Geochemical Characteristics and Controlling Factors of Lower Cretaceous Lacustrine Hydrocarbon Source Rocks in the Erdengsumu Sag, Erlian Basin, NE China

Abstract

This study analyzes the lacustrine hydrocarbon source rocks of the Lower Cretaceous in the Erdengsumu sag of the Erlian Basin, evaluating their characteristics and identifying areas with oil resource potential, while also investigating the ancient lake environment, material source input, and controlling factors, ultimately developing a sedimentary model for lacustrine hydrocarbon source rocks. The findings suggest the following: (1) The lower Tengger Member (K₁bt₁) and the Aershan Formation (K₁ba) are the primary oil-producing strata, with an effective hydrocarbon source rock exhibiting a lower limit of total organic carbon (TOC) at 0.95%. The Ro value typically remains below 0.8%, indicating that high-maturity oil production has not yet been attained. (2) The oil generation threshold depths for the Dalestai and Sayinhutuge sub-sags are 1500 m and 1214 m, respectively. The thickness of the effective hydrocarbon source rock surpasses 200 m, covering areas of 42.48 km² and 88.71 km², respectively. The cumulative hydrocarbon generation intensity of wells Y1 and Y2 is 486 × 10⁴ t/km² and 26 × 10⁴ t/km², respectively, suggesting that the Dalestai sub-sag possesses considerable petroleum potential. The Aershan Formation in the Chagantala sub-sag has a maximum burial depth of merely 1800 m, insufficient to attain the oil generation threshold depth. (3) The research area’s productive hydrocarbon source rocks consist of organic matter types I and II₁. The Pr/Ph range is extensive (0.33–2.07), signifying a reducing to slightly oxidizing sedimentary environment. This aligns with the attributes of small fault lake basins, characterized by shallow water and robust hydrodynamics. (4) The low ratio of ∑nC₂₁₋/∑nC₂₂₊ (0.36–0.81), high CPI values (>1.49), and high C₂₉ sterane concentration suggest a substantial terrestrial contribution, with negligible input from aquatic algae–bacterial organic matter. Moreover, as sedimentation duration extends, the contribution from higher plants progressively increases. (5) The ratio of the width of the deep depression zone to the width of the depression in the Erdengsumu sag is less than 0.25. The boundary fault scale is small, its activity is low, and there is not much input from the ground. Most of the source rocks are in the reducing sedimentary environment of the near-lying gently sloping zone.

1. Introduction

Lacustrine source rocks are extensively distributed in the Mesozoic sedimentary basins of northern China and represent a significant region for petroleum exploration and production (

Table 1. Standardized forms for petroleum system elements.

Element	Geological Characteristics	Key Evaluation Parameters
Source Rock	Organic-rich fine-grained rocks (mudstone, shale, carbonate)	TOC content (>0.5%)
		Kerogen type (I/II/III)
		Maturity (Ro value)
		Hydrocarbon potential (S1 + S2)
Reservoir	Porous/permeable rocks (sandstone, carbonate, fractured basement)	Porosity (>8%)
		Permeability (>1 mD)
		Pore structure (mercury injection)
Seal/Cap Rock	Low-permeability rocks (evaporites, tight mudstone)	Breakthrough pressure (>5 MPa)
		Thickness (>10 m)
		Lateral continuity
Migration Pathway	Faults/fractures/unconformities/permeable layers	Migration capacity index
		Migration direction (fluid inclusions)
		Migration distance
Trap	Structural/stratigraphic/lithologic traps	Closure height
		Effective volume
		Timing (match with migration)
Timing	Trap formation period ≤ main hydrocarbon migration period	Burial-thermal history modeling
		Fluid inclusion homogenization temperature
Preservation	Structural stability/intact seal/stable fluid environment	Formation pressure coefficient
		Water chemistry (salinity)
		Biomarker degradation

). Several substantial oil fields have been identified in these lacustrine basins, including Bohai Bay, Songliao, Ordos, Junggar, Erlian, and Hailar basins [1,2,3,4,5,6]. The formation mechanism of lacustrine source rocks is affected by multiple elements, such as the sedimentary environment, paleoclimatic conditions, and tectonic activities [7]. We may classify them into several types based on their sedimentary environment, including salty lacustrine facies, brackish deep lacustrine facies, and freshwater lacustrine facies [8,9].

The Erlian Basin, situated in the north-central region of the Inner Mongolia Autonomous Region, is among China’s most prolific basins for petroleum resources, containing the largest proven conventional petroleum reserves and undeveloped petroleum resources in northern China, with potential geological petroleum resources estimated at 10.93 × 10⁸ tons and cumulative proven geological petroleum reserves totaling 2.82 × 10⁸ tons [5,10,11,12,13]. The Erlian Basin consists of over 60 discrete small-scale sags that exhibit numerous analogous features, including sedimentary formations, basin infill, and tectonic stratigraphic development. Every sag or sub-sag signifies a distinct petroleum system [14,15]. The sedimentary environments and biological origins of organic matter in the high-quality mudstones of the Tengger and Aershan formations varied throughout many sags, including the Wuliyasitai, Saihan, and Baiyinchagan sags [16,17]. Furthermore, there are differences in the developmental stratigraphical position and oil production thresholds of source rocks within each sag [18,19,20,21,22,23]. The Erdengsumu sag is situated in the east-central region of the Erlian Basin, recognized as one of the sags with the highest potential for petroleum resources within the basin. The adjacent Baolegentaohai sag has confirmed oil geological reserves of 23,989,500 tons, the Saihanwuli sag has verified reserves of 2,630,200 tons, and an industrial oil flow was discovered in the Zhage sag [22,24]. It is widely accepted that the existence of effective source rocks has a direct impact on a basin’s capability for producing petroleum [25,26]. Nevertheless, prior research on the Erdengsumu sag has predominantly concentrated on stratigraphy, volcanic rocks, tectonic attributes and evolution, petroleum geological characteristics, and hydrocarbon formation conditions [27], while the development strata, estimate of petroleum potential, and controlling factors of the lacustrine hydrocarbon source rocks remain ambiguous. The Erdengsumu sag has generated numerous source rock formations from the Mesozoic, exhibiting substantial vertical and horizontal variations, which suggest enormous resource potential. This study can serve as a foundation for further exploratory decisions.

Currently, extensive geochemical data on hydrocarbon source rocks and regional geological data from six wells in the Lower Cretaceous Formation have been systematically gathered in the Erdengsumu sag to facilitate a thorough investigation of the characteristics of the hydrocarbon source rocks in this area. The objectives are as follows: (1) to systematically assess the attributes of the Lower Cretaceous lacustrine hydrocarbon source rocks; (2) to analyze the developmental characteristics of source rocks in the Dalestai sub-sag compared to the Sayinhutuge sub-sag and identify ideal regions for petroleum potential; (3) to elucidate the contributions of material sources to lacustrine hydrocarbon source rocks, alterations in sedimentary environments, and the principal controlling factors; and (4) to integrate geologic and geochemical data to formulate an effective sedimentary model for hydrocarbon source rocks in the Lower Cretaceous lake-faulted basins of the Erdengsumu sag. This research can serve as a foundation for predicting hydrocarbon source rocks and facilitating hydrocarbon exploration in additional depressions or lacustrine fault basins.

2. Geological Setting

The Erlian Basin is a continental rift basin located in Inner Mongolia, Northern China. It is a typical representative of the Cretaceous Northeast Asian Rift System, which includes many small petroliferous basins in the Mongolian Republic and Northern China. The Erlian Basin is situated in the suture zone between the Siberian Plate and the North China Plate and is a Meso-Cenozoic faulted basin formed on a Paleozoic folded basement [28,29,30]. Spanning an area of 100,000 km², it is a significant petroleum production region. The tectonics of the basin basement is predominantly oriented NE, NEE, and EW, with developed faults [31,32,33]. The rift-controlled basin has one uplift and five depressions, featuring 53 sags and 21 uplifts (Figure 1a), defined by “both uplifts and depressions” oriented in the same direction, as well as “mul-uplifts and mul-sags [34].” The Sunite uplift, located in the central region of the basin, partitions the Erlian Basin into a northern depression and a southern depression. The northern depression comprises the Manite, Wulanchabu, and Chunjin depressions, while the southern depression includes the Wunite and Tengger depressions [28,35,36]. During the late Mesozoic, the basin experienced the Yanshan movement, typified by an NW–SE-oriented extensional environment, with depressions exhibiting semi-graben or asymmetric graben fault structures. The formation of Cretaceous hydrocarbon source rocks in the basin exhibits significant heterogeneity attributable to differences in fault structure, scale, regional tectonic location, and tectonic-sedimentary history [37]. In the basin, three sets of hydrocarbon source rocks are present, with the Lower Cretaceous Aershan Formation (K₁ba) and the Tengger Formation (K₁bt) of lacustrine mudstone serving as the primary hydrocarbon source rocks, while the Middle-Lower Jurassic lacustrine coal formation acts as the secondary hydrocarbon source rock [38,39] (Figure 1c). The reservoir mostly consists of sandstones and conglomerates, with additional components including tuffs, granites, and carbonates. The submarine fan, fan delta, and braided river delta leading edge subphases are often advantageous reservoir phase zones. Overall, the reservoir is compact and has suboptimal physical characteristics.

The Erdengsumu sag (longitude 114–117° E, latitude 42°30′–42°40′ N) is a secondary tectonic unit of the Tengger Depression, oriented NEE. The Sunite uplift borders it to the north, the Baolegentaohai sag to the south, the Saihanwuli sag to the west, and the Daxing’an mountains to the east. This composite skip-shaped sag extends 240 km in length and varies from 16 km to 44 km in width, encompassing an area of 6280 km². It comprises multiple sub-sags and uplifts, exhibiting an overall tectonic configuration characterized by “concave and convex” features (Figure 2). The principal sub-sag in the region comprises the Dalestai, Sayinhutuge, Chagantala, and Ajitu sub-sags (Figure 1b). The Dalestai sub-sag encompasses an area of 500 km², whereas the Sayinhutuge sub-sag possesses the greatest basement depth of 3350 m. Due to varying tectonic evolution, the northern and southern sub-sags of the Sayinhutuge sub-sag exhibit distinct sedimentary characteristics. The northern sub-sag encompasses a larger area, features an open water body, and is primarily characterized by the shallow lacustrine facies of the main oil-bearing layer, the lower Tengger Member (K₁bt₁). Conversely, the southern sub-sag is smaller, has a narrower water body, and exhibits thinner deposition.

The hydrocarbon source rocks in the Erdengsumu sag are predominantly found within the Bayanhua Group of the Lower Cretaceous, comprising four distinct layers of dark mudstones arranged from top to bottom: the Saihan Formation (K₁bs), the upper Tengger Member (K₁bt₂), the lower Tengger Member (K₁bt₁), and the Aershan Formation (K₁ba) (including the upper Aershan Member (K₁ba₃₊₄) and the lower Aershan Member (K₁ba₁₊₂)).

In wells Y1 and Y2 (

Table 2. Geochemical data of mudstone in the Erdengsumu sag.

Well	Strata	Lithology	Thicknesss (m)	TOC (%)	Chloroform Bitumen “A” (%)	Rock Pyrolysis Parameters			Ro (%)
						S1 + S2 (mg/g)	HI (mg/g)	Tmax (°C)
Y1	K1bs	Dark-gray mudstone	407.1	0.19~3.77 1.05	0.0063~0.0169 0.0094	0.13~10.7 0.88	31.43~60.64 42.51	429~434 430	0.39~0.47 0.40
		Coal	4.5	23.4		42.03	32.84	430	0.39
	K1bt2	Brown mudstone	55.6	0.03~0.38 0.08	0.0105~0.0128 0.0117	0.09~0.81 0.13	31.43~36.84 34.14	424~438 432	0.46~0.48 0.47
	K1bt1	Gray mudstone	311.3	0.03~1.54 0.52	0.0030~0.0257 0.0129	0.09~5.51 0.50	3.92~60 25.07	430~439 437	0.47~0.74 0.63
	K1ba	Dark-gray mudstone	359.3	0.03~4.35 0.98	0.0305~0.1753 0.1113	0.04~27.65 4.58	137.6~315.7 234.02	442~446 443	0.71~0.79 0.74
Y2	K1bs	Brown mudstone	92.5	0.26~4.13 1.93	0.0175	0.02~1.15 0.56	3.85~38.46 22.29	422~433 427	0.13
	K1bt2	Dark-gray mudstone	279	0.25~1.96 0.44	0.0046~0.0086 0.0066	0.01~1.89 0.14	0.00~93.23 9.58	402~454 434	0.33~0.68 0.51
	K1bt1	Dark-gray mudstone	599	0.09~1.54 0.76	0.0038~0.0279 0.0128	0.02~6.61 1.02	4.55~594.12 116.6	428~453 440.81	0.57~1.14 0.81
	K1ba	Dark-gray mudstone	35	0.17~1.79 0.78	0.0036~0.0656 0.024	0.06~6.60 1.60	9.68~507.23 148.69	424~467 447	1.03~1.23 1.16

The data in the table are minimum-to-maximum values/average values.

), the total thicknesses of K₁bs dark mudstone are 407.1 m and 92.5 m, respectively, with gray mudstone being the predominant lithology. The total thicknesses of K₁bt₂ dark mudstone in wells Y1 and Y2 are 55.6 m and 279 m, respectively, with the predominant lithology being dark-gray mudstone. The cumulative thickness of K₁bt₁ dark mudstone in wells Y1 and Y2 is 311.3 m and 599 m, respectively, with the predominant lithology being dark-gray mudstone. The cumulative thickness of K₁ba dark mudstone in wells Y1 and Y2 is 359.3 m and 35 m, respectively, also mostly consisting of dark-gray mudstone.

3. Materials and Methods

Rock pyrolysis analyses were conducted on dark mudstone samples obtained from wells Y1 and Y2. Samples were collected from mudstone chips and cores throughout the entire well section, with chips taken at 1 m intervals and cores at 0.5 m intervals, resulting in a total of 694 samples. In well Y1, the total number of samples is 545, while in well Y2, it is 149. The layer distribution comprises 95 samples from the Saihan Formation (K₁bs), 123 samples from the upper Tengger Member (K₁bt₂), 254 samples from the lower Tengger Member (K₁bt₁), and 223 samples from the Aershan Formation (K₁ba). In addition, it is stated that the data in this paper are representative data selected from 694 samples by segmented statistical treatment. The pyrolysis analysis method involves grinding samples to around 100 mesh, utilizing the YY3000A (Beijing Nuojiu Technology Co., Ltd., Beijing, China) oil-rock comprehensive evaluator, and adhering to the GB/T 18602-2012 standard [40] for rock pyrolysis analysis.

The testing content encompasses the quantification of total organic carbon (TOC) in hydrocarbon source rock samples, rock pyrolysis analysis, chloroform bitumen “A” group component analysis, kerogen elemental analysis, kerogen vitrinite reflectance measurement, kerogen carbon isotope analysis, gas chromatography analysis of saturated hydrocarbons, and biomarker compound analysis, all conducted in the geochemistry laboratory at Northwest University. We calculate the organic carbon content by burning rock samples at elevated temperatures and quantifying the resulting CO₂ emissions. The methodologies for testing and analyzing chloroform bitumen “A,” kerogen elemental composition, kerogen vitrinite reflectance, and kerogen carbon isotope ratios are detailed in the literature [41,42,43]. The examination of saturated hydrocarbons was performed with an HP6890N gas chromatograph (from Hewlett-Packard, United States), fitted with an HP-PONA 30 m × 0.25 mm × 0.5 μm capillary column. The starting temperature is 35 °C. We elevate it to 300 °C at a rate of 4 °C/min after a 5 min interval, and then we hold it for 20 min. Helium serves as the carrier gas, and a constant flow mode operates at a flow rate of 1 mL/min. The biomarker study was conducted using chromatography-mass spectrometry on an HP6890-GC/5973MSD (from Hewlett-Packard, United States), system equipped with an HP-5MS 30 × 0.25 mm × 0.5 μm column. The initial temperature is 50 °C. After 2 min, it is elevated to 310 °C at a rate of 3 °C/min, followed by an 18 min hold. The carrier gas is helium, employed in a constant flow mode at a rate of 1 mL/min.

4. Results

4.1. Source Rock Geology

During the Cretaceous, the global climate was warmer than it is today. Compared to the adjacent Songliao Basin (China’s largest lacustrine basin), the Erlian Basin’s lower Cretaceous source rocks did not form continuously over a large area such as those of the Aptian Qingshankou formation. Instead, they developed in many relatively independent small sags, much like Lake Tanganyika in East Africa and the Tertiary basins of Thailand [44]. The various water depths, provenances, and preservation conditions exert multiple effects on source rock formation in these independent small subbasins [45]. The redox conditions, salinity and sediment types thus control the formation of hydrocarbon source rocks in different small sags that have the same climate and settlement background [46].

4.2. TOC and “S₁ + S₂”

The hydrocarbon potential of sedimentary rocks is contingent upon the quantity and quality of organic matter, with TOC serving as a crucial and widely utilized metric for assessing the quality of hydrocarbon source rocks, thereby offering a more robust material foundation for the development of hydrocarbon reservoirs [47,48,49]. The examination of TOC and hydrocarbon potential “S₁ + S₂” (Table 2) reveals notable disparities in TOC and “S₁ + S₂” concentrations among different strata, a characteristic feature of source rocks in faulted basins. The two sub-sags exhibit similar trends, with the K₁bt₂ mudstone displaying the lowest content. The mean TOC value of the K₁bt₁ mudstone in the Dalestai sub-sag is 0.52%, with data points predominantly situated within the category of poor hydrocarbon source rocks. The average TOC value of K₁ba mudstone is 0.98%, with data points ranging from fair to excellent (Figure 3a). At depths of 2630.8 to 3008 m (Figure 4), it forms promising source rocks. The average TOC value of the K₁bt₁ mudstone in the Sayinhutuge sub-sag is 0.76%, categorizing it as poor-to-good source rock (Figure 3b). The average TOC value of the K₁ba mudstone is 0.78%, classifying it as medium-to-good source rock, albeit with a thickness of only 35 m. Consequently, the Dalestai sub-sag possesses significant petroleum generation potential.

4.3. Results of δ¹³C_PDB

The carbon isotope content of kerogen serves as a crucial indicator in the geochemistry of oil and gas, especially in the analysis of source rocks. It not only inherits the traits of its biological progenitor, but it is also shaped through diagenesis and genesis. Generally speaking, the effects of diagenesis and thermal maturation on the carbon isotopes of kerogen are minimal. Organisms originating from diverse sources and habitats exhibit distinct stable carbon isotope compositions. Under identical conditions, aquatic species collect a greater concentration of light carbon isotopes than terrestrial organisms, and lipid molecules have a higher enrichment of light carbon isotopes relative to other components [6]. The kerogen carbon isotope (δ¹³C_PDB) values of more than 51 mudstone samples were measured to assess the source and type of organic matter (

Table 3. Kerogen atomic H/C, O/C and δ¹³C_PDB measurements for mudstone samples of the Erdengsumu sag.

Well	Depth (m)	Statra	H/C	O/C	δ13CPDB (‰)	Well	Depth (m)	Statra	H/C	O/C	δ13CPDB (‰)
Y1	751.4	K1bs	0.96	0.38	–22.4	Y2	580.5	K1bs	0.56	0.17	–20.9
Y1	857.1	K1bs	1.00	0.45	–22.1	Y2	830	K1bt2	0.41	0.15	–22.0
Y1	893.7	K1bs	0.97	0.38	–23.3	Y2	969.8	K1bt2	0.24	0.17	–24.4
Y1	956.5	K1bs	0.93	0.33	–23.2	Y2	1077.5	K1bt2	0.62	0.18	–22.6
Y1	986.7	K1bs	1.01	0.38	–23.3	Y2	1235	K1bt2	0.71	0.19	–22.4
Y1	1056.6	K1bs	1.00	0.41	–22.9	Y2	1379	K1bt2	0.54	0.16	–21.9
Y1	1155.9	K1bs	0.94	0.37	–22.4	Y2	1468.1	K1bt2	0.41	0.16	–21.7
Y1	1187.8	K1bs	0.90	0.31	–21.9	Y2	1555.4	K1bt1	0.50	0.21	–24.7
Y1	1376.2	K1bt2	1.53	0.89	–23.1	Y2	1673.7	K1bt1	0.59	0.16	–22.7
Y1	2025.6	K1bt2	1.73	1.25	–24.9	Y2	1679.4	K1bt1	0.42	0.17	–24.1
Y1	2124.2	K1bt1	1.18	0.73	–24.2	Y2	1806.4	K1bt1	0.67	0.13	−22.0
Y1	2194.1	K1bt1	1.12	0.73	–24.4	Y2	1833.5	K1bt1	0.91	0.15	–24.7
Y1	2245	K1bt1	0.96	0.50	–25.2	Y2	1912.7	K1bt1	0.71	0.09	–22.5
Y1	2255.3	K1bt1	1.00	0.30	–24.9	Y2	1994.6	K1bt1	0.7	0.13	–23.0
Y1	2302.2	K1bt1	0.98	0.46	–25.4	Y2	2079	K1bt1	0.78	0.14	–23.8
Y1	2342.8	K1bt1	1.12	0.54	–28.7	Y2	2092.5	K1bt1	0.89	0.09	–24.8
Y1	2458	K1bt1	0.82	0.29	–24.4	Y2	2096.2	K1bt1	0.92	0.09	–30.0
Y1	2507.3	K1bt1	1.22	0.66	–23.7	Y2	2116.5	K1bt1	0.80	0.14	–24.4
Y1	2554.2	K1bt1	1.25	0.53	–24.9	Y2	2206.2	K1bt1	0.72	0.17	–23.1
Y1	2644.0	K1ba	1.18	0.53	–24.1	Y2	2257.5	K1bt1	1.01	0.08	–26.9
Y1	2705.2	K1ba	0.95	0.39	–24.1	Y2	2288	K1bt1	1.19	0.06	–30.6
Y1	2759.3	K1ba	1.00	0.42	–24.5	Y2	2307	K1ba	0.66	0.12	–27.3
Y1	2811.8	K1ba	1.79	1.14	–27.2	Y2	2355.4	K1ba	0.65	0.10	–23.3
Y1	2871.4	K1ba	1.21	1.82	–28.6	Y2	2356.5	K1ba	0.76	0.11	–26.9
Y1	2925.4	K1ba	1.03	0.45	–28.3	Y2	2391	K1ba	0.97	0.09	–27.0
Y1	2995.4	K1ba	0.92	0.25	–27.6

). The δ¹³C_PDB values for K₁bs and K₁bt₂ range from –20.9‰ to –24.98‰, suggesting that the organic matter predominantly originates from terrestrial vegetation and has traits of Type III kerogen (Figure 5). The δ¹³C_PDB values of the K₁bt₁ in the Dalestai sub-sag range from –23.67‰ to –28.69‰, which means that most of the organic matter is made up of algae and small aquatic animals that show Type II₂ to II₁ kerogen traits. The δ¹³C_PDB readings for K₁ba range from –24.11‰ to –28.56‰, which suggests that the organic matter mostly comes from lower aquatic species and has Type II₁ to I kerogen characteristics. The δ¹³C_PDB values of K₁bt₁ in the Sayinhutuge sub-sag range from –22.5‰ to –30.6‰, which shows a wide range of kerogen types, especially types I–III, with type III kerogen being the most common. The K₁ba’s δ¹³C_PDB readings range from –23.3‰ to –27.3‰, indicating type III to II₁ kerogen.

4.4. Rock-Eval Pyrolysis and Kerogen Type

The composition of organic matter in source rocks is a crucial indicator for evaluating the hydrocarbon generation evolution characteristics of organic matter. There are notable disparities in oil and gas generating capacity, hydrocarbon types produced, and hydrocarbon creation procedures across various source rock types [50,51,52,53]. The correlation between the hydrogen index (HI) and T_max is frequently employed to differentiate the varieties of organic matter in source rocks. The results demonstrate a significant variance in kerogen types over the strata of the Erdengsumu sag, exhibiting a broad spectrum from Type I to Type III, which aligns with the considerable difference in the hydrogen index (Table 2). Figure 6 illustrates that the data points for the K₁bs and the K₁bt₂ both reside within the Type III kerogen classification. The K₁bt₁ and K₁ba in the Dalestai sub-sag are classified as Type III and Type II₁–II₂ kerogen, respectively, but the K₁bt₁ and K₁ba in the Sayinhutuge sub-sag exhibit a broader distribution, encompassing Type I to Type III kerogen. Overall, there is a gradual improvement in organic matter types from top to bottom.

4.5. Organic Matter Maturity

The transformation of organic matter into hydrocarbons necessitates a sequence of alterations, with the maturity of the organic matter serving as the metric that quantifies the degree of these modifications [12,54]. Generally, vitrinite reflectance (Ro) values increase with depth due to an increase in temperature and increasing age of the rock with depth [3]. It is widely accepted that the value of Ro exceeding 0.5% or T_max surpassing 435 °C signifies the commencement of the mature thermal evolution phase [55,56]. When the value of Ro exceeds 0.5%, it signifies that the hydrocarbon generation threshold depths for the Dalestai sub-sag and Sayinhutuge sub-sag are 1500 m and 1214 m, respectively (Figure 7).

The maturity characteristics of oil-bearing rocks and the identification of the oil-generating threshold reveal that the Saihan Formation (K₁bs), the upper Tengger Member (K₁bt₂), and the upper portion of the lower Tengger Member (K₁bt₁) are classified as immature, whereas the middle and lower sections of the lower Tengger Member (K₁bt₁) and the Aershan Formation (K₁ba) are located within the mature oil-generating zone. The Ro value of the oil-producing rocks within the maturity and oil production threshold is generally below 0.8%, signifying a low maturity stage that has not reached high maturity or substantial oil production, a notable feature of the Erdengsumu sag.

4.6. Molecular Geochemistry of Organic Matter

Biomarkers have garnered significant interest in recent decades, mainly for their utility in assessing the kind and quality of organic matter, sedimentary conditions (including salinity, oxygen levels, anoxia, etc.), maturity, biodegradation extent, and lithology [6,47].

Table 4. N-alkane and isoprenoid parameter data for mudstone samples from the K₁bs, K₁bt₂, K₁bt₁, and K₁ba formations in the Erdengsumu sag.

No.	Well	Depth (m)	Strata	MPC	∑nC21−	nC21+22	Pr/Ph	Pr/n-C17	Ph/n-C18	CPI	OEP
					∑nC22+	nC28+29
1	Y2	437.5	K1bs	C23	0.61	1.30	0.68	0.58	0.86	1.51	1.58
2	Y1	852.1	K1bs	C23	0.30	2.62	0.42	0.58	0.78	1.66	1.24
3	Y1	949.3	K1bs	C25	0.25	1.64	0.50	0.59	0.71	2.03	1.79
4	Y1	1051.7	K1bs	C27	0.26	1.26	0.66	0.65	0.81	2.20	2.36
5	Y2	830	K1bt2	C27	0.53	0.72	0.73	0.66	0.86	1.54	1.61
6	Y2	969.8	K1bt2	C18	1.08	4.13	0.77	0.54	0.70	1.54	0.96
7	Y2	1077.5	K1bt2	C27	0.51	0.63	0.75	0.67	0.84	1.61	1.52
8	Y1	1188.3	K1bt2	C25	0.23	1.42	0.42	0.56	0.76	2.17	1.81
9	Y2	1235	K1bt2	C27	0.65	1.41	0.66	0.67	0.98	1.13	1.20
10	Y1	1372.5	K1bt2	C23	0.22	1.43	0.56	0.55	0.59	2.07	1.32
11	Y2	1379	K1bt2	C29	0.47	0.66	0.80	0.68	0.61	1.36	1.69
12	Y2	1468.1	K1bt2	C27	0.43	0.89	0.77	0.57	0.64	1.49	1.44
13	Y2	1555.4	K1bt1	C25	0.54	0.85	1.47	0.68	0.49	1.77	1.74
14	Y2	1673.7	K1bt1	C29	0.39	0.6	1.00	0.56	0.54	1.28	1.52
15	Y2	1679.4	K1bt1	C27	0.34	0.57	0.69	0.58	0.66	1.19	1.19
16	Y2	1725	K1bt1	C25	0.70	1.35	1.12	0.31	0.28	2.18	1.99
17	Y2	1806.4	K1bt1	C25	0.55	4.15	0.35	0.44	0.58	1.12	1.09
18	Y2	1833.5	K1bt1	C27	0.56	0.91	1.16	0.27	0.26	2.71	2.72
19	Y2	1836.5	K1bt1	C27	0.59	1.27	1.08	0.33	0.30	2.31	2.62
20	Y2	1912.7	K1bt1	C23	0.57	0.17	2.01	0.74	0.27	1.79	1.72
21	Y2	1994.6	K1bt1	C18	0.54	0.71	0.50	0.35	0.54	1.16	0.92
22	Y2	2079	K1bt1	C23	0.82	2.00	0.92	0.26	0.27	1.71	1.26
23	Y2	2092.5	K1bt1	C25	0.89	2.68	2.04	0.34	0.15	1.47	1.48
24	Y2	2096.2	K1bt1	C25	0.26	3.13	1.08	0.14	0.08	1.53	1.30
25	Y1	2112.5	K1bt1	C23	0.31	3.01	0.61	0.58	0.67	1.40	1.10
26	Y2	2116.5	K1bt1	C27	0.71	1.16	1.02	0.29	0.29	2.11	2.05
27	Y2	2206.2	K1bt1	C27	0.27	0.31	0.55	0.45	0.69	1.16	1.10
28	Y1	2246.3	K1bt1	C23	0.44	2.01	0.38	0.53	0.94	1.14	1.08
29	Y2	2257.5	K1bt1	C19	1.12	2.76	1.11	0.24	0.21	1.35	1.03
30	Y2	2288	K1bt1	C17	0.89	0.73	1.83	0.65	0.39	1.23	0.99
31	Y1	2299.5	K1bt1	C23	0.41	2.12	0.53	0.54	0.72	1.33	1.18
32	Y1	2455.5	K1bt1	C23	0.42	2.68	0.33	0.35	0.37	1.40	1.10
33	Y1	2550.9	K1bt1	C23	0.43	3.39	0.45	0.40	0.63	1.15	1.12
34	Y2	2307	K1ba	C19	1.04	3.36	1.12	0.35	0.30	1.32	1.03
35	Y2	2355.4	K1ba	C21	1.89	2.48	1.83	0.21	0.11	1.28	1.07
36	Y2	2356.5	K1ba	C21	1.21	3.04	1.69	0.46	0.27	1.41	1.14
37	Y2	2391	K1ba	C16	1.07	0.71	2.07	0.89	0.48	1.29	0.91
38	Y1	2642.9	K1ba	C23	0.4	1.86	1.08	0.45	0.30	1.58	1.30
39	Y1	2705.4	K1ba	C23	0.41	3.15	0.99	0.50	0.35	1.42	1.18
40	Y1	2755.3	K1ba	C23	0.54	2.63	1.39	0.46	0.25	1.38	1.16
41	Y1	2812	K1ba	C23	0.65	3.22	0.69	0.27	0.35	1.39	1.25
42	Y1	2872.5	K1ba	C23	0.59	3.18	0.47	0.37	0.59	1.23	1.18
43	Y1	2927	K1ba	C23	0.55	2.74	0.51	0.33	0.46	1.36	1.18
44	Y1	2989.9	K1ba	C23	0.59	2.80	0.63	0.32	0.38	1.37	1.18

Note: MPC = Main Peak Carbon; Pr/Ph = pristane/phytane; Pr/n-C₁₇ = pristine/C₁₇ n-alkane; Ph/n-C₁₈ = phytane/C₁₈ n-alkane; CPI = carbon preference index; OEP = Odd Even Predominance.

illustrates the distribution of biomarkers inside the mudstone of the Erdengsumu sag.

4.6.1. n-Alkanes

The distribution properties of n-alkanes help ascertain the origin of organic matter and depositional settings. High carbon number (>C₂₃) n-alkanes exhibiting parity dominance signify the contribution of terrestrial higher plants, with nC₂₇, nC₂₉, or nC₃₁ as the predominant carbon; lower carbon number (<C₂₀) n-alkanes, particularly nC₁₅ and nC₁₇ as the predominant carbon peaks with diminished parity dominance, suggest aquatic origins such as algae [57]. Lower levels of the light hydrocarbon/heavy hydrocarbon ratio (ΣC₂₁₋/ΣC₂₂₊) usually mean that most of the organic matter in marshes or shallow lakes comes from higher plants on land, while higher levels of the ratio mean that most of the organic matter in deep lake sediments comes from lower aquatic organisms like algae. However, as thermal evolution progresses, long-chain n-alkanes in hydrocarbon source rocks typically experience C-C bond cleavage due to thermal cracking, resulting in the formation of medium- and short-chain n-alkanes. Consequently, the distribution peak of n-alkanes shifts forward, highlighting the predominance of lighter carbon. Therefore, when employing the parameters ∑nC₂₁₋/∑nC₂₂₊ and nC₂₁₊₂₂/nC₂₈₊₂₉ to ascertain the origin of organic matter in source rocks, it is essential to account for maturity factors [43].

Given that K₁bs, K₁bt₂, K₁bt₁, and K₁ba hydrocarbon source rocks are primarily in an immature to mature state, the metrics ∑nC₂₁₋/∑nC₂₂₊ and nC₂₁₊₂₂/nC₂₈₊₂₉ serve as indicators of the provenance of the hydrocarbon source rock parent material. The predominant orthoalkane peaks in the K₁bs, K₁bt₂, K₁bt₁, and K1ba hydrocarbon source rocks are primarily nC₂₃, nC₂₅, nC₂₇, and nC₂₉, exhibiting a broad carbon number distribution from nC₁₆ to nC₃₆ (Figure 8). The average values of ∑nC₂₁₋/∑nC₂₂₊ ratio range from 0.36 to 0.81, while the average values of nC₂₁₊₂₂/nC₂₈₊₂₉ ratio range from 1.41 to 2.65. indicates that n-alkanes have a pronounced predominance of heavy carbon, suggesting that the parent source of hydrocarbon source rocks is primarily derived from higher plants, with contributions from lesser aquatic creatures. The ratio of ∑nC₂₁₋/∑nC₂₂₊ progressively diminishes from the lower to the upper sections in the longitudinal stratigraphic profile (Table 4), indicating a steady rise in the contribution of parent higher plant inputs across the Lower Cretaceous depositional era (Figure 9b).

4.6.2. Steranes

The comparative concentrations of regular steranes C₂₇, C₂₈, and C₂₉ can also be utilized to ascertain the origin of organic materials. C₂₇ steranes are predominantly sourced from planktonic species, C₂₈ steranes are primarily linked to planktonic organisms, and C₂₉ steranes are chiefly derived from terrestrial higher plants [48]. The proportion of C₂₇–C₂₉ steranes can reveal the characteristics of the source rock input [58,59]. The relative concentration of C₂₇ steranes in the source rock samples ranges from 19.42% to 43.67%, with an average of 29.23%; the relative abundance of C₂₈ steranes spans from 10.78% to 23.65%, averaging 19%; the relative abundance of C₂₉ steranes varies from 40.17% to 83.41%, with an average of 51.34%. C₂₇ steranes surpass C₂₈ steranes, while C₂₈ steranes are inferior to C₂₉ steranes. The characteristic asymmetric “V” shape, in which C₂₇ steranes are lower than C₂₉ steranes, shows that the source rock comes from a mix of higher plants and plankton, with higher plant contributions having the most impact (Figure 9a). This is in line with the mixed source characteristic shown by the distribution of organic matter types from type III to type I in the previous section.

4.6.3. Isoprenoids

Pristane (Pr) and phytane (Ph) are prominent biomarker chemicals characterized by stable structures and significant concentrations in organic matter, rendering them ideal indicators for investigating organic matter depositional environments [60,61,62,63]. Pr/Ph serves as a sensitive indication of the redox conditions in lake water. Typically, a Pr/Ph ratio of less than 0.5 signifies a highly reducing environment; a ratio between 0.5 and 1.0 denotes a reducing environment; a ratio ranging from 1.0 to 2.0 suggests a weakly reducing to weakly oxidizing environment; and a ratio over 2.0 reflects an oxidizing environment [41,42].

The redox conditions of depositional habitats are critical elements influencing the preservation of organic materials, with reducing environments typically regarded as advantageous for the deposition of high-quality hydrocarbon source rocks [64]. The Pr/Ph ratios of the majority of hydrocarbon source rock samples from K₁bs and K₁bt₂ in the region range from 0.42 to 0.8 (Table 4), suggesting that the Lower Cretaceous K₁bs and K₁bt₂ hydrocarbon source rocks originated in a reduced sedimentary paleoenvironment. In contrast, the Pr/Ph ratios for K₁bt₁ and K₁ba range from 0.33 to 2.04 and 0.47 to 2.07, respectively, indicating that the K₁bt₁ and K₁ba hydrocarbon source rocks developed in a reduced to weakly oxidized sedimentary environment. The ratio of Pr/n-C₁₇ and Ph/n-C₁₈ is frequently employed to ascertain the depositional environment [65]. The sample locations are predominantly situated in reduced to weakly oxidized depositional settings (Figure 10a), aligning with the shallow water conditions and robust hydrodynamics of small-scale faulted lake basins. The Pr/Ph, Pr/n-C₁₇, and Ph/n-C₁₈ diagrams differentiate the genesis of hydrocarbon source rocks, with the distribution of sample points revealing that the K₁bs and K₁bt₂ hydrocarbon source rocks are low-maturity oils originating from freshwater–brackish lacustrine facies, whereas the K₁bt₁ and K₁ba source rocks are low-maturity oils derived from brackish to saline lacustrine facies (Figure 10b).

4.7. Trace Element Th/U

The Th/U ratio of trace elements can function as a criterion for differentiating between marine and terrestrial sedimentary settings. A Th/U ratio beyond 7 signifies a terrestrial freshwater environment, a ratio between 2 and 7 indicates a slightly salty to brackish sedimentary environment, and a ratio below 2 denotes a marine saline water environment [66]. The Th/U analytical results (

Table 5. Data table for natural gamma energy spectrum Th/U curve analysis.

Strata	Statistical Well Sections (m)	Maximum Values	Minimum Value	Average Value
K1bs	646–925	21.828	0.662	4.311
	925–1181	8.158	3.145	6.54
K1bt2	1181–1497	80.75	2.012	13.78
	1497–2055.5	80.267	4.67	23.327
K1bt1	2055.5–2263	7.65	2.45	5.89
	2263–2420	8.478	2.68	4.6
	2420–2575	54.23	2.36	6.31
K1ba4	2575–2743	10.15	2.21	6.71
K1ba3	2743–3008	8.259	0.37	4.29
K1ba2	3008–3250	36.58	2.46	20.20

Note: K₁ba₂ = the Aershan II Member; K₁ba₃ = the Aershan III Member; K₁ba₄ = the Aershan IV Member; K₁bt₁ = the lower Tengger Member; K₁bt₂ = the upper Tengger Member; K₁bs = Saihan Formation.

) indicate that K₁bs, K₁bt₁, and K₁ba₃₊₄ were deposited in a slightly salty to brackish sedimentary environment, whereas K₁bt₂ and the Aershan II Member (K₁ba₂) were deposited in a terrestrial freshwater environment.

5. Discussion

5.1. The Minimum Threshold of TOC

The existing TOC measurement fails to accurately depict the quantity of hydrocarbons created by the source rock or the volume evacuated from it; it solely indicates the abundance of residual organic matter within the source rock. Consequently, it is imprudent to employ a basic TOC for assessing the efficacy of source rocks. In recent years, the envelope approach for identifying effective hydrocarbon source rocks, predicated on the correlation between organic carbon content and hydrocarbon index, has been extensively utilized [41]. This method’s principle is that S₁/w(TOC) exhibits an initial increase followed by a decrease as organic carbon content rises. The TOC value at which S₁/w(TOC) begins to decline represents the lower threshold of organic matter abundance for effective hydrocarbon source rocks in this region, as significant hydrocarbon discharge from the source rock commences with the reduction in S₁/w(TOC). The correlation plot between TOC and S₁/w(TOC) for hydrocarbon source rocks in the study area (Figure 11) indicates a greater number of data points for mudstone-type hydrocarbon source rocks. The decline in S₁/w(TOC) initiates at a TOC value of 0.95%, establishing that the lower threshold of TOC for effective hydrocarbon source rocks of the mudstone type in the study area is 0.95%.

5.2. Distribution of Productive Hydrocarbon Source Rocks

Despite the sub-sags in the Erdengsumu sag being situated within the same geological formation and sharing the same tectonic background, the distinct depositional conditions lead to significant variations in the distribution, thickness, and hydrocarbon thresholds of the source rocks. The hydrocarbon thresholds for the Dalestai and Sayinhutuge sub-sags are 2200 m and 1600 m, respectively, indicating a significant disparity. It is posited that the well Y2 is situated nearer to the secondary fracture of the depression, attributed to heightened tectonic activity. The mudstone in the examined region is well-developed, with significant hydrocarbon source rocks mostly located in K₁bt₁ and K₁ba, principally characterized by dark-gray mudstone lithology (Figure 4 and Figure 12). The hydrocarbon source rock thickness in the Dalestai sub-sag surpasses 200 m over an area of 42.48 km², whereas in the Sayinhutuge sub-sag, it similarly exceeds 200 m across 88.71 km². Moreover, the total thickness of the northern sub-sag exceeds that of the southern sub-sag (Figure 13). The Aershan Formation (K₁ba) in the Chagantala sub-sag has a maximum burial depth of merely 1800 m (Figure 2), insufficient to attain the critical depth necessary for oil generation, hence lacking the essential conditions for oil formation. The principal hydrocarbon source rock of the well Y1, the Aershan Formation (K₁ba), demonstrates significant thickness (Figure 4; Table 2), high abundance, advantageous type, and advanced maturity, culminating in an increased hydrocarbon intensity with a computed total hydrocarbon intensity of 486 × 10⁴ t/km². Conversely, the primary hydrocarbon source rock of the Y2 well, the lower Tengger Member (K₁bt₁), although considerably thick (Figure 12), exhibits lower abundance, inferior quality, and diminished maturity relative to the Aershan Formation (K₁ba), resulting in a significantly reduced hydrocarbon intensity of only 26 × 10⁴ t/km².

In sedimentary basins, organic matter richness, hydrocarbon proneness, and the kind of organic matter are important factors to consider when evaluating exploration risks [67]. The Dalestai sub-sag has significantly developed high-quality, mature source rocks that contain substantial petroleum deposits. The analytical tests of the wells Shun1–7, Shun2, Ba1, and Ba2 demonstrate that the oil-bearing formations in the studied region possess high quality. The organic matter is categorized as I to II₁, and the TOC of the Aershan Formation (K₁ba) varies from 0.17% to 5.35%, with an average of 2.04% (

Table 6. Analysis and testing data of mudstone samples from the Aershan Formation (K₁ba) obtained from the wells Shun1–7, Shun2, Ba2, and Ba1 in the Dalestai sub-sag.

Well	Depth (m)	TOC (%)	Tmax (℃)	HI (mg/g)	S1 (mg/g)	S2 (mg/g)	S1 + S2 (mg/g)	Organic Matter Type	Evaluation
Shun1–7	2200–2250	1.58	439	350	0.22	5.53	5.75	II1	fair
Shun1–7	2270–2290	1.98	440	423	0.42	8.37	8.79	II1	good
Shun1–7	2290–2310	1.89	439	410	0.27	7.75	8.02	II1	good
Shun2	1300–1342	2.05	434	483	0.17	9.9	10.07	II1	good
Shun2	1340	5.35	433	710	0.82	37.97	38.79	I	good
Shun2	1466–1491	2.29	432	523	0.24	11.98	12.22	II1	good
Shun2	1469–1479	2.51	433	337	0.15	8.47	8.62	II1	good
Shun2	1480–1490	3.78	435	544	0.48	20.58	21.06	I	good
Ba2	1865	2.55	437	722	0.18	18.41	18.6	I	good
Ba2	1880	2.37	437	603	0.13	14.32	14.46	I	good
Ba1	1355	1.16	438	341	0.02	3.94	3.96	III	fair
Ba1	1365	0.17	428	74	0.00	0.13	0.13	III	poor
Ba1	1376	1.49	436	377	0.02	5.62	5.64	II1	fair
Ba1	1385	1.90	433	493	0.05	9.37	9.42	II1	good
Ba1	1396	0.73	440	193	0.01	1.41	1.41	II2	non
Ba1	1406	1.50	434	429	0.03	6.42	6.45	II1	good
Ba1	1416	1.73	434	520	0.04	9.02	9.05	II1	good
Ba1	1426	1.72	436	385	0.02	6.63	6.66	II1	good
Ba1	1436	1.57	436	350	0.02	5.50	5.52	II1	fair
Ba1	1446	1.20	438	280	0.02	3.36	3.38	II1	fair
Ba1	1456	1.18	437	190	0.01	2.24	2.25	II2	fair
Ba1	1466	1.76	434	377	0.04	6.63	6.67	II1	good
Ba1	1476	1.24	436	287	0.02	3.56	3.58	II1	fair
Ba1	1486	1.46	434	272	0.03	5.43	5.46	II1	fair
Ba1	1496	1.48	438	343	0.04	5.06	5.09	II1	fair
Ba1	1506	1.54	435	364	0.05	5.62	5.66	II1	fair
Ba1	1516	0.85	438	211	0.00	1.80	1.80	II2	poor
Ba1	1526	1.58	435	433	0.04	6.84	6.88	II1	good
Ba1	1536	1.29	439	389	0.01	5.02	5.02	II1	fair
Ba1	1546	2.77	434	749	0.03	20.71	20.73	I	excellent
Ba1	8706	1.30	436	426	0.00	5.55	5.55	II1	fair
Ba1	1566	1.52	436	570	0.01	8.67	8.68	II1	good
Ba1	1576	2.10	437	657	0.01	13.77	13.78	I	good
Ba1	1586	2.63	432	679	0.02	17.84	17.86	I	good
Ba1	1596	2.06	435	649	0.01	13.38	13.38	I	good
Ba1	1605	2.75	432	723	0.03	19.85	19.88	I	good
Ba1	1686	1.63	435	569	0.00	9.28	9.28	II1	good
Ba1	1725	1.63	432	625	0.00	10.17	10.17	I	good
Ba1	1736	1.72	433	577	0.00	9.91	9.91	II1	good
Ba1	1746	2.35	436	725	0.03	17.04	17.07	I	good
Ba1	1846	2.72	435	702	0.00	19.09	19.10	I	good
Ba1	1855	2.52	434	680	0.03	17.14	17.17	I	good
Ba1	1880	3.32	439	768	0.01	25.51	25.52	I	excellent
Ba1	1891	4.15	434	378	0.05	15.70	15.75	II1	good
Ba1	1901	3.40	438	776	0.06	26.34	26.39	I	excellent
Ba1	1910	3.47	437	772	0.04	26.81	26.84	I	excellent

), so it is classified as an effective hydrocarbon source rock. The cumulative thickness exceeds 200 m, with Ro oscillating between 0.8% and 0.9%. It has reached the maturation stage for oil production and is expected to reveal significant reserves.

5.3. Main Control Factors for Source Rock Formation

5.3.1. Source of Material Input

Substantial contributions of terrestrial organic matter are a defining feature that distinguishes lacustrine basins from marine basins, with smaller fractured lake basins receiving increased organic matter inputs due to their diminished size and proximity to the source. The mass fraction of C₂₇ steranes relative to C₂₉ steranes signifies the source of organic matter, with heightened mass fractions of C₂₇ steranes generally indicating contributions from phytoplankton or algae in aquatic environments, and augmented mass fractions of the increased mass proportion of C₂₉ steranes signify a more substantial contribution from higher terrestrial plants [41,48]. This research employs the mass fraction ratio of C₂₇ to C₂₉ steranes, w(C₂₇)/(C₂₉), to signify the degree of organic matter contribution from terrestrial sources; a higher ratio denotes diminished terrestrial organic matter input, whereas a lower ratio reflects enhanced terrestrial organic matter intake.

Figure 14a illustrates the correlation between w(C₂₇)/w(C₂₉) and w(TOC) for the hydrocarbon source rocks of the Erdengsumu Sag. A considerable positive association exists between w(C₂₇)/w(C₂₉) and w(TOC); specifically, as w(C₂₇)/w(C₂₉) increases, the hydrocarbon source rock w(TOC) tends to grow as well. The contribution of terrestrial organic matter exerts a significant influence on the development of hydrocarbon source rocks. As the ratio w(C₂₇)/w(C₂₉ rises, the contribution of terrestrial organic matter diminishes, while the w(TOC) of hydrocarbon source rocks progressively increases.

5.3.2. Sedimentary Environment

The redox conditions during deposition dictate the preservation of organic materials. The oxidation–reduction potential of the sedimentary environment can be assessed using the trace element Th/U ratio. Thorium (Th) is a relatively immobile element under low-temperature surface conditions and is predominantly found in weathering-resistant minerals, which are more prevalent in oxidizing environments. Conversely, uranium (U) is typically deposited in reducing environments. Therefore, the Th/U ratio serves as an indicator of the oxidation–reduction state of the sedimentary water body, with lower Th/U values generally indicating a more reductive sedimentary environment [66]. The association between the redox trace element indicator Th/U and w(TOC) is illustrated (Figure 14b), indicating a notable negative correlation, wherein w(TOC) exhibits a distinct decline when the Th/U ratio increases. The formation process of hydrocarbon source rocks is greatly influenced by the degree of oxidation–reduction, with a stronger reduction in the depositional environment being more favorable for their development.

5.3.3. Rate of Sedimentation

The Erlian Basin is a minor fault basin characterized by relatively independent sags. The lake basins in the northern depression zone feature expansive lake areas, excellent connectivity, profound water bodies, and substantial deposits of dark mudstone. In contrast, the lake basins in the southern depression zone are diminutive, shallow, poorly connected, underdeveloped, and heavily inundated, leading to a marked disparity in the correlation between the sedimentation rate of the depressions and the concentration of organic matter in the hydrocarbon source rocks within the basin [68,69].

The Aer, Wuli, and Bayindoulan sags in the Erlian Basin display a positive extension inheritance structure, which is distinguished by significant border faults and intense geological activity. During the sedimentation period of the lower Tengger Member (K₁bt₁), the activity rate of the boundary fault reached up to 0.215 mm/a, while the sedimentation rate of the Lower Cretaceous was between 0.30 and 0.65 mm/a. Despite the high sedimentation rate, it had almost no impact on the organic matter content. The Ananabei, Jier, and Hongte sags are influenced by NW–SE directed extensional stress with large-scale and highly active boundary faults. During a sedimentary epoch in the lower Tengger Member (K₁bt₁), the activity rate of the boundary fault of the Anan-Anbei depression is approximately 0.145 mm/a, with a moderate sedimentation rate. When the sedimentation rate is less than 0.05 mm/a, it affects the organic matter content, and as the sedimentation rate increases, the organic carbon content tends to rise. However, when the sedimentation rate is greater than 0.05 mm/a, as the rate increases, the organic carbon content tends to decrease. The Naoer and Saihan sags, formed by extensional and torsional processes along pre-existing basement faults, exhibit a NE–SWW orientation. The boundary faults are characterized by their small size and low level of activity. The Saihan sag boundary fault had an activity rate of only 0.05 mm/a during the lower Tengger Member (K₁bt₁) sedimentary period, with a low sedimentation rate. However, when the sedimentation rate is less than 0.05 mm/a, it has almost no impact on the organic carbon content. When the sedimentation rate exceeds 0.05 mm/a, it significantly affects the organic carbon content. As the sedimentation rate increases, the organic carbon content noticeably decreases [16,70]. Research indicates that the deposition of organic materials in the Aer, Wuli, Naoer, and Saihan sags within the Erlian Basin is independent of sedimentation rates, signifying that sedimentation rates do not affect the formation of source rocks [25].

In conclusion, the correlation between sedimentation rate and total organic carbon (TOC) in small-scale fault basins is intricate within each depression, attributable to variations in tectonic settings. This paper calculates the sediment thickness of the Lower Cretaceous (K₁bt and K₁ba) in each sub-sag of the Erdengsumu sag using drilling and seismic data. The sediment thicknesses for the Dalestai, Sayinhutuge, and Chagantala sub-sags are 2700 m, 1700 m, and 2400 m, respectively, with estimated sedimentation rates of 0.158 mm/a, 0.1 mm/a, and 0.141 mm/a. The average sedimentation rate is 0.133 mm/a, indicating a modest level. The mean organic carbon concentration of the Lower Cretaceous formations (K₁bt and K₁ba) in the Dalestai sub-sag and Sayinhutuge sub-sag is 0.62% and 0.71%, respectively, suggesting that sedimentation rates do not significantly influence the formation of source rocks.

5.4. Hydrocarbon Source Rock Sedimentation Model

Katz [71] posits that three primary factors govern the deposition of hydrocarbon source rocks within an organic matter diagenetic system: organic production, organic matter preservation, and deposition rate. Despite variations in organic matter preservation among various caseinate types, redox conditions are widely acknowledged as a critical element in the preservation of organic matter and the production of hydrocarbon source rocks [72]. The diminished influx of clastic sediments has altered the sedimentary environment of the Erdengsumu sag, resulting in increased reducing conditions, as indicated by the low Pr/Ph ratio and the saturated hydrocarbon gas chromatographic indicators of the source rock (Figure 9a). The Erdengsumu sag is defined by coarse sediments, a limited lake area, shallow water, a brief lake duration, and a substantial tertiary system. It is described as a red coarse depression with a thick exterior and a thin interior [69,71]. Both the basal and boundary fractures are oriented northeast, and there is a development of small-scale sedimentary strata. During the deposition of hydrocarbon source rocks, the border cracks exhibited moderate activity, leading to a minor influx of clastic sediments containing limited terrestrial organic matter and dissolved inorganic carbon and nitrate. The introduction of minimal detrital sediments results in sluggish sedimentation, low deposition rates, and a steady decline in paleoproductivity, as evidenced by the shift in productivity seen in Figure 9b, where anoxic settings supplant productivity.

The structural differences and formation mechanisms of small-scale faulted lake basin depressions can affect the dimensions and activity of boundary faults, which in turn regulates the productivity of the lake basin and the oxidation–reduction environment, ultimately influencing the distribution of efficient hydrocarbon source rocks. Zhao et al. [69] established a correlation between the distribution of effective hydrocarbon source rocks in the Erlian Basin sags and the ratio of the deep-lying zone’s width to the depression’s width. When this ratio surpasses 0.5, effective hydrocarbon source rocks are mostly located in the deep subsurface zone; conversely, when the ratio falls below 0.25, these rocks are chiefly situated in the near-surface gently sloping region, exhibiting modest development in both the deep subsurface zone and the distant gently sloping area. Effective hydrocarbon source rocks are located in the deeper belt and the contiguous gentle slope belt when the ratio fluctuates between 0.25 and 0.50, leaving the remote gentle slope belt largely undeveloped. The ratio of the width of the deep depression zone to the width of the depression in the Erdengsumu sag is less than 0.25; the scale of boundary faults is minor, activity is subdued, terrestrial input is minimal, paleoproductivity is low, and the overall quantity of primitive organic matter is limited. Consequently, only the organic matter is preserved under optimal conditions to form effective hydrocarbon source rocks. The relative width of the deep-lying zone is minimal, exhibiting turbulence influenced by material sources. In contrast, the near-lying, gently sloping zone is comparatively tranquil, with a more reducing sedimentary environment conducive to the preservation of organic matter. Consequently, effective hydrocarbon source rocks are predominantly located in the near-lying gently sloping zone (Figure 15), while the deep-lying zone and the far-lying gently sloping zone exhibit a lack of effective hydrocarbon source rock development.

In the comprehensive analysis, the combination of redox conditions and terrestrial organic matter intake generated the lacustrine hydrocarbon source rocks of Erdengsumu sag, with redox conditions acting as the primary controlling factors. Humid airflow from the Paleo-Pacific Ocean affected the Erlian Basin during the Early Cretaceous period, creating a humid climatic environment that facilitated the formation of oil-bearing and coal-bearing strata in the Bayanhua Group [73]. The primary cause of hydrocarbon source rock deposition is the synergistic evolution of the environment and species inside the lake system.

6. Conclusions

This article performs an extensive geochemical analysis of hydrocarbon source rocks across various stratigraphic levels in the Erdengsumu sag, pinpointing regions with petroleum potential and elucidating the diagenetic controlling factors and formation mechanisms of lacustrine hydrocarbon source rocks under diverse structural conditions. The following conclusions were drawn.

• The Aershan Formation (K₁ba), which is the main source rock of the Dalestai sub-sag, has a high level of maturity, a large thickness, and good kerogen type (Type I-II₁) and abundance. The total hydrocarbon generation intensity is 486 × 10⁴ t/km². The lower Tengger Member (K₁bt₁), the principal hydrocarbon source rock of the Sayinhutuge sub-sag, is substantial; nonetheless, its limited abundance and inferior kerogen type (Type III-II₂), together with poorer maturity compared to the Aershan Formation, are notable drawbacks. The total hydrocarbon generation intensity is only 26 × 10⁴ t/km². It indicates that the Dalestai sub-sag has significant petroleum potential. The Aershan Formation in the Chagantala sub-sag reaches a maximum burial depth of only 1800 m, inadequate to achieve the critical depth required for oil generation, hence lacking the necessary conditions for oil generation.
• The lower threshold of TOC for effective hydrocarbon source rocks of the mudstone type in the study area is 0.95%. The productive hydrocarbon source rocks are predominantly found in K₁bt₁ and K₁ba, characterized primarily by dark-gray mudstone lithology. On the plane, the effective hydrocarbon source rock thickness in the Dalestai sub-sag exceeds 200 m across an area of 42.48 km², while in the Sayinhutuge sub-sag, it also surpasses 200 m over 88.71 km². Additionally, the northern sub-sag is thicker than the southern.
• The Lower Cretaceous hydrocarbon source rocks have different paleosedimentary environments for each stratum; the K₁bs and K₁bt₂ hydrocarbon source rocks formed in a reduced semi-saline to freshwater lake environment, while the K₁bt₁ and K₁ba hydrocarbon source rocks formed in a reduced to weakly oxidized brackish to saline lake environment. The parent source is characterized as “mixed sources of higher plants and plankton as a whole, with the input of higher plants dominating.”
• The redox conditions primarily govern the creation of the Erdengsumu sag lacustrine hydrocarbon source rocks, but terrestrial organic matter input also exerts a significant influence on their formation. Effective source rocks are predominantly located in the near-depression gentle slope zone. Petroleum exploration in the Erdengsumu sag of the Erlian Basin should concentrate on the diminishing sedimentary environments of the lower Tengger Member and the upper section of the Aershan Formation.