Geochemical characterization and artificial thermal maturation of kerogen density fractions from the Eocene Huadian oil shale, NE China
Introduction
Oil shales are an important alternative energy source, following retorting to produce liquid hydrocarbons, estimated to be the equivalent of 2.9 trillion barrels of oil (Knaus et al., 2010). In situ retorting technology, which breaks down the kerogen in oil shales to release volatile hydrocarbons and cracks the kerogen into lower molecular hydrocarbon products, has been applied commercially for oil shale exploitation. The composition and the hydrocarbon generation capacity of the kerogen in oil shales are both fundamental for the evaluation of this resource. Kerogen is a mixture of highly resistant bio- and geomacromolecules and these have different chemical behaviors related to the different chemical structures of their bio-precursors (e.g., from higher land plants and algae). Maceral composition analysis can provide a measure of the relative contents of the organic matter sources in shales.
The hydrocarbon generation potential of each maceral is another key parameter for shale oil evaluation. However, it is a challenge to evaluate the hydrocarbon generation potential of specific macerals because of the mixed nature of kerogen and the fine-grained characteristics of many rocks, including the organic fractions. Fortunately, different macerals have different density properties due to their different chemical characteristics (aliphatic, alicyclic, aromatic and heteroatomic contents) (Hartgers et al., 1995) and such differences can be exploited by using density separation.
Many researchers have studied the separation and preparation of macerals to obtain pure density fractions of a particular maceral (Crelling et al., 1992, Nip et al., 1992, Van Krevelen, 1981, Dyrkacz and Bloomquist, 2001). Van Krevelen (1981) first used a zinc chloride solution to separate single macerals from coals and later Karas et al. (1985) carried out the separation of macerals using density gradient centrifugation (DGC). A review by Crelling et al. (1992) highlights a more practical approach for the separation of coal macerals. Although DGC methods have been applied to the study of both oil shale and coal since about 1983, they have not been used commonly for shale samples (Silbernagel et al., 1986, Dyrkacz and Bloomquist, 2001, Machnikowska et al., 2002, Jorjani et al., 2013, Zhang et al., 2016, Yan et al., 2019). A few studies have tried to isolate marine amorphous organic matter (AOM) from Paleozoic and Mesozoic Type II kerogens (Kruge et al., 1989, Taulbee et al., 1990, Stankiewicz et al., 1994, Stankiewicz et al., 1996).
Oil shales and coals have large differences in maceral compositions and mineral contents. Coal is mainly composed of plant-derived macerals, chiefly vitrinite and inertinite, with some liptinite, such as cutinite and sporinite originating from plants. TOC contents can be > 80% with little mineral content. Oil shale, including those deposited in marine and lacustrine settings, is also an organic-rich rock, but has a much lower TOC content, normally < 30%. According to Pickel et al. (2017), macerals in marine oil shales are dominated by bituminite, while lamalginite is a major component in lacustrine oil shales, especially in passive rifted margins and in intermontane basins in North America, Australia, Asia and Europe. Besides lamalginite, some telalginite and plant-derived macerals are normally found in the lacustrine oil shales. Alginite, including lamalginite and telalginite, is an aliphatic-rich liptinite maceral that can be separated with difficulty using dense liquids, such as aqueous cesium chloride (Dyrkacz and Horwitz, 1982), or carbon tetrachloride and bromoform (Das, 2001), which are hydrophilic liquids. According to Arnold and Aplan (1988), hydrophobicity decreases in the order of liptinite > vitrinite > inertinite, with these three maceral groups having typical contact angles of 90–130°, 60–70° and 25–40°, respectively (Barraza and Piñeres, 2005).
Compared to coals, oil shale is a complicated heterogeneous material composed of varied organic matter and mineral assemblages; variations in the composition of individual maceral organic matter in shales can significantly influence the geochemical characterization of the bulk organic matter. Each maceral has different physical and chemical characteristics and the relative proportion of each type of maceral has a direct contribution to the hydrocarbon potential of the shales. Chemical characterization of individual macerals has allowed the recognition of specific biological precursors contributing to the shale (Nip et al., 1992, Hartgers et al., 1994). Thus, separation and analysis of pure maceral fractions can enhance our understanding of the geochemical and pyrolysis properties of organic matter in oil shales.
The Huadian oil shale is one of the key resources for in situ oil shale retorting in China. This oil shale, dated to the middle Eocene based on mammalian fauna (Manchester et al., 2005), was deposited when the Huadian lake expanded. It has characteristics of high oil yield (10–12 wt%) and an ash content of 54–62 wt% (Sun et al., 2013). The macerals in this shale consist mainly of telalginite, lamalginite and some detrovitrinite (Xie et al., 2014) and this makes it appropriate to study the float-sink method for maceral separation. Through the study of carefully separated macerals, it is possible to better understand the chemical parameters of individual macerals and to investigate the mechanism and hydrocarbon generation potential in oil shales.
Section snippets
Geological setting
The Huadian Basin is located in the southeastern part of Jilin Province, northeastern China. It occurs along the Dunhua–Mishan Fault Zone and is characterized by asymmetric half-graben structures and formed as a consequence of dextral strike-slip faulting during the Eocene (Sun et al., 2013). The Huadian Formation contains up to 1500 m of basin fill and overlies various basement units, such as granite and Lower Paleozoic and Permo-Carboniferous sedimentary rocks. The formation contains three
Materials and methods
The original rock sample BTZ-2 was analyzed using a Rock-Eval 6 (Vinci Technologies, France) and organic petrography. The carbon isotope value of whole kerogen from the rock (the parent kerogen) had been measured previously. The kerogen density fractions separated from the parent kerogen were analyzed by Rock-Eval 6, organic petrography, micro-FTIR (Fourier transform infrared) spectroscopy and carbon isotope mass spectrometry. All these measurements were performed at the State Key Laboratory of
Rock-Eval pyrolysis and organic petrology of the parent oil shale
The oil shale BTZ-2 has a high TOC content (21.5%), high S2 value (165 mg HC/g rock) and high hydrogen index (766 mg HC/g TOC), with low S1 and oxygen index values (Table 1), indicating Type I kerogen (Sinninghe Damsté et al., 1993) and good hydrocarbon generation potential. The results are consistent with those of Xie et al. (2014) for the analysis of the Huadian oil shale from Guanglangtou district (Fig. 1).
Maceral classification schemes for coal and organic petrology (ICCP, 2001) have been
Is the non-fluorescing maceral, vitrinite or pre-oil solid bitumen?
Maceral composition is important for evaluating the hydrocarbon generation potential of a shale. In the Huadian Basin, algal blooms and an oxygen-depleted depositional environment resulted in the accumulation of 13 thin (<7 m) oil shale layers (Strobl et al., 2015). Macerals derived from algae (including lamalginite and telalginite) are dominant in the Huadian oil shales and the variations of oil shale quality among different layers are due to variable proportions of terrigenous organic matter.
Conclusions
Isolated maceral kerogen groups have been obtained from the Eocene Huadian oil shale using float-sink separation on chemically demineralized kerogen. The geochemical characteristics of different density fractions show that the hydrocarbon generation potential (represented by Rock-Eval S2 and HI and amounts of aliphatic compounds determined by FTIR), decreases with increasing kerogen density. The δ13C results show slight variations within these density fractions. The lightest density fraction
Declaration of Competing Interest
The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.
Acknowledgements
This research was supported by the National Natural Science Foundation of China (Grant No. 41603047 and 41972163), National Science and Technology Major Project of the Ministry of Science and Technology of China (Grant No.2017ZX05049-001) and Liu Baoju Youth Earth Science Foundation (Grant No. DMSM2017027) and the China National Basic Research Program (973 Programs) (Grants No. G 2014CB239101). Prof. Jinzhong Liu, Mr. Caiming Zhang and Ms. Xiaoqing Rui are thanked for experimental assistance.
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