Paleoenvironment and Hydrocarbon Potential of Salinized Lacustrine Shale with High Terrigenous Input in the Paleogene Biyang Depression (East China): Evidence from Organic Petrography and Geochemistry

Abstract

Salinized lacustrine shale (SLS) represents a frontier in the global quest for unconventional hydrocarbon resources. The impact of terrigenous input, which includes terrigenous organic matter (OM) and detrital matter, on the deposition and hydrocarbon potential of SLS is still controversial. Here, we examine this issue using the newly discovered SLS within the Paleogene Biyang Depression, employing a combination of organic petrographic and geochemical analyses. A high influx of terrigenous input (terrigenous OM and detrital matter) promotes the formation of SLS. On the one hand, terrigenous higher plants emerge as the primary source of OM in the SLS, as indicated by the dominance of terrigenous macerals (e.g., terrigenous liptinite) and the abundance of plant-derived biomarkers (e.g., tricyclic terpanes). Additionally, a portion of the OM may originate from bacteria. On the other hand, the rapid input of detrital matter improves the preservation of OM, resulting in the deposition of SLS with high total organic carbon (TOC) contents and low hydrogen index (HI) values. The findings of this study contribute to a deeper understanding of SLS deposition and provide guidance for regional hydrocarbon exploration.

1. Introduction

With the growing demand for energy and the dwindling conventional oil reserves, both the exploration and exploitation of unconventional oil reservoirs become imperative. Among these, salinized lacustrine shale systems stand out for their distinct characteristics, presenting both challenges and opportunities for oil exploration and exploitation [1,2]. Salinity exerts a profound influence on sedimentation, diagenesis, and organic matter preservation, ultimately shaping the composition and distribution of hydrocarbon resources [3]. As such, unravelling the complex relationships between organic matter, depositional environments, and hydrocarbon potential in salinized lacustrine shale is essential for resource assessment and exploration strategies [4]. Note that the term ‘shale’ in this study refers to fine-grained sediments include clay particles (<4 μm), with varying proportions of silt-sized floating grains (up to 62.5 μm) of biogenic and detrital origin [5,6].

Salinized lacustrine shale was extensively deposited during the Paleogene period worldwide, with examples including the Green River Formation of Wyoming in the United States [1]; the Salt IV Formation of the Mulhouse Basin [7] and the Bituminous Limestone of the Camargue Basin in France [8]; the Brown Shale Formation of the Central Sumatra Basin in Indonesia [9]; the Xiaganchaigou Formation of the Qaidam Basin in Northwestern China [10]; and the Kongdian and Shahejie formations of the Bohai Bay Basin [11,12], the Qianjiang Formation of the Jianghan Basin [13], the Funing Formation of the Subei Basin (Eastern China) [14], and the Hetaoyuan Formation of the Nanxiang Basin in Eastern China [15]. Many of these salinized lacustrine shales are renowned for their potential as prolific hydrocarbon source rocks, as well as sources and reservoirs for shale oil resources [4]. Saline lacustrine basins harbor diverse biological organisms and demonstrate significant biological activities. This activity plays a role in enriching the sedimentary organic matter within the basins. The enrichment process includes biological bloom, primary productivity, water stratification, and organic matter preservation. Water stratification in saline lacustrine basins facilitates the preservation of sedimentary organic matter by inducing bottom water anoxia [16].

The Biyang Depression within the Nanxiang Basin represents the first shale oil breakthrough in Eastern China. The Well BYHF1, situated at the center of the depression, achieved a peak daily oil production of 24.2 tons [17]. However, oil production from the well declined rapidly, dropping to less than 5 tons per day after only 100 days [18]. Aside from potential hydraulic fracturing difficulties, the heterogeneity of salinized lacustrine shale is a major contributor to the rapid decline in production [19]. Consequently, in recent years, alongside shale oil exploration and exploitation in the Eh₃³ and Eh₃² strata, which contain salinized lacustrine shale with the highest quality and the largest thickness, preliminary exploration of deeper shale strata (e.g., Eh₃⁶ and Eh₃⁵) in the depression is also planned [19]. However, there is still a lack of studies on organic matter source, depositional environment, and hydrocarbon potential for these deeper shale strata, significantly impending further shale oil exploration efforts in the Biyang Depression.

This article presents the results of a comprehensive organic petrographic and geochemical study conducted on the newly explored, deeper salinized lacustrine shale strata in the Paleogene Biyang Depression. Through integrated analyses, our objective was to elucidate the origin of organic matter, characterize the depositional environment of the shale strata, and assess their implications for hydrocarbon prospectivity. The findings of this study not only contribute to the understanding of salinized lacustrine shale systems in East China but also provide valuable insights into hydrocarbon exploration and resource assessment in similar geological settings worldwide.

2. Geological Setting

The Nanxiang Basin, situated in East China, is a sedimentary rift basin covering approximately 1.7 × 10⁴ km² (Figure 1A). It includes the Xiangzao, Nanyang, and Biyang depressions, as well as the Shigang, Xinye, Tanghe, and Sheqi uplifts (Figure 1B). The hydrocarbon-rich Biyang Depression spans nearly 1000 km² and boasts conventional oil reserves of 306 million tons and shale oil reserves of 285 million tons [16,20]. The depression takes the form of a half-graben rift, further divided into the northern slope belt, central deep sag, and southern steep slope belt (Figure 1C,D).

There are four distinct episodes that comprise the structural evolution of a depression. (Episodes I−IV; Figure 2) [21,22,23]. Episode I signifies the early initial rifting stage, extending from the Paleocene to the very Early Eocene. The Yuhuangding Formation (Ey) was deposited during this phase, characterized by the prevalence of yellow-to-red coarse-grained sandstone interbedded with mudstone, suggesting fluvial facies. Episode II represents the late initial rifting stage and aligns with the deposition of the Early Eocene Dacangfang Formation (Ed). The Ed is marked by an abundance of purple-red coarse- and medium-grained sandstone and grey mudstone, with the occurrence of gypsum at the top, deposited in semi-saline lacustrine environments. The peak of the rifting stage, Episode III, spans the Middle-to-Late Eocene and is denoted by the third and second members of the Hetaoyuan Formation (Eh₃ and Eh₂). The Eh₃ mainly comprises grey-to-dark-grey shale interbedded with carbonate rock, deposited in deep-to-semi-deep saline lacustrine environments. The Eh₂ consists of greyish-green-to-light-grey mudstone, carbonate rock, and fine-grained sandstone, indicating shallow lacustrine environments. Trona is occasionally found interbedded with dolostone in both the upper Eh₃ and Eh₂. The late rifting stage, Episode IV during the Oligocene, coincides with the deposition of the first member of the Hetaoyuan Formation (Eh₁) and the Liaozhuang Formation (El). The Eh₁ exhibits greyish-green-to-light-grey mudstone interbedded with medium and fine sandstone, suggesting shoreline shallow lake environment. The El is characterized by brown-red fine-grained sandstone, mudstone, and gypsum, signifying a transition from a riverine environment to a saline-lake environment.

The Eh₃ interval is further subdivided into eight units, denoted as Unit VIII to Unit I from bottom to top (Eh₃⁸ to Eh₃¹; Figure 2). This study focuses on the Units VI and V (Eh₃⁶ and Eh₃⁵), deposited in a deep/semi-deep lake, which comprises salinized lacustrine shale, and they have been prominent targets in recent hydrocarbon exploration efforts [20].

3. Materials and Methods

In the exploration well A3, a total of twenty fine-grained sediments were collected from depths ranging from 3195.2 to 3383.6 m, which is located in the southern part of the central deep sag (Figure 1C). All samples were analyzed for total organic carbon (TOC; wt. %) and Rock-Eval pyrolysis. A Leco CS-230 instrument (LECO Corporation, St. Joseph, MI, USA) was employed to determine the TOC contents after the acidification of samples to eliminate carbonate. A Rock-Eval 6 instrument (Vinci Technologies, Nanterre, France) was used for characterizing free hydrocarbons (S₁; mg HC/g rock), hydrocarbons cracked from kerogen (S₂; mg HC/g rock), and the maximum temperature of hydrocarbon generation (T_max; °C).

Ten samples were selected for the organic petrographic analysis. Polished sections were observed using a Nikon microscope (Nikon Corporation, Tokyo, Japan) equipped with reflected and fluorescent light, as well as 20× and 50× oil-immersion lenses. Mean random vitrinite reflectance of six samples was determined in accordance with an established procedure [24].

Major and trace elemental compositions were analyzed in 19 samples. The determination of major-element oxide contents was conducted using a Shimadzu XRF-1800 instrument (Shimadzu, Kyoto, Japan), while a Thermo Fisher Scientific Element XR ICP-MS (Thermo Fisher Scientific, Waltham, MA, USA) was used to determine the concentration of trace elements. To ensure analytical reliability, both standard materials and duplicate determination of samples were employed.

A total of 11 samples underwent biomarker analysis in this study. Initially, powdered samples were subjected to 72-h extraction with chloroform. Asphaltenes were then precipitated from an 80:1 (v:v) solution of hexane and dichloromethane (DCM) and subsequently separated via centrifugation. Soluble components of hexane were further divided into saturates, aromatics, and NSO compounds by silica gel and alumina column chromatography (Al₂O₃). This separation process involved successive elution with hexane, a DCM–hexane solution (2:1, v:v), DCM, and methanol (MeOH). Subsequently, the saturated and aromatic fractions were subjected to analysis using a gas chromatograph equipped with a 30 m DB-5MS fused silica column (inner diameter 0.25 mm; film thickness 0.25 μm) coupled to an Agilent 7890-5977B gas chromatography–mass spectrometry (GC-MS) system (Agilent, Santa Clara, CA, USA). The oven temperature was programmed to increase from 70 °C to 300 °C at a rate of 3 °C/min, followed by an isothermal period lasting 30 min. The mass spectrometer operated in the electron ionization mode, covering a scan range from mass to charge (m/z) of 50 to m/z 650, with a total scan time of 0.7 s.

4. Results

4.1. Bulk Geochemistry

The Eh₃⁵ shale contains TOC contents ranging from 0.3 wt. % to 1.8 wt. %, which is lower than that of the Eh₃⁶ shale (0.8−2.2 wt. %;

Table 1. Bulk geochemical parameters, maceral compositions, vitrinite reflectance, and elemental ratios for the Eh36 and Eh35 shale from the Biyang Depression.

Strata	Depth (m)	TOC (wt. %)	S1 + S2 (mg/g)	HI (mg/g TOC)	Tmax (°C)	PI	OSI (mg/g TOC)	Maceral Compositions (vol. %)					102 × P/Al	Babio	B/ Ga	Sr/ Ba	UEF	MoEF	TiO2	Al2O3
								Telalg	Ter Lip	Lipto	Vitr	Iner
Eh35	3195.2	1.0	1.8	149	456	0.18	33	0.3	0.7	0.1	0.9	0.6
	3196.2	0.8	1.6	162	448	0.19	37						2.0	241	1.0	2.7	4.2	8.6	0.65	15.3
	3205.9	0.6	1.2	130	452	0.29	52						0.7	181	0.5	2.5	1.7	2.1	0.73	17.7
	3206.5	0.8	1.6	148	442	0.31	65	0.1	0.2	0.2	0.4	0.1	0.8	238	0.9	2.6	1.6	4.3	0.62	14.4
	3207	0.4	0.7	123	455	0.37	71						1.0	285	2.6	3.5	3.2	1.5	0.28	6.7
	3208.5	0.9	1.7	142	451	0.24	44	0.3	0.2	0.1	0.5	0.4	0.7	353	1.5	2.8	2.8	4.4	0.46	10.5
	3209.7	1.3	2.8	166	455	0.22	46	0.4	0.0	0.1	1.1	0.6	1.4	82	0.9	3.8	3.7	8.9	0.59	16.1
	3210.2	1.8	4.1	162	444	0.28	62	0.8	0.8	0.2	1.9	0.8	2.4	298	0.8	2.1	4.3	18.4	0.65	15.7
	3212	0.6	1.0	126	447	0.18	27						1.9	367	2.8	2.5	4.9	7.7	0.27	7.3
	3213	1.0	1.9	154	454	0.22	43						1.3	125	0.5	2.6	3.5	4.9	0.76	18.4
	3214	0.3	0.5	100	431	0.39	63						1.0	172	0.7	1.9	1.4	15.5	0.72	15.9
	3214.5	1.1	2.2	151	442	0.23	46							191	1.8	1.7	7.0	12.5	0.56	13.8
Eh36	3342.6	2.2	2.9	81	443	0.40	54						0.8	57	0.8	3.1	3.8	19.8	0.60	14.8
	3342.7	2.0	2.3	71	442	0.37	42	0.3	0.6	0.1	1.6	0.7	1.1	46	0.6	4.6	3.6	28.6	0.66	15.7
	3349.2	1.5	2.0	93	445	0.29	39	0.2	0.2	0.2	1.2	0.6	0.9	87	1.7	5.4	5.2	34.0	0.53	13.4
	3349.6	1.6	2.5	98	459	0.35	54	0.3	0.5	0.2	2.0	0.5	0.8	277	1.0	3.2	2.7	12.2	0.66	12.5
	3357.2	1.2	1.8	111	462	0.28	43	0.1	0.2	0.2	0.7	0.5		232	0.8	3.2	9.8	27.4	0.52	12.8
	3357.6	0.8	1.3	119	452	0.27	44						1.1	15	1.1	2.8	4.4	24.3	0.65	15.7
	3382.8	1.4	2.1	91	459	0.38	55						1.7	97	1.5	3.8	3.7	14.9	0.50	13.2
	3383.6	1.6	2.2	81	439	0.42	58	0.3	0.5	0.1	2.5	0.4	0.7	76	1.0	2.9	2.8	19.3	0.56	15.3

Tel = telalginite. Ter Lip = terrigenous liptinite. Lipto = liptodetrinite. Vitr = vitrinite. Iner = inertinite.

). The S₁+S₂ values span 1.3−2.5 mg HC/g rock and 0.5−4.1 mg HC/g rock in the Eh₃⁶ and Eh₃⁵ shale, respectively. The hydrogen index (HI = 100 × S₂/TOC) exhibits low values in the Eh₃⁶ shale (71−119 mg HC/g TOC) and high values in the Eh₃⁵ shale (100−166 mg HC/g TOC). A comparable range of T_max values are observed in the Eh₃⁶ and Eh₃⁵ shale, ranging from 439 to 462 °C and from 431 to 456 °C, respectively. Type II₂ kerogen predominates in the Eh₃⁵ shale, while type III kerogen dominates the Eh₃⁶ shale, according to cross-plots of HI versus T_max and S₂ versus TOC (Figure 3).

4.2. Organic Petrography and Vitrinite Reflectance

The volume percentages (vol. %) of maceral in the Eh₃⁶ and Eh₃⁵ shale are less than 5.0 vol. % (Figure 4; Table 1). The Eh₃⁵ shale contains a larger concentration of telalginite (including degraded telalginite) than the Eh₃⁶ shale, resulting in higher HI values (Figure 3A). Telalginite appears as a unicellular spherical or almost-round shape with yellow-to-orange fluorescence (Figure 5A), whereas degraded telalginite has indistinct boundaries and diminished fluorescence (Figure 5B). Terrigenous liptinite, which is dominated by sporinite and cutinite, ranges from 0.2 to 0.6 vol. % and less than 0.1 to 0.8 vol. % in the Eh₃⁶ and Eh₃⁵ shale, respectively. Sporinite is distinguished by its elongated thread-like or fusiform shape with yellow-orange fluorescence, whereas cutinite has a serrated edge and poor fluorescent properties (Figure 5C). Both intervals contain trace amounts of liptodetrinite (<0.2 vol. %), which has a small and irregular shape with yellow fluorescence (Figure 5A,C). Among macerals, vitrinite is most prevalent, with values in the Eh₃⁶ shale ranging from 0.7 to 2.5 vol. %, and in the Eh₃⁵ shale from 0.4 to 1.9 vol. %. The spherical shape of vitrinite suggests that it may transport across long distances, probably suggesting deep-to-semi-deep lacustrine environments (Figure 5D). Inertinite is found in needle-shaped grains and is most likely broken fusinite or semifusinite (Figure 5E). Furthermore, a minor amount of framboidal and semi-cube pyrite is observed, indicating that there were possibly different stages of pyrite formation (Figure 5F). The average values of random vitrinite reflectance (%Rr) vary between 0.9 and 1.0% (Figure 4; Table 1).

4.3. Elemental Compositions

The elemental metrics used as paleoenvironmental indicators are listed in Table 1, including the P/Al ratio; biogenic Ba value (Ba_bio = Ba_tot−Al × (Ba/Al)_detrital, where Ba_tot and Al are the total amounts of Ba and Al, and (Ba/Al)_detrital is estimated based on the cross-plot of Ba versus Al) [25]; Sr/Ba and B/Ga ratios; enrichment factors of U and Mo (TE_EF = (TE/Al)_sample/(TE/Al)_UCC [26], where TE stands for the U or Mo concentrations, and UCC refers to elemental composition of the Upper Continental Crust) [27]; and TiO₂ and Al₂O₃ contents.

The 100 × P/Al ratios in the Eh₃⁶ and Eh₃⁵ shale range from 0.7 to 1.7 and from 0.7 to 2.4, respectively. The Eh₃⁶ shale has Ba_bio levels ranging from 15 to 277 ppm, which is less than the Eh₃⁵ shale’s range, which is from 82 to 367 ppm. The Eh₃⁶ and Eh₃⁵ shale have Sr/Ba ratios that range from 0.6 to 1.7 and from 0.5 to 2.8, respectively. The B/Ga ratios of the Eh₃⁶ shale (2.8–5.4) are greater than those of the Eh₃⁵ shale (1.7–3.8). The U_EF and Mo_EF values exhibit the same pattern, with higher values in the Eh₃⁶ shale (U_EF: 2.7–9.8; Mo_EF: 12.2–34.0) and lower values in the Eh₃⁵ shale (U_EF: 1.4–7.0; Mo_EF: 1.5–18.4). Regarding the TiO₂ and Al₂O₃ contents, the Eh₃⁶ shale values range from 0.50 to 0.66 wt. % and from 12.5 to 15.7 wt. %, respectively, while in the Eh₃⁵ shale, they range from 0.27 to 0.76 wt. % and from 6.7 to 18.4 wt. %, respectively (Figure 6).

4.4. Biomarkers

The Eh₃⁶ and Eh₃⁵ shale contain varying levels of chloroform bitumen ‘A’, ranging from 0.10 to 0.17 wt. % and from 0.08 to 0.16 wt. %, respectively (

Table 2. Chloroform bitumen ‘A’, group composition, and biomarker ratios for the Eh36 and Eh35 shale from the Biyang Depression.

Strata	Depth (m)	A (wt. %)	B (wt. %)	C	D	E	F	G	H	I	J	K	L	M	N	O	P	Q	R (%)	S (%)	T (%)
Eh35	3195.2	0.10	85.8	3.4	1.31	0.44	0.36	0.88	1.48	0.24	0.60	0.60	0.46	1.66	0.52	0.67	0.88	0.84	32	46	22
	3196.2	0.09	82.0	4.4	1.12	0.39	0.33	0.70	1.43	0.37	0.64	0.59	0.71	2.21	0.52	0.66	0.87	0.96	35	42	23
	3206.5	0.08	85.2	2.9	1.05	0.36	0.38	1.11	1.71	0.37	0.62	0.59	0.51	1.64	0.51	0.67	0.91	0.86	41	29	30
	3208.5	0.11	82.7	3.9	1.12	0.38	0.34	1.09	1.47	0.38	0.63	0.58	0.64	2.32	0.51	0.66	0.96	0.93	31	41	28
	3209.7	0.14	85.0	3.4	0.98	0.42	0.29	0.96	1.66	0.21	0.73	0.61	0.5	1.50	0.54	0.66	1.01	0.91	36	36	28
	3210.2	0.16	88.2	3.0	1.37	0.51	0.33	0.88	1.54	0.32	0.57	0.57	0.51	1.85	0.51	0.63	0.86	0.89	28	51	21
Eh36	3342.7	0.13	88.5	3.2	1.01	0.28	0.28	1.80	2.11	0.47	0.76	0.59	0.64	1.89	0.57	0.70	0.95	0.95	34	30	36
	3349.2	0.17	94.4	4.5	0.99	0.12	0.13	1.63	2.28	0.51	0.68	0.60	0.59	2.64	0.54	0.71	0.97	0.98	28	41	31
	3349.6	0.11	89.7	2.8	0.87	0.24	0.17	1.33	1.66	0.46	0.67	0.61	0.71	2.81	0.58	0.68	1.07	1.02	32	30	38
	3357.2	0.10	87.1	3.8	0.89	0.31	0.32	1.13	1.87	0.38	0.75	0.58	0.82	2.65	0.53	0.67	1.01	0.95	24	28	48
	3383.6	0.10	87.1	3.1	0.91	0.2	0.22	1.21	1.97	0.66	0.72	0.6	0.67	2.43	0.55	0.7	0.89	1.00	22	27	51

A = chloroform bitumen ‘A’. B = sum of saturated and aromatic hydrocarbon fractions. C = saturated/aromatic hydrocarbons. D = Pr/Ph. E = Pr/n-C₁₇. F = Ph/n-C₁₈. G = rearranged drimanes/drimanes. H = 8β(H)-homodrimane/8β(H)-drimane. I = C₂₄ tetracyclic/C₂₆ tricyclic terpanes. J = Ts/(Ts+Tm). K = C₃₁ homohopane 22S/(22S+22R). L = gammacerane/ab C₃₀ hopane. M = ααα C₂₉/C₂₇ sterane (20R). N = ααα C₂₉ steranes 20S/(20S+20R). O = ββ/(ββ+αα) C₂₉ steranes. P = MPI-1. Q = TNR-2. R = fluorene. S = dibenzofuran. T = dibenzothiophene. The sum of fluorene, dibenzofuran, and dibenzothiophene is 100%.

). The Eh₃⁶ shale (87.1–94.4 wt. %) contains higher proportions of hydrocarbon fractions compared to the Eh₃⁵ shale (82.0–88.2 wt. %). Both intervals exhibit a prevalence of saturated over aromatic fractions, with saturated/aromatic hydrocarbon ratios varying between 2.8 and 4.5.

The Eh₃⁶ and Eh₃⁵ shale are dominated by short-chain n-alkanes (n-C_17-23) with a predominance of odd over even (Figure 7A). The acyclic isoprenoid pristane (Pr) exhibits a higher abundance compared to phytane (Ph), with Pr/Ph ratios ranging from 0.87 to 1.01 in the Eh₃⁶ shale and from 0.98 to 1.37 in the Eh₃⁵ shale (Table 2). The Eh₃⁶ shale has ratios of Pr/n-C₁₇ and Ph/n-C₁₈ that fall between 0.12 and 0.31 and between 0.17 and 0.32, respectively. On the other hand, the Eh₃⁵ shale exhibits two ratios that vary from 0.36 to 0.51 (Pr/n-C₁₇) and from 0.29 to 0.38 (Ph/n-C₁₈), respectively. Drimanes, labdanes, methylheptadecanes, and b-carotane are also assigned in the TIC chromatogram (Figure 7A).

The mass chromatograms of drimanes (m/z 123; Figure 7B) reveal relatively high abundance of 8a(H)-drimane, followed by rearranged drimanes, 8β(H)-homodrimane, 8β(H)-drimane, and bisabolane. The Eh₃⁶ shale has ratios ranging from 1.13 to 1.80 for rearranged drimanes/drimanes and from 1.66 to 2.28 for 8β(H)-homodrimane/8β(H)-drimane. In contrast, two ratios in the Eh₃⁵ shale fall between 0.70 and 1.11 and between 1.43 and 1.71, respectively (Table 2).

The mass chromatograms of terpenoids (m/z 191; Figure 7C) illustrate that tricyclic terpanes are assigned within the range from C₂₁ to C₃₀ (excluding C₂₂ and C₂₇), along with C₂₄ tetracyclic terpane. Short-chain tricyclic terpanes (<C₂₄) are more abundant compared to their longer-chain homologues. The ratios of C₂₄ tetracyclic/C₂₆ tricyclic terpanes vary from 0.38 to 0.66 in the Eh₃⁶ shale and from 0.21 to 0.38 in the Eh₃⁵ shale (Table 2). The non-aromatic cyclic triterpenoids are primarily composed of hopanoids. The most abundant hopanoid is 17α, 21β C₃₀ hopane (C₃₀H), followed by 17a, 21β C₂₉ norhopane, 17α, 21β C_31-32 homohopane (22S+22R), 17β, 21α C_29-30 moretane, and 18α(H)-trisnorhopane (Ts) and 17α(H)-trisnorhopane (Tm). The ratios of Ts/(Ts+Tm) and C₃₁ homohopane 22S/(22S+22R) isomers range from 0.67 to 0.76 and from 0.58 to 0.61 in the Eh₃⁶ shale, while in the Eh₃⁵ shale, these ratios vary between 0.57 and 0.73 and between 0.57 and 0.61, respectively. Gammacerane (Ga) is also assigned in m/z 191 mass chromatograms, with Ga/C₃₀H ratios of 0.59–0.82 in the Eh₃⁶ shale and 0.50–0.71 in the Eh₃⁵ shale.

The mass chromatograms of steroids (m/z 217; Figure 7D) indicate the highest abundance of C₂₉ regular steranes, followed by C₂₇ and C₂₈ regular steranes. The ratios of ααα C₂₉/C₂₇ sterane (20R) range from 1.89 to 2.64 in the Eh₃⁶ shale and from 1.50 to 2.32 in the Eh₃⁵ shale (Table 2). Within the range of C_27-29 regular steranes, the 5α,14β,17β(H) steranes (20S+20R) dominate over the 5α,14α,17α(H) steranes (20S+20R). The ratios of aaa C₂₉ steranes 20S/(20S+20R) and ββ/(ββ+αα) C₂₉ steranes fluctuate between 0.53 and 0.58 and between 0.68 and 0.71 in the Eh₃⁶ shale, whereas the Eh₃⁵ shale exhibits two ratios of 0.51–0.54 and 0.63–0.67, respectively. Additionally, minor proportions of 13α,17β C₂₇ diasteranes (20S+20R) are also assigned.

Phenanthrene (P) and its mono-, di-, and tri-methyl-substituted homologues (MP, DMP, and TMP) are the predominant aromatic compounds (Figure 8), followed by chrysene and its methyl-substituted homologues (MChr), benzo[e]pyrene (B[e]P), fluorene (F), methyl biphenyl (MB), dibenzofuran (DBF), tri- and tetra-methyl naphthalene (TMN, TeMN), and dibenzothiophene (DBT). The Methylphenanthrene Index 1 (MPI-1 = 1.89×(3-MP+2-MP)/[P+1.26×(9-MP+1-MP)]) [28] values in the Eh₃⁶ and Eh₃⁵ shale ranges from 0.89 to 1.07 and from 0.86 to 1.01, respectively (Table 2). The trimethylnaphthalene ratio-2 (TNR-2 = (2,3,6-TMN+1,3,7-TMN)/(1,3,5-TMN+1,3,6-TMN+ 1,4,6-TMN)) [29] values vary between 0.95 and 1.02 for the Eh₃⁶ shale and between 0.84 and 0.93 for the Eh₃⁵ shale. Considering F, DBF, and DBT as 100%, the Eh₃⁶ shale has a larger percentage of DBT, but the Eh₃⁵ shale has a higher concentration of DBF.

5. Discussion

5.1. Maturity

A peak oil window maturity is indicated by the mean values of random vitrinite reflectance (0.9–1.0%) for the Eh₃⁶ and Eh₃⁵ shale (Figure 4; Table 1). The conclusion is confirmed by the T_max values, which are mainly distributed between 440 °C and 460 °C (Figure 3). Maturity indicators derived from terpenoids and steroids, including αβ C₃₁ homohopane 22S/(22S+22R), Ts/(Ts+Tm), ααα C₂₉ sterane 20S/(20S+20R), and ββ/(ββ+αα) C₂₉ steranes ratios, are close to the corresponding equilibrium values (Figure 9A,B), all of which suggest a maturity characteristic of the peak oil window [30]. Furthermore, aromatic maturity indicators like MPI-1 and TNR-2 confirm a maturity stage at the peak oil window (Figure 9C). Overall, the Eh₃⁶ shale has greater MPI-1 and TNR-2 values than the Eh₃⁵ shale, revealing a comparatively higher maturity. The peak oil window maturity is also evidenced by the presence of degraded telalginite (Figure 5B). Considering that the influences of thermal maturity on both intervals are comparable, paleoenvironmental biomarker indicators (e.g., Pr/Ph) are applied to contrast the paleoenvironmental differences between two intervals.

5.2. Organic Matter (OM) Source

In contrast to the Eh₃³ and Eh₃² shales, which exhibit a majority of type I-II₁ kerogen [15], the Eh₃⁶ and Eh₃⁵ shales display dominance by type II₂-III kerogen, suggesting that the organic matter is primarily derived from terrigenous higher plants (Figure 3). This inference is supported by the prevalence of terrigenous macerals (e.g., terrigenous liptinite, vitrinite, and inertinite) in both shale intervals, accounting for 82–91 vol.% (mmf = mineral matter free) and 68–85 vol.% (mmf) in the Eh₃⁶ and Eh₃⁵ shale, respectively. A negative correlation exists between the HI values and the contents of terrigenous macerals, indicating that the decreased HI values are associated with the increased contribution of higher plants (Table 1).

High ratios of C₂₄ tetracyclic/C₂₆ tricyclic terpanes (C₂₄ Tet/C₂₆ TT) are indicative of significant input of terrigenous OM [31]. The Eh₃⁶ shale exhibits higher C₂₄ Tet/C₂₆ TT ratios compared to the Eh₃⁵ shale, suggesting a substantial influx of terrigenous OM during the shale’s deposition (Figure 10A). It is commonly known that the main source of C₂₇ sterols is algae, whereas higher plants are usually linked to C₂₉ sterols. [32]. While some biomarker studies have revealed elevated levels of 24-ethylesterols in some microalgae species [33], the likelihood of microalgae-derived C₂₉ steranes can be ruled out in this case, given that OM is predominantly sourced from higher plants. Therefore, the elevated ratios of C₂₉/C₂₇ ααα steranes (20R) in the Eh₃⁶ shale are consistent with the increased terrigenous OM input, which corroborates the findings of C₂₄ Tet/C₂₆ TT ratios (Figure 10A). Labdanes, which are typical higher plant-derived biomarkers [34], have also been assigned (Figure 7A), further confirming the contribution of terrigenous OM to the shale.

Furthermore, a portion of OM in shale may originate from bacteria, as indicated by the elevated concentrations of hopanoids (particularly αβ C₃₀ hopane) and the assignment of methylheptadecanes (Figure 7A,C) [35]. Hopanoids are mainly produced by prokaryotic organisms such as bacteria [36], whereas 7- and 8-methylheptadecanes are primarily generated by cyanobacteria and are found in significant concentrations in pure cultures of cyanobacteria [37].

5.3. Paleoenvironment Reconstruction

In the middle of the Biyang Depression during the Eh₃⁶ and Eh₃⁵ periods, deep-to-semi-deep lacustrine environments were generally developed [20,22]. The integration of elemental compositions and biomarkers of shale reflects a variety of depositional environments, including paleosalinity, redox conditions, paleoproductivity, and detrital input. The B/Ga and Sr/Ba ratios, as well as the gammacerane index (GI = Ga/C₃₀H ratios), are utilized to infer paleosalinity levels. The B/Ga ratios range from 2.8 to 5.4 in the Eh₃⁶ shale and from 1.7 to 3.8 in the Eh₃⁵ shale, indicative of predominantly brackish and freshwater conditions, respectively (Figure 11A; based on the threshold proposed by [38]). This interpretation is corroborated by the higher GI values observed in the Eh₃⁶ shale (0.59–0.82) compared to the Eh₃⁵ shale (0.50–0.71; Figure 10B). However, the results derived from Sr/Ba ratios differ from those of the preceding parameters (Figure 11A). The impact of carbonate-hosted Sr in the shale is thought to be the cause of this discrepancy, as indicated by a robust positive correlation between the CaO contents and Sr concentrations (the inset figure in Figure 11A).

The Pr/Ph ratios exhibit variability, ranging from 0.87 to 1.0 in the Eh₃⁶ shale and 0.98 to 1.37 in the Eh₃⁵ shale, suggesting the prevalence of more reducing conditions, probably anoxic (in accordance with the threshold proposed by [39]), during the deposition of Eh₃⁶ shale (Figure 10B). Similarly, the cross-plot of Pr/n-C₁₇ versus Ph/n-C₁₈ indicates that the Eh₃⁶ shale plots closer to the region representing reducing conditions (Figure 10C). Fluorene (F) tends to convert into dibenzofuran (DBF) under sufficient oxygen conditions, whereas it tends to generate dibenzothiophene (DBT) in oxygen-depleted conditions [40]. Thus, the positioning of shale in the ternary plot of DBT-F-DBF suggests that the Eh₃⁶ shale was formed under comparatively more reducing conditions than the Eh₃⁵ shale (Figure 10D). Furthermore, the enrichment factors of U and Mo, serving as redox proxies of sediments [41], also indicate the prevalence of more reducing conditions during the deposition of Eh₃⁶ shale (Figure 11B).

The P/Al ratio and Ba_bio value are applied to assess paleoproductivity. Overall, the Eh₃⁵ shale exhibits high P/Al ratios and Ba_bio values, whereas the Eh₃⁶ shale displays comparatively low ratios and values (Figure 11C). These findings possibly suggest that the elevated paleoproductivity prevailed during the deposition of Eh₃⁵ shale. However, this conclusion may raise questions, as an essential premise for utilizing P and Ba as productivity indicators is the predominance of aquatic-origin OM [42], which is evidently inconsistent with the studied shale. As discussed in Section 5.2, the primary source of OM is terrigenous higher plants, implying potentially low productivity of aquatic organisms. Therefore, it is postulated that aquatic productivity was low during the deposition of both intervals, potentially exerting limited influence on OM enrichment and shale formation.

Aluminum primarily originates from clay minerals, while titanium mainly occurs in clay and heavy minerals such as rutile. Clay minerals are abundant in both the Eh₃⁶ and Eh₃⁵ shale, whereas rutile is commonly found in the Eh₃ [19,22]. Therefore, the contents of Al and Ti are utilized to reveal detrital influx. The Eh₃⁶ shale has a slightly higher average Al₂O₃ and TiO₂ concentration than the Eh₃⁵ shale, suggesting an increased detrital supply to the paleo-lake during the deposition of Eh₃⁶ shale.

The cartoons illustrating the depositional models of Eh₃⁶ and Eh₃⁵ shale are depicted in Figure 12. During the deposition of Eh₃⁶ shale, there was a notable influx of detrital matter and terrigenous OM into the paleo-lake. Using 2000 Monte Carlo simulations of potential sedimentation rates, the earlier study performed an enhanced correlation coefficient (COCO) analysis for every member of Eh₃, resulting in high sediment accumulation rates (SARs), at 17.8 cm/kyr [23]. These high SARs facilitated the rapid burial of terrigenous OM, thus favoring its preservation. Moreover, because of the occurrence of gypsum at the top of the Ed and the relatively dry paleoenvironment, surface runoff may have transported salt ions released through the weathering of parent rock [43], leading to increased salinity in the paleo-lake and potentially promoting water stratification. Accordingly, the deposition of Eh36 shale, which has a high TOC and low HI value, was facilitated by the combination of a large terrigenous OM input and advantageous preservation circumstances (Figure 12A). In contrast, the deposition of Eh₃⁵ shale was characterized by comparatively lower detrital matter and terrigenous OM, corresponding to lower SARs [23]. This lower terrigenous OM input, in conjunction with freshwater and suboxic conditions, resulted in the deposition of Eh₃⁵ shale with low TOC and relatively higher HI values (Figure 12B).

5.4. Hydrocarbon Potential and Implications for Regional Hydrocarbon Exploration

The hydrocarbon generation potential of the Eh₃⁶ and Eh₃⁵ shale was evaluated using the cross-plot of TOC versus S₁+S₂ [44]. The Eh₃⁶ shale falls within the region characterized by fair potential, whereas the Eh₃⁵ shale predominantly exhibits poor-to-fair potential (Figure 13A). This observation is further corroborated by the cross-plot of TOC versus HI, where the Eh₃⁶ shale demonstrates fair oil potential, while the Eh₃⁵ shale exhibits little-to-fair oil potential (Figure 13B). The hydrocarbon retention potential of the Eh₃⁶ and Eh₃⁵ shale is assessed through the cross-plots of TOC versus S₁ and production index (PI = S₁/(S₁+S₂)) versus oil saturation index (OSI = 100 × S₁/TOC). In these figures, comparatively higher contents of free (or migrated) hydrocarbons are evident in the Eh₃⁶ shale compared to the Eh₃⁵ shale (Figure 13C,D).

Overall, the Eh₃⁶ and Eh₃⁵ shale studied herein exhibit only poor-to-fair oil potential, suggesting their limited contribution to oil reservoirs in the Biyang Depression. However, given the predominance of type II₂-III kerogen, it is hypothesized that these shales may possess significant gas potential in regions where wet/dry gas window maturity is attained. Notably, several gas fields have already been discovered near the Well A3 (Figure 1C). Considering the minimum OSI threshold (~100 mg HC/g TOC) for prospective shale oil successions in the lacustrine basins of China, ⁴ the studied Eh₃⁶ and Eh₃⁵ shale exhibit only minimal potential for shale oil exploration. Nevertheless, it is speculated that, in the central region of the paleo-lake, distant from the source area, there may be deposition of salinized lacustrine shale characterized by type I-II₁ kerogen and higher free oil contents. Therefore, the Eh₃⁶ and Eh₃⁵ shale around the Anpeng area, which was the sedimentary depocenter during the period, could represent a promising target for shale oil exploration.

6. Conclusions

The impact of terrigenous input on the deposition of salinized lacustrine shale was investigated using an example from the newly explored strata (Eh₃⁶ and Eh₃⁵) of the deep regions in the Biyang Depression, East China. The TOC contents of Eh₃⁶ and Eh₃⁵ shale range from 0.3 to 2.2 wt. %, with a predominance of type II₂-III kerogen. Both shale intervals exhibit a peak oil window maturity, as evidenced by vitrinite reflectance, T_max, and biomarker-derived maturity parameters. The primary source of OM is considered to be terrigenous higher plants for both shale intervals, supported by the dominance of terrigenous macerals (e.g., terrigenous liptinite, vitrinite, and inertinite), low HI values, and biomarker indicators. Additionally, a portion of the OM may originate from bacteria, as indicated by the high abundance of hopanoids and the assignment of 7- and 8-methylheptadecanes. During the deposition of Eh₃⁶ shale, a significant influx of detrital matter and terrigenous OM occurred, corresponding to high sediment accumulation rates (SARs). These high SARs facilitated the rapid burial of OM and increased paleosalinity by transporting salt ions from the provenance regions to the paleo-lake, thereby favoring OM preservation. Consequently, the Eh₃⁶ shale, characterized by high TOC and low HI values, was deposited under the influence of high terrigenous OM input and favorable preservation conditions. In contrast, the deposition of Eh₃⁵ shale involved a comparatively lower flux of detrital matter and terrigenous OM, resulting in shale with lower TOC and relatively higher HI values. Overall, the studied shale exhibits only poor-to-fair potential for hydrocarbon generation and retention. However, areas with higher maturity and a better kerogen type may hold significant potential for conventional gas and shale oil exploration in the Biyang Depression, respectively.