 content is 1.39%, the H2 content is 6.27%, and the CO2 content is 0.06%. The reservoir is a gas reservoir containing slight N2, low CO2, and no sulfur. Since the relevant test and analysis of gas samples have not been systematically carried out, the hydrocarbon–source rock correlation studies cannot be carried out. However, based on the vertical development characteristics and the source–reservoir relationship in well H6, it was inferred that the gas source rock is the K1b1 hydrocarbon source rock.

5.1.6 Volcanic gas reservoir

The strata encountered in the volcanic gas reservoir is K1b1, and the reservoir lithology is mainly andesite, dacite, basalt, and other volcanic rocks. The lithology of this type of gas reservoir in well H5 is gray basaltic andesite, with porphyritic structure, almond-shaped structure, developed fractures, and dissolution pores, where a large number of core water immersion testing show that there was good gas content (Figure 2j–k). Microscopic observation shows that the main mineral of the reservoir is basic plagioclase, which is crystallite-oriented or tripod-shaped, with microcrystalline alteration amphibole. The pores are more common and round or irregular, and its diameter is about 0.2–0.55 mm. But some of the pores are filled with chalcedony, zeolite, quartz, and calcite. The porosity of reservoir is 5.9–7.7% (avg. 7.36%), and the permeability is 0.09 × 10−3–0.18 × 10−3 μm2 (avg. 0.13 × 10−3 μm2). The macroscopic scale of the reservoir space is dominated by primary almond pores, which develop dissolution pores, interlayer fractures, high-angle fractures, etc. Microscopically, the intergranular dissolution pores and microfractures that have developed contribute to the reservoir’s pore space, which is essential for gas storage (Figure 3g–i).

Gas production has been successfully achieved from well H5 within this type of gas reservoir. The hydrocarbon components of gas are mainly methane, ethane, and propane, the methane content is 76.8–88.5%, and the average drying coefficient is 0.88, which belongs to humid gas. The non-hydrocarbon gases are mainly N2 and CO2, N2 content is between 1.38 and 6.00%, and CO2 content is avg. 4.36%. The reservoir is a low N2, medium CO2, and slight sulfur gas reservoir. The gas–source rock correlation studies cannot be carried out due to the lack of systematic testing and analysis of gas samples, but the nature of gas in volcanic gas reservoirs is very close to that in lime mudstone gas reservoirs, and it is speculated that the gas source rock is the K1b2 source rock.

5.2 Symbiosis characteristics of oil and gas reservoirs

The unconventional oil reservoirs discovered in Hari Sag include tight sandstone reservoir and shale reservoir, and the unconventional gas reservoirs include dolomitic mudstone biogas reservoir, shale gas reservoir, tight sandstone gas reservoir, and volcanic gas reservoir. From the perspective of hydrocarbon phase state and fluid properties, the unconventional oil and gas reservoirs in the study area show the characteristics of “coexistence of oil reservoirs and gas reservoirs.” In addition, except for the dolomitic mudstone biogenic gas reservoirs of the shallow Yingen Formation, the main oil- and gas-producing layers of the Bayingobi Formation and Suhongtu Formation show the distribution characteristics of “shallow oil and deep gas.” That is, the central deep sag belt at the low part of the structure is the gas reservoir development area, the eastern steep slope belt, and the western slope belt at the high part of the structure are the oil reservoir development areas (Figure 6). At the same time, the confirmed unconventional oil and gas in Hari Sag include shale oil, shale gas, dolomitic mudstone biological gas reservoir, and volcanic gas reservoir, but the conventional oil and gas reservoir is not developed. From the perspective of resource types, the oil and gas reservoirs in the study area show the characteristics of “multi-type unconventional oil and gas symbiosis, the conventional oil and gas reservoirs are not developed. According to the trap types, the oil and gas reservoirs in Hari Sag are characterized by “both structural and lithologic reservoirs.” The dolomitic mudstone biogenic gas reservoir belongs to the lithologic reservoir, the shale oil and gas reservoir is mainly a lithologic reservoir controlled by structure, the tight sandstone oil and gas reservoir is mostly lithologic reservoir, the volcanic gas reservoirs are lithologic reservoirs controlled by reservoirs, and it can be seen that the lithologic oil and gas reservoir in the study area is dominant (Figure 6).

Figure 6 Reservoir profile of wells HC1–H3–H8–H2 in Hari Sag.
Figure 6

Reservoir profile of wells HC1–H3–H8–H2 in Hari Sag.

6 Analysis of oil and gas accumulation mechanism

6.1 The lack of effective hydrocarbon migration pathway is the main reason for “near/within source rocks accumulation” of oil and gas reservoirs

The characteristics of “near source rocks accumulation” of oil and gas reservoirs in Hari Sag have been confirmed by previous studies [13,26]. After it is clear that the oil and gas of the Bayingobi Formation come from the source rocks of the Bayingobi Formation [13,27], the maturity of crude oil and the source rocks of the well H2 in the high tectonic position are compared with that of the well H3 in the low tectonic position. The maturity parameters of biomarker compounds such as C29 steranes 20S/20(R + S), C29 steranes αββ/(ααα + αββ), and T S/(T s + T m) are used. According to the thermal transformation effect of the compounds, these parameters increase with the increase of maturity [51,52,53,54]. As shown in Figure 7, the maturity of the source rock of well H2 is very close to that of the crude oil of well H2, the maturity of the source rock of well H3 is also very close to that of the crude oil of well H3, and the maturity of the source rock and crude oil of well H2 is obviously less than that of the source rock and crude oil of well H3, which further indicates that the oil and gas reservoir of Bayingobi Formation exhibits the characteristics of “near source rocks accumulation.” It is not difficult to understand the “within source rocks accumulation,” the study area of dolomitic mudstone biogas reservoir, shale gas reservoir, shale oil reservoir, and other unconventional oil and gas reservoirs, mudstone is not only a source rock but also a reservoir, and oil and gas reservoirs reflect the characteristics of “self-generation and self-reservoir.

Figure 7 Comparison of biomarker maturity parameters of K1b source rocks and oils between well H2 and well H3.
Figure 7

Comparison of biomarker maturity parameters of K1b source rocks and oils between well H2 and well H3.

The main reason for the “near source rocks accumulation and within source rocks accumulation” in the study area is the lack of effective hydrocarbon migration pathway, the Cretaceous in Hari Sag mainly develops lakes, fan deltas, nearshore subaqueous fans, and other sedimentary systems. The sedimentary characteristics determine that the Cretaceous is dominated by deep-water fine-grained sediments, and the sand body is the main channel for secondary migration of oil and gas generally undeveloped (Figure 8a). Due to the small size scale of the sag and the rapid change of sedimentary facies, the lateral connectivity of the sand body is poor, and the oil and gas migration capacity is limited. The unconformity surface, known for its role as an effective hydrocarbon migration pathway, is characterized by significant migration distances and high efficiency [55,56]. This phenomenon, with the unconformity surface serving as the primary pathway for hydrocarbon accumulation, has been validated by numerous basins worldwide [57,58]. However, the Mesozoic section of the Hari sag lacks a regional unconformity surface that fulfills this role. The fracture or fracture system with permeability can be used as a hydrocarbon migration pathway, and its migration performance is related to the nature of the fault, the size of the fault, the time of fault activity, and other factors [55,59,60]; medium and small normal faults are mainly developed in the Mesozoic of Hari Sag. The faults present in the region are effectively sealed, exhibiting constrained migration capabilities, with the majority classified as synsedimentary faults. The main activity time of the faults is earlier than the hydrocarbon accumulation time, which cannot be used as an effective hydrocarbon migration pathway. In the absence of effective migration channels, the secondary migration distance of oil and gas generated by hydrocarbon source rocks is extremely limited, and oil and gas “within source rocks” or “near source rocks” are accumulated into reservoirs.

Figure 8 Sedimentary facies of K1b (a), distribution prediction of unconventional oil and gas reservoirs (b) in Hari Sag.
Figure 8

Sedimentary facies of K1b (a), distribution prediction of unconventional oil and gas reservoirs (b) in Hari Sag.

6.2 The difference in the thermal evolution degree of the main source rocks makes the oil and gas exhibit the distribution characteristics of “upper oil and lower gas”

According to the gravity differentiation effect of oil and gas, it should reflect the distribution characteristics of “upper gas and lower oil” under normal circumstances, but there is an abnormal phenomenon of “oil reservoir developed at high tectonic position and gas reservoir developed at low tectonic position” in the Bayingobi Formation (Figure 6). There are two reasons for this abnormal accumulation phenomenon, the first is that the oil and gas reflects the characteristics of “near source rocks and within source rocks” accumulation and the other is that the hydrocarbon generation characteristics (maturity) of the main source rocks are different. “Near source rocks accumulation, within source rocks accumulation” has been confirmed by previous studies [13,26], and the reasons for its formation have also been discussed earlier. The comparative study of oil and gas sources shows that, in addition to the special biogas reservoirs of the Yingen Formation, the main source rocks of other layers in the study area are K1b1 and K1b2 source rocks. Comparing the K1b1 and K1b2 source rocks of wells in different tectonic positions, it is obvious that there are great differences in their maturity (Table 3). The buried depth of K1b1 and K1b2 source rock in well H2 located in the high slope zone is 980–1418 m, R o is 0.60–1.01%, T max is avg. 428℃, and the source rock is low mature–mature (the evaluation criterion can be seen from [61], the same below). According to the thermal simulation experiment results of K1b2 source rock, the source rock is in the stage of pyrolysis-condensate generation, and the type of hydrocarbon production is mainly oil generation (Figure 9). The buried depth of K1b1 and K1b2 source rocks in well H3 located in the low slope belt is 1617–2129 m, R o is avg. 1.14%, and T max is avg. 443℃, the source rock is mature, it is mainly in the condensate generation stage, and the hydrocarbon type is mainly oil generating. The buried depth of K1b1 and K1b2 source rock in well HC1 in the deep sag is 2794–3193 m, R o is avg. 1.81%, T max is avg. 450℃, the source rock is highly mature–over mature, it is mainly in the stage of oil cracking and gas generation, and the hydrocarbon type is mainly gas production. The difference in the depth of K1b1 and K1b2 source rock leads to the difference in the degree of thermal evolution, and the hydrocarbon generation type of K1b1 and K1b2 source rock in different tectonic positions of the sag is completely consistent with the type of oil and gas production, which further shows that the difference in the degree of thermal evolution of K1b1 and K1b2 source rock is the direct cause of the distribution characteristics of oil and gas with “upper oil and lower gas.”

Table 3

Maturity of K1b1 + K1b2 source rocks in different structural positions in Hari Sag

Well Construction location Depth (m) R o (%) T max (℃)
H2 High slope zone 980–1,418 0.60–1.01 338–460
0.68(11) 428(14)
H3 Low slope zone 1,617–2,129 0.86–1.46 404–473
1.14(7) 443(5)
HC1 Deep sag zone 2,794–3,193 1.06–2.17 428–537
1.81(12) 450(12)

R o is vitrinite reflectance; T max is the highest pyrolysis peak temper; and “0.60–1.01,0.68(11)” for “min–max, average(number)”.

Figure 9 Thermal simulation results and hydrocarbon-generation stage classification of K1b2 source rock in Hari Sag.
Figure 9

Thermal simulation results and hydrocarbon-generation stage classification of K1b2 source rock in Hari Sag.

6.3 The development of multi-type effective unconventional reservoirs creates the situation of “multi-type unconventional oil and gas reservoir symbiosis”

The Mesozoic in Hari Sag is dominated by deep-water fine-grained sediments with rapid sedimentary facies changes [25,62], the overall development of conventional reservoirs is poor, and the thickness of single layer is small. However, the unconventional reservoirs in Hari Sag are relatively developed, mainly including mudstone, sandstone, and volcanic rock, which are subdivided into more than ten kinds of lithology (Table 4). The lithology of unconventional sandstone reservoirs is siltstone, fine sandstone, etc., and they are distributed in more layers, K1s, K1b3, K1b2, and K1b1. The porosity is 0.1–8.8% (avg. 4.6%), and the permeability is 0.034 × 10−3–0.504 × 10−3 μm2 (avg. 0.118 × 10−3 μm2). According to the evaluation standard of clastic rock reservoir [50], this kind of reservoir is mainly low porosity and ultra-low permeability reservoir, which is a typical tight sandstone reservoir. Mudstone reservoirs and volcanic reservoirs are other two important unconventional reservoirs. Mudstone reservoirs can be divided into dolomitic mudstone type (including dolomitic mudstone, mud crystalline dolomite, containing dolomite mudstone, etc.) and lime mudstone type (including lime mudstone, contenting lime mudstone, etc.). The porosity of dolomitic mudstone reservoirs is 2.3–14.5% (avg. 9.8%), the permeability is 0.006 × 10−3–0.231 × 10−3 μm2 (avg. 0.085 × 10−3 μm2). The porosity of lime mudstone reservoirs is 0.1–11.5% (avg. 5.1%), the permeability is 0.004 × 10−3–0.860 × 10−3 μm2 (avg. 0.026 × 10−3 μm2). The reservoir porosity of andesite, basalt and other volcanic reservoirs is 0.1–8.8% (avg. 4.6%), the permeability is 0.034 × 10−3–0.504 × 10−3 μm2 (avg. 0.118 × 10−3 μm2). According to the shale gas reservoir classification standard [63], the mudstone reservoirs and volcanic reservoirs in the study area are mostly medium-pore and low-permeability reservoirs, with dissolution pores, fractures, and almond pores as the main reservoir space, with good porosity but poor permeability (Table 4).

Table 4

Types and characteristics of unconventional reservoirs in Hari Sag

Reservoir types Lithology Reservoir space Reservoir physical properties Reservoir evaluation
Mudstone Dolomitic mudstone, mud crystalline dolomite, containing dolomite mudstone, etc. Dissolution pores and cracks The porosity is avg. 9.8% and the permeability is avg. 0.085 × 10−3 μm2 Medium pore ultra-low permeability
Lime mudstone and containing lime mudstone Micro-cracks, dissolution pores, dissolution cracks, intergranular pores, intragranular pores, etc. The porosity is avg. 5.1% and the permeability is avg. 0.026 × 10−3 μm2 Medium pore ultra-low permeability
Volcanic Rocks An desite, dingite, basalt, etc. Almond pores, dissolution pores, interlayer crack, high angle crack, micro-crack, etc. The porosity is avg. 7.36% and the permeability is avg. 0.130 × 10−3 μm2 Medium pore ultra-low permeability
Sandstone Siltstone, fine sandstone, conglomerate, etc. Dissolution pores, intergranular micro-crack, bedding crack, intergranular micro-pore, crystalline intergranular micro-crack, etc. The porosity is avg. 4.6% and the permeability is avg. 0.118 × 10−3 μm2 Low pore ultra-low permeability

Note: Reservoir evaluation criteria can be found in [50,63].

The exploration practice shows that as long as there is reservoir space, the reservoir can be formed under the condition of “source-reservoir matching” (the reservoir is close to the main source rocks of K1y, K1b2, and K1b1). The abundant types of unconventional reservoirs in Hari Sag provide a variety of accumulation sites for oil and gas accumulation, and the development of multiple types of effective unconventional reservoirs creates a situation of "multi-type unconventional oil and gas reservoir symbiosis".

7 Prediction of unconventional oil and gas distribution

According to the oil and gas display of drilling and the oil and gas test effect, under the premise of drilling constraints, combined with the reservoir characteristics, structural characteristics, and other factors, the distribution of various types of unconventional oil and gas reservoirs in Hari Sag is predicted (Figure 8b). The prediction results show that the cumulative oil and gas area of six types of oil and gas reservoirs in Hari Sag is 381 km2. The biogas reservoir in K1y is mainly distributed in the wells H5–H8–H7–H4–HC1–H1 block, with a wide distribution area of about 117 km2. The shale gas reservoir mainly developed in K1b2 are distributed in the wells H1–HC1–H5 block and well H6 block in the north and south sides of the central deep sag belt, with a total area of 51 km2. The shale reservoir is distributed in the wells H2–H7–H3–H8 block in the western slope zone, with an area of about 36 km2. Tight sandstone reservoir exhibits many oil-bearing layers and wide distribution, mainly distributed in the wells H5–H8–H2–H7–H3–H4–HC1–H1 block in the south sub-sag, with an area of about 155 km2. Tight sandstone gas reservoirs are distributed in the well H6 block in the north sub-sag, with a small area of about 13 km2. Volcanic gas reservoirs are distributed in the well H5 block, with a small area of about 9 km2.

8 Conclusions

  1. Hari Sag hosts a diverse array of unconventional oil and gas reservoirs, including biogas, shale gas, shale oil, tight sandstone oil, tight sandstone gas, and volcanic gas reservoirs. They take K1y, K1b2, and K1b1 source rocks as the main source rocks, which exhibits the characteristics of “near source rocks and within source rocks” accumulation.

  2. The unconventional oil and gas reservoirs in Hari Sag are characterized by “undeveloped conventional oil and gas reservoirs, various types of unconventional oil and gas reservoirs,” “coexistence of oil and gas reservoirs, shallow oil and deep gas,” and “both structural and lithologic oil and gas reservoirs are found, and lithologic oil and gas reservoirs are dominant”.

  3. The study of oil and gas accumulation mechanism shows that the lack of effective oil and gas migration pathway leads to the characteristics of “near source rocks accumulation and within source rocks accumulation,” and the differences in the thermal evolution of the main source rocks in different structural positions make the oil and gas reflect the distribution characteristics of “shallow oil and deep gas,” the development of multi-type effective unconventional reservoirs creates a situation of "multi-type unconventional oil and gas reservoir symbiosis.”

  4. According to the oil and gas display, the distribution of various types of oil and gas reservoirs in Hari Sag is predicted, the results show that the cumulative area of six types of unconventional oil and gas reservoirs is 381 km2, so the Hari Sag presents a large unconventional oil and gas exploration potential.

Acknowledgments

We would like to take this opportunity to acknowledge the time and effort devoted by the three anonymous reviewers to improving the quality of the published manuscript in Open Geosciences.

  1. Funding information: This research was funded by the Ministry of Land and Resources of the People’s Republic of China Project (No. 2017YQZYPJ01), Scientific Research Program Project of Department of Education of Shaanxi Province (No. 20JS115), Natural Science Foundation of Department of Science and Technology of Shaanxi Province (No. 2017JQ4013), and Doctoral research start-up fund project of Xi’an Shiyou University (No. 2014BS04).

  2. Author contributions: Chao Ding contributed to the conception of the manuscript and revised it. Zhijun Chen contributed importantly to the analysis, review, and editing. Lan Guo and Shun Guo helped perform data curation. Xunqing Su contributed to the data collection and processing. Xiaoyin Bai helped revised the manuscript. All authors have read and agreed to the published version of the manuscript.

  3. Conflict of interest: The authors declare no conflict of interest.

  4. Data availability statement: The data supporting the findings of this study are available within the article.

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Received: 2023-11-06
Revised: 2024-04-21
Accepted: 2024-05-02
Published Online: 2024-06-11

© 2024 the author(s), published by De Gruyter

This work is licensed under the Creative Commons Attribution 4.0 International License.

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https://doi.org/10.1515/geo-2022-0651
Keywords for this article
characteristics of unconventional oil and gas reservoirs; hydrocarbon accumulation mechanism; small-scale fault basin; Yin’e Basin
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Articles in the same Issue

  1. Regular Articles
  2. Theoretical magnetotelluric response of stratiform earth consisting of alternative homogeneous and transitional layers
  3. The research of common drought indexes for the application to the drought monitoring in the region of Jin Sha river
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  5. On the use of low-frequency passive seismic as a direct hydrocarbon indicator: A case study at Banyubang oil field, Indonesia
  6. Water transportation planning in connection with extreme weather conditions; case study – Port of Novi Sad, Serbia
  7. Zircon U–Pb ages of the Paleozoic volcaniclastic strata in the Junggar Basin, NW China
  8. Monitoring of mangrove forests vegetation based on optical versus microwave data: A case study western coast of Saudi Arabia
  9. Microfacies analysis of marine shale: A case study of the shales of the Wufeng–Longmaxi formation in the western Chongqing, Sichuan Basin, China
  10. Multisource remote sensing image fusion processing in plateau seismic region feature information extraction and application analysis – An example of the Menyuan Ms6.9 earthquake on January 8, 2022
  11. Identification of magnetic mineralogy and paleo-flow direction of the Miocene-quaternary volcanic products in the north of Lake Van, Eastern Turkey
  12. Impact of fully rotating steel casing bored pile on adjacent tunnels
  13. Adolescents’ consumption intentions toward leisure tourism in high-risk leisure environments in riverine areas
  14. Petrogenesis of Jurassic granitic rocks in South China Block: Implications for events related to subduction of Paleo-Pacific plate
  15. Differences in urban daytime and night block vitality based on mobile phone signaling data: A case study of Kunming’s urban district
  16. Random forest and artificial neural network-based tsunami forests classification using data fusion of Sentinel-2 and Airbus Vision-1 satellites: A case study of Garhi Chandan, Pakistan
  17. Integrated geophysical approach for detection and size-geometry characterization of a multiscale karst system in carbonate units, semiarid Brazil
  18. Spatial and temporal changes in ecosystem services value and analysis of driving factors in the Yangtze River Delta Region
  19. Deep fault sliding rates for Ka-Ping block of Xinjiang based on repeating earthquakes
  20. Improved deep learning segmentation of outdoor point clouds with different sampling strategies and using intensities
  21. Platform margin belt structure and sedimentation characteristics of Changxing Formation reefs on both sides of the Kaijiang-Liangping trough, eastern Sichuan Basin, China
  22. Enhancing attapulgite and cement-modified loess for effective landfill lining: A study on seepage prevention and Cu/Pb ion adsorption
  23. Flood risk assessment, a case study in an arid environment of Southeast Morocco
  24. Lower limits of physical properties and classification evaluation criteria of the tight reservoir in the Ahe Formation in the Dibei Area of the Kuqa depression
  25. Evaluation of Viaducts’ contribution to road network accessibility in the Yunnan–Guizhou area based on the node deletion method
  26. Permian tectonic switch of the southern Central Asian Orogenic Belt: Constraints from magmatism in the southern Alxa region, NW China
  27. Element geochemical differences in lower Cambrian black shales with hydrothermal sedimentation in the Yangtze block, South China
  28. Three-dimensional finite-memory quasi-Newton inversion of the magnetotelluric based on unstructured grids
  29. Obliquity-paced summer monsoon from the Shilou red clay section on the eastern Chinese Loess Plateau
  30. Classification and logging identification of reservoir space near the upper Ordovician pinch-out line in Tahe Oilfield
  31. Ultra-deep channel sand body target recognition method based on improved deep learning under UAV cluster
  32. New formula to determine flyrock distance on sedimentary rocks with low strength
  33. Assessing the ecological security of tourism in Northeast China
  34. Effective reservoir identification and sweet spot prediction in Chang 8 Member tight oil reservoirs in Huanjiang area, Ordos Basin
  35. Detecting heterogeneity of spatial accessibility to sports facilities for adolescents at fine scale: A case study in Changsha, China
  36. Effects of freeze–thaw cycles on soil nutrients by soft rock and sand remodeling
  37. Vibration prediction with a method based on the absorption property of blast-induced seismic waves: A case study
  38. A new look at the geodynamic development of the Ediacaran–early Cambrian forearc basalts of the Tannuola-Khamsara Island Arc (Central Asia, Russia): Conclusions from geological, geochemical, and Nd-isotope data
  39. Spatio-temporal analysis of the driving factors of urban land use expansion in China: A study of the Yangtze River Delta region
  40. Selection of Euler deconvolution solutions using the enhanced horizontal gradient and stable vertical differentiation
  41. Phase change of the Ordovician hydrocarbon in the Tarim Basin: A case study from the Halahatang–Shunbei area
  42. Using interpretative structure model and analytical network process for optimum site selection of airport locations in Delta Egypt
  43. Geochemistry of magnetite from Fe-skarn deposits along the central Loei Fold Belt, Thailand
  44. Functional typology of settlements in the Srem region, Serbia
  45. Hunger Games Search for the elucidation of gravity anomalies with application to geothermal energy investigations and volcanic activity studies
  46. Addressing incomplete tile phenomena in image tiling: Introducing the grid six-intersection model
  47. Evaluation and control model for resilience of water resource building system based on fuzzy comprehensive evaluation method and its application
  48. MIF and AHP methods for delineation of groundwater potential zones using remote sensing and GIS techniques in Tirunelveli, Tenkasi District, India
  49. New database for the estimation of dynamic coefficient of friction of snow
  50. Measuring urban growth dynamics: A study in Hue city, Vietnam
  51. Comparative models of support-vector machine, multilayer perceptron, and decision tree ‎predication approaches for landslide ‎susceptibility analysis
  52. Experimental study on the influence of clay content on the shear strength of silty soil and mechanism analysis
  53. Geosite assessment as a contribution to the sustainable development of Babušnica, Serbia
  54. Using fuzzy analytical hierarchy process for road transportation services management based on remote sensing and GIS technology
  55. Accumulation mechanism of multi-type unconventional oil and gas reservoirs in Northern China: Taking Hari Sag of the Yin’e Basin as an example
  56. TOC prediction of source rocks based on the convolutional neural network and logging curves – A case study of Pinghu Formation in Xihu Sag
  57. A method for fast detection of wind farms from remote sensing images using deep learning and geospatial analysis
  58. Spatial distribution and driving factors of karst rocky desertification in Southwest China based on GIS and geodetector
  59. Physicochemical and mineralogical composition studies of clays from Share and Tshonga areas, Northern Bida Basin, Nigeria: Implications for Geophagia
  60. Geochemical sedimentary records of eutrophication and environmental change in Chaohu Lake, East China
  61. Research progress of freeze–thaw rock using bibliometric analysis
  62. Mixed irrigation affects the composition and diversity of the soil bacterial community
  63. Examining the swelling potential of cohesive soils with high plasticity according to their index properties using GIS
  64. Geological genesis and identification of high-porosity and low-permeability sandstones in the Cretaceous Bashkirchik Formation, northern Tarim Basin
  65. Usability of PPGIS tools exemplified by geodiscussion – a tool for public participation in shaping public space
  66. Efficient development technology of Upper Paleozoic Lower Shihezi tight sandstone gas reservoir in northeastern Ordos Basin
  67. Assessment of soil resources of agricultural landscapes in Turkestan region of the Republic of Kazakhstan based on agrochemical indexes
  68. Evaluating the impact of DEM interpolation algorithms on relief index for soil resource management
  69. Petrogenetic relationship between plutonic and subvolcanic rocks in the Jurassic Shuikoushan complex, South China
  70. A novel workflow for shale lithology identification – A case study in the Gulong Depression, Songliao Basin, China
  71. Characteristics and main controlling factors of dolomite reservoirs in Fei-3 Member of Feixianguan Formation of Lower Triassic, Puguang area
  72. Impact of high-speed railway network on county-level accessibility and economic linkage in Jiangxi Province, China: A spatio-temporal data analysis
  73. Estimation model of wild fractional vegetation cover based on RGB vegetation index and its application
  74. Lithofacies, petrography, and geochemistry of the Lamphun oceanic plate stratigraphy: As a record of the subduction history of Paleo-Tethys in Chiang Mai-Chiang Rai Suture Zone of Thailand
  75. Structural features and tectonic activity of the Weihe Fault, central China
  76. Application of the wavelet transform and Hilbert–Huang transform in stratigraphic sequence division of Jurassic Shaximiao Formation in Southwest Sichuan Basin
  77. Structural detachment influences the shale gas preservation in the Wufeng-Longmaxi Formation, Northern Guizhou Province
  78. Distribution law of Chang 7 Member tight oil in the western Ordos Basin based on geological, logging and numerical simulation techniques
  79. Evaluation of alteration in the geothermal province west of Cappadocia, Türkiye: Mineralogical, petrographical, geochemical, and remote sensing data
  80. Numerical modeling of site response at large strains with simplified nonlinear models: Application to Lotung seismic array
  81. Quantitative characterization of granite failure intensity under dynamic disturbance from energy standpoint
  82. Characteristics of debris flow dynamics and prediction of the hazardous area in Bangou Village, Yanqing District, Beijing, China
  83. Rockfall mapping and susceptibility evaluation based on UAV high-resolution imagery and support vector machine method
  84. Statistical comparison analysis of different real-time kinematic methods for the development of photogrammetric products: CORS-RTK, CORS-RTK + PPK, RTK-DRTK2, and RTK + DRTK2 + GCP
  85. Hydrogeological mapping of fracture networks using earth observation data to improve rainfall–runoff modeling in arid mountains, Saudi Arabia
  86. Petrography and geochemistry of pegmatite and leucogranite of Ntega-Marangara area, Burundi, in relation to rare metal mineralisation
  87. Prediction of formation fracture pressure based on reinforcement learning and XGBoost
  88. Hazard zonation for potential earthquake-induced landslide in the eastern East Kunlun fault zone
  89. Monitoring water infiltration in multiple layers of sandstone coal mining model with cracks using ERT
  90. Study of the patterns of ice lake variation and the factors influencing these changes in the western Nyingchi area
  91. Productive conservation at the landslide prone area under the threat of rapid land cover changes
  92. Sedimentary processes and patterns in deposits corresponding to freshwater lake-facies of hyperpycnal flow – An experimental study based on flume depositional simulations
  93. Study on time-dependent injectability evaluation of mudstone considering the self-healing effect
  94. Detection of objects with diverse geometric shapes in GPR images using deep-learning methods
  95. Behavior of trace metals in sedimentary cores from marine and lacustrine environments in Algeria
  96. Spatiotemporal variation pattern and spatial coupling relationship between NDVI and LST in Mu Us Sandy Land
  97. Formation mechanism and oil-bearing properties of gravity flow sand body of Chang 63 sub-member of Yanchang Formation in Huaqing area, Ordos Basin
  98. Diagenesis of marine-continental transitional shale from the Upper Permian Longtan Formation in southern Sichuan Basin, China
  99. Vertical high-velocity structures and seismic activity in western Shandong Rise, China: Case study inspired by double-difference seismic tomography
  100. Spatial coupling relationship between metamorphic core complex and gold deposits: Constraints from geophysical electromagnetics
  101. Disparities in the geospatial allocation of public facilities from the perspective of living circles
  102. Research on spatial correlation structure of war heritage based on field theory. A case study of Jinzhai County, China
  103. Formation mechanisms of Qiaoba-Zhongdu Danxia landforms in southwestern Sichuan Province, China
  104. Magnetic data interpretation: Implication for structure and hydrocarbon potentiality at Delta Wadi Diit, Southeastern Egypt
  105. Deeply buried clastic rock diagenesis evolution mechanism of Dongdaohaizi sag in the center of Junggar fault basin, Northwest China
  106. Application of LS-RAPID to simulate the motion of two contrasting landslides triggered by earthquakes
  107. The new insight of tectonic setting in Sunda–Banda transition zone using tomography seismic. Case study: 7.1 M deep earthquake 29 August 2023
  108. The critical role of c and φ in ensuring stability: A study on rockfill dams
  109. Evidence of late quaternary activity of the Weining-Shuicheng Fault in Guizhou, China
  110. Extreme hydroclimatic events and response of vegetation in the eastern QTP since 10 ka
  111. Spatial–temporal effect of sea–land gradient on landscape pattern and ecological risk in the coastal zone: A case study of Dalian City
  112. Study on the influence mechanism of land use on carbon storage under multiple scenarios: A case study of Wenzhou
  113. A new method for identifying reservoir fluid properties based on well logging data: A case study from PL block of Bohai Bay Basin, North China
  114. Comparison between thermal models across the Middle Magdalena Valley, Eastern Cordillera, and Eastern Llanos basins in Colombia
  115. Mineralogical and elemental analysis of Kazakh coals from three mines: Preliminary insights from mode of occurrence to environmental impacts
  116. Chlorite-induced porosity evolution in multi-source tight sandstone reservoirs: A case study of the Shaximiao Formation in western Sichuan Basin
  117. Predicting stability factors for rotational failures in earth slopes and embankments using artificial intelligence techniques
  118. Origin of Late Cretaceous A-type granitoids in South China: Response to the rollback and retreat of the Paleo-Pacific plate
  119. Modification of dolomitization on reservoir spaces in reef–shoal complex: A case study of Permian Changxing Formation, Sichuan Basin, SW China
  120. Geological characteristics of the Daduhe gold belt, western Sichuan, China: Implications for exploration
  121. Rock physics model for deep coal-bed methane reservoir based on equivalent medium theory: A case study of Carboniferous-Permian in Eastern Ordos Basin
  122. Enhancing the total-field magnetic anomaly using the normalized source strength
  123. Shear wave velocity profiling of Riyadh City, Saudi Arabia, utilizing the multi-channel analysis of surface waves method
  124. Effect of coal facies on pore structure heterogeneity of coal measures: Quantitative characterization and comparative study
  125. Inversion method of organic matter content of different types of soils in black soil area based on hyperspectral indices
  126. Detection of seepage zones in artificial levees: A case study at the Körös River, Hungary
  127. Tight sandstone fluid detection technology based on multi-wave seismic data
  128. Characteristics and control techniques of soft rock tunnel lining cracks in high geo-stress environments: Case study of Wushaoling tunnel group
  129. Influence of pore structure characteristics on the Permian Shan-1 reservoir in Longdong, Southwest Ordos Basin, China
  130. Study on sedimentary model of Shanxi Formation – Lower Shihezi Formation in Da 17 well area of Daniudi gas field, Ordos Basin
  131. Multi-scenario territorial spatial simulation and dynamic changes: A case study of Jilin Province in China from 1985 to 2030
  132. Review Articles
  133. Major ascidian species with negative impacts on bivalve aquaculture: Current knowledge and future research aims
  134. Prediction and assessment of meteorological drought in southwest China using long short-term memory model
  135. Communication
  136. Essential questions in earth and geosciences according to large language models
  137. Erratum
  138. Erratum to “Random forest and artificial neural network-based tsunami forests classification using data fusion of Sentinel-2 and Airbus Vision-1 satellites: A case study of Garhi Chandan, Pakistan”
  139. Special Issue: Natural Resources and Environmental Risks: Towards a Sustainable Future - Part I
  140. Spatial-temporal and trend analysis of traffic accidents in AP Vojvodina (North Serbia)
  141. Exploring environmental awareness, knowledge, and safety: A comparative study among students in Montenegro and North Macedonia
  142. Determinants influencing tourists’ willingness to visit Türkiye – Impact of earthquake hazards on Serbian visitors’ preferences
  143. Application of remote sensing in monitoring land degradation: A case study of Stanari municipality (Bosnia and Herzegovina)
  144. Optimizing agricultural land use: A GIS-based assessment of suitability in the Sana River Basin, Bosnia and Herzegovina
  145. Assessing risk-prone areas in the Kratovska Reka catchment (North Macedonia) by integrating advanced geospatial analytics and flash flood potential index
  146. Analysis of the intensity of erosive processes and state of vegetation cover in the zone of influence of the Kolubara Mining Basin
  147. GIS-based spatial modeling of landslide susceptibility using BWM-LSI: A case study – city of Smederevo (Serbia)
  148. Geospatial modeling of wildfire susceptibility on a national scale in Montenegro: A comparative evaluation of F-AHP and FR methodologies
  149. Geosite assessment as the first step for the development of canyoning activities in North Montenegro
  150. Urban geoheritage and degradation risk assessment of the Sokograd fortress (Sokobanja, Eastern Serbia)
  151. Multi-hazard modeling of erosion and landslide susceptibility at the national scale in the example of North Macedonia
  152. Understanding seismic hazard resilience in Montenegro: A qualitative analysis of community preparedness and response capabilities
  153. Forest soil CO2 emission in Quercus robur level II monitoring site
  154. Characterization of glomalin proteins in soil: A potential indicator of erosion intensity
  155. Power of Terroir: Case study of Grašac at the Fruška Gora wine region (North Serbia)
  156. Special Issue: Geospatial and Environmental Dynamics - Part I
  157. Qualitative insights into cultural heritage protection in Serbia: Addressing legal and institutional gaps for disaster risk resilience
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