Since the successful exploration and development of shale gas in North America, the world petroleum industry has gradually entered an era of unconventional oil and gas. According to the U.S. Energy Information Administration (EIA) survey report, the technically recoverable resources of global shale oil are about 469 × 10⁸t, and shale oil has become another critical unconventional resource after shale gas (Zhang et al., 2015; Wang et al., 2016; U.S. Energy Information Administration, 2017). Shale oil and gas have become an important energy source in North America, a major high-yield area in the world, especially in the Bakken Formation, Eagle Ford Formation, and Barnett Formation (Jarvie et al., 2007; Jarvie, 2012). Organic-rich shales are widely developed in lacustrine basins in China including Bohai Bay Basin, Songliao Basin, Ordos Basin, Jungar Basin, and other large basins (Zhang et al., 2012; Liu et al., 2019; Zhao et al., 2019), and previous studies have proved that some of these lacustrine basins were rich in shale oil resources (Zou et al., 2013; Zhang et al., 2014). Compared with the United States, which has decades of exploration and development history, China is lagging in the exploration and development of unconventional oil. Due to the differences in geological characteristics between the lacustrine shale in China and the marine shale in North America, such as complex structure, deep burial, and strong heterogeneity, it is hard to copy the successful experience and models of North America (Cui et al., 2015; Zhou et al., 2015; Jin et al., 2016). At present, the research of lacustrine shale has already made certain understanding and essential progress in mineral composition and genesis (Aplin and Macquaker, 2011; Slatt and Rodriguez, 2012; Chermak and Schreiber, 2014; Liu et al., 2020a), shale sedimentary environment (Wang et al., 2019; Liu et al., 2020b; Ji et al., 2020; Liu et al., 2021; Wang et al., 2021), and pore types and characteristics (Loucks et al., 2012; Milliken et al., 2013; Ji et al., 2019). The lithofacies of shale contain information including mineral components, rock types, sedimentary structures, and organic matter abundance (Loucks and Ruppel, 2007; Ross and Bustin, 2009; Xu et al., 2018; Xu et al., 2019; Xu et al., 2020), which makes the division and distribution of lithofacies become a fundamental geology issue (Newport et al., 2016; Tang et al., 2016; Wang et al., 2018). However, due to differences in application purposes and research methods, there is still no unified standards to classify and characterize shale lithofacies, and the predecessors have made some explorations and attempts in different regions (Dill et al., 2005; Loucks and Ruppel, 2007; Wu et al., 2016). Taking Wufeng-Longmaxi Formation shale as an example, Liang et al. (2012) divided the shale into five lithofacies based on the mineral composition. Wu et al. (2016) improved the three-terminal element diagram and divided shale into eight lithofacies types; Wang et al. (2018) divided shale into four categories based on mineral composition and then combined geological factors such as sedimentary environment which are further subdivided into 31 lithofacies. Hu et al. (2019) determined three shale lithofacies, siliceous lithofacies, argillaceous lithofacies, and mixed lithofacies based on the shale mineral components, to discuss the effect of the lithofacies on the pore system of over-mature shales. Six lithofacies were identified with the combination of the three-end-member method and TOC, and shale lithofacies evaluation criteria were established (Wang et al., 2020).

As the understanding of shale geology continues to deepen, shale color and mineral content, parameters such as paleontological type, grain size, organic matter type, and abundance, and sedimentary structure have also been applied to the lithofacies classification scheme (Dill et al., 2005; Liu et al., 2019). Since the development and distribution characteristics of different lithofacies have not been systematically explained, it will severely limit the exploration of shale oil (Wu et al., 2016; Ma et al., 2017, Ma et al., 2019; Wang et al., 2020). To solve this problem, the author takes the second member of the Kongdian Formation (Ek₂) as the research object with the critical wells in the Cangdong Sag. The division of shale facies in the Cangdong Sag has been in the exploratory stage (Yan and Zheng, 2015; Chen et al., 2019; Deng et al., 2020; Xin et al., 2021). Yan and Zheng (2015) proposed a three-terminal and four-component division scheme based on XRD data to classify the Ek₂ shale into 4 categories and 12 lithofacies types, including felsic shale, carbonate shale, clay shale, and fine-grained mixed shale. On this basis, Deng et al., 2020, divided Ek₂ into two major categories and five lithofacies according to the differences in material composition and mixing methods. In this study, the lithofacies of shales and their characteristics will be clarified based on the thin-section description, scanning electron microscopy, total organic carbon content testing, XRD, and other test data. This study will summarize the dominant lithofacies and spatial distribution characteristics of the lacustrine shale, facilitating shale oil exploration in lacustrine settings.

The Bohai Bay Basin is located on the east coast of China, with a total area of 200,000 km² (Figure 1A) (Chang, 1991; Huang et al., 2018). The Cangdong Sag is a secondary structural unit in the southern area of the Huanghua Depression in the Bohai Bay Basin, with an exploration area of about 1760 km² (Figure 1B). It has a structural background of weak tectonic activity, high frequency, and small amplitude and belongs to a faulted lake basin. The study area is held between the Xuhei Uplift in the south and reaches the Cangxian Uplift in the north. It is composed of the Kongdian structural belt, the Shenvsi fault nose, the Kongxi slope, the Kongdong slope, and the Nanpi slope (Pu et al., 2016). The Kongdian Formation is distributed with the third member of Kongdian Formation (Ek₃) to the first member of Kongdian Formation (Ek₁) developed from bottom to top (Zhao et al., 2019) (Figure 2). The Ek₂ is deposited in a relatively closed semi-deep water-deep water environment with a thickness of 400–600 m (Pu et al., 2019), which is the main oil-generating interval in the study area (Zhou et al., 2020).

The Kongdian Formation is a second-order sequence stratigraphic unit, and the Ek₂ is a complete third-order sequence, which can be further divided into four third-order sequence stratigraphic sub-members (Ek₂ ⁴, Ek₂ ³, Ek₂ ², and Ek₂ ¹ from bottom to top) and the shales of different sub-members have apparent differences in vertical distribution (Pu et al., 2016). The Ek₂ ⁴ is low-stand system tract (LST) and mainly composed of the combination of sandstone and mudstone of the delta-front subfacies. The Ek₂ ³ and Ek₂ ² belong to lake expansion system tract (EST), and the top of Ek₂ ² exhibits the maximum flooding surface. The two sub-members were deposited with a set of semi-deep-lake fine-grain deposits and mainly consisted of organic-rich shale, pelitic dolomite, and fine siltstone. The Ek₂ ¹ is high-stand system tract (HST) and consists of black shale and laminated dolomite, as well as thin-layer sandstone (Zhao et al., 2018).

This research takes three typical wells in Cangdong Sag G-X well, GD-Y well, and GD-Z well as objects. Well G-X is located at the southwestern edge of the Kongdian structural belt in Cangdong Sag. The total thickness of the coring section in the Ek₂ is 468.5 m. Ek₂ ⁴ is dominated by fine gray sandstone and gray mudstone, with a thickness of 68.9 m; Ek₂ ³ is dominated by gray-black mud shale and dark-gray dolomite shale, with a thickness of 136 m; Ek₂ ² is dominated by dark-gray shale and argillaceous dolomite, with a thickness of 181.75 m, and its top surface is the largest flooding surface of the Kongdian Formation with a set of fine sandstones; Ek₂ ¹ is mainly gray-black mud shale with some interbedded dolomite layers, with a thickness of 81.85 m. GD-Y well and GD-Z well are situated in the center of Cangdong Sag, with a total thickness of 147.8 m in the coring section in the Ek₂.

The samples were collected from the core of Ek₂ in Cangdong Sag (well G-X, GD-Y, and GD-Z), which is gray-black shale. These whole cores are dissected at 1/3 position, of which 1/3 retained with detailed core description was performed, and the remaining 2/3 is used for sampling analysis. Since G-X well contains all four sub-members of the Ek₂, 30 samples were collected from each sub-member for thin-section observation, TOC, Rock-Eval pyrolysis, SEM, X-ray fluorescence (XRF), and XRD experiments in this study. The other two wells, the GD-Y well and GD-Z well, mainly provide observations and supplements for the research.

One hundred twenty samples were crushed and ground to a size of 100–200 mesh for TOC analyses, Rock-Eval pyrolysis, and XRD. Total organic carbon (TOC) analyses were carried out for 120 bulk powder samples and were performed in the Key Laboratory of Deep Oil and Gas of the China University of Petroleum (East China) using a Leco CS-744 carbon-sulfur analyzer to determine the TOC. 120 samples were analyzed by using a Rock-Eval seven instrument following the standard technique (Espitalié and Bordeave, 1993), which yielded the free oil or volatile hydrocarbon content (S₁), the residual hydrocarbon generation potential (S₂), and the temperature of the maximum pyrolysis yield (T_max). The analytical instrument of the XRD is X’pert Pro MPD, and the relative mineral percentages were estimated according to Pecharsky and Zavalij (2003). Scanning electron microscopy (SEM) was used to observe the mineral arrangement, laminar characteristics, and pore structure of samples.

The shale of the Ek₂ in the Cangdong Sag is dominated by Type I and Type II₁ kerogen, indicating that it is a typical oil-prone lacustrine shale in the mature stage. The mineral composition is dominated by quartz, feldspar, and dolomite, followed by calcite, clay minerals, and analcime.

Based on the combination of TOC, mineral components, and sedimentary structure, eight lithofacies were identified in the Ek₂ shales: ① low to moderate organic matter content (referred to as “low to moderate TOC”) massive calcareous mudstone (C-1); ② low to moderate TOC laminated calcareous mudstone (C-2); ③ low to moderate TOC layered mixed calcareous mudstone (C-3); ④ moderate to high organic matter content (referred to as “moderate to high TOC”) laminated calcareous siliceous mudstone (S-1); ⑤ moderate to high TOC massive mixed siliceous mudstone (S-2); ⑥ moderate to high TOC laminated clayey siliceous mudstone (S-3); ⑦ low to moderate TOC massive mixed mudstone (M-1); ⑧ moderate to high TOC layered calcareous/siliceous mixed mudstone (M-2).

The eight lithofacies are different in terms of geochemical characteristics. S-1, S-2, S-3, and M-2 samples show high TOC and a very good to excellent potential for oil generation, while C-1, C-2, C-3, and M-1 samples are characterized by lower TOC. The pore structure characteristics of the eight lithofacies are different. The C-2, S-1, S-2, S-3, and M-2 samples are characterized by high porosity and dominated by macropores, while the C-1, C-3, and M-1 samples are dominated by mesopores. S-1 is currently regarded as the most favorable lithofacies with the highest hydrocarbon potential and abundant organic pores, and M-1 were regarded as the least-promising lithofacies. The distribution characteristics of shale facies in four sub-members are quite different, and the most favorable lithofacies for shale oil exploration were mainly distributed in Ek₂ ³.