Geochemical characteristics and oil–source rock correlation in the Paleogene source rocks of the Qinnan Sag, Bohai Bay basin

Abstract

The Paleogene Shahejie Formation, including the first (Es₁) and third (Es₃) members of the Shahejie Formation, and the third member of Dongying Formation (Ed₃) are important source rocks in the Qinnan Sag, Bohai Bay Basin. In order to uncover the source of oil and gas in this sag, basic geochemical, molecular geochemical, organic petrological, and n-alkane monomer carbon isotopic characteristics of source rocks and oils were analyzed in detail. In combination with the geological settings, the percentage contribution of these three sets of source rocks was assessed in the Qinnan Sag. Results obtained from the source rocks offered the following insights: (1) total organic carbon (TOC) ranged from 1.0% to 3.0%, and the S₂-TOC indicated that the qualities of source rocks followed the order of Es₃ > Es₁ > Ed₃. (2) Organic matter (OM) of the Ed₃ source rock belonged to Type II₂, while those of Es₁ and Es₃ belonged to Type II₁. The molecular geochemical parameters (CPI, C₂₄TeT/C₂₆TT, C₂₇–C₂₉ regular steranes, and 4-MSI) also revealed that the organic matter in the source rocks mainly originated from mixtures of algae and terrestrial higher plants. (3) The % R_o values of Ed₃, Es₁, and Es₃ were 0.61%, 0.80%, and 0.88%, respectively. These results were consistent with the maturity molecular parameters (including T-max, Ts/Tm, C₂₉-ααα20S/(20S + 20R) and C₂₉-ββ/(ββ + αα)). (4) Pr/Ph, Pr/nC₁₇, and Ph/nC₁₈ values indicated that the three sets of source rocks were deposited in a reduced lacustrine environment with different salinities (analyzed with G/C₃₀H), and the salinities of Ed₃ and Es₃ indicated a freshwater brackish water environment, while that of Es₁ suggested a brackish semi-saline water environment. (5) combining the geological settings with the geochemical results of oil–source correlations, it was found that the contribution of Es₁ source rock dominated (>50%) in the sag. Overall, this study provides more accurate data of oil source formation and is significant for oil exploration in the Qinan Sag, Bohai Bay Basin.

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1 Introduction

The Bohai Bay Basin, located in eastern North China, is one of the most important petroleum basins in China.¹ Depressions within the basin can be classified into three categories based on their geological history: pre-Paleogene, Paleogene, and Neogene.² The Qinnan Sag, positioned in the western Bohai Bay Basin, remains one of the least explored areas in the region. The discovery of the billion-ton Qinhuangdao 29 (QHD29) oilfield in 2009 stimulated intensified exploration efforts within the Qinnan Sag.

Although the tectonic framework, sedimentary characteristics, and source rock properties of the Qinnan Sag have been investigated, no significant breakthroughs have been achieved in petroleum exploration. Zhang et al. (2019; 2021)^3,4 investigated the QHD29 area and concluded that the formation of high-quality reservoirs in the region is mainly characterized by three factors: rich spiral mixed beach facies, early dolomitization of buried diagenesis, and dissolution during the middle- and late-stages of diagenesis. Furthermore, they emphasized that the evolution of source rocks and modification of physical properties of the reservoir were significantly influenced by thermal fluids. Xue et al. (2020)⁵ examined Es₁ reservoir rocks using casting sheet, scanning electron microscopy (SEM), and carbon–oxygen isotope data, revealing the widespread presence of bioclasts and emphasizing the significant influence of tectonic and sedimentary processes on reservoir quality variations. The experimental results on evaporation fractionation and biodegradation processes in the QHD29-2 oilfield demonstrate significant variations in reservoir properties between the upper and lower layers of the oil and gas reservoir.⁶ Furthermore, Zhuang et al. (2011)⁷ combined natural gas composition, isotope analysis and fluid inclusion studies, concluding that the hydrocarbons in the QHD29-2 oilfield originated from a mixture of Es₁ and Es₃ source rocks. The high-quality Paleogene source rocks in the Qinnan Sag are primarily found in the Es₃, Es₁, and Ed₃, with the southeastern subsag being particularly enriched in high-quality Es₃ and Es₁ source rocks.^8–11 The Es₃ source rocks are characterized by high organic matter abundance, providing a solid material foundation for large-scale petroleum accumulation.¹² These findings highlight the importance of systematic geochemical characterization of source rocks and crude oil for guiding further exploration strategies.

In oil–source correlation studies, a wide range of geochemical parameters—including biomarkers and carbon isotopes—have emerged as critical tools.^13,14 Wang et al. (2015)¹⁵ examined crude oil geochemistry and thermal maturity in the QHD29-2 oilfield using ten geochemical indicators, including 4-methylsterane (4-MSI) and gammacerane/C₃₀ hopane (G/C₃₀H), based on the classification framework proposed by Hao et al. (2009).¹⁶ Shi et al. (2022)¹⁷ expanded the application of these indicators to both source rocks and crude oil from the eastern Qinnan Sag, evaluating geochemical traits, maturity levels, and oil–source relationships. However, due to the similarity in sterane and terpene biomarker distributions among source rocks, direct biomarker-based oil–source correlation proved inconclusive. In contrast, carbon isotope analysis has been shown to be a more reliable method for distinguishing oil sources.¹⁸

A multi-proxy geochemical approach was applied in this study, combining TOC analysis, rock pyrolysis, organic petrology, gas chromatography-mass spectrometry (GC-MS), and analysis of n-alkane monomer carbon isotopes. This integrated methodology was used to characterize the geochemical properties of source rocks and crude oil, establish oil–source correlations using both biomarker and isotopic evidence, and quantify the relative contributions of distinct source rock intervals to hydrocarbon generation within the Qinnan Sag. Notably, the n-alkane monomer carbon isotope composition provides critical constraints on oil–source relationships, particularly in cases where biomarker-based correlations yield ambiguous results. The findings provide new geochemical insights into source rock and crude oil characteristics in the Qinnan Sag, Bohai Bay Basin, offering valuable support for petroleum exploration and resource assessment in the region.

2 Geological overview

The Bohai Bay Basin has undergone both the Paleogene syn-rift and Neogene post-rift periods. The Qinnan Sag (Fig. 1), located in the northwestern margin of the Bohai Bay Basin, lies at the intersection of the Tanlu Fault Zone, Penglai Strike-Slip Fault Zone, and Lvshun Fault.¹⁹ Extending in an east–west direction, the sag can be divided into four subsags from west to east: West Subsag, Middle Subsag, East Subsag, and Southeast Subsag. The structural framework of the depression is primarily controlled by the Qinnan I and Qinnan II faults, with adjacent tectonic units including the Qinnan Uplift, Liaoxi Low-Uplift, Shijiutuo Uplift, and Matouying Uplift.^20,21

Fig. 1 (a) Simplified structural map illustrating the regional settings of the Bohai Bay Basin. The black rectangle outlines the location of the Qinnan Sag. Structural map of the Qinnan Sag showing the localities of sampling (X, Y, Z, and W areas are for crude oil sampling, and A, B, C, D, and E are for source rock sampling wells). (b) Generalized stratigraphy of the Qinnan Sag.

The Qinnan Sag hosts a sequence of Paleogene strata overlying the Mesozoic (Mz) basement, consisting of the Kongdian Formation (Ek), Shahejie Formation (Es), and Dongying Formation (Ed) from bottom to top.²² The primary sedimentary systems in the Paleogene include fan deltas, braided river deltas, and lacustrine deposits. The Kongdian Formation and the Fourth Member of the Shahejie Formation were deposited under arid, oxidizing conditions, primarily forming small lacustrine or alluvial fan deposits. During the deposition of the Third Member of the Shahejie Formation, rapid subsidence created significant accommodation space. A warm and humid climate, coupled with increased precipitation, facilitated lake deepening, resulting in the extensive development of deep to semi-deep lacustrine facies, with fan delta sediments distributed along the basin margins. During the sedimentation of the First and Second Members of the Shahejie Formation, climatic conditions became slightly more arid, and fault activity weakened; however, lacustrine deposition remained dominant. In the early stages of these formations, shallow coastal lakes prevailed, whereas later stages saw lake expansion. Consequently, the depositional environment primarily consisted of shallow to semi-deep lacustrine facies, with fan deltas along the periphery and localized carbonate platform development. The Dongying Formation was influenced by strong tectonic activity and experienced a transition from lacustrine to braided river delta sedimentation. Notably, the third stage of the Dongying Formation was predominantly characterized by lacustrine deposits.^23–25

3 Samples and experimental methods

In this study, a total of 17 crude oil samples were selected from four stratigraphic layers: Ed₃ in the Dongying Formation, Es₁₂ in the Shahejie Formation, Ek in the Kongdian Formation, and Mz in the Mesozoic. Additionally, 15 source rock samples were collected from five wells across three layers: Ed₃ in the Dongying Formation, Es₁ in the Shahejie Formation, and Es₃ in the Shahejie Formation (Fig. 1).

3.1 Organic petrological analysis

This analysis includes vitrinite reflectance (R_o) measurement and maceral identification. Vitrinite reflectance (% R_o) was determined using an MSP400 microfluorescence spectrometer, applying the dual-standard calibration method (standard reference: GBW 130012), in accordance with SY/T 5124-2012. Maceral identification was performed using an MF43 transmitted polarized fluorescence microscope, equipped with a 50× oil immersion objective; the specific analytical method follows the industry standard SY/T 6414-2014.

3.2 Rock pyrolysis analysis

Samples were cleaned and crushed, then 200-mesh samples were selected and analyzed with an OGE-VI Rock-Eval pyrolysis instrument.^26,27 Samples were heated to 600 °C in a helium environment, and the volatile cracking substances were carried into a hydrogen flame ionization detector (FID) through carrier gas for detection. The free hydrocarbon (S₁), residual petroleum potential (S₂), and the temperature (T-max) corresponding to the highest value of the S₂ peak, CO₂ release from organic matter (S₃), and the residual carbon content (S₄) after rock pyrolysis were detected, respectively.

3.3 Total organic carbon (TOC) analysis

Samples were cleaned and crushed, then 200-mesh samples were selected and a suitable amount of powder was weighed into a crucible. The sample was treated with 1 : 7 dilute hydrochloric acid solution at 80 °C in a water bath for 12 hours to remove inorganic carbon. The sample was rinsed with ultrapure water until neutral and oven-dried. TOC content was determined using a CS-230PCHC carbon–sulfur analyzer.^26,28

3.4 Gas chromatography-mass spectrometry (GC-MS) and pre-treatment analysis

Samples were cleaned and crushed, then 200-mesh samples were selected and extracted using Soxhlet extraction with dichloromethane as the solvent for 72 hours. Approximately 20 mg of crude oil and source rock extracts were separated into fractions using a solid-phase chromatography column packed with silica gel and alumina. Before removing asphaltenes, n-hexane was added, and the solution was left undisturbed for 12 hours to allow precipitation. Fractions were sequentially eluted with n-hexane, a 2 : 1 mixture of n-hexane and dichloromethane, and a 93 : 7 mixture of dichloromethane and methanol to obtain saturated hydrocarbons, aromatic hydrocarbons, and non-hydrocarbon fractions, respectively. The separated saturated hydrocarbon fraction was analyzed using an Agilent 7890B-5977B GC-MS system.²⁹ The chromatographic column was an HP-5MS quartz capillary column (30 m × 0.25 mm × 0.25 μm). The injector temperature was set to 300 °C, with helium as the carrier gas at a flow rate of 1 mL min⁻¹. The heating program was as follows: the initial temperature was 50 °C, held for 2 minutes, then increased at 3 °C min⁻¹ to 310 °C, and held constant for 18 minutes. Electron ionization (EI) was used, with an ionization energy of 70 eV and a full mass scan range of 50–550 amu.

3.5 Carbon isotope analysis of n-alkane monomers

After component separation, n-alkanes from the crude oil and source rock extracts were subjected to monomer carbon isotope analysis.³⁰ The instrument used was an Isoprime (HP8890) isotope ratio mass spectrometer (IRMS), equipped with an HP-5MS quartz capillary column (30 m × 0.25 mm × 0.25 μm). The injector operated in splitless mode, with a temperature of 290 °C, using helium as the carrier gas at a flow rate of 1.0 mL min⁻¹. The temperature program was as follows: the initial temperature was 60 °C, held for 2 minutes, then ramped to 120 °C at 15 °C min⁻¹, followed by an increase to 300 °C at 4 °C min⁻¹, and held constant for 15 minutes.

4 Results

4.1 Organic petrological characteristics of source rocks

The organic matter in the source rock samples from the Qinnan Sag exhibits moderate thermal maturity, as indicated by fluorescence observed under microscopy and their evident hydrocarbon generation potential. The average vitrinite reflectance (% R_o) values for Ed₃, Es₁, and Es₃ are 0.61, 0.80, and 0.88, respectively. Microscopic identification of macerals provides direct insights into the types and origins of the organic matter present in these rocks. Overall, vitrinite is abundantly developed in the Qinnan Sag source rocks, while algal content is also relatively high (Fig. 2). Well A, located in the western subsag and proximal to the provenance, is characterized by organic matter predominantly derived from terrestrial higher plants, with vitrinite as the dominant maceral component, indicative of type II₂–III kerogen (Fig. 2a and b). In Well D, situated on the Shijiutuo Uplift, vitrinite remains dominant in the Es₁ formation, while the Es₃ interval contains a greater proportion of aquatic algal organic matter (Fig. 2c–f). Well C, located near the deep lacustrine center, is characterized by organic matter dominated by lower aquatic organisms in both Es₁ and Es₃, with a notably higher algal contribution in Es₃ (Fig. 2g–l). Along a transect from Well A to Well D and then to Well C, a progressive decrease in vitrinite content and a corresponding increase in sapropelic organic matter is observed. This trend reflects the increasing distance from the provenance area and indicates an enhanced contribution from lower aquatic organisms, leading to an overall improvement in organic matter type and hydrocarbon generation potential.

Fig. 2 Maceral identification of polished thin sections in the Qinnan sag (Scale bar = 50 μm). Note: (a) characteristics of Es₃ sample from Well A under transmitted light, visible development of vitrinite. (b) Characteristics of Es₃ sample under reflected light from Well A. (c) Characteristics of Es₁ sample from Well D under transmitted light, visible development of vitrinite. (d) Characteristics of Es₃ sample from Well D under transmitted light. (e) Characteristics of Es₃ sample under reflected light in Well D. (f) Fluorescence characteristics of Es₃ sample from Well D show the development of lamalginite. (g) Characteristics of Es₁ sample from Well C under transmitted light. (h) Characteristics of Well C Es₁ sample under reflected light. (i) Fluorescence characteristics of Es₁ sample from Well C show the development of lamalginite. (j) Characteristics of Es₃ sample from Well C under transmitted light. (k) Characteristics of Well C Es₃ sample under reflected light. (l) Fluorescence characteristics of Es₃ sample from Well C show the development of lamalginite.

4.2 Basic geochemical characteristics of source rocks

The TOC content of the source rocks follows a decreasing trend in the order of Es₃ (0.17–3.85%, average 1.93%) > Es₁ (0.34–2.54%, average 1.41%) > Ed₃ (0.30–3.00%, average 1.19%). The average values of S₁, S₂, and S₃ in Es₃ samples are 0.86 mg g⁻¹, 8.04 mg g⁻¹, and 2.13 mg g⁻¹, respectively, which are significantly higher than for other source rock layers. The average T-max value is 434 °C, with an HI range of 158–471 mg per g TOC and an average of 335 mg per g TOC, indicating a relatively good preservation of hydrogen-rich organic matter. For Es₁ and Ed₃, the average T-max values are 430 °C and 416 °C, respectively, with HI values of 207–424 mg g⁻¹ and 106–300 mg per g TOC, respectively, suggesting moderate to good hydrocarbon potential. The productive carbon (PC) content in Es₃ ranges from 0.03% to 1.81%, higher than those of Es₁ and Ed₃ (Table 1).

Table 1 Basic geochemical parameters of source rocks in the Qinnan Sag^a

Number	Sampling	Depth (m)	Layer	S1 (mg g^−1)	S2 (mg g^−1)	S3 (mg g^−1)	T-max (°C)	S1 + S2 (mg g^−1)	S4 (mg g^−1)	TOC (%)	PI	HI (mg g^−1)	PC (%)
a S = source rock; S1 = free hydrocarbon; S2 = residual petroleum potential; S3 = CO2 release from organic matter; S4 = residual carbon after cracking; T-max = S2 peak temperature; TOC = total organic carbon; PI = S1/(S1 + S2); HI = S2 × 100/TOC; PC = 0.083 × (S1 + S2).
S-1	A	2630	Ed3	0.09	0.46	1.13	409	0.55	2.10	0.30	0.16	153	0.09
S-2		2875	Es1	0.16	1.14	0.98	431	1.30	4.00	0.55	0.13	207	0.15
S-3		2935	Es1	0.13	1.34	1.30	429	1.47	1.60	0.34	0.09	394	0.18
S-4	B	3014	Es1	0.12	4.70	1.4	434	4.82	13.20	1.72	0.02	273	0.4
S-5		3062	Es1	0.17	4.14	1.22	435	4.31	11.20	1.48	0.03	279	0.35
S-6		3096	Es3	0.10	3.96	1.94	433	4.06	9.50	1.36	0.02	291	0.41
S-7	C	3330	Ed3	0.54	1.65	1.85	404	2.19	2.90	0.55	0.25	300	0.26
S-8		3605	Es1	0.82	10.91	3.07	442	11.73	15.70	2.54	0.07	431	0.98
S-9		3660	Es3	0.74	9.79	3.72	440	10.53	14.70	2.34	0.07	420	0.88
S-10	D	2930	Ed3	0.21	1.55	2.44	406	1.76	5.90	0.83	0.12	187	0.24
S-11		3160	Es1	0.28	2.50	2.00	417	2.78	4.50	0.76	0.10	329	0.31
S-12		3320	Es3	2.49	18.14	1.85	436	20.63	20.40	3.85	0.12	471	1.81
S-13	E	3110	Ed3	0.30	3.26	1.32	445	3.57	27.78	3.07	0.09	106	0.30
S-14		3150	Es1	0.61	10.58	2.87	442	11.19	15.68	2.50	0.05	424	0.93
S-15		3290	Es3	0.11	0.27	1.01	425	0.37	1.36	0.17	0.29	158	0.03

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4.3 Characteristics of biomarker compounds in source rocks

n-Alkanes, as dominant constituents in both source rocks and crude oils, are among the relatively early and extensively studied classes of biomarker compounds in petroleum geochemistry.^31,32 The mass fragment ion chromatograms (m/z = 85) of n-alkanes from source rock samples are shown in Fig. 3. The Pristane/Phytane (Pr/Ph) ratios range from 0.48 to 1.19 in the Ed₃ interval, 0.16 to 1.24 in Es₁, and 0.23 to 1.02 in Es₃, reflecting variations in redox conditions during sediment deposition. For isoprenoid alkanes, the Pr/nC₁₇ ratios in Ed₃, Es₁, and Es₃ are within the ranges of 0.49–0.85, 0.20–0.88, and 0.23–0.85, respectively. Meanwhile, the Ph/nC₁₈ ratios vary between 0.57–1.25, 0.43–1.12, and 0.56–1.30, respectively. These parameters reflect differences in depositional environments and organic matter input among the three formations. The carbon preference index (CPI) and odd–even predominance (OEP) values, used as proxies for organic matter maturity and source input, exhibit average values of 1.39, 1.63, and 1.36 for CPI, and 1.11, 1.17, and 1.20 for OEP in the Ed₃, Es₁, and Es₃ intervals, respectively.

Fig. 3 Distribution characteristics of n-alkane, terpene and sterane series in different layers of source rocks and crude oil in the Qinnan Sag (m/z = 85, m/z = 191, m/z = 217).

The gas chromatograms of steroid and terpenoid biomarkers (Fig. 3) of three source rock samples exhibit similar characteristics: the low molecular weight tricyclic terpene shows relatively low abundance, whereas higher molecular weight hopanes and C_27–29 steranes show pronounced peaks. Selected biomarker parameters are summarized in Table 2. The ratio of C₂₄ tetracyclic terpenoids to C₂₆ tricyclic terpenoids (C₂₄TeT/C₂₆TT) falls between 0.59 and 0.76, with the ratio for occasional samples exceeding 1. The average values of ∑w (tricyclic terpenes)/∑w (hopanes) for Ed₃, Es₁, and Es₃ are 0.22, 0.21, and 0.20, respectively. The relative ratios of C₂₇, C₂₈, and C₂₉ regular steranes in Ed₃ range from 1.52% to 36.05%, 6.95% to 18.00%, and 45.95% to 91.52%, respectively. The C₂₇/C₂₉ sterane ratios range from 0.02 to 0.78, with an average of 0.29. The relative ratios of C₂₇, C₂₈, and C₂₉ regular steranes in Es₁ range from 1.52% to 19.83%, 4.91% to 27.82%, and 57.53% to 90.07%, respectively, with C₂₇/C₂₉ ratios ranging from 0.02 to 0.33 (average 0.13). In Es₃, the C₂₇, C₂₈, and C₂₉ steranes range from 3.62% to 23.92%, 6.86% to 14.14%, and 64.79% to 88.60%, respectively, with C₂₇/C₂₉ ratio ranges from 0.04 to 0.35, averaging 0.19. All formations display a predominance of C₂₉ steranes, consistent with higher plant-derived organic matter input. The abundance of tetramethylsterane (4-MSI) ranges from 0.06 to 0.33 in Ed₃, 0.07 to 0.33 in Es₁, and 0.06 to 0.35 in Es₃.

Table 2 n-Alkane series and common terpene and sterane parameters in source rock and crude oil of different layers in the Qinnan Sag^a

Number	Sampling	Layer	Depth (m)	CPI	OEP	Pr/nC17	Ph/nC18	Pr/Ph	nC21/nC22+	C19T/C23T	C23T/C30H	C24Te/C26T	Ts/Tm	C29Ts/C29H	diaC27/diaC29	diaC29/reC29	C29 sterane 20S/(20S + 20R)	C29 sterane ββ/(αα + ββ)	G/C30H	4-MSI
a O = oil sample; S = source rock sample; CPI = {(C25 + C27 + C29 + C31 + C33)[1/(C24 + C26 + C28 + C30 + C32) + 1/(C26 + C28 + C30 + C32 + C34)]}/2; OEP = [(Ci + 6 Ci+2 + Ci+4)/4(Ci+1 + Ci+3)]^m, where m = (−1)^i+1, i + 2 is the carbon number of the main peak; Pr = pristane; Ph = phytane; n = n-alkanes; T = tricyclic terpene; H = hopane; Te = tetracyclic terpenes; Ts = 18α(H)-trisnorhopane; Tm = 17α(H)-trisnorhopane; dia = diasterane; re = regular sterane; G = gammacerane.
O-1	X area	Ed3	3301	1.10	1.07	0.36	0.56	0.66	0.98	0.21	0.03	0.51	0.93	0.40	0.98	0.19	0.48	0.59	0.19	0.32
O-2		Ed3	3195	1.11	1.06	0.39	0.58	0.76	1.11	0.46	0.14	0.59	1.10	0.47	1.40	0.24	0.49	0.61	0.32	0.24
O-3	Y Area	Es12	3175	1.17	1.05	0.32	0.43	0.89	1.18	0.44	0.26	0.48	1.68	0.45	1.46	0.31	0.50	0.62	0.39	0.20
O-4		Es12	3280	1.08	1.05	0.30	0.44	0.69	0.96	0.36	0.09	0.44	1.43	0.54	1.49	0.21	0.50	0.63	0.35	0.27
O-5		Es12	3495	1.09	1.06	0.49	1.14	0.51	0.97	0.36	0.08	0.51	0.75	0.39	1.32	0.19	0.49	0.64	0.43	0.17
O-6		Es12	3308	1.10	1.04	0.42	0.87	0.55	0.97	0.47	0.13	0.50	1.11	0.46	1.15	0.23	0.51	0.64	0.47	0.17
O-7		Es12	3475	1.12	1.08	0.48	1.28	0.46	0.97	0.26	0.03	0.53	0.60	0.30	0.94	0.14	0.43	0.47	0.39	0.14
O-8		Es12	3390	1.19	1.13	0.45	0.70	0.67	0.99	0.22	0.04	0.52	0.71	0.34	1.18	0.22	0.36	0.36	0.24	0.39
O-9	Z area	Mz	3388	1.13	1.10	0.63	1.21	0.47	0.96	0.16	0.03	0.66	0.81	0.28	0.75	0.15	0.43	0.52	0.35	0.15
O-10		Es12	2747	1.16	1.06	0.32	0.44	0.82	1.26	0.29	0.08	0.42	1.02	0.39	2.58	0.14	0.41	0.53	0.30	0.35
O-11		Ek	2938	1.09	1.01	0.32	0.43	0.70	1.43	0.60	0.03	0.71	0.58	0.29	1.62	0.11	0.44	0.53	0.24	0.16
O-12	W area	Ed3	3065	1.06	1.05	0.24	0.28	0.82	1.00	0.20	0.07	0.41	1.15	0.49	1.51	0.22	0.48	0.59	0.49	0.26
O-13		Es12	3167	1.10	1.07	0.23	0.24	0.91	1.01	0.46	0.14	0.59	1.10	0.47	1.40	0.24	0.39	0.49	0.32	0.52
O-14		Es12	3282	1.06	1.07	0.24	0.29	0.77	0.97	0.27	0.04	0.56	1.28	0.42	1.07	0.22	0.46	0.51	0.46	0.27
O-15		Mz	3401	1.09	1.06	0.24	0.29	0.79	0.96	0.25	0.05	0.56	1.28	0.56	1.78	0.17	0.50	0.53	0.33	0.28
O-16		Mz	3400	1.09	1.06	0.19	0.20	0.89	0.95	0.20	0.04	0.51	1.23	0.50	1.92	0.15	0.40	0.43	0.24	0.26
O-17		Ek	3187	1.12	1.16	2.91	4.00	0.86	0.89	0.16	0.08	0.40	1.08	0.42	1.29	0.26	0.53	0.64	0.40	0.50
S-1	A	Ed3	2630	1.24	1.03	0.85	1.26	0.48	0.54	0.09	0.33	0.64	0.92	8.69	1.13	0.38	0.45	0.41	0.09	0.33
S-2		Es12	2875	1.19	1.03	0.88	1.12	0.52	0.64	0.02	0.13	1.06	0.47	1.90	0.51	0.50	0.40	0.21	0.32	0.29
S-3		Es12	2935	1.75	1.08	0.82	1.02	0.78	0.55	0.26	0.46	0.64	0.89	0.36	0.92	0.59	0.36	0.39	0.16	0.15
S-4	B	Es12	3014	2.18	1.27	0.20	0.43	0.17	0.97	0.25	0.01	1.29	0.57	0.34	1.44	0.11	0.65	0.40	0.08	0.07
S-5		Es12	3062	2.10	1.39	0.21	0.55	0.16	1.11	0.27	0.01	1.01	0.59	0.32	0.25	0.62	0.69	0.29	0.24	0.10
S-6		Es3	3096	1.46	1.15	0.23	0.56	0.23	0.87	0.21	0.02	0.66	0.66	0.44	0.29	0.59	0.53	0.35	0.25	0.13
S-7	C	Ed3	3330	1.20	1.12	0.54	0.84	0.86	0.87	0.27	0.04	0.59	0.56	0.36	0.19	0.92	0.42	0.57	0.49	0.06
S-8		Es12	3605	1.34	1.23	0.56	0.87	1.25	1.06	0.96	0.01	1.23	0.48	0.34	0.67	0.50	0.48	0.68	0.05	0.13
S-9		Es3	3660	1.42	1.29	0.51	1.01	1.03	0.99	0.36	0.01	1.75	0.61	0.38	0.53	0.41	0.48	0.62	0.03	0.06
S-10	D	Ed3	2930	1.45	1.15	0.54	0.89	0.76	1.07	0.09	0.04	0.75	0.56	0.39	0.35	0.41	0.48	0.51	0.23	0.12
S-11		Es12	3160	1.49	1.04	0.60	0.80	0.98	1.07	0.62	0.04	0.72	0.70	0.48	0.25	0.77	0.47	0.50	0.73	0.27
S-12		Es3	3320	1.27	1.24	0.84	1.30	0.56	1.03	0.18	0.01	0.74	0.63	0.25	0.45	0.49	0.68	0.48	0.04	0.28
S-13	E	Ed3	3110	1.69	1.13	0.49	0.57	1.19	1.07	0.16	0.03	0.76	0.41	0.52	0.40	0.57	0.55	0.41	0.08	0.10
S-14		Es12	3150	1.39	1.17	0.62	0.93	0.90	0.86	0.25	0.06	0.76	0.55	0.47	0.10	0.96	0.33	0.41	0.35	0.32
S-15		Es3	3290	1.28	1.10	0.41	0.59	0.51	0.66	0.03	0.57	0.67	0.83	0.44	0.32	0.81	0.60	0.51	0.13	0.35

---

4.4 Characteristics of biomarker compounds in crude oil

The n-alkane series in crude oil samples is relatively complete and exhibits a predominantly unimodal distribution. The analysis of saturated hydrocarbons (Table 2) shows that the Pr/Ph ratios in all samples are below 1. Specifically, the Pr/Ph values range from 0.66 to 0.82 in Ed₃ (average: 0.75), 0.46 to 0.91 in Es₁₂ (average: 0.70), 0.70 to 0.86 in Ek (average: 0.78), and 0.47 to 0.89 in Mz (average: 0.72). The average CPI values for Ed₃, Es₁₂, Ek, and Mz are 1.09, 1.12, 1.10, and 1.10, respectively, while their OEP values are 1.06, 1.07, 1.09, and 1.10, respectively. For isoprenoid alkanes, Pr/nC₁₇ values generally range from 0.19 to 0.63, while most Ph/nC₁₈ values fall between 0.20 and 1.28.

The sterane and terpane biomarkers in the crude oil exhibit compositional characteristics similar to those observed in the source rocks. Low-molecular-weight tricyclic terpenes are present in low abundance, with the ∑w (tricyclic terpenes)/∑w (hopanes) ratio primarily ranging from 0.12 to 0.61. In contrast, high-molecular-weight hopanes and C_27–29 regular steranes are relatively enriched. The relative proportions of C₂₇, C₂₈, and C₂₉ regular steranes range from 0.16–0.33%, 0.31–0.60%, and 0.11–0.46%, respectively. The C₂₇/C₂₉ sterane ratio varies from 0.38 to 2.60, with an average of 0.75, indicating a predominance of C₂₉ steranes. Table 2 indicates that the terpenoid biomarker parameters of crude oil samples are relatively concentrated. The C₂₄TeT/C₂₆TT ratio, an indicator of higher plant input, is relatively low and shows a marked contrast with that observed in the Es₃ section. The G/C₃₀H ratio ranges from 0.19 to 0.46, with an average of 0.35. The 4-MSI ratio ranges from 0.14 to 0.50.

4.5 Monomer carbon isotope characteristics of n-alkanes in source rocks and crude oil

n-Alkane monomer carbon isotopic analysis (δ¹³C) was conducted to investigate the genetic relationship between source rocks and crude oils in the Qinnan Sag. The analysis focused on n-alkanes ranging from nC₁₄–nC₃₂ and Pr and Ph data. The δ¹³C values for crude oil (Fig. 4) ranged from −30‰ to −24‰, with an average of −28.02‰. The δ¹³C values of the source rocks (Fig. 5) ranged from −30‰ to −26‰, with an average of −29.41‰. A few samples exhibited δ¹³C values ranging from −30‰ to −24‰. Crude oils exhibited more enriched and consistent δ¹³C values than the source rocks. Due to abnormal δ¹³C signatures observed in Ek crude oil samples, these were excluded from subsequent oil–source correlation analyses.

Fig. 4 Carbon isotope characteristics of n-alkane monomers of source rocks in the Qinnan Sag.

Fig. 5 Carbon isotope characteristics of n-alkane monomers of crude oils in the Qinnan Sag.

5 Discussion

5.1 Type and maturity

The hydrocarbon generation potential of source rocks should be evaluated based on the organic matter type and maturity.^33–35 The kerogen type classification diagram based on T-max versus HI (Fig. 6a) indicates that Es₃ samples fall within Type II₁, Ed₃ samples in Type II₂, and Es₁ samples in Type II₁. Microscopic composition analysis (Fig. 2) further supports these classifications. The T-max data indicate that the source rocks in the Qinnan Sag are distributed from immature to maturity stages. Combined with the % R_o data, it can be concluded that Es₁ and Es₃ exhibit characteristics of low to moderate maturity, while Ed₃ exhibits immature to low maturity stages.³⁶

Fig. 6 T-Max-HI values of (a), Ts/Tm-C₂₉20S/(20S + 20R) (b), C₂₉ββ/(αα + ββ)–C₂₉20S/(20S + 20R) (c), and S₂-TOC (d) classification diagrams of source rock and crude oil in the Qinnan Sag.

In terms of biomarker-based maturity parameters, the thermal evolution trends reflected by individual indicators are broadly consistent. It is generally believed that with increasing maturity, Tm gradually transforms into Ts, causing Ts/Tm to increase.³⁷ As shown in Fig. 6b, the mean value of Es₃ in source rocks is higher than those of Es₁ and Ed₃, indicating a greater thermal maturity. The Ts/Tm values in crude oil samples are generally above 1, reflecting their overall higher maturity, which suggests that Ed₃ source rocks may have made only a limited contribution to oil generation. The isomerization ratios of C₂₉ steranes, such as C₂₉-ααα20S/(20S + 20R) and C₂₉ββ/(ββ + αα), are also widely used as maturity indicators.³⁸ With thermal evolution, α-type steranes convert into β-types, and the biological configuration (20R) shifts toward the geological equilibrium configuration (20S), resulting in increased ratios.³⁹ In both source rock and crude oil samples, the C₂₉-ααα20S/(20S + 20R) and C₂₉ββ/(ββ + αα) values cluster around 0.5 and 0.6 (Fig. 6c), indicating that these samples have reached isomerization equilibrium.³⁰ Consequently, these parameters are less effective for further maturity discrimination among crude oil samples. Based on the above data and the distribution map of S₂-TOC (Fig. 6d), it can be concluded that Es₃ is a high-quality source rock and Es₁ is the least favorable in terms of hydrocarbon generation potential.

5.2 Source of parent material and sedimentary environment

The nature of the parent material plays a decisive role in determining both the type and hydrocarbon generation potential of source rocks. Biomarkers such as peak carbon number, CPI values, C₁₉TT/C₂₃TT, C₂₄TeT/C₂₆TT, C₂₇–C₂₉ regular steranes, and 4-MSI index are commonly used as indicators of organic input and depositional settings.

Biomarker analysis of source rock samples from the Qinnan Sag shows that the n-alkane series in most samples exhibited a bimodal pattern, with two distinct peak groups.¹⁸ In these bimodal distributions, the first peak typically centers around nC₁₆, while the second peak is generally observed near nC₂₅. This pattern reflects the relatively small loss of low molecular weight compounds and suggests a mixed origin of organic matter. The intervening trough between the two peaks generally appears at nC₂₁ or nC₂₂, exhibiting a weak odd-carbon preference. However, this feature is relatively insignificant when compared to the pronounced odd–even predominance typically observed in terrestrial plant and modern surface sediments.²⁸ Based on multiple geochemical indicators—including C₂₄TeT/C₂₆TT, the distribution of C₂₇–C₂₉ regular steranes, and molecular composition characteristics—it is inferred that the source rocks contain a mixed organic input derived from both lower aquatic organisms (e.g., algae) and terrestrial higher plants. In contrast, the n-alkane distribution in crude oil samples is relatively complete and predominantly unimodal, although both front and rear peak types are present, suggesting varying contributions from different biogenic sources. CPI and OEP values close to 1 indicate no significant odd–even preference, further supporting the thermal maturity and absence of recent terrestrial contamination. Taking into account biomarker parameters such as C₂₄TeT/C₂₆TT and sterane distribution, the crude oil is believed to originate from a mixed source dominated by algal input.

Pr/Ph ratios are widely recognized as proxies for redox conditions, while Pr/nC₁₇ and Ph/nC₁₈ ratios are commonly used to evaluate both the sedimentary environment and organic matter input.^39–41 Stratigraphic comparison of source rock samples indicates that Ed₃, Es₁, and Es₃ were all deposited under reducing conditions, as suggested by the low Pr/Ph values (Fig. 7a). The Pr/nC₁₇ and Ph/nC₁₈ ratios also indicate the characteristics of their lacustrine sedimentary environment, and their organic matter types are consistent with T-max-HI, confirming that the parent material of the crude oil was derived from a relatively reducing lacustrine environment (Fig. 7b).

Fig. 7 Analysis of the relationship between Pr/Ph and G/C₃₀H (a) and Pr/nC₁₇ and Ph/nC₁₈ (b) values in source rocks and crude oil of the Qinnan Sag.

Gammacerane, a pentacyclic triterpenoid, is generally formed via the reduction of tetracyclic alcohols in protozoa and photosynthetic bacteria, and its presence is closely linked to the depositional environment. Elevated gammacerane concentrations are typically associated with strongly reducing, stratified, and saline water bodies. The gammacerane index (G/C₃₀H) is commonly used to assess salinity: values above 0.2 are generally indicative of brackish to saline depositional conditions and can be used as a marker for water stratification.²⁷ In the Qinnan Sag, Ed₃ and Es₃ source rocks were deposited in freshwater to brackish water settings, while Es₁ reflects a brackish to semi-saline environment. The crude oil samples are interpreted to have formed in saline to slightly saline conditions (Fig. 7a).

5.3 Oil–source rock correlation

Oil–source rock correlation integrates geological context with geochemical data to evaluate the genetic relationships between crude oils and potential source rocks. A wide array of geochemical indicators are typically employed in such analyses, including crude oil physical properties, bulk compositions, biomarker compounds, and stable carbon isotopes.⁴² However, each parameter has specific limitations and applicable conditions.^43–45 It is generally necessary to integrate various parameters for geochemical correlation so that the results are more reliable. Traditional oil–source correlation relies on comparing the geochemical characteristics of oils and source rocks to infer shared origins. For example, n-alkanes, tricyclic terpenes, tetracyclic terpenes, C₃₀ hopane, and C₂₇, C₂₈, C₂₉ regular steranes are used to analyze the sources of bacteria, algae, and higher plants.^46–49 Exploring thermal maturity using Ts/Tm, C₂₉-ααα20S/(20S + 20R) and C₂₉ββ/(ββ + αα).^50–52 Pr/nC₁₇, Ph/nC₁₈, and gammacerane indicate sedimentary redox conditions and salinity levels.^53–55 Previous studies in the Bohai Bay Basin⁵⁶ identified 4-MSI as a key biomarker for oil–source correlation. This compound is typically derived from 4α-methylsterols produced by dinoflagellates, although it may also originate from certain bacteria.⁵⁶ Hao et al. (2009)¹⁶ utilized 4-MSI as a key indicator for oil source analysis in the Bozhong Depression and Shijiutuo Uplift. Wang et al. (2015)¹⁵ used the parameters from Hao et al. (2009)¹⁶ to conduct cluster analysis on the QHD29 oilfield, which effectively identified the oil source information of crude oil. However, Shi et al. (2022)¹⁷ compared crude oil and source rock characteristics in the eastern part of Qinnan using indicators such as 4MSI and G/C₃₀ hopane and found that the application of the biomarker compound characteristic by Hao et al. (2009)¹⁶ in the Qinnan area presents certain limitations. The high similarity of sterane and terpene biomarkers in source rocks reduces the significance of parameter-based comparisons, resulting in unclear oil–source correlation outcomes. These findings suggest that, in the Qinnan Sag, biomarker-based approaches alone are insufficient for reliable oil–source correlation, and that alternative methods are required to improve the accuracy of oil–source identification.

Previous studies^18,57 have found that, despite similar biomarker distributions, significant distinctions arise when comparing carbon isotopic signatures. δ¹³C values of sedimentary organic matter primarily reflect the carbon isotope composition of its biological precursors.^58,59 Unlike biomarkers, monomer carbon isotopes are less affected by biodegradation or migration, making them more reliable indicators of source input and depositional environment. However, direct oil–source comparison between crude oil and over-mature source rocks should be avoided. Compared to group component carbon isotopes, monomer carbon isotopes provide more refined results and enable source analysis at a finer molecular level.⁶⁰ Therefore, this study employs n-alkane monomer carbon isotopes for oil–source correlation analysis.

The n-alkane carbon isotope results from 15 source rock samples in the Qinnan Sag reveal distinct isotopic differences across different stratigraphic intervals. After eliminating incomplete and anomalous data, 10 representative samples from three different layers were selected for further analysis (Fig. 8). Isotopic differentiation is mainly observed in three aspects: (a) the δ¹³C values of light n-alkanes with carbon numbers below 17, (b) correlations between nC₁₇–nC₁₉ and isoprenoids (Pr and Ph), and (c) variations in the δ¹³C values of heavy n-alkanes with carbon numbers above 20.

Fig. 8 Carbon isotope characteristics of n-alkane monomers of source rock in different layers of the Qinnan Sag.

From the distribution of n-alkane monomer carbon isotopes in the source rocks (Fig. 8), the Ed₃ formation exhibits notable isotopic heterogeneity, especially in the S-1 well, which displays significantly heavier carbon isotope values compared to those from the Southeast Subsag and the Eastern Fault-Step Zone. These isotope values appear to be minimally affected by carbon number, showing relatively gradual changes as the carbon number increases. This pattern is likely attributed to the proximity to a major sediment source and substantial input of terrestrial organic matter. This inference is further supported by organic petrographic observations under the microscope. For light hydrocarbons with carbon numbers less than 17, the δ¹³C values increase progressively with increasing carbon number. The isotopic compositions of nC₁₇–nC₁₉, Pr, and Ph exhibit relatively smooth variations, while heavier hydrocarbons with higher carbon numbers show a gentle and stable isotopic trend.

For the Es₁ source rocks, the carbon isotopes of the n-alkane monomers show that the δ¹³C values of light components with carbon numbers less than 17 become progressively heavier with increasing carbon number. nC₁₇–nC₁₉, Pr, and Ph display a V-shaped trend, with Ph exhibiting the most negative (lightest) value. In contrast, the δ¹³C values of higher molecular weight hydrocarbons display a downward trend, becoming lighter as the carbon number increases.

For the Es₃ source rocks, the carbon isotopes of n-alkane monomers show that the δ¹³C values of light components with carbon numbers less than 17 become progressively lighter with increasing carbon number. nC₁₇–nC₁₉ and Pr and Ph exhibit a W-shaped trend, with both Pr and Ph showing relatively light values, while higher molecular weight carbon isotopes show a decreasing weight trend.

The difference in n-alkane monomer carbon isotope signatures among source rocks makes them a valuable indicator for oil–source correlation in the Qinnan Sag. By comparing the isotopic characteristics of n-alkane monomers in crude oils from different stratigraphic intervals, it was found that the crude oil from the Ed₃ and the Mz (Fig. 9) exhibit characteristics of heavy in the early stage, a W-shaped trend in the middle segment, and an upward trend in the later segment. This pattern closely corresponds to the isotopic characteristics observed in the Es₃ source rocks.

Fig. 9 Monomer isotopic characteristics of n-alkanes in Ed₃ and Mz crude oils from Qinnan Sag.

The origin of crude oil in the Es₁₂ is complex and can be further subdivided into Southeast Subsag crude oil and Liaoxi Low Uplift crude oil based on regional differences (Fig. 10). The analysis reveals that the crude oil from the Es₁₂ in Southeast Subsag exhibits two distinct isotopic patterns: (1) the front part is heavier, the middle part is W-shaped, and the rear part rises, which is consistent with the characteristics of the Es₃ source rocks. (2) The front section is light, the middle segment is slightly V-shaped, and the rear section is slightly descending, which is consistent with the characteristics of the Es₁ source rocks. This indicates that the crude oil in Southeast Subsag is a mixed source. In contrast, the crude oil from the Liaoxi Low Uplift show a heavier front segment, a W-shaped middle section, and a rear segment with both upward and slightly downward trends, indicating Es₃ source dominance with minor Es₁ contribution.

Fig. 10 Monomer carbon isotopic characteristics of n-alkanes in Es₁₂ crude oil from Qinnan Sag. Note: (A) Es₁₂ crude oil total data; (B) Es₃ characteristic crude oil data in Southeast subsag; (C) Liaoxi low rise crude oil data; and (D) Es₁ characteristic crude oil data in Southeast subsag.

Based on the above analysis, the percentage contribution of hydrocarbon source rocks to nearby areas at each layer were evaluated (Fig. 11). This intuitively reveals the oil source contribution and quality of the three sets of hydrocarbon source rocks in each region from a planar perspective. The calculation methodology is outlined as follows: the monomer carbon isotopic characteristics of n-alkanes from source rocks within the three stratigraphic intervals served as the geochemical basis for oil–source differentiation. According to the spatial distribution of crude oil samples, four calculation zones were delineated to assess the relative contributions of different source rock intervals. Within each region, the percentage contribution of each source rock interval was determined by calculating the proportion of crude oil samples whose monomer carbon isotope signatures matched those of a specific source rock interval.

Fig. 11 Contribution characteristics of source rocks from different layers in the Qinnan Sag to crude oil in different areas.

In summary, the results of the integrated geochemical and isotopic analyses are indicative of a primary crude oil origin from the Es₃ source rocks. The Es₁ source rocks contribute notably to the crude oil in the Southeast Subsag and to a lesser extent in the Liaoxi Low Uplift. In contrast, there is no geochemical or isotopic evidence supporting a contribution from the Ed₃ source rocks.

6 Conclusions

(1) The T-max, HI, and microscopic composition characteristics of the Qinnan Sag suggest that the Ed₃ source rocks are primarily composed of type II₂ kerogen, while Es₁ and Es₃ source rocks are dominated by type II₁ kerogen. Maturity parameters such as T-max, % R_o, and molecular geochemical indicators suggest that Ed₃ source rocks are in the immature to low-mature stage, whereas Es₁ and Es₃ have reached low-mature to mature stages. According to the S₂-TOC distribution, the Es₃ is classified as high-quality source rocks, Es₁ is of relatively good quality, and Ed₃ is the least favorable.

(2) Geochemical parameters including CPI, C₂₄TeT/C₂₆TT, C₂₇–C₂₉ regular steranes, and 4-MSI, combined with microscopic compositional analysis, suggest that the source rocks are derived from a mixed organic input of lower aquatic organisms (e.g., algae) and terrestrial higher plants. In contrast, the biomarker composition of crude oil points to a predominantly algal origin. Pr/Ph, Pr/nC₁₇, and Ph/nC₁₈ ratios collectively indicate that both the source rocks and the precursor organic matter of the crude oil were deposited in a reducing lacustrine environment. Gammacerane index (G/C₃₀H) values suggest that the Ed₃ and Es₃ source rocks were formed in freshwater to brackish settings, whereas Es₁ was deposited under brackish to semi-saline conditions. The overall crude oil hydrocarbon generation parent material is in a salty to slightly salty water environment.

(3) GC-MS analysis reveals that the distributions and compositions of steranes and terpanes in both source rocks and crude oils from the Qinnan Sag are generally similar, suggesting that traditional molecular geochemical parameters possess limited effectiveness for oil–source correlation in this region. In contrast, carbon isotopes provide a relatively stable geochemical indicator that is less affected by migration or thermal maturity; furthermore, compound-specific carbon isotopes provide integrated insights into the type of organic matter, depositional environment, and hydrocarbon generation processes. These features make them a powerful tool for oil–source correlation. The monomer carbon isotopic signatures of n-alkanes demonstrate distinctive patterns across different stratigraphic source rocks: Ed₃ exhibits a “light-flat-gentle” trend from front to back; Es₁ is characterized by a “light front-moderate V-shaped middle-light rear decline”; while Es₃ shows a “heavy front-W-shaped middle-rising rear” pattern.

(4) Crude oil in the Qinnan Sag shows relatively high thermal maturity, and there is no geochemical or isotopic evidence indicating a contribution from the Ed₃ source rocks. The isotopic characteristics of crude oils from Ed₃ and Mz strata resemble those of Ed₃ source rocks, while the Es₁₂ crude oil exhibits more complex origins. Based on regional differences, Es₁₂ crude oil can be divided into two groups: crude oil from the Southeast Subsag shows mixed-source characteristics derived from both Es₁- and Es₃-type source rocks; Liaoxi-Low-Uplift crude oil exhibits characteristics with contributions from the Es₃ main type and a small amount of Es₁.

Data availability

The raw data generated during this study and the raw dataset used to generate research results are stored in the author's personal database. Interested parties can contact the author to obtain them. These data have been anonymized and/or pseudonymized to ensure compliance with privacy regulations. The processed and analyzed data are stored in the author's personal database, and interested parties can contact the author. Part of the data processing was carried out using the software “Data Analysis”, as described in Sections 4.2–4.4 of the manuscript. More detailed information can be obtained by consulting the author via email. All data used to support the results of this study are included in this article. Unless otherwise stated in the manuscript, any interested party may replicate our experiments and/or analyze the data using standard statistical tools and protocols.

Author contributions

Xukai Shi: writing – original draft. Xiaomin Xie: writing – review & editing.

Conflicts of 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 work was supported by the National Natural Science Foundation of China [grant number 41503034, 41972122, 42172139]; China National Offshore Oil Corporation [grant number CCL2021TJTONST0365]. Thanks to CNOOC Tianjin Branch for their support for this research. Thanks to Hubei Key Laboratory of Petroleum Geochemistry and Environment. Thanks to the journal editor and reviewers for providing constructive feedback and suggestions for improving this article.

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