**1. Introduction**

Crude oil and gas exploration in the Junggar Basin began in 1909 and has a history of more than 100 years. As of 2013, the proven crude oil and natural gas reserves in the Junggar Basin were 23.34 × 10<sup>8</sup> t and 1972 × 10<sup>8</sup> m3, respectively [1]. The Junggar Basin is one of the most important onshore oil and gas production sites in China [1,2]. Although the current oil and gas exploration in the Junggar Basin is dominated by conventional reservoirs, the exploration of unconventional shale oil, represented by the Middle Permian Lucaogou Formation (P2l) in the Jimsar Depression, the Middle Permian Pingdiquan Formation (P2p) in the Wucaiwan–Shishugou area, and the Lower Permian Fengcheng Formation (P1f) in Fengcheng area of the northwestern margin, has shown promising results [3–5].

**Citation:** He, W.; Liu, Y.; Wang, D.; Lei, D.; Liu, G.; Gao, G.; Huang, L.; Qi, Y. Geochemical Characteristics and Process of Hydrocarbon Generation Evolution of the Lucaogou Formation Shale, Jimsar Depression, Junggar Basin. *Energies* **2022**, *15*, 2331.

https://doi.org/10.3390/en15072331

Academic Editors: Hossein Hamidi

Received: 6 February 2022 Accepted: 21 March 2022 Published: 23 March 2022

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Compared with conventional oil reservoirs, shale oil reservoirs are significantly different, and the main differences are as follows: (1) source–reservoir integration and near-source or intra-source accumulation; (2) extremely low porosity and permeability; (3) the ambiguous boundary conditions of the trap; and (4) Darcy's law of seepage flow not being met during the secondary migration of oil and gas [6–8]. At present, this type of integrated source–reservoir shale oil and gas exploration is still in its infancy in China, and the predicted resource amount is around 11 × 10<sup>9</sup> t, of which Junggar Basin alone accounts for 29 × 10<sup>8</sup> t (26.4% of the total) [6]. Unlike foreign shale oil, which is dominated by marine deposits, the shale oil in China is dominated by lacustrine deposits. The source rocks in the lake are typically thick, with a small distribution, and their porosity (<10%) and permeability (<0.1 mD) are lower than those in the maritime environment [6,9]. The P2l lacustrine source rocks in the Jimsar Depression, located in the eastern part of the Junggar Basin, can be regarded as the world's largest lacustrine mudstone in terms of its thickness and organic matter abundance (Figure 1a,b) [10]. At present, this area is one of the main areas of shale oil exploration in China, with a predicted resource amount of 7.02 × 10<sup>8</sup> t [1,6].

**Figure 1.** Overview of the petroleum geology of the Jimsar Depression. (**a**) The lithology column of Lucaogou Formation; (**b**) The location of Jimsar Depression in the Junggar Basin; (**c**) Detailed structural map of the Jimsar Depression.

The organic matter abundance and hydrocarbon generation capacity of source rocks are the most important factors used for evaluating the quality of shale oil [8]. Previous researchers had studied P2l shale oil in the Jimsar Depression, mainly focusing on the sedimentary facies and lithology of the P2l shale [11], oil and gas source comparison [12], the heterogeneity of the source rocks [13], and the hydrocarbon accumulation process [14,15]. These studies have greatly enriched research on unconventional oil and gas, and promoted the exploration and development of shale oil in the Jimsar Depression. However, current research on the characteristics of hydrocarbon generation and the evolution of P2l source rocks in the study area is still in a relatively early stage. Based on the analysis of the static hydrocarbon generation capacity of the P2l source rocks, in this study a gold-tube thermal simulation experiment was conducted in a closed system. Based on this and the two-dimensional basin simulation, the hydrocarbon generation mechanism, hydrocarbon expulsion efficiency, and the evolution process were systematically studied, providing strong support for the evaluation of continental shale oil and gas.

#### **2. Geologic Background**

The Junggar Basin is located in the Xinjiang Uygur Autonomous Region in northwestern China, with an area of approximately 1.3 × 10<sup>5</sup> km2. It can be divided into a total of six primary structural units, including two major depressions (the Central Depression and the Wulungu Depression), three major uplifts (the Luliang Uplift, the Western Uplift, and the Eastern Uplift), and a thrust-fold belt (the North Tianshan Thrust-Fold Belt) (Figure 1b) [16,17]. The study area is a secondary structural unit in the Eastern Uplift in the Jimsar Depression, bounded by the Shaqi Uplift to the north, the Santai Uplift to the west, the Fukang Fault Zone to the south, and the Guxi Uplift to the east, and has an area of around 1500 km<sup>2</sup> (Figure 1c) [1,18]. The depression has undergone multiple tectonic movements (Hercynian, Indosinian, Yanshanian, and Himalayan movements). There are huge, thick Paleozoic–Cenozoic sedimentary rocks overlying the Precambrian crystalline basement and Paleozoic metamorphic basement. At their thickest, the rocks exceed 5000 m, and the deposits in the depression gradually become thinner from west to east (Figure 1c) [1,17].

The Middle Permian Lucaogou Formation in the Jimsar Depression was formed in a saline lacustrine basin environment after the relict sea was closed [1,19], and it is widely distributed in the depression, with an area of approximately 1278 km2, a thickness of 200–350 m, and a maximum thickness of >500 m (Figure 1a) [20]. The Lucaogou Formation is a set of lacustrine deposits that has recorded multiple complete cycles of lake water depth fluctuations from shallow to deep, and can be further divided into the upper sub-member (P2l 2) and the lower sub-member (P2l 1) (Figure 1a). Previous studies have shown that the Lucaogou Formation contains a set of lacustrine source rocks that are rich in organic matter [15,18,21]. Their lithology includes gray–black mudstone, dolomitic mudstone, siltstone, and dolomite [15,21]. The main lithology of the reservoir includes dolomite, dolomitic siltstone, sandy dolomite, diabase, and a small amount of tuff [11,17]. The storage space of the reservoir is dominated by nanopores and microfractures, the pore throat radius is 100–500 nm, the porosity is 2.5–16.27%, and the permeability is less than 0.1 mD [6].

#### **3. Samples and Analytical Methods**
