Characteristics of Source Rocks and Oil–Source Correlation in the Seventh Member of the Yanchang Formation (Chang 7 Member), Pingbei Area, Ordos Basin

Abstract

To clarify the hydrocarbon generation potential of dark mudstones and the source of crude oil in the seventh member of the Yanchang Formation (Chang 7 Member) in the Pingbei area of the Ordos Basin, and to support tight oil exploration in this region, this study focuses on the source rocks and crude oils from the Chang 7 Member. Comprehensive analyses including total organic carbon (TOC), rock pyrolysis, vitrinite reflectance (Ro), and saturated hydrocarbon gas chromatography–mass spectrometry (GC-MS) were conducted to systematically investigate the characteristics of source rocks and the geochemical properties of crude oils, and to perform oil–source correlation. The results indicate that the dark mudstones in the Chang 7 Member of the Pingbei area meet the geological conditions of effective source rocks: they exhibit high organic matter abundance with an average TOC content of 1.69% and strong heterogeneity, among which the Chang 7³ sub-member has an average organic carbon content of 2.8%, conforming to the standard of high-quality source rocks; the organic matter type is dominated by Type II₁, mixed with a small amount of Type II₂ and Type III, characterized by both aquatic biological and terrestrial organic matter inputs; the Ro values range from 0.76% to 0.87%, indicating a mature stage corresponding to the peak period of liquid hydrocarbon generation. The crude oils in the study area can be classified into two types (Type A and Type B): Type A crude oil is distributed in deep reservoirs of the Chang 7 Member, while Type B crude oil is present in both shallow and deep layers. Oil–source correlation shows that Type A crude oil is highly consistent with the dark mudstones of the Chang 7 Member in terms of Pr/Ph ratio, rearranged hopane enrichment degree, and pentacyclic triterpane distribution pattern, clearly indicating that the Chang 7 Member dark mudstones are the main source rocks for Type A crude oil. In contrast, Type B crude oil is geochemically consistent with crude oils from the sixth member of the Yanchang Formation (Chang 6 Member) in oilfields surrounding the Pingbei area; it is derived from the Chang 6 Member source rocks in the peripheral regions.

1. Introduction

The Ordos Basin is a significant large-scale petroliferous basin in China. The Triassic Yanchang Formation within the basin is a typical representative of continental tight oil exploration and represents a key area for present and future growth in oil and gas reserves and production [1,2,3,4,5,6,7]. The seventh member of the Yanchang Formation (Chang 7 Member) is universally recognized as the principal Mesozoic source rock interval in the basin, characterized by the development of thick, organic-rich black shales, and dark mudstones [8,9,10,11], which exert a crucial control on tight oil accumulation [12,13,14]. The Pingbei area is situated within the Pingqiao nose fold belt on the central Yishan Slope Zone, in a delta-front distributary channel area under the northeastern provenance system. Sand bodies, such as distributary channels and sheet sands, are widely developed, forming typical low-porosity and low-permeability tight reservoirs [15,16]. However, its location distal from the main hydrocarbon generation center complicates research on crude oil migration and accumulation mechanisms.

Previous studies have systematically revealed the geochemical characteristics of the Chang 7 Member source rocks in the Ordos Basin and their key role as the basin’s primary source rocks. Nevertheless, in the Pingbei area—a geologically complex marginal zone—the Chang 7 Member source rocks are not typical organic-rich shales but are dominated by dark mudstones [17,18]. Research on the hydrocarbon generation potential of these locally developed, potentially atypical dark mudstones, and their specific contribution to local oil and gas accumulation remains insufficient and unclear. Key issues, such as whether the dark mudstones are effective source rocks, whether there is multiplicity in crude oil sources, and the correlation between oils from different horizons and source rocks, remain unresolved. These uncertainties constrain the accurate evaluation of tight oil exploration potential in this area.

Therefore, this study focuses on the Chang 7 Member in the Pingbei area. By systematically collecting source rock and crude oil samples and applying petrographic techniques (maceral identification, vitrinite reflectance measurement) and geochemical analyses (TOC, rock pyrolysis, saturated/aromatic hydrocarbon GC-MS), this study aims to address the research gap concerning the hydrocarbon generation potential of dark mudstones and oil–source relationships in the Pingbei area. It provides theoretical support for tight oil exploration in the Chang 7 Member and deeper layers, holding significant practical importance for optimizing exploration and development strategies.

2. Geological Background

The Ordos Basin is located in the western part of the North China Craton, with an overall rectangular outline. As a large-scale polycyclic sedimentary superimposed basin in China, it is divided into six tectonic units: the Yimeng Uplift, Weibei Uplift, Western Margin Thrust Belt, Tianhuan Depression, Yishan Slope, and Jinxi Flexure Belt [19,20,21]. The study area is situated in the Pingqiao nose fold belt in the central part of the Yishan Slope Zone, covering an exploration area of approximately 65 km² (Figure 1a). The Triassic Yanchang Formation is the largest tight oil production base in China [22]. Due to environmental changes, the Yanchang Formation experienced the entire process of initial lake formation, continuous expansion, and gradual contraction. Based on lithological and sedimentary characteristics, the Yanchang Formation can be divided into ten oil-bearing intervals (Chang 1 to Chang 10) from bottom to top [23,24]. During the middle stage of lake development, the basin expanded significantly to 5.5 × 10⁴ km², with prosperous aquatic organisms. Deep lake and semi-deep lake sediments were mainly developed, widely distributed in Wuqi–Dingbian County. The Chang 7 Member is further subdivided into three sub-members (Chang 7¹, Chang 7², and Chang 7³) from top to bottom (Figure 1b), mainly consisting of approximately 100 m thick dark gray mudstones or oil shales with high-quality and high-abundance organic matter [25]. The areal distribution of areas with a cumulative thickness greater than 20 m reaches up to 3 × 10⁴ km². The organic-rich shales have high TOC contents, mainly ranging from 6% to 14%, with the “Zhangjiatan” shale at the bottom as a typical representative, showing great development potential.

3. Materials and Methods

3.1. Sample Collection

To ensure the representativeness of the dataset, source rock and crude oil samples were systematically collected from multiple wells across the Pingbei area, covering the key stratigraphic intervals (Chang 7², Chang 7³, Chang 6³, and Chang 4 + 5²). Sampling prioritized fresh core material from depths below the weathering zone to minimize surface alteration. All samples were immediately sealed in aluminum foil and stored at 4 °C to prevent oxidation and hydrocarbon loss prior to analysis. There were a total of 41 source rock samples. The study area is located within the Pingqiao nose fold belt in the central part of the Yishan Slope, where lateral migration pathways (such as delta-front distributary channel sand bodies) exist. Research in surrounding areas has confirmed that hydrocarbons can migrate laterally through such sand bodies into underlying strata. Additionally, faults are present between some shallow formations (e.g., Chang 6 and Chang 4 + 5) and the Chang 7 Formation, which may facilitate cross-strata migration of hydrocarbons.

3.2. Experimental Analysis Methods

3.2.1. Total Organic Carbon (TOC) Analysis

TOC content was determined in compliance with the standard SY/T 5735-2019. Samples were first treated with 10% hydrochloric acid to remove carbonate minerals, dried at 60 °C to constant weight, and then measured using a LECO CS-230 carbon–sulfur analyzer.

3.2.2. Rock Pyrolysis Analysis

Samples were crushed to 80 mesh and analyzed using a Rock-Eval 6 pyrolyzer. The pyrolysis procedure consisted of low-temperature oxidation (300 °C, 3 min), programmed heating from 300 to 600 °C at a rate of 25 °C/min, and high-temperature oxidation (600–850 °C). Key parameters obtained included the free hydrocarbon content (S₁), pyrolyzable hydrocarbon content (S₂), and the maximum pyrolysis temperature (Tmax).

3.2.3. Maceral Identification and Organic Matter Type Determination

Maceral classification followed the International Committee for Coal and Organic Petrology (ICCP) System 1994 [26,27]. The sample preparation protocol was as follows: source rock samples were crushed to <1 mm, mounted in epoxy resin, and polished to produce polished particulate blocks. Observations were carried out under reflected light using a Leitz Ortholux II microscope fitted with a reflected light attachment and 50 × oil immersion objective. The relative abundances of vitrinite, inertinite, and liptinite maceral groups were determined by point counting, with at least 500 points counted per sample using a regular grid spacing of approximately 0.4 mm. Alginite was identified as a distinctive liptinite maceral when present. Organic matter type was assessed based on maceral composition and calculated type index from petrological analysis, and corroborated with geochemical data (hydrogen index vs. Tmax cross-plot) from Rock-Eval pyrolysis. Among the 41 source rock samples, 20 representative samples (covering different well locations and various sub-members) were selected for petrological analysis. The selection criteria were as follows: total organic carbon (TOC) content ≥ 0.5% (the lower limit for effective source rocks), intact lithology, and absence of weathering.

3.2.4. Vitrinite Reflectance (Ro) Measurement

Vitrinite reflectance (Ro) measurements were conducted in accordance with the Chinese petroleum industry standard SY/T 5124-2019. Sample preparation was consistent with the procedure described for maceral identification (Section 3.2.3). Reflectance measurements were performed on vitrinite particles using a Leitz MPV-SP microscope photometer under incident light at a wavelength of 546 nm. Following the guidelines of the ASTM D7708 standard and recent best practices for dispersed organic matter [27], we aimed for a minimum of 20–30 valid measurements per sample. Raw data were screened, and statistical outliers (defined as measurements falling outside ±2 standard deviations from the preliminary mean) were excluded to obtain a robust mean reflectance value for each sample. The final mean Ro, its standard deviation, and the count of valid measurements for each of the 20 analyzed samples are provided in

Table A1. Glossary.

Term	Definition
TOC (Total Organic Carbon)	The mass percentage of organic carbon in source rocks, a core indicator of organic matter abundance. Classified as: ordinary source rocks (0.5–1%), good source rocks (1–2%), high-quality source rocks (>2%).
Rock Pyrolysis	A thermal analysis method to evaluate hydrocarbon generation potential. Key parameters: S1 (free hydrocarbons, mg/g), S2 (pyrolyzable hydrocarbons, mg/g), Tmax (maximum pyrolysis temperature, °C).
Vitrinite Reflectance (Ro)	The reflectance of vitrinite macerals under incident light (546 nm), a critical indicator of organic matter maturity. Stages: immature (<0.5%), mature (0.5–1.3%), highly mature (1.3–2.0%), over-mature (>2.0%).
GC-MS (Gas Chromatography–Mass Spectrometry)	An analytical technique combining gas chromatography (separation) and mass spectrometry (detection) to identify and quantify organic compounds (e.g., saturated/aromatic hydrocarbons, biomarkers).
Biomarker	Specific organic compounds preserved in geological samples (oils, source rocks) that reflect the origin, sedimentary environment, and thermal evolution of organic matter (e.g., steranes, terpanes, isoprenoids).
Pr/Ph Ratio (Pristane/Phytane Ratio)	The ratio of two isoprenoid alkanes (pristane, Ph; phytane, Pr). Indicates paleo-redox conditions: Pr/Ph > 1 (oxic–suboxic environment), Pr/Ph < 1 (reducing environment).
Ts/Tm Ratio	The ratio of 18α(H)-22,29,30-Trisnorneohopane (Ts) to 17α(H)-22,29,30-Trisnorhopane (Tm). Influenced by thermal maturity and sedimentary environment; higher values indicate higher maturity or oxic conditions.
Steranes	Cyclic biomarkers derived from eukaryotic cell membranes (algae, plants). C27 steranes (aquatic algae), C29 steranes (terrestrial plants); C29 sterane 20S/(20S + 20R) and ββ/(αα + ββ) ratios indicate maturity.
Terpanes	Cyclic biomarkers derived from prokaryotic cell membranes (bacteria) and plant resins. Tricyclic terpanes (source input), pentacyclic hopanes (sedimentary environment/maturity), rearranged hopanes (clay catalysis).
Organic Matter Type	Classified by origin and hydrocarbon generation potential: Type I (sapropelic, aquatic algae, high oil potential), Type II1 (mixed sapropelic–humic, aquatic + terrestrial, good oil potential), Type II2 (mixed humic–sapropelic, terrestrial + aquatic, oil–gas potential), Type III (humic, terrestrial plants, high gas potential).
Maturity	The degree of thermal transformation of organic matter under burial. Mature stage (Ro = 0.7–1.3%) corresponds to peak liquid hydrocarbon generation; controlled by burial depth, geothermal gradient, and heating time.
Oil–Source Correlation	A method to link crude oils to their parent source rocks using consistent geochemical signatures (biomarker ratios, isotope compositions, molecular distributions).
Tmax	The temperature at which the maximum pyrolysis yield (S2 peak) occurs in rock pyrolysis, reflecting organic matter type and maturity (higher values indicate higher maturity or terrestrial organic matter input).
HI (Hydrogen Index)	The ratio of pyrolyzable hydrocarbons (S2) to TOC (mg HC/g TOC), indicating organic matter type (higher values = more oil-prone Type I/II1).
S1 + S2	The sum of free and pyrolyzable hydrocarbons, a direct indicator of source rock hydrocarbon generation potential (effective source rocks: S1 + S2 > 2 mg/g).

. A minimum of 20 valid data points were collected per sample, with outliers excluded from the final calculation. Among the 41 source rock samples, 20 representative samples covering different well locations and stratigraphic sub-members were selected for detailed petrological analysis. The selection criteria were: (1) a total organic carbon (TOC) content ≥ 0.5% (considered the lower limit for effective source rocks); (2) intact lithology; and (3) absence of weathering.

3.2.5. Analysis of Aromatic Hydrocarbon Fraction

Following separation of the saturated and aromatic hydrocarbon fractions, the aromatic fraction was analyzed using an Agilent 7890A-5975C gas chromatography–mass spectrometer (GC–MS). The system was equipped with a DB-5MS capillary column (30 m × 0.25 mm × 0.25 μm film thickness). The GC oven temperature was programmed as follows: initial temperature of 60 °C (maintained for 2 min), then ramped to 300 °C at 5 °C/min, and finally held at 300 °C for 20 min. High-purity helium was used as the carrier gas at a constant flow rate of 1.0 mL/min. The mass spectrometer was operated in electron impact (EI) ionization mode at 70 eV, with an ion source temperature of 230 °C. Compound quantification was achieved using the peak area normalization method. The same set of 20 representative source rock samples selected for petrological analysis, along with 12 crude oil samples (5 from the Pingbei area and 7 from surrounding oilfields), was subjected to GC–MS analysis for both saturated and aromatic hydrocarbons. The remaining 21 source rock samples were analyzed solely for total organic carbon (TOC) content and Rock-Eval pyrolysis parameters.

3.2.6. Saturated and Aromatic Hydrocarbon GC–MS Analysis

Prior to chromatographic analysis, samples were extracted using a Soxhlet extractor with a chloroform–methanol mixture (9:1 by volume) for 72 h. The resulting total extract was subsequently separated into saturated hydrocarbon, aromatic hydrocarbon, and non-hydrocarbon (including asphaltene) fractions via silica gel–alumina column chromatography, using sequential elution with *n*-hexane, benzene, and methanol. Both saturated and aromatic hydrocarbon fractions were analyzed using an Agilent 7890A-5975C gas chromatography–mass spectrometer (GC–MS) equipped with a DB-5MS capillary column (30 m × 0.25 mm × 0.25 μm). For the saturated hydrocarbon fraction, the GC oven temperature was programmed from an initial 80 °C (held for 2 min) to 300 °C at a rate of 4 °C/min, followed by a 15 min isothermal hold at 300 °C. For the aromatic hydrocarbon fraction, the temperature program began at 60 °C (held for 2 min), was raised to 300 °C at 5 °C/min, and was then held at 300 °C for 20 min. In terms of the separation efficiency of target compounds, aromatic hydrocarbons in crude oils and source rocks (e.g., naphthalenes, phenanthrenes, dibenzothiophenes) have a wide range of molecular weights and boiling points (60–350 °C). A heating rate of 5 °C/min balances separation efficiency and analysis time—a rate slower than 5 °C/min would extend runtime without significant separation improvement, while faster rates cause peak co-elution (e.g., methylnaphthalene isomers).

Complete elution of high-molecular-weight aromatics: The 20 min hold at 300 °C ensures full elution of high-molecular-weight aromatic homologs (e.g., pentamethylnaphthalenes, trimethylphenanthrenes), avoiding sample carryover and ensuring accurate quantification of maturity-sensitive biomarkers. This temperature program was optimized to achieve effective separation and detection of saturated and aromatic hydrocarbon compounds. The low initial temperature aids in retaining low-boiling-point components, while the slow ramp rate combined with a final isothermal stage ensures adequate elution and chromatographic resolution of medium- to high-molecular-weight biomarkers (e.g., steranes, hopanes) and polycyclic aromatic hydrocarbons, consistent with established analytical protocols and previous studies.

3.2.7. Investigation of Source Rock Distribution

Based on the established sedimentary facies framework, well-log lithology interpretations were calibrated against core descriptions and cuttings logs. This process enabled the precise delineation of vertical dark mudstone intervals within individual wells. Subsequently, within the context of sedimentary microfacies distribution, the lateral continuity and areal extent of these organic-rich, dark mudstone units were predicted and mapped.

4. Results

4.1. Geochemical and Petrological Characteristics of Source Rocks

4.1.1. Distribution of Source Rocks

The source rock system of the Chang 7 Member exhibits a distribution pattern characterized by extensive lateral coverage yet significant local variability, in which black shale and dark mudstone are complementarily distributed [25]. In the Pingbei area, the dark mudstone within the Chang 7 Member has a thickness ranging from 40 to 60 m, constituting over 60% of the total member thickness. Spatially, the thickness demonstrates a general decreasing trend from the northeast to the southwest. Specifically, the northern and southeastern sectors of the area feature greater thicknesses, while the central part is relatively thinner (Figure 2 and Figure 3).

4.1.2. Organic Matter Abundance

The measured total organic carbon (TOC) content of the analyzed source rock samples ranges from 0.61% to 6.15%, with an average of 1.69% (The complete dataset of TOC and Rock-Eval pyrolysis for all 41 samples is provided in Appendix A 

Table A2. Complete data table of Source rock TOC and rock pyrolysis.

No.	Well Number	Depth/m	Stratigraphic Horizon	Lithology	TOC%	Tmax°C	S1 (mg/g)	S2 (mg/g)	S1 + S2 (mg/g)	HI/gTOC
1	P45-903	1488.05	Chang 72	Dark gray mudstone	2.78	452	1.23	8.33	9.56	300
2	P45-903	1488.76	Chang 72	Dark gray mudstone	2.72	452	1.11	8.58	9.69	315
3	P45-903	1489.02	Chang 72	Dark gray mudstone	2.69	451	1.2	8.63	9.83	321
4	P45-903	1489.46	Chang 72	Dark gray mudstone	2.05	448	1.4	7.36	8.76	359
5	P45-903	1489.62	Chang 72	Dark gray mudstone	2.87	451	0.85	8.82	9.67	307
6	P45-903	1489.79	Chang 72	Dark gray mudstone	2.36	450	0.91	7.37	8.28	312
7	P45-903	1490.06	Chang 72	Dark gray mudstone	3.27	452	1.03	10.42	11.45	319
8	P65-109	1413.5	Chang 72	Dark gray silty mudstone	0.72	450	0.81	2.8	0.92	109.72
9	P65-109	1416	Chang 72	Dark gray mudstone	2.23	451	0.36	0.87	4.66	178.03
10	P65-109	1420.5	Chang 72	Gray silty mudstone	0.83	451	0.1	1.2	0.48	48.19
11	P45-903	1492.37	Chang 73	Dark gray mudstone	0.71	455	0.1	0.61	0.71	86
12	P45-903	1509.42	Chang 73	Dark gray mudstone	0.88	453	0.37	1.29	1.66	147
13	P45-903	1510.05	Chang 73	Dark gray mudstone	1.63	448	0.24	4.23	4.47	260
14	P45-903	1510.5	Chang 73	Dark gray mudstone	0.95	448	0.19	2.1	2.29	221
15	P45-903	1510.77	Chang 73	Dark gray mudstone	5.33	440	1.25	10.74	11.99	202
16	P45-903	1512.12	Chang 73	Dark gray mudstone	0.83	456	0.12	0.66	0.78	80
17	P45-903	1512.89	Chang 73	Dark gray mudstone	0.61	455	0.1	0.63	0.73	103
18	P45-903	1513.16	Chang 73	Dark gray mudstone	0.81	448	0.14	1.27	1.41	157
19	P45-903	1513.44	Chang 73	Dark gray mudstone	0.74	454	0.09	0.58	0.67	78
20	P45-903	1515.48	Chang 73	silty mudstone	1.44	446	0.29	2.83	3.12	197
21	P45-903	1515.9	Chang 73	silty mudstone	1.05	450	0.35	2.6	2.95	248
22	P45-903	1516.58	Chang 73	silty mudstone	1.02	447	0.17	1.62	1.79	159
23	P45-903	1516.9	Chang 73	silty mudstone	1.26	449	0.33	2.02	2.35	160
24	P45-903	1517.3	Chang 73	silty mudstone	1.51	450	0.41	3.16	3.57	209
25	P45-903	1518.52	Chang 73	Dark gray mudstone	1.54	447	0.27	3.72	3.99	242
26	P45-903	1518.72	Chang 73	Dark gray mudstone	1.35	447	0.24	2.29	2.53	170
27	P45-903	1519.1	Chang 73	Dark gray mudstone	0.75	453	0.08	0.72	0.8	96
28	P45-903	1520.28	Chang 73	Dark gray mudstone	0.8	449	0.15	1.22	1.37	153
29	P45-903	1520.77	Chang 73	Dark gray mudstone	0.78	450	0.15	1.61	1.76	206
30	P45-903	1521.92	Chang 73	silty mudstone	0.84	448	0.17	1.14	1.31	136
31	P45-903	1522.2	Chang 73	Dark gray mudstone	0.76	450	0.15	1.02	1.17	134
32	P45-903	1523.99	Chang 73	Dark gray mudstone	0.61	451	0.07	0.49	0.56	80
33	P45-903	1525.69	Chang 73	Dark gray mudstone	0.76	450	0.11	0.94	1.05	124
34	P45-903	1526.84	Chang 73	Dark gray mudstone	1.01	450	0.13	1.15	1.28	114
35	P45-903	1527.52	Chang 73	Dark gray mudstone	4.14	444	0.92	10	10.92	242
36	P45-903	1527.6	Chang 73	Dark gray mudstone	6.15	442	1.59	20.6	22.19	335
37	P45-903	1527.84	Chang 73	Dark gray mudstone	0.78	453	0.1	1.21	1.31	155
38	P45-903	1528	Chang 73	Dark gray mudstone	3	444	0.81	9.75	10.56	325
39	P45-903	1530.73	Chang 73	Dark gray mudstone	0.88	453	0.09	0.84	0.93	95
40	P45-903	1530.94	Chang 73	Dark gray mudstone	2.3	447	0.78	6.23	7.01	271
41	P45-903	1531.22	Chang 73	Dark gray mudstone	1.36	446	0.21	1.91	2.12	140

). Based on established TOC thresholds for source rock evaluation, the samples are classified as follows: 13 are high-quality source rocks (TOC > 2%), 10 are good source rocks (TOC 1–2%), and 18 are ordinary source rocks (TOC 0.5–1%). At the sub-member scale, the Chang 7³ interval exhibits the highest organic richness, with an average TOC of 2.8%, meeting the criterion for high-quality source rocks. The Chang 7² sub-member also shows considerable organic matter abundance, with an average TOC of 2.23% (Figure 4).

The hydrocarbon generation potential (S₁ + S₂) of the samples ranges from 0.48 to 22.19 mg/g, with an average of 4.45 mg/g (Figure 5). The TOC content exhibits a strong positive linear correlation with S₁, S₂, and the total S₁ + S₂ values (Figure 6). Specifically, the content of free hydrocarbons (S₁) varies from 0.07 to 1.59 mg/g (average 0.47 mg/g), while the pyrolyzable hydrocarbon yield (S₂) ranges from 0.49 to 20.6 mg/g (average 4.18 mg/g).

This confirms that the organic matter in the studied source rocks is the primary contributor to both the detectable hydrocarbons (S₁) and the potential generative hydrocarbons (S₂). This correlation indicates that organic matter abundance (TOC) directly controls the source rock’s hydrocarbon potential, and the conversion efficiency of organic matter is relatively consistent across samples. Variations in slopes may reflect minor differences in organic matter type or maturity, but the overall trend supports the use of TOC as a reliable proxy for evaluating the generative capacity of these source rocks.

As indicated in

Table 1. Statistical table of average hydrocarbon generation potential of source rocks in the Chang 7 Member, Pingbei area.

Stratigraphic Horizon	TOC%	S1 (mg/g)	S2 (mg/g)	S1 + S2 (mg/g)
Chang 72	2.25	1.1	8.5	9.6
Chang 73	1.5	0.33	3.2	3.53
Average	1.69	0.47	4.18	4.45

, significant variations exist in the average hydrocarbon generation potential among different sub-members. The Zhangjiatan shale exhibits superior hydrocarbon generation capacity compared to the other intervals, although its potential only meets the criteria for ordinary source rocks. The average values for the remaining layers fall below the threshold required for effective hydrocarbon generation.

4.1.3. Organic Matter Type

Organic matter types in this study were classified by integrating petrographic composition and geochemical parameters, following the kerogen classification scheme of Peters [28] and using maceral terminology defined by the International Committee for Coal and Organic Petrology (ICCP, 1994).

(1)

Type II₁ (Oil-Prone Mixed Type): This type is characterized by a high hydrogen index (HI > 300 mg HC/g TOC) and a maceral composition dominated by alginite (aquatic algae, a liptinite maceral per ICCP 1994) and vitrinite (terrestrial plants). It represents excellent potential for generating liquid hydrocarbons and is typically deposited in suboxic lacustrine environments with significant contributions from both aquatic and terrestrial organic matter.

(2)

Type II₂ (Oil–Gas Transitional Type): This type has a moderate hydrogen index (HI generally 200–300 mg HC/g TOC). Petrographically, it contains a lower proportion of alginite and a higher proportion of vitrinite compared to Type II₁, indicating a greater terrestrial input. It possesses significant oil generation potential and appreciable gas generation potential upon higher maturity, often associated with shallow lacustrine or deltaic settings.

(3)

Type III (Gas-Prone Humic Type): This type is defined by a low hydrogen index (HI < 200 mg HC/g TOC). It is petrographically dominated by vitrinite and inertinite, with minimal liptinite (including alginite) content. It is primarily gas-generating and indicative of oxidizing terrestrial (e.g., swampy) depositional environments.

A total of four samples from the Chang 7 Member were analyzed for organic matter type. Due to the limited number of samples (n = 4) available for maceral analysis, the results presented here should be interpreted with caution and may not fully represent the heterogeneity of organic matter types across the entire Pingbei area. They are, however, considered indicative of the dominant kerogen type. Among these, three samples from the Chang 7² sub-member are classified as Type II (mixed-type) organic matter, while one sample from the Chang 7³ sub-member is identified as Type III (humic type).

Microscopic identification of macerals yielded the following compositional ranges: alginite (35.7–65.7%), liptinite (36.4–67%), vitrinite (32.7–63.3%), and inertinite (0.3–0.7%). Based on maceral composition, the organic matter is predominantly Type II₁, with minor contributions from Type II₂ and Type III (

Table 2. Summary of organic matter types of dark mudstones in the Pingbei area.

Well Number	Depth/m	Stratigraphic Horizon	Lithology	Alginite/%	Liptinite/%	Vitrinite/%	Inertinite%	Type Index	Organic Matter Type
P65-109	1415.0	Chang 72	Dark gray silty mudstone	65.7	67	32.7	0.3	41.5	TypeII1
P65-109	1417.5	Chang 72	Dark gray mudstone	60.7	61.7	37.7	0.7	32.2	TypeII2
P65-109	1422.0	Chang 72	Gray silty mudstone	62.7	63.4	36.3	0.3	35.5	TypeII2
P31-97	1558.3	Chang 73	Dark gray mudstone	35.7	36.4	63.3	0.3	−11.7	Type III

). The HI of the Chang 7² sub-member ranges from 48.19 to 359 mg/g (average 257 mg/g); the HI of the Chang 7³ sub-member ranges from 78 to 335 mg/g (average 172 mg/g). The HI-Tmax cross-plot confirms the organic matter type distribution (Figure 7).

Maceral identification based on four polished sections revealed a composition dominated by alginite and vitrinite (Table 2), consistent with Type II₁ kerogen. The representativeness of this limited dataset is discussed in Section 5.7.

4.1.4. Organic Matter Maturity

Organic matter maturity is a fundamental parameter for assessing the hydrocarbon generation potential of source rocks, as it directly governs the conversion efficiency of organic matter into hydrocarbons [29]. The measured maturity parameters for the studied samples are as follows: vitrinite reflectance (Ro) measurements on 20 representative samples yielded a range from 0.76% to 0.87% (detailed data, including mean, standard deviation, and measurement count for each sample, are provided in Table A1; see the distribution histogram in Figure 8a); the maximum pyrolysis temperature (Tmax) varies between 440 and 456 °C (Figure 8b); and the hydrocarbon conversion index (HCI) spans from 10 to 68 mg/g TOC, with an average of 23.8 mg/g TOC. In accordance with the petroleum industry standard SY/T 5735-2019, these collective indicators place the source rocks within the mature stage, corresponding to the peak window for liquid hydrocarbon generation.

Vitrinite reflectance measurements were conducted on 20 representative samples. Following the ASTM D7708 standard guideline, a minimum of 20 valid measurements were targeted per sample. Outliers, identified as values deviating by more than two standard deviations from the initial mean, were excluded prior to calculating the final mean Ro and standard deviation for each sample (see Table A1 for detailed data). Although the final number of valid measurements for some samples was slightly below 20, the consistency of Ro values with other maturity parameters (e.g., biomarker ratios) supports the reliability of the dataset (see Section 5.4).

Both Ro (Table A1) and Tmax (Appendix A Table A2) values for the corresponding set of 20 source rock samples indicate a mature stage. However, a plot of mean Ro versus Tmax for these paired samples does not show a strong linear correlation (Figure 8b). The potential reasons for this discrepancy, including organic matter type heterogeneity and potential methodological factors, are analyzed in Section 5.4.

4.2. Geochemical Characteristics and Classification of Crude Oils

4.2.1. Saturated Hydrocarbon Chromatographic Characteristics

Isoprenoid alkane assemblages were detected in all crude oil samples. In strongly reducing and hypersaline depositional settings, phytane typically shows distinct predominance with relatively high abundance, whereas pristane tends to dominate in more oxidizing environments such as swamps [30]. As shown in

Table 3. Distribution characteristics and related parameters of normal and isoalkanes in crude oils from different blocks (M/z85, whole oil GC-MS quantification).

Area	Well Number	Stratigraphic Horizon	Pr/Ph	Pr/C17	Ph/C18	R29	C21−/C2+	0EP 19–23	Carbon Number Range	Dominant Carbon Peak
Pingbei	P53-99	Chang 63	0.84	0.20	0.24	1.11	1.65	1.04	<C10–C40	C20
	P70-119	Chang 63	0.85	0.21	0.25	1.14	1.40	1.05	<C10–C40	C20
	P59-120	Chang 4 + 52	0.85	0.21	0.25	1.11	1.75	1.04	<C10–C40	C20
	P59-118	Chang 7	1.77	0.12	0.07	1.11	1.35	1.03	<C10–C40	C20
	P65-109	Chang 7	1.78	0.16	0.09	1.11	1.30	1.03	<C10–C40	C21
Peripheral	Qi 3-341	Chang 61+2	0.87	0.21	0.24	1.10	1.61	1.03	<C10–C40	C20
	Liu 139-14	Chang 61+2	0.80	0.17	0.21	1.12	1.36	1.06	<C10–C40	C21
	Liu 140-12	Chang 612	0.89	0.20	0.22	1.15	1.16	1.05	<C10–C40	C20
	Qi 73-62	Chang 61	0.85	0.20	0.24	1.10	1.59	1.01	<C10–C40	C19
	Pan 08-46	Chang 7	1.01	0.18	0.18	1.11	1.70	1.03	<C10–C28	C17
	Pan 38-24	Chang 7	1.26	0.15	0.11	1.11	1.36	1.05	<C10–C40	C19
	Xing 85	Chang 7	1.15	0.18	0.15	1.13	1.39	1.04	<C10–C40	C20

, the measured parameters for the studied oils are as follows: the pristane/C₁₇ ratio (Pr/C₁₇) ranges from 0.12 to 0.21, the phytane/C₁₈ ratio (Ph/C₁₈) from 0.07 to 0.25, and the pristane/phytane ratio (Pr/Ph) from 0.84 to 1.78. Notably, crude oils from the Chang 7 Member exhibit higher Pr/Ph values (1.77–1.78), suggesting their source rocks were deposited in a suboxic to weakly oxic environment, while those from shallow reservoirs show lower ratios (0.80–0.89) indicative of a more strongly reducing depositional setting. Variations in Pr/C₁₇ and Ph/C₁₈ ratios are related to organic matter input and maturity, with higher values often associated with greater terrestrial contribution or lower maturity.

Figure 9 is an m/z 123 mass chromatogram showing the detection of bicyclic sesquiterpenoids, a typical terrestrial biomarker whose isomer distribution is controlled by maturity and source facies. It compares two key samples: the upper plot represents Type B crude oil from P70-119 (Chang 6³, shallow reservoir) with higher J/K ratios (1.63–1.74) and lower (A + B)/C ratios (0.53–0.68), indicating relatively low maturity and distinct terrestrial organic matter input; the lower plot corresponds to Type A crude oil from P65-109 (Chang 7, deep reservoir) with lower J/K ratios (0.37–0.92) and significantly higher (A + B)/C ratios (1.40–5.00) (

Table 4. Distribution characteristics of bicyclic sesquiterpenoids (m/z123; ABCHJK see Figure 9; quantified by saturated hydrocarbon GC-MS).

Area	Well Number	Stratigraphic Horizon	J/K	(A + B)/C	A/B	C/H
Pingbei	P53-99	Chang 63	1.63	0.57	0.63	1.73
	P70-119	Chang 63	1.63	0.68	0.73	1.66
	P59-120	Chang 4 + 52	1.74	0.53	0.58	1.76
	P59-118	Chang 7	0.37	5.00	2.24	1.42
	P65-109	Chang 7	0.92	1.40	0.80	1.19
Peripheral	Qi 3-341	Chang 61+2	1.03	1.44	1.05	1.64
	Liu 139-14	Chang 612	1.03	1.56	0.94	1.35
	Qi 73-62	Chang 61	1.04	1.28	0.95	1.50
	Liu 140-12	Chang 612	1.21	1.58	0.98	1.28
	Xing 85	Chang 7	1.31	1.33	0.84	1.13
	Pan 38-24	Chang 7	0.93	3.20	1.67	0.82
	Pan 08-46	Chang 7	0.70	2.96	1.64	1.23

), reflecting higher thermal maturity consistent with the Chang 7 Member source rocks, showing greater affinity with the characteristics of the Chang 7 source rocks.

The Ts/Tm ratio is primarily controlled by two factors: the degree of thermal evolution and the characteristics of the sedimentary environment [31]. The measured Ts/Tm values for deep crude oils range from 3.47 to 7.18, while those for shallow crude oils are significantly lower, ranging from 0.48 to 0.51. Furthermore, other biomarker ratios, including C₂₉Ts/C₂₉ hopane, C₂₃ tricyclic terpane/C₃₀ hopane, and C₃₀ rearranged hopane/C₃₀ hopane, exhibit variation trends consistent with those of the Ts/Tm ratio (

Table 5. Distribution characteristics of long-chain tricyclic terpanes and pentacyclic triterpanes in crude oils.

Area	Well Number	Stratigraphic Horizon	Tricyclic Terpane C21/C23	C24 Tetracyclic /C26Tricyclic Terpane	C23 Tricyclic Terpane /C30 Hopane	Ts/Tm	C29 Rearranged Hopane/C29 Hopane	C29Ts /C29 Hopane	C30 Rearranged Hopane/C30Hopane	Gammacerane /C31Hopane
Ping bei	P53-99	Chang 63	0.83	2.46	0.03	0.48	0.08	0.23	0.08	0.34
	P70-119	Chang 63	0.82	2.34	0.03	0.51	0.08	0.22	0.08	0.34
	P59-120	Chang 4 + 52	0.81	2.48	0.04	0.50	0.07	0.22	0.08	0.32
	P59-118	Chang 7	0.82	2.88	0.11	7.18	2.32	1.89	1.92	0.41
	P65-109	Chang 7	0.99	2.63	0.12	3.47	0.39	0.93	0.32	0.37
Peripheral	Qi 3-341	Chang61+2	0.82	1.57	0.06	0.89	0.16	0.33	0.13	0.50
	Liu 139-14	Chang 612	0.80	1.94	0.04	2.08	0.19	0.45	0.14	0.32
	Qi 73-62	Chang 61	0.80	1.63	0.06	0.73	0.14	0.32	0.12	0.45
	Liu 140-12	Chang 612	0.77	1.79	0.05	2.14	0.21	0.51	0.17	0.38
	Xing 85	Chang 7	0.84	1.41	0.08	6.53	0.86	1.49	0.48	0.43
	Pan 38-24	Chang 7	0.74	1.45	0.09	6.75	0.90	1.36	0.40	0.36
	Pan 08-46	Chang 7	0.72	0.87	0.18	6.34	0.76	1.14	0.51	0.46

).

4.2.2. Composition and Distribution Characteristics of Steranes

The relative abundances of C₂₇, C₂₈, and C₂₉ regular steranes (ααα20R configuration) in crude oil serve as important indicators for reconstructing organic matter input [32]. It is widely recognized that C₂₇ regular steranes primarily originate from lower aquatic organisms and algae, whereas C₂₉ regular steranes are predominantly derived from terrestrial higher plants [33]. In the analyzed crude oils, regular steranes are overwhelmingly dominant, with their abundances significantly exceeding those of rearranged steranes. The distribution patterns of the ααα20R stereoisomers for C₂₇, C₂₈, and C₂₉ regular steranes reveal distinct trends: shallow crude oils exhibit an asymmetric “V”-shaped pattern with C₂₉ as the dominant peak, while deep crude oils display an inverted “L”-shaped distribution (Figure 10). This shift in sterane profile indicates a transition in the primary source of organic matter from terrestrial higher plants to aquatic algae with increasing burial depth [34].

Quantitative analysis of sterane parameters reveals distinct differences between deep and shallow crude oils. The ratio of C₂₇ rearranged steranes to regular steranes ranges from 1.24 to 2.67 in deep crude oils, compared to a significantly lower range of 0.36–0.38 in shallow crude oils. Furthermore, maturity-sensitive sterane parameters indicate that all samples have entered the mature stage: the C₂₉ sterane 20S/(20S + 20R) ratios range from 0.53 to 0.61, and the C₂₉ sterane ββ/(αα + ββ) ratios range from 0.52 to 0.59 (

Table 6. Sterane distribution characteristics and selected parameters in crude oils.

Area	Well Number	Stratigraphic Horizon	C27Rearranged Sterane/ C27Sterane	C29Sterane S/(S + R)	C29Sterane ββ/(αα + ββ)	C29Sterane ββ20R/αα20R	C29 Sterane 5α20S/20R	C27%	C28%	C29%
Pingbei	P53-99	Chang 63	0.36	0.53	0.52	1.26	1.13	24	35	41
	P70-119	Chang 63	0.38	0.53	0.53	1.24	1.13	25	36	40
	P59-120	Chang 4 + 52	0.36	0.53	0.52	1.15	1.12	24	35	41
	P59-118	Chang 7	2.67	0.59	0.59	1.69	1.47	28	37	36
	P65-109	Chang 7	1.24	0.61	0.54	1.54	1.53	18	28	54
Peripheral	Qi 3-341	Chang 61+2	0.68	0.54	0.56	1.43	1.19	23	36	41
	Liu 139-14	Chang 61+2	0.68	0.57	0.54	1.36	1.30	26	33	41
	Qi 73-62	Chang 61	0.65	0.55	0.56	1.45	1.24	24	36	40
	Liu 140-12	Chang 612	0.77	0.57	0.55	1.48	1.35	25	35	41
	Xing 85	Chang 7	0.60	0.56	0.56	1.45	1.26	21	36	42
	Pan 38-24	Chang 7	1.42	0.63	0.55	1.64	1.71	22	36	42
	Pan 08-46	Chang 7	1.19	0.60	0.57	1.61	1.53	24	39	37

).

4.2.3. Characteristics of Aromatic Hydrocarbon Compounds

GC–MS analysis indicates that the aromatic hydrocarbon profiles of crude oils from the Chang 6 and Chang 7 Members exhibit systematic differences consistent with thermal maturation. Within the naphthalene series, methylnaphthalenes show the highest abundance, with a progressive decrease as the number of alkyl substituents increases. A comparative analysis between the two members reveals that the relative abundances of C₁-, C₂-, and C₃-naphthalene homologs are significantly higher in Chang 7 crude oils than in Chang 6 crude oils (Figure 11). This distribution trend suggests the preferential enrichment of lower-ring-number aromatic compounds with increasing thermal maturity.

Parameters C, D, and E listed in

Table 7. Distribution characteristics and selected geochemical parameters of aromatic hydrocarbon compounds in crude oils (based on GC–MS analysis of the aromatic fraction). The methylphenanthrene/C₃₀ hopane ratio is included as a maturity-sensitive parameter for oil classification.

Area	Well Number	Stratigraphic Horizon	A	B	C	D	E	F	Rc	G	H	I	J	K	L	M	N	O	P
Pingbei	P59-120	Chang 4 + 52	1.42	0.82	0.60	0.69	0.22	0.71	0.83	0.83	0.86	0.54	2.99	1.06	0.82	0.49	0.83	0.09	0.70
	P70-119	Chang 63	1.52	0.86	0.62	0.70	0.24	0.74	0.85	0.84	0.86	0.56	4.00	1.20	0.99	0.67	0.55	0.09	0.68
	P53-99	Chang 63	1.52	0.83	0.63	0.71	0.24	0.72	0.83	0.84	0.86	0.58	3.50	1.14	1.03	0.59	0.75	0.08	0.69
	P59-118	Chang 7	1.64	1.24	0.77	0.73	0.61	0.75	0.85	0.91	1.36	0.14	4.23	1.37	1.33	0.70	0.52	0.12	1.45
	P65-109	Chang 7	1.84	1.34	0.84	0.84	0.54	0.82	0.89	1.10	0.98	0.14	6.30	1.60	1.37	1.00	0.16	0.06	1.38
Peripheral	Qi 73-62	Chang 61	1.48	1.03	0.76	0.77	0.28	0.83	0.90	0.92	0.96	0.28	4.84	1.57	1.18	1.17	0.37	0.088	0.65
	Liu 140-12	Chang 612	1.53	0.99	0.68	0.64	0.29	0.70	0.82	0.85	0.90	0.42	3.76	1.18	0.99	0.61	0.37	0.076	0.63
	Liu 139-14	Chang 612	1.49	1.00	0.70	0.68	0.25	0.76	0.86	0.89	0.93	0.38	4.60	2.19	1.70	0.69	0.37	0.072	0.61
	Qi 3-341	Chang 61+2	1.62	1.10	0.78	0.77	0.29	0.82	0.89	0.93	1.00	0.25	4.94	1.72	1.19	1.02	0.34	0.091	0.67
	Xing 85	Chang 7	1.36	0.87	0.70	0.68	0.32	0.66	0.80	0.74	0.80	0.41	3.84	1.13	0.95	0.79	0.47	0.077	0.89
	Pan 38-24	Chang 7	1.65	1.08	0.71	0.65	0.55	0.71	0.82	0.82	1.09	0.41	4.20	1.26	1.01	0.61	0.36	0.080	0.92
	Pan 08-46	Chang 7	1.68	1.25	0.87	0.80	0.57	0.84	0.91	0.95	0.93	0.12	6.04	1.73	1.29	1.04	0.23	0.073	0.95

A: 2-/1-Methylnaphthalene; B: (2,7- + 2,6-)/(1,3- + 1,6-) Dimethylnaphthalene; C: 1,3,7-/(1,3,7- + 1,2,5-) Trimethylnaphthalene; D:1,3,6,7-/(1,3,6,7- + 1,2,5,6- + 1,2,3,5-) Tetramethylnaphthalene; E: 1,2,4,6,7-/(1,2,4,6,7- + 1,2,3,5,6-) Pentamethylnaphthalene; F: MPI1 = 1.5 × (2- + 3-Methylphenanthrene)/(Phenanthrene + 9-Methylphenanthrene + 1-Methylphenanthrene); Rc: Rc = 0.6 × MPI1 + 0.40; (3- + 2-)/(9- + 1-) Methylphenanthrene; G: (3- + 2-)/(9- + 1-) Methylphenanthrene; H: (1,6- + 2,9- + 2,5-)/1,7-Dimethylphenanthrene; I: 1,2,8-/(1,3,7- + 2,6,9- + 2,7,9-) Trimethylphenanthrene; J: 4-/1-Methyldibenzothiophene; K: 4,6-/1,4-Dimethyldibenzothiophene; L: 2,4-/1,4-Dimethyldibenzothiophene; M: Dibenzothiophene/Dibenzofuran; N: Dibenzofuran/Fluorene; O: Dibenzothiophene/Phenanthrene; P: Methylphenanthrene/C₃₀ Hopane = (1- + 2- + 3- + 9-Methylphenanthrene)/C₃₀ Hopane (calculated from GC–MS peak area ratios).

are maturity indicators derived from the distribution patterns of trimethylnaphthalene, tetramethylnaphthalene, and pentamethylnaphthalene, respectively. As illustrated in Figure 12, the relative abundances of these poly-methylated naphthalene isomers vary systematically with increasing thermal maturity. Specifically, Parameter C (defined as the ratio 1,3,7-/(1,3,7- + 1,2,5-trimethylnaphthalene)) exhibits relatively high values (0.77–0.84) in deep crude oils from the Pingbei area, while shallow crude oils show lower values (0.60–0.63). A comparison with oils from surrounding areas indicates that elevated values of this parameter are generally associated with deeper reservoirs, although some deep crude oils also display lower values.

The deep crude oils (Chang 7) show lower Ph/C₁₈ ratios (Table 3). This could be attributed to several factors: Firstly, their higher Pr/Ph ratios suggest a relatively more oxic depositional environment, which is less favorable for the reductive conversion of phytol (the precursor of phytane) to phytane. Secondly, higher thermal maturity may promote the cracking or isomerization of phytane relative to n-alkanes. Additionally, it may reflect specific biological source compositions within the source rock organic matter.

Comparative analysis of alkylphenanthrene compounds in the Chang 7 and Chang 6 crude oils reveals marked differences in their phenanthrene series distributions (Figure 13). The primary distinctions lie in the relative abundances of key dimethylphenanthrene isomers: 1,7-dimethylphenanthrene, the combined (1,6- + 2,9- + 2,5)-dimethylphenanthrene, and the combined (1,3- + 2,10- + 3,9- + 3,10)-dimethylphenanthrene. The abundance ratio of lower- to higher-molecular-weight compounds is notably higher in Chang 7 crude oils, indicating a relative enrichment of lower-carbon-number alkylphenanthrenes with increasing maturity. Furthermore, within the trimethylphenanthrene system, the relative abundance of 1,2,8-trimethylphenanthrene serves as a key discriminant. Parameter I (1,2,8-/(1,3,7- + 2,6,9- + 2,7,9-) trimethylphenanthrene) ranges from 0.54 to 0.58 in Chang 6 oils but drops sharply to approximately 0.14 in Chang 7 oils. This pronounced contrast in Parameter I values further suggests that the two oil groups may originate from different genetic sources or have experienced distinct hydrocarbon generation and expulsion histories.

4.2.4. Classification of Crude Oil Genetic Types

The Ts/Tm ratio is influenced by both sedimentary environment characteristics and thermal evolution degree [35]. Based on cross-plots of Ts/Tm versus Pr/Ph (Figure 14) and Ts/Tm versus methylphenanthrene/C₃₀ hopane (Figure 15), the crude oils in the study area are classified into two distinct genetic types:

Type A oils are found in deep reservoirs of the Chang 7 Member. They are characterized by high Ts/Tm values (3.47–7.18), high Pr/Ph ratios (1.77–1.78), and elevated methylphenanthrene/C₃₀ hopane ratios.

Type B oils are found in both shallow and deep reservoirs. They are characterized by low Ts/Tm values (0.48–0.51), low Pr/Ph ratios (0.84–0.85), and low methylphenanthrene/C₃₀ hopane ratios.

4.3. Oil–Source Correlation Analysis

4.3.1. Correlation Between Type A Crude Oil and Chang 7 Member Source Rocks

Type A crude oil exhibits a high degree of geochemical consistency with the dark mudstones of the Chang 7 Member. This affinity is demonstrated by their comparable Pr/Ph ratios, similar enrichment levels of rearranged hopanes, and congruent distribution patterns of pentacyclic triterpanes. Both the oil and the source rocks are notably enriched in C₃₀ and C₂₉ rearranged hopanes, the abundances of which exceed that of regular C₃₀ hopane (Figure 16). The concentration of C₃₀ rearranged hopanes is influenced primarily by sedimentary conditions (e.g., redox state), clay mineral content, and thermal maturity. Elevated abundances of these compounds are commonly indicative of a suboxic to oxic depositional environment [37].

The basic geochemical parameters, including n-alkanes and isoprenoids, for the Chang 7 Member source rocks are summarized in

Table 8. Hydrocarbon source rock basic geochemical parameters (n-alkanes and isoprenoids).

No.	Well Number	Stratigraphic Horizon	Sample Name	Carbon Number Range	Dominant Carbon Peak	0EP	Pr/Ph	Pr/n -C17	Ph/n -C18	(C21 + C22)/ (C28 + C29)	∑C21−/∑C22+
1	P31-97	Chang 73	Dark Gray Mudstone	C15–C38	C19	1.03	0.51	0.48	0.48	3.92	1.14
2	P65-109	Chang 72	Dark Gray Siltstone Mudstone	C13–C40	C19	1.05	3.78	0.62	0.15	2.01	0.96
3	P65-109	Chang 72	Dark Gray Mudstone	C13–C40	C19	1.06	4.21	0.85	0.17	1.99	0.80
4	P65-109	Chang 72	Gray Siltstone Mudstone	C13–C40	C19	1.00	1.47	0.32	0.19	1.72	0.75
5	P31-97	Chang 73	Dark Gray Mudstone	C14–C36	C25	1.25	2.54	0.85	0.29	1.96	0.84
6	P31-97	Chang 73	Dark Gray Mudstone	C14–C38	C19	1.00	2.32	0.89	0.25	5.78	1.43
7	P31-97	Chang 73	Dark Gray Mudstone	C14–C39	C19	1.03	3.95	1.56	0.34	4.67	1.42
8	P65-109	Chang 72	Dark Gray Mudstone	C14–C40	C20	1.00	1.77	0.23	0.11	1.99	0.85
9	P65-109	Chang 72	Dark Gray Mudstone	C14–C40	C20	1.00	1.81	0.21	0.09	2.43	0.94

. Corresponding biomarker parameters, encompassing terpanes and steranes, are presented in

Table 9. Hydrocarbon source rock biomarker parameters (triterpanes and steranes).

No.	Well Number	Stratigraphic Horizon	Ts/ Tm	C23 Tricyclic Terpane/C30 Hopane	C30 Rearranged Hopane/C30 Hopane	C29Ts/ C29 Hopane	Gammacerane/C31 Hopane	C27%	C28%	C29%	C29 Sterane S/(S + R)	C29 Steraneββ/(αα + ββ)	C27 Rearranged Sterane/C27 Sterane
1	P31-97	Chang 73	2.85	0.09	0.35	0.89	0.32	26	34	40	0.52	0.53	0.87
2	P65-109	Chang 72	6.82	0.12	1.87	1.82	0.36	28	35	37	0.58	0.57	2.54
3	P65-109	Chang 72	7.15	0.13	1.92	1.89	0.38	29	36	35	0.60	0.59	2.67
4	P65-109	Chang 72	3.51	0.10	0.42	0.93	0.33	25	34	41	0.53	0.54	0.92
5	P31-97	Chang 73	2.97	0.08	0.38	0.91	0.31	24	33	43	0.51	0.52	0.83
6	P31-97	Chang 73	3.02	0.09	0.40	0.95	0.34	27	35	38	0.53	0.53	0.89
7	P31-97	Chang 73	3.18	0.10	0.45	1.02	0.35	26	34	40	0.54	0.54	0.95
8	P65-109	Chang 72	3.47	0.11	0.48	1.05	0.37	28	36	36	0.55	0.55	1.01
9	P65-109	Chang 72	3.62	0.12	0.51	1.12	0.39	27	35	38	0.56	0.56	1.08

Ts = 18α(H)-22,29,30-Trisnorneohopane; Tm = 17α(H)-22,29,30-Trisnorhopane; all parameters were analyzed by Agilent 7890A-5975C GC-MS.

. The Pr/Ph ratios of Type A crude oils (1.77–1.78) fall within the range observed for the Chang 7 Member source rock samples (1.47–4.21). This correspondence, along with the biomarker consistency noted above, confirms that the dark mudstones of the Chang 7 Member are the principal source rocks for the Type A oils. As potential source rocks, these dark gray mudstones display characteristic terpane and n-alkane distributions in their chromatographic profiles. These patterns directly reflect their hydrocarbon-generating potential and the types of organic parent materials [28].

4.3.2. Correlation Between Type B Crude Oil and Surrounding Chang 6 Member Source Rocks

The geochemical characteristics of Type B crude oils show no affinity with the local Chang 7 Member source rocks but closely resemble those of crude oils produced from the Chang 6 Member in surrounding oilfields. This similarity is evident in key biomarker ratios: the Pr/Ph ratios of Type B oils (0.84–0.85) and their Ts/Tm ratios (0.48–0.51) are consistent with the respective ranges observed in the surrounding Chang 6 oils (Pr/Ph: 0.80–0.89; Ts/Tm: 0.73–2.14).

5. Discussion

5.1. Effectiveness of the Chang 7 Member Dark Mudstones as Hydrocarbon Source Rocks

Geochemical and petrological analyses demonstrate that the Chang 7 dark mudstones in the Pingbei area possess fair to good organic matter abundance (avg. TOC 1.69%) and oil-prone Type II₁ kerogen, collectively meeting the criteria for effective source rocks. The development of these good-quality source rocks aligns with the general characteristics of lacustrine source rocks in continental basins across China, where dark mudstones deposited in deep lake environments are primary contributors to hydrocarbon generation [1]. The maturity (Ro = 0.76–0.87%) of these rocks corresponds to the peak stage of liquid hydrocarbon generation [38]. Furthermore, the maceral composition is characterized by a high abundance of alginate (35.7–65.7%), which provides a substantial material foundation for large-scale hydrocarbon generation [39]. Consequently, the Pingbei area itself constitutes an independent, effective source rock kitchen. This fundamentally alters the petroleum system context of the area, transforming it from a “prospect” potentially reliant entirely on external sources into a viable exploration play with self-sourcing potential. Establishing the presence of local source rocks is the primary geological prerequisite for assessing tight oil resource potential and optimizing well placement in this region.

5.2. Genetic Mechanisms of the Two Types of Crude Oils

The formation of the two distinct crude oil types is primarily controlled by the sedimentary environment and thermal evolution history of their respective source rocks. Type A oils, sourced from the Chang 7 Member, are characterized by high Pr/Ph and Ts/Tm ratios. These features are consistent with a suboxic depositional setting and a mature stage of thermal evolution [36]. The enrichment of rearranged hopanes in these oils is further promoted by clay mineral catalysis within the source rock interval.

The classification into Type A and Type B oils is supported by established biomarker principles [32]. The Pr/Ph ratio serves as a proxy for paleo-redox conditions [40], with Type A oils (Pr/Ph = 1.77–1.78) indicating a weakly oxic–suboxic environment, and Type B oils (Pr/Ph = 0.84–0.85) suggesting a more strongly reducing setting. Similarly, the Ts/Tm and methylphenanthrene/C₃₀ hopane ratios reflect thermal maturity [41]. The higher values of these parameters in Type A oils confirm their more advanced thermal evolution compared to Type B oils. These geochemical signatures are consistent with the depositional and thermal histories of their inferred source rocks, thereby validating the genetic classification [42].

In contrast, Type B oils are interpreted to originate from the surrounding Chang 6 Member source rocks. Their low Pr/Ph and Ts/Tm ratios correspond to a relatively strong reducing sedimentary environment and a slightly lower degree of thermal evolution. The systematic differences in aromatic hydrocarbon compositions between the two oil types further reflect this maturity contrast [43].

This reveals a “dual hybrid charging system” in the Pingbei area. This system comprises (1) locally sourced oil: derived from mature Chang 7 delta-front mudstones, primarily migrating short distances vertically/near-source and (2) externally sourced oil: derived from peripheral Chang 6 deep-lacustrine shales, potentially undergoing longer-distance lateral migration. This model breaks the simplistic view of the area as a single-source system and provides the essential framework for understanding complex hydrocarbon distribution, mixing phenomena, and predicting fluid properties across different intervals.

5.3. Implications of Oil–Source Correlation for Tight Oil Exploration

A robust oil–source correlation is established based on the consistent biomarker fingerprints between the crude oils and potential source rocks. The Type A oils (produced from the Chang 7 reservoirs in the Pingbei area) exhibit Ts/Tm ratios of 3.47–7.18 and C₃₀ rearranged hopane/C₃₀ hopane ratios of 0.32–1.92. These ranges show complete overlap with those of the Chang 7² sub-member source rocks (Ts/Tm: 3.47–7.15; C₃₀ rearranged hopane/C₃₀ hopane: 0.48–1.92), indicating a clear genetic relationship. In contrast, Type B oils possess significantly lower Ts/Tm ratios (0.48–0.51), which differ markedly from the values characteristic of the Chang 7 Member source rocks. This distinction, combined with the consistent low Pr/Ph and Ts/Tm ratios, low rearranged sterane/hopane abundances, and distinct aromatic hydrocarbon profiles, strongly indicates that Type B crude oil is derived from the Chang 6 Member source rocks developed in the peripheral regions of the basin.

The identification of two types of crude oils helps optimize exploration strategies: focusing on Chang 7 Member deep reservoirs for Type A crude oil and considering Chang 6 Member shallow reservoirs for Type B crude oil, providing a scientific basis for efficient development.

5.4. Analysis of Contradictions in Maturity Parameters

A robust assessment of thermal maturity necessitates the integration of multiple independent geochemical parameters. As synthesized in

Table 10. Summary of key thermal maturity parameters for the Chang 7 Member source rocks in the Pingbei area.

Parameter	Value Range (This Study)	Interpretation (Maturity Stage)
Vitrinite Reflectance (Ro, %)	0.76–0.87	Mature (Main Oil Window)
Tmax from Rock-Eval (°C)	440–456	Mature (Main Oil Window)
Ts/(Ts + Tm) Ratio	0.74–0.88	High to Very High Maturity (Main–Late Oil Window)
C29 Sterane 20S/(20S + 20R)	0.51–0.63	Early to Mid-Oil Window (Approaching Equilibrium)
C29 Sterane ββ/(αα + ββ)	0.52–0.59	Immature to Early Oil Window (Below Equilibrium)

(detailed biomarker data are provided in Table A2), the various maturity indicators for the Chang 7 source rocks collectively affirm an oil-generating window but reveal notable internal discrepancies.

Vitrinite Reflectance (Ro) and Rock-Eval Tmax uniformly indicate a mature stage (0.76–0.87% and 440–456 °C, respectively).

Hopane-based Maturity: The Ts/(Ts + Tm) ratios are exceptionally high (0.74–0.88), which in conventional interpretation suggests high to very high thermal maturity (main to late oil window).

Sterane-based Maturity: The C₂₉ sterane 20S/(20S + 20R) ratios (0.51–0.61) for some samples approach the equilibrium range (0.52–0.55 for regular steranes; [44]), indicating mid-oil window maturity. In contrast, the C₂₉ sterane ββ/(αα + ββ) ratios (0.52–0.59) remain significantly below their equilibrium endpoint (~0.67–0.71) [44], suggesting a maturity level spanning from late immature to the early oil window.

Therefore, a central paradox emerges: the hopane parameter (Ts/Tm) implies higher maturity than the sterane parameter (C₂₉ ββ/(αα + ββ)). This discrepancy, coupled with the weak correlation between Ro and Tmax (Figure 8b), constitutes the focus of the following analysis. We evaluate four non-exclusive causative factors: (1) the differential geochemical behavior of biomarker parameters; (2) heterogeneity in organic matter type; (3) geological heterogeneity in thermal history; and (4) potential analytical artifacts or contamination.

Figure 8b indicates no clear positive correlation between Tmax and Ro, an observation that appears inconsistent with the general rule that both parameters increase with organic matter maturity. Considering the geological context and sample characteristics of the study area, the potential causes for this discrepancy are analyzed below:

Variations in Organic Matter Type: Maceral analysis (Table A2) reveals that some samples from the Chang 7³ sub-member contain Type II₂ organic matter, whereas most samples from the Chang 7² sub-member are Type II₁. According to Peters et al. [28], Tmax is influenced not only by thermal maturity but also by organic matter type. Type II₂ organic matter, which has a higher terrestrial input, tends to yield a higher Tmax than Type II₁ at an equivalent maturity. For instance, sample P31-97-3 (Chang 7³, Type II₂) has an Ro of 0.78% but a Tmax of 454 °C, which is 8 °C higher than that of sample P65-109-1 (Chang 7², Type II₁, Ro = 0.78%, Tmax = 446 °C). This type-dependent variation weakens the overall correlation between Tmax and Ro.

Heterogeneity in Thermal Evolution: The study area is situated within a delta-front distributary channel system where sand bodies are extensively developed and interbedded with dark mudstones. Sandstone possesses higher thermal conductivity than mudstone, leading to localized uneven heat flow. For example, the Chang 7³ sub-member in the northern part contains intercalated distributary channel sandstones 5–8 m thick. This results in an Ro of 0.87% for sample P31-97-4 (near a sandstone–mudstone contact) and 0.76% for sample P31-97-5 (5 m away from the contact), a difference of 0.11%. Such spatial heterogeneity in thermal history causes non-parallel changes in Tmax and Ro.

Differential Response of Hopane and Sterane Maturity Parameters: The apparent contradiction between the high Ts/(Ts + Tm) ratios and the lower C₂₉ ββ/(αα + ββ) ratios can be reconciled by understanding their distinct controlling factors. The Ts/(Ts + Tm) ratio is strongly influenced by sedimentary redox conditions and clay mineral catalysis, not solely by thermal maturity [45]. Deposition in suboxic to oxic environments (supported by high Pr/Ph ratios) favors Ts formation [46]. In contrast, sterane isomerization (C₂₉ ββ/(αα + ββ)) is a more thermally driven process. Thus, high Ts/(Ts + Tm) likely reflects depositional setting, confirming a mid-oil window maturity level consistent with the Ro and sterane 20S/(20S + 20R) data.

Evaluation of Potential Contamination by Drilling Additives: Contamination from drilling additives (e.g., lignite) could artificially elevate Tmax and potentially alter biomarker distributions. We have rigorously evaluated this possibility. First, detailed petrographic examination of all polished sections used for Ro measurement revealed no visible extraneous particles under reflected light microscopy, which would be the primary method to identify particulate contaminants like lignite powder. Second, review of the gas chromatograms (m/z 85) for the saturated hydrocarbon fractions showed no anomalous unresolved complex mixtures (UCMs) or aberrant n-alkane distributions that are characteristic of severe contamination by drilling mud organic matter. While subtle molecular-level interference cannot be entirely ruled out, the internal consistency observed among the majority of independent parameters (e.g., the logical progression of Ro with depth and its correlation with sterane isomerization) suggests that contamination is not the predominant factor governing the dataset. Therefore, the elevated Tmax values in specific samples are more parsimoniously explained by the prevalence of Type II₂/III organic matter, as discussed earlier.

To accurately determine source rock maturity, a comprehensive evaluation using multiple parameters is essential, rather than relying on a single index. Integrating the following three indicators confirms that the Chang 7 Member source rocks in the Pingbei area are generally within the mature stage: (1) Vitrinite Reflectance (Ro): Values range from 0.76% to 0.87%, consistent with the mature stage. (2) Biomarker Parameters: The C₂₉ sterane 20S/(20S + 20R) ratio ranges from 0.53 to 0.61, typical of mature organic matter. (3) Hydrocarbon Generation Potential: S₁ + S₂ values range from 0.48 to 22.19 mg/g, indicating the rocks are within the peak liquid hydrocarbon generation window.

The vitrinite reflectance data, presented in Table A1, form the basis of our thermal maturity assessment. We acknowledge that for a subset of samples, the final number of valid measurements after outlier removal is below the 20–30 range recommended by international standards such as ASTM D7708 for optimal statistical precision in dispersed organic matter [27,47]. However, the reliability of our Ro dataset is strengthened by several factors: First, the measurement protocol itself followed strict quality control, including outlier rejection. Second, the calculated mean Ro values for all 20 samples are highly consistent, clustering within a narrow range (0.76–0.87%) typical for the oil window. Most importantly, the Ro values show a coherent relationship with independent maturity parameters. For instance, samples with higher mean Ro (e.g., >0.85%) generally correspond to higher Ts/Tm ratios and more advanced sterane isomerization values (e.g., C₂₉ ααα 20S/(S + R) > 0.55). This multi-parameter consistency provides strong support that the Ro data, even with slightly reduced measurement counts in some cases, accurately reflect the thermal maturity level of the source rocks.

5.5. Analysis of the Discrepancy Between C₂₉ Steranes and Maceral Composition

A notable discrepancy was observed: while the maceral composition of the Chang 7 source rocks is dominated by alginite (35.7–65.7%), indicating a predominant contribution from aquatic algae, biomarker data reveal that C₂₉ regular steranes constitute the highest proportion (35–43%) among C₂₇–C₂₉ steranes—a pattern typically associated with terrestrial higher plant input. This apparent contradiction can be explained by two key factors, supported by geological and geochemical evidence:

Mixed Organic Matter Input and Differential Sterane Preservation: The Chang 7 source rocks are characterized by Type II₁ organic matter, representing a mixture of aquatic algae and terrestrial higher plants. According to Volkman [34], C₂₉ steranes derived from terrestrial plants are more stable during diagenesis and hydrocarbon generation than C₂₇ steranes derived from aquatic algae, leading to their preferential preservation. Consequently, even with a lower initial input of terrestrial organic material relative to aquatic material, the C₂₉ steranes from terrestrial sources are more likely to be retained in both source rocks and crude oils, resulting in their higher relative abundance in biomarker distributions [32].

Sedimentary Environment Controlling Terrestrial Input: The study area is situated within a delta-front setting of the Ordos Basin, where fluvial systems continuously transported terrestrial plant detritus into the lacustrine environment (Section 2). Delta-front environments are typically characterized by high fluxes of terrestrial organic matter, and this detrital material can be effectively preserved within the dark mudstones interbedded with sandy deposits [48,49]. This additional terrestrial input further amplifies the contribution of C₂₉ steranes, thereby accentuating the observed divergence between maceral-based and sterane-based source assessments.

In summary, the apparent contradiction between C₂₉ sterane predominance and alginite-rich maceral composition does not represent a true conflict. Instead, it reflects the interplay of mixed organic matter sources and the differential preservation of steranes within a delta-front sedimentary system. This interpretation further corroborates the mixed-source origin of the Chang 7 source rocks, a characteristic that is favorable for the generation of high-quality tight oil.

5.6. Implications of Mixed Kerogen Origin

The dominance of Type II₁ kerogen, with significant contributions from both aquatic (alginite) and terrestrial (vitrinite) macerals, has important implications for hydrocarbon generation and fluid properties. This mixed organic matter input results in a broad spectrum of generated hydrocarbons, contributing to the medium to good overall hydrocarbon potential observed. The terrestrial component may enhance gas generation potential at higher maturities, while the aquatic algae-derived material is primarily responsible for the liquid hydrocarbon yield during the peak oil window. Furthermore, the mixed origin likely influences the geochemical fingerprint of the expelled oils, including the biomarker distributions (e.g., sterane patterns) discussed earlier. Understanding this duality is crucial for accurate basin modeling and predicting the phase behavior (oil vs. gas) of generated hydrocarbons in the study area.

5.7. Limitations of Maceral Analysis and Data Reliability

The organic petrographic data in this study are derived from only four samples, which limits their statistical representativeness for the entire heterogeneous Chang 7 Member. Furthermore, technical issues during sample handling precluded the acquisition of publishable photomicrographs. However, we assert the reliability of our maceral identifications based on the following: (1) Standardized procedure: Polished sections were used solely for non-destructive petrographic analysis (maceral counting and vitrinite reflectance). All subsequent destructive geochemical analyses (TOC, pyrolysis, GC-MS) were performed on separately prepared, homogenized rock powders to avoid any interference. (2) Rigorous quality control: Each sample was analyzed via duplicate sections with point counting of over 500 particles per section to ensure precision. (3) Regional consistency: The obtained maceral composition (alginite-rich) aligns well with established characteristics of Chang 7 source rocks in the Ordos Basin as reported in prior studies [12,25]. (4) Geochemical corroboration: The kerogen type inferred from macerals (Type II₁) is supported by independent geochemical data (HI vs. Tmax plot; Figure 7).

6. Conclusions

(1)

The dark mudstones of the Chang 7 Member in the Pingbei area have the geological conditions to serve as effective source rocks. They have high organic matter abundance with an average TOC of 1.69%, among which the Chang 7³ sub-member has an average total organic carbon (TOC) content of 2.8%, meeting the standard of high-quality source rocks. The organic matter is dominated by Type II₁, mixed with a small amount of Type II₂ and Type III, characterized by the input of both aquatic organisms and terrestrial organic matter. The vitrinite reflectance (Ro) ranges from 0.76% to 0.87%, indicating a mature stage corresponding to the peak period of liquid hydrocarbon generation. The overall hydrocarbon-generating potential is of medium to good level, which constitutes an important material basis for regional hydrocarbon accumulation.

(2)

The crude oils in the study area can be classified into two types (Type A and Type B). Type A crude oils are derived from the Chang 7 Member and are characterized by high Pr/Ph ratios (1.77–1.78), high Ts/Tm ratios (3.47–7.18), high abundances of rearranged hopanes, and relative enrichment of C₁-, C₂-, and C₃-naphthalene series in saturated hydrocarbons. The geochemical differences between the two types of crude oils are mainly caused by the differentiation of sedimentary environments and thermal evolution degrees of source rocks.

(3)

The results of oil–source correlation show that Type A crude oils are extremely similar to the dark mudstones of the Chang 7 Member in terms of significant geochemical characteristics. Both are rich in C₃₀ rearranged hopanes and C₂₉ rearranged hopanes, with overlapping Pr/Ph ratio ranges and consistent pentacyclic triterpenoid distribution patterns, confirming that the dark mudstones of the Chang 7 Member are the main source rocks for Type A crude oils. In contrast, the geochemical characteristics of Type B crude oils are inconsistent with those of the local Chang 7 Member source rocks but are highly similar to the Chang 6 Member crude oils in oilfields surrounding the Pingbei area. Therefore, it is inferred that Type B crude oils belong to allochthonous reservoirs and are derived from the Chang 6 Member source rocks in surrounding areas.