Next Article in Journal
Dehydroxylation of Kaolinite: Evaluation of Activation Energy by Thermogravimetric Analysis and Density Functional Theory Insights
Previous Article in Journal
Hornblende and Plagioclase Micro-Texture and Compositions: Evidence for Magma Mixing in High-Mg Adakitic Pluton, North China Craton
Previous Article in Special Issue
Characterization and Analysis of the Main Factors of Brittleness of Shale Oil Reservoirs in the Liushagang Formation, X Depression, Beibuwan Basin
 
 
Search for Articles:
Title / Keyword
Author / Affiliation / Email
Journal
Article Type
 
 
Advanced Search
 
Section
Special Issue
Volume
Issue
Number
Page
 
Journals
Minerals
Volume 15
Issue 6
10.3390/min15060606
minerals-logo
Submit to this Journal Review for this Journal Propose a Special Issue
► Article Menu

Article Menu

share Share announcement Help format_quote Cite question_answer Discuss in SciProfiles
first_page
settings
Order Article Reprints
Font Type:
Arial Georgia Verdana
Font Size:
Aa Aa Aa
Line Spacing:
Column Width:
Background:
Article

Classification Evaluation and Genetic Analysis of Source Rocks of Lower Permian Fengcheng Formation in Hashan Area, Junggar Basin, China

by
Zhongliang Sun
1,2,3,*,
Zhiming Li
1,2,3,
Kuihua Zhang
4,
Zhenxiang Song
1,2,3,
Hongzhou Yu
5,
Bin Wang
1,2,3,
Meiyuan Song
5 and
Tingting Cao
1,2,3
1
Wuxi Research Institute of Petroleum Geology, Research Institute of Petroleum Exploration & Production, SINOPEC, Wuxi 214151, China
2
SINOPEC Key Laboratory of Petroleum Accumulation Mechanisms, Wuxi 214151, China
3
State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Wuxi 214151, China
4
Shengli Oilfield Company, SINOPEC, Dongying 257000, China
5
Exploration and Development Research Institute, Shengli Oilfield Company, SINOPEC, Dongying 257015, China
*
Author to whom correspondence should be addressed.
Minerals 2025, 15(6), 606; https://doi.org/10.3390/min15060606
Submission received: 9 March 2025 / Revised: 24 May 2025 / Accepted: 25 May 2025 / Published: 4 June 2025
(This article belongs to the Special Issue Distribution and Development of Faults and Fractures in Shales)
Browse Figures
Versions Notes

Abstract

:
The exploration of shale oil in the Fengcheng Formation of the Permian system in the Hashan area shows considerable promise, with breakthroughs in a number of shale oil exploration wells. This study evaluates the source rocks in the Fengcheng Formation in the Hashan area to determine their types, clarify the quality and hydrocarbon potentials of the different types, and analyze the main factors affecting their quality and generation potential based on lithofacies classification. The results indicate that the Fengcheng Formation in the Hashan area contains four types of lithofacies: terrigenous clastic lithofacies, dolomitic mixed lithofacies, tephra-bearing mixed lithofacies, and alkaline mineral-bearing mixed lithofacies. The tephra-bearing mixed lithofacies source rocks have the best source rock quality, followed by terrigenous clastic lithofacies and dolomitic mixed lithofacies. The quality of the source rocks is mainly controlled by their sedimentary environment (including paleoenvironment, alkaline minerals, and volcanic activity), the hydrocarbon-generating properties of the source material, and maturity. Organic matter in the dolomitic mixed lithofacies and the alkaline mineral-bearing mixed lithofacies is more concentrated in deepwater-reducing environments with medium to high salinity and arid conditions. The main biological source material is green algae (Dunaliella), which is characterized by early hydrocarbon generation and the high transformation ratio of oil, allowing for rapid hydrocarbon generation at low maturity. However, as the maturity increases, the hydrocarbon-generating potential of the source rocks decreases rapidly. Organic matter in terrigenous clastic lithofacies is more concentrated in relatively shallow water in oxygen-depleted, low-salinity, arid to semi-arid environments, with cyanobacteria being the main biological source. Cyanobacteria have the characteristics of long hydrocarbon generation periods and high hydrocarbon potential, with the peak of hydrocarbon generation occurring later than green algae (Dunaliella). Therefore, even at a relatively high maturity level, the source rocks still maintain a relatively high hydrocarbon-generating potential. Moderate volcanic activity provides favorable conditions for organic matter accumulation.

1. Introduction

Theoretical research on hydrocarbon generation from source rocks in saline lacustrine basins is an important direction for understanding continental oil generation [1,2]. Saline lacustrine basins are widely distributed throughout geological history, forming when the evaporation of the water in the lacustrine basin exceeds the input of fresh water [3]. Studies have shown that mudstones and carbonate rocks associated with salinization are often rich in organic matter and can form high-quality source rocks, even forming the major source rocks in some hydrocarbon-rich depressions [4]. Many examples are found in Cenozoic deposits in China, including the Shahejie Formation in the Bohai Bay Basin [5], the Qianjiang Formation in the Jianghan Basin [6], and the famous Luhe Formation in the Daluhe Basin [7], which is part of the Junggar Basin in Xinjiang. High-quality saline source rocks are also found in the late Paleozoic Permian in northern Xinjiang, for example, in the Lower Permian Fengcheng Formation in the Mahu Sag in the northwest margin of the Junggar Basin [1], which formed the Karamay, Fengcheng, Wuerhe, and other oil fields. However, saline environments are usually accompanied by complex organic facies transitions and special salt mineral formations, presenting great challenges to understanding the laws and theory of hydrocarbon generation, one of the most difficult and persistent problems in this field of research [1,3,8,9]. The evolution of organic matter is an important link in hydrocarbon generation, and the quality of the source rocks and their hydrocarbon generation mechanisms can provide a scientific basis for the accurate and reasonable prediction of oil and gas resources and, therefore, for guiding exploration [10,11].
The Hala’alat Mountain area (herein referred to as the Hashan area) is located in the northwest margin of the Mahu Sag, in the thrust-nappe structural belt. It has a similar sedimentary background to the sag itself, being a lacustrine basin center where ancient alkaline lacustrine source rocks are developed [4,12]. Alkali lacustrine is a type of saline lacustrine basin but is different from common salt lacustrine (sulfate lacustrine). The distinguishing features are the development of sulfate and alkali minerals, which are often associated with an abundance of microorganisms (sulfate-reducing bacteria). Early studies showed that the organic matter richness of shale in the Fengcheng Formation ranges from 0.11 wt. % to 3.5 wt. %, which is generally considered to represent medium-abundance source rocks. The hydrocarbon potential (S1 + S2) varies from 0.1 to 55 mg/g. The organic matter is mainly types I and II, with some type III [13]. Liu’s [14] research shows that the clayey shale source rocks located at the edge of the alkaline lacustrine have the best quality. Next are the dolomitic shales in the transitional zone of the alkaline lacustrine. The organic matter richness of the saline shales in the central area of the alkaline lacustrine is relatively low. But, it did not reveal the reasons for the differences in the organic matter richness of different lithofacies. Hou’s [15] research shows that the low productivity under high salinity is the main reason for the low organic matter richness in saline shales, and cyanobacteria are the main hydrocarbon-generating source materials in the Hashan area.
Due to their unique alkali lacustrine background, the source rocks of the Fengcheng Formation have unique hydrocarbon generation rules. A number of previous studies have investigated the types of source rocks in the Fengcheng Formation shale and their hydrocarbon generation features. Meng et al. [16] extensively researched the Fengcheng Formation source rocks in the Mahu Sag, positing that the variations observed are mostly due to different sources of organic matter. Each sedimentary facies deposited different types of organic matter, but the organic matter in the Fengcheng Formation source rocks is predominantly algal. Some studies [17,18] have concluded that, despite the relatively lower organic matter content in the source rocks of the Fengcheng Formation compared to other hydrocarbon-rich depressions, the key to its capacity for forming large oil regions lies in the high transformation ratio of hydrocarbon generation within the source rocks. The unique alkaline lacustrine environment also allows the Fengcheng Formation source rocks to remain in peak oil generation at high maturity levels, greatly extending the oil generation period compared to other high-quality lacustrine source rocks. However, other studies [19,20] have verified, through hydrocarbon generation simulation, that the hydrocarbon potential of alkaline lacustrine source rocks does not differ significantly from that of conventional lacustrine source rocks (freshwater, brackish-saline, sulfate lacustrine). There is still controversy regarding the interpretation of the quality differences and hydrocarbon generation features of the source rocks in the Fengcheng Formation. Based on shale samples from many wells, this paper classifies the lithofacies in the Fengcheng Formation in the Hashan region, assesses the quality of source rocks across the various lithofacies, and investigates the factors that impact the quality of these source rocks. It will provide valuable guidance for future shale oil exploration in the Fengcheng Formation.

2. Geological Setting

The Hashan area is located in the Tacheng and Altay regions of the Xinjiang Uyghur Autonomous Region. It is structurally situated at the northwestern end of the Wu-Xia (Wuerhe-Xiazijie) fault zone along the northwestern margin of the Junggar Basin, adjacent to the hydrocarbon-rich Mahu Sag in the south and bordering the Heshituoluogai Basin in the north (Figure 1A), with an exploration area of 5794.8 km2. The structural lines in the area trend generally northeast, with the main structure being a thrust-nappe tectonic zone (Figure 1C), where thrust-nappe structures and autochthonous sedimentary strata, as well as medium-deep thrust-nappe structures and autochthonous sedimentary strata, are developed [21]. During the deposition of the Lower Permian Fengcheng Formation (P1f) in the Hashan area, the main sedimentary system was fan delta-lacustrine, which is divided (from bottom to top) into the Feng 1 Member (P1f1), the Feng 2 Member (P1f2), and the Feng 3 Member (P1f3). The deposition period featured initial salinization followed by freshening from P1f1 to P1f3, with the middle-upper part of P1f2 being the interval with the most pronounced concentration of alkaline minerals [22]. The complex mineral sediment types and hydrocarbon source rock development conditions of this formation are the result of mixed deposition from multiple sources, including exogenous chemical sediments formed in a xerothermic evaporative environment, volcanic materials provided by peripheral volcanic activities, and proximal terrestrial clastic sediments formed by the erosion of the western thrust bodies. This combination has resulted in the formation of different types of source rocks. The bottom of P1f1 is distal delta front, which evolved into a shallow lacustrine in the upper part of P1f1. P1f2 is dominated by lacustrine deposition, mainly semi-deep to shallow lacustrine within the area, with local influence from volcanic activity. During the deposition of P1f3, the Hashan area primarily formed a distal delta front (Figure 1B) [22,23].

3. Samples and Experiments

3.1. Samples

The samples selected for this study include samples taken from Well HS5 in the middle part of the Hashan area, as well as Wells HS11, HS1, HQ6, HQ101, and HSX1 in the western part. The locations are shown in Figure 1A. Due to the multiple overthrust and superimposed tectonic features in the Hashan area, many of the wells contain both thrust-nappe strata and autochthonous sedimentary strata, with differences in the thrust-nappe intervals (Figure 1C) having laterally affected the distribution and classification of sedimentary facies. The thrust-nappe strata were, therefore, realigned before further research was undertaken. The sampling points in Well HS5 include the thrust-nappe P1f2 strata and the nearly autochthonous P1f2 and P1f1 strata. The lower part of the thrust-nappe P1f2 is shore-shallow lacustrine deposition, while the upper part is distal delta front deposition. The nearly autochthonous P1f2 represents semi-deep to deep lacustrine deposition, and the P1f1 is shore-shallow lacustrine deposition. Wells HS1, HQ6, and HQ101 mainly consist of thrust-nappe strata. Among them, the sampling points in Well HS1 include points in P1f1 and P1f2, which are, respectively, distal delta front deposition and shore-shallow lacustrine deposition; the sampling points in Well HQ6 include points in P1f3 and P1f2, which are, respectively, distal delta front deposition and shallow lacustrine deposition. The sampling point in Well HQ101 is in P1f3, which is distal delta front deposition. The sampling points in Well HS11 include points in the thrust-nappe P1f3 and the nearly autochthonous P1f2, which are, respectively, distal delta front deposition and shore-shallow lacustrine deposition. The core from Well HSX1 was taken from nearly autochthonous strata, including P1f2 and P1f3, which are, respectively, shore-shallow lacustrine deposition and distal delta front deposition (Figure 2).

3.2. Experimental Methods

The experimental data used in this study include hydrocarbon generation simulations, pyrolysis, total organic carbon (TOC), X-ray diffraction (XRD), and handheld X-ray fluorescence (XRF) scanning. The experiment was conducted in a high-temperature and high-pressure semi-closed hydrous pyrolysis hydrocarbon generation and expulsion pyrolysis system developed by Wuxi Research Institute of Petroleum Geology, Petroleum Exploration & Production Research Institute, SINOPEC. The episodic hydrocarbon expulsion method was used to better simulate the evolution of hydrocarbon generation and retention in the source rocks. Using burial history and thermal evolution as geological constraints, the experiment simulated formation temperature and pressure conditions and systematically analyzed the products of the thermal simulations under different temperature and pressure conditions. The pyrolysis experiments involved crushing the samples to about 100 mesh and testing according to the ramping temperature method set out in the national standard “Rock Pyrolysis Analysis” (GB/T 18602-2012 [24]). A hydrogen flame ionization detector was used to detect the free hydrocarbons (S1), adsorbed hydrocarbons (S2), and pyrolysis peak temperature (Tmax) in the carrier gas heat flow during the rock pyrolysis process. The TOC testing process involved selecting about 0.2 g of each sample, crushing it to less than 100 mesh, adding dilute hydrochloric acid (1:7), heating in a 70 °C water bath to remove inorganic carbon, rinsing with distilled water to remove hydrochloric acid, and then conducting the test. For X-ray diffraction (XRD) and X-ray fluorescence (XRF) testing, the samples were crushed to 100 mesh and compacted into a flat surface to ensure accurate test results. The qualitative and quantitative analyses of the minerals were identified (~1% error) using the RDB mineral data-base. Since XRF test results are significantly affected by element molecular weight and content, five tests were averaged to yield the result.
The elements analyzed in this study include Fe, Al, Ca, Mg, V, Ni, Ba, Sr, and Rb. Terrigenous clastic rocks have relatively high contents of both Fe and Al, and the contents of these elements in mudstones decrease as enrichment with carbonate minerals increases. In contrast, Ca and Mg are mainly found in carbonate rocks, with their contents correlating negatively with increases in Fe and Al contents. The increase in the content of carbonate rocks in the studied interval indicates a shortage of terrigenous materials and an increase in distance from the shore. The (Fe + Al)/(Ca + Mg) ratio is, therefore, a good indicator of the distance from the shore in the studied interval [25]. Elements such as V and Ni are easily soluble under oxidizing conditions but tend to be enriched in oxygen-poor reducing conditions. The V/(V + Ni) ratios can, therefore, be used to indicate the paleoredox [26,27,28]. Enrichment with Sr and Ba is controlled by salinity. For example, Ba has relatively weak migration ability. When the water salinity increases, Ba precipitates first in the form of BaSO4. In contrast, Sr has strong migration ability and only precipitates in the form of SrSO4 when the water salinity increases to a certain extent. Therefore, the Sr/Ba ratio is a good indicator of paleosalinity, with which it shows an obvious positive correlation [29,30]. There are differences in the enrichment of elements under different climatic conditions. For example, elements such as Rb tend to accumulate in warm and humid environments, while Sr content is relatively high in xerothermic climates. The Rb/Sr ratio can, therefore, be used to characterize the paleoclimate [31,32].

4. Lithofacies Division

Lithological observation, mineral composition analysis, and thin section scanning and identification indicated a good correspondence between sedimentary facies and lithology. The distal delta front mainly consists of silty mudstone and argillaceous siltstone (Figure 2 and Figure 3(A1,A2,B1,B2)). Clay, quartz, and feldspar are the main mineral components, accounting for about 80% of the total mineral content. Of these, silty mudstone has a higher clay content, generally ranging from 20% to 40% (with an average of 31%), followed by quartz (19.1% to 24.1%, with an average of 21.35%) and plagioclase (16% to 37.4%, with an average of 20.5%). The clay content in the argillaceous siltstone is relatively small, generally around 20%, while the content of quartz and feldspar is significantly higher, with their combined contents exceeding 60% (Figure 4A). The silty mudstone samples are well bedded (Figure 3(B2)), reflecting a relatively quiet depositional environment, which is characteristic of interdistributary bay deposition in the distal delta front that is developed in P1f3 and some upper-middle parts of P1f2. The argillaceous siltstone is mainly massive (Figure 3(B1)), with good sorting and subangular to subrounded grains, reflecting strong hydrodynamic characteristics. It represents the deposition of distal sand bars in the distal delta front and is mainly developed in P1f3 and some upper-middle parts of P1f2.
Lithologies such as dolomitic mudstone, dolomitic siltstone, and argillaceous dolomite are mainly developed in the shore-shallow lacustrine environment (Figure 2 and Figure 3(C1,C2,D1,D2)). The clay content is generally lower than 15%, with an average of 11.8%. Quartz (ranging from 9% to 56%, with an average of 31.11%) and dolomite (ranging from 5.1% to 56.2%, with an average of 19.17%) are the main mineral components, but with highly variable contents (Figure 4B). Sedimentary structures include layered (Figure 3(C2)), laminated (Figure 3(D2)), and massive structures. Seasonal rhythmic layers (interbedded siltstone and dolomite) (Figure 3(D2)) and slump structures are common (Figure 3(C1)), indicating a certain slope during deposition. The bedding is mainly horizontal, with occasional wavy bedding. These sediments mainly occur in the lower-middle parts of P1f2.
Lithologies such as dolomitic mudstone containing alkaline minerals and mudstone containing alkaline minerals are developed in semi-deep to deep lacustrine environments (Figure 2 and Figure 3(E1,E2)). The mineral composition is complex and changes rapidly due to the lithological variations (Figure 4C). The dominant mineral components are mainly related to the specific lithology. In this type of lithofacies, the contents of magnesite and pyrite are significantly increased, reflecting a strong reducing environment. Microscopic observation shows that the alkaline minerals include Na2Mg (CO3)2, Na2Ca(CO3)2, and NaBSiO4. The cyclic deposition of dolomitic mudstone, dolomitic mudstone containing alkaline minerals, and trona occurred as the evaporation environment altered. The alkaline minerals are mainly distributed in snowflake-like, banded, and reticulated patterns within the dolomitic mudstone (Figure 3(E1,E2)). These sediments are mainly developed in the upper part of P1f1 and the middle-lower parts of P1f2.
The Fengcheng Formation also has lithologies such as tuff, tuffaceous siltstone, and tuffaceous mudstone, which have been greatly influenced by volcanic activity, which caused the development layers and locations to become irregular. This lithofacies is observed in P1f1 in Well HS 5, P1f2 in Well HSX 1, and P1f1 in Well HS 1. In the Hashan area, it is mainly developed in shore-shallow lacustrine environments, with dolomite minerals being the main components (ranging from 21.7% to 55%, with an average of 33.37%) and also contains volcanic detrital minerals such as amphibole and pyroxene (Figure 4D).
Based on the lithological characteristics of the different sedimentary facies in the Fengcheng Formation in the Hashan area, the lithological combinations of mudstone, siltstone, and silty mudstone deposited in the distal delta front are classified as terrigenous clastic lithofacies. Lithologies dominated by exogenous chemical sediments in the shore-shallow lacustrine environment, such as dolomitic mudstone, argillaceous dolomite, and dolomitic sandstone, are classified as dolomitic mixed lithofacies. Lithologies of mudstone (alkaline mineral content > 50%) and mudstone containing alkaline minerals deposited in deep to semi-deep lacustrine environments are classified as alkaline mineral-bearing mixed lithofacies. The sedimentary facies that have been influenced by volcanic activity develop tephra-bearing mixed lithofacies, mainly deposited as tuffaceous mudstone and tuffaceous dolomitic mudstone.

5. Quality of Source Rocks

5.1. Organic Matter Richness

Organic matter richness is the basis for hydrocarbon generation in source rocks, and common indicators for assessing organic matter richness include total organic carbon (TOC) content and hydrocarbon potential (S1 + S2) [33]. The statistical analysis of over 290 data points from six wells in Hashan, classified according to lithology (Figure 5), reveals that the Fengcheng Formation in the Hashan area develops medium-abundance source rocks with an average TOC of around 1–2 wt. %. However, there are marked differences in organic matter richness among the different lithofacies. Organic matter richness in tephra-bearing mixed lithofacies is generally high, with the average TOC exceeding 1 wt. % (n = 59). The source rocks in Well HSX1 have the highest average TOC of 1.74 wt. % (n = 14), followed by those in Well HS11 with an average TOC of 1.62 wt. % (n = 8). The average TOC values in Wells HS1 and HS5 are 1.36% (n = 24) and 1.05% (n = 13), respectively. Organic matter contents in the terrigenous clastic lithofacies vary greatly, with the lowest TOC being 0.11 wt. % and the highest 3.54 wt. %. The source rocks in Well HS5 have the lowest average TOC of 0.84 wt. % (n = 15), while those in Well HS11 have the highest average TOC of 1.83 wt. % (n = 9). The TOC in the dolomitic mixed lithofacies is relatively consistent, with the average values in the various wells generally exceeding 1 wt. % (n = 59). The source rocks in Well HSX1 have the highest organic matter richness, with a maximum TOC of 2.77 wt. % and an average of 1.81 wt. % (n = 17). The source rocks in Well HS5 have the lowest organic matter richness, with an average TOC of 0.98 wt. % (n = 15). The organic matter richness in source rocks with alkaline mineral-bearing mixed lithofacies is the poorest, with an average value of only 0.55% (n = 23).
There are significant differences in hydrocarbon potential among the different source rock lithologies in the Fengcheng Formation in the Hashan area (Figure 6). Corresponding to organic matter richness, the hydrocarbon potential of the source rocks in tephra-bearing mixed lithofacies remains high, with the average value exceeding 6mg/g (except for Well HS5 (n = 71)). The hydrocarbon potential of different source rocks in terrigenous clastic lithofacies varies greatly. Some samples from Well HS5 have a hydrocarbon potential of only 0.11 mg/g (n = 16), while those from Well HSX1 can reach 55.1 mg/g (n = 27) (some samples of terrigenous clastic lithofacies in Well HSX1 contain coal and have abnormally high S2 values). The source rocks in Well HS5 have the lowest average hydrocarbon potential of 2.17 mg/g (n = 16), followed by Well HS1 in the western area of Hashan with an average of 2.70 mg/g (n = 25). The hydrocarbon potential of source rock samples from other wells in the Fengcheng Formation is generally higher than 6 mg/g, with the source rocks in Well HSX1 having the highest hydrocarbon potential of greater than 15 mg/g (n = 27). There are also obvious differences in hydrocarbon potential among source rocks from different wells in dolomitic mixed lithofacies. The average hydrocarbon potential of source rocks in Wells HS5 (n = 16) and HS11 (n = 3) is lower than 3 mg/g, while in Wells HS1 (n = 26) and HQ6 (n = 20), it is around 6 mg/g. The source rocks in Well HSX1 have the greatest hydrocarbon potential, exceeding 11 mg/g (n = 26). The source rocks in alkaline mineral-bearing mixed lithofacies have the poorest hydrocarbon potential, with an average value of 1.14 mg/g in Well HS5 (n = 14).

5.2. Types of Organic Matter

A comparison of the organic matter types in the source rocks of different lithofacies (Figure 7) shows that the organic matter in the shale of the Fengcheng Formation in the Hashan area is mainly of type II, followed by type I, with some type III. In terrigenous clastic lithofacies, type II1 organic matter dominates, followed by type II2 and type I. There are differences in the organic matter types in the source rocks from different wells. The organic matter types in the source rocks from Wells HS11, HSX1, HQ101, and HQ6 are mainly type II1 and type I, while Wells HS5 and HS1 contain mainly type II2. In dolomitic mixed lithofacies source rocks, the organic matter is also mainly of type II, although there are variations between wells. The organic matter types in the source rocks from Wells HQ6, HS1, and HSX1 are mainly type II1 and type I, while Well HS11 contains type II2 and Well HS5 is mainly type III. In tephra-bearing mixed lithofacies, the organic matter types in the source rocks of the western area of Hashan are type II1 and type I, while Well HS5 of the central area of Hashan contains mainly type II2. The organic matter types in the source rocks in the alkaline mineral-bearing mixed lithofacies of Well HS5 are mainly type II2 and type III.
Consistent with this organic matter type classification, organic petrological macerals reveal (Table 1) that sapropelite accounts for a relatively high proportion of the organic matter in the mudstone of terrigenous clastic lithofacies, exceeding 45%, followed by vitrinite, which accounts for more than 28%. The vitrinite content in some argillaceous siltstone exceeds 80%, while the inertinite and exinite contents are relatively low, generally below 20%. Some of the argillaceous siltstones in terrigenous clastic lithofacies have high solid bitumen contents, which may be a result of oil migration. Dolomitic mixed lithofacies contains predominantly vitrinite, with a content generally higher than 60%, followed by inertinite. The exinite and sapropelite contents are relatively low, generally below 10%. In alkaline mineral-bearing mixed lithofacies, vitrinite and inertinite account for relatively large proportions, and the solid bitumen content is generally higher than 15%, indicating oil generation and migration in this lithofacies. The components of tephra-bearing mixed lithofacies are similar to those in dolomitic mixed lithofacies, with vitrinite content generally exceeding 60%, followed by inertinite, with a content generally higher than 20%, and a small amount of exinite.

5.3. Maturity of Organic Matter

A number of factors, such as overthrusting and tectonic uplift, have resulted in significant differences in organic matter maturity between the central and western areas of the Hashan area. According to vitrinite reflectance (Ro) tests (Figure 8), the overall burial depth in the western part of the Hashan area ranges from 2000 to 4000 m, with little variation in Ro values, which range from 0.79% to 0.97%, peaking around 0.9%, which are slightly lower than those of the Mahu Sag (0.85% to 1.1%). The burial depth in the center of the Hashan area is between 3900 and 5500 m, with maturity ranging from 1.2% to 1.37%, which is higher than for the Mahu Sag and the western part of Hashan. Maturity increases with depth. Tmax in the western part of Hashan is around 430 °C, corresponding to a maturity of about 0.6%, which is generally lower than that suggested by the vitrinite reflectance results. This may be due to the presence of more asphaltene in the rock samples [19,34]. The maximum temperature at the top of the S2 peak of Well HS5 in the central part of the Hashan area is between 430 °C and 470 °C, with some samples showing left-shifted characteristics, which may be explained by the accumulation of exogenous oil and gas due to migration.

6. Analysis of the Factors Influencing Source Rock Quality

6.1. Sedimentary Environment

6.1.1. Paleoenvironment

Comparing organic matter richness and types reveals significant differences in organic matter richness and type among different lithofacies (Figure 4, Figure 5 and Figure 6). Even within the same lithofacies, there are marked variations. For example, in the terrigenous clastic lithofacies of Well HS5, the highest organic matter richness is around 2 wt. %, while the lowest is only 0.43 wt. % (Figure 4), and the organic matter types vary between type II and type III (Figure 6). An analysis of the richness and type of organic matter in different samples of terrigenous clastic lithofacies finds that laminated mudstones deposited in interdistributary bay areas characterized by low-energy and quiet water environments have high organic matter richness and better organic matter types (Figure 3(B1,B2)), confirming that a sedimentary environment influences the enrichment of organic matter.
The statistical analysis of the paleoenvironmental characteristics of the different lithofacies reveals significant differences (Figure 9). The correlation between the paleo-water depth index ((Al + Fe)/(Ca + Mg)) [27] and TOC indicates that organic matter richness decreases as water depth decreases, suggesting that deep-water environments are conducive to the enrichment of organic matter. Different lithofacies are located at varying water depths, and the optimal water depth for organic matter richness differs. Corresponding to sedimentary facies, alkaline mineral-bearing mixed lithofacies develops in the deepest waters, followed by dolomitic mixed lithofacies, while terrigenous clastic lithofacies develops at shallower depths. Tephra-bearing mixed lithofacies develops in both deep and shallow waters. The TOC peaks of alkaline mineral-bearing mixed lithofacies and dolomitic mixed lithofacies occur in relatively deep water environments, while the TOC peaks of tephra-bearing mixed lithofacies and terrigenous clastic lithofacies occur in relatively shallow waters, which may be attributed to differences in source materials or the different controlling factors for organic matter enrichment among lithofacies. Compared to argillaceous siltstone, silty mudstone is located in deeper waters with less terrigenous detrital input, quiet water conditions, and more enriched organic matter.
The correlations between the TOC and the paleoredox index (V/(V + Ni)) [28,29,30] of different lithofacies show that, as the oxygen content of water decreases, organic matter richness increases, indicating that preservation conditions are an important factor for organic matter enrichment. However, the peaks of organic matter richness in different lithofacies all occur in reducing environments, suggesting that preservation conditions are not the main reason for the differences in organic matter richness among different lithofacies.
Comparing the changes in organic matter richness with the paleo-salinity index (Sr/Ba) [31,32] of different lithofacies indicates that the overall Sr/Ba ratio of samples in the study area is greater than 0.5, indicating a brackish-to-saline water environment. The development of different lithofacies is less influenced by paleosalinity, and there is a weak correlation between organic matter richness and paleosalinity. Specifically, there is a weak negative correlation between organic matter richness and paleosalinity in terrigenous clastic lithofacies, with organic matter richness decreasing as paleosalinity increases. In dolomitic mixed lithofacies, organic matter richness first increases and then decreases with increasing paleosalinity, indicating that water salinity has a slight influence on the enrichment of organic matter in different lithofacies. Since water salinity affects biological communities and preservation conditions, the overall Sr/Ba ratio of samples in the study area is greater than 0.5, indicating good preservation conditions. The changes in organic matter richness with paleosalinity between different lithofacies may be influenced by different biological communities. The source materials of alkaline mineral-bearing mixed lithofacies and dolomitic mixed lithofacies have relatively higher salt tolerances.
Comparing the paleoclimate index (Rb/Sr) [33,34] characteristics of different lithofacies shows that, as the climate changes from arid to humid, organic matter richness decreases. Alkaline mineral-bearing mixed lithofacies, dolomitic mixed lithofacies, and tephra-bearing mixed lithofacies are deposited under relatively arid conditions, and their TOC peaks all occur in arid paleoenvironments. Terrigenous clastic lithofacies are deposited in relatively humid paleoenvironments, with their TOC peaks occurring in these environments, indicating differences in the hydrocarbon-producing organisms among the different lithologies. The different paleoenvironmental characteristics of lithofacies indicate that the paleoenvironments of dolomitic mixed lithofacies and alkaline mineral-bearing mixed lithofacies are relatively stable, while the paleoenvironmental characteristics of terrigenous clastic lithofacies vary significantly. This, in turn, leads to smaller differences in organic matter richness and type between dolomitic mixed lithofacies and alkaline mineral-bearing mixed lithofacies, while terrigenous clastic lithofacies have larger differences in organic matter richness and type.

6.1.2. Alkaline Minerals and Volcanism

Alkaline minerals and volcanism are also important environmental factors affecting the quality of hydrocarbon source rocks with different petrographic characteristics. Wells HS11 and HSX1 are located close to each other and both contain dolomitic mixed lithofacies. However, Well HSX1 has better organic matter richness and type than Well HS11. The main difference between the wells is that Well HSX1 has been more significantly influenced by volcanic activity (3650~3950 m) (Figure 2). An analysis of paleoenvironments (Figure 9) shows that tephra-bearing mixed lithofacies in environments that are relatively shallow, oxygen-depleted, and low in salinity still have high organic matter richness, although they are generally unfavorable for organic matter accumulation. This suggests that volcanism promotes the accumulation of organic matter. The volcaniclastic materials in the Hashan area include amphibole and pyroxene (Figure 4). In this study, the content of volcaniclastic materials (amphibole + pyroxene) is used to quantify the impact of volcanic activity on organic matter accumulation. As shown in Figure 10A, TOC first increases and then decreases as volcaniclastic content increases. When the volcaniclastic content is around 10%, TOC is at its highest, indicating that a small amount of volcaniclastic material is beneficial for organic matter accumulation, while excessive volcanic activity is unfavorable. The impact of volcanic activity on organic matter accumulation is reflected in two ways. Firstly, the surface of volcanic ash carries large amounts of water-soluble metal salts, which release significant amounts of nutrients such as Fe, Mg, Ca, and Zn when dissolved in water, thereby enhancing the primary productivity of the water body. In addition, intense volcanic activity can release large amounts of acidic material, acidifying the water body and inhibiting the growth and reproduction of organisms. Wang et al. [35] and Kamo et al. [36] explained that acidic substances can cause large-scale mortality among organisms, resulting in the rapid burial of large amounts of hydrocarbon-generating source material, which is conducive to the development of high-quality source rocks. However, in the study area, the main area of strong volcanic activity is at the bottom of P1f1 (Figure 2), where the original productivity was very low, resulting in low organic matter richness.
In Well HS5, the dolomitic mixed lithofacies has better organic matter richness and type than the alkaline mineral-bearing mixed lithofacies (Figure 4), indicating that the alkaline environment also has a significant impact on organic matter accumulation. The alkaline minerals in the Fengcheng Formation in the Hashan area include Na2Mg(CO3)2, Na2Ca(CO3)2, and NaBSiO4 (Figure 4). Due to the limitations of X-ray diffraction experiments, it is difficult to accurately determine the number of sodium ions, so it is difficult to quantify the alkaline mineral contents. According to the deposition sequence of alkaline minerals, clastic rocks, carbonate rocks, and evaporite rocks will be deposited in succession as salinity increases [37]. Therefore, in this study, the content of anhydrite (CaSO4)—which is positively correlated with paleosalinity—is used to represent the content of alkaline minerals. Figure 10B shows that, as the anhydrite content increases, the TOC value decreases, indicating that alkaline minerals inhibit organic matter accumulation; this is consistent with the research results of Hou et al. [15]. Previous studies have found that an increase in alkaline minerals enhances the microbial transformation of algae [35], which may be an important reason for the lower organic matter richness in hydrocarbon source rocks with alkaline mineral-bearing mixed lithofacies. Zhang et al. [36] discovered, through their research on nitrogen-containing compounds, that high salinity can inhibit the molecular aggregation of organic matter, resulting in a longer oil window for alkaline lacustrine source rocks, which may also lead to a lower final TOC. In addition, the precipitation of alkaline minerals can also dilute organic matter, leading to lower measured values for organic matter richness.

6.2. Biological Origins of Source Rocks and Their Hydrocarbon-Generating Properties

6.2.1. Biological Origin of Source Rocks

A comparison of the relationship between organic matter richness and hydrocarbon potential (Figure 11) shows that the hydrocarbon potential per unit of organic matter in terrigenous clastic lithofacies source rocks is significantly different from that of dolomitic mixed lithofacies, which suggests differences in biological origins between the two. According to organic petrological statistics, sapropelite is the main organic component in terrigenous clastic mudstones, while vitrinite predominates in dolomitic mixed lithofacies and alkaline mineral-bearing mixed lithofacies (Table 1). This may be the immediate reason for the relatively higher measured values for hydrocarbon potential in terrigenous clastic lithofacies source rocks and may also indirectly reflect potential differences in the biological origins of organic matter.
Xia et al. [38,39] found, through biomarker analysis, that, in the carbonate rock area of the depocenter, a salt-tolerant green alga (Dunaliella) grows in the high-alkaline environment. From the depocenter to the depositional margin, as the salinity of the water decreases, the proportion of Dunaliella decreases, and the content of cyanobacteria increases. SEM and organic petrology reveal that the hydrocarbon-generating organisms in the Fengcheng Formation in the Hashan area are mainly planktonic algae (Figure 12C–F), although higher plant debris is also common (Figure 12A,B). Terrigenous clastic lithofacies contains large populations of lamalginite with weak green fluorescence and telalginite with strong visible yellow-green fluorescence (Figure 12C). The microscopic examination of kerogens reveals large numbers of amorphous mass in dolomitic mixed lithofacies that are formed by microbial activity modifying telalginite [40]. Some amorphous mass still retains algal structures (Figure 12D) and Dunaliella has been found in both dolomitic mixed lithofacies and alkaline mineral-bearing mixed lithofacies (Figure 12E,F), verifying the conclusion from paleoenvironmental analysis that there are differences in hydrocarbon-generating organisms between terrigenous clastic lithofacies, dolomitic mixed lithofacies, and alkaline mineral-bearing mixed lithofacies. In this study, the characteristics of sedimentary facies and their corresponding lithofacies are combined to develop a bio-environmental co-evolution model for the different sedimentary zones (Figure 13). In the distal delta front, microorganisms such as cyanobacteria predominate have a low content of salt-tolerant green algae (Dunaliella). In the shore-shallow lacustrine area, the content of microorganisms such as cyanobacteria decreases, while the content of Dunaliella increases. In the deep–semi-deep lacustrine area, Dunaliella is the principal biological source. Research shows that Dunaliella is a green alga with extremely high oil content, which can produce up to 45 wt. % of bio-oil through rapid pyrolysis [9] and is capable of high-efficiency hydrocarbon generation. This may explain the relatively low hydrocarbon potential per unit of organic matter in dolomitic mixed lithofacies.

6.2.2. Analysis of the Differences in Hydrocarbon Generation Performance of Source Rocks with Different Biological Origins

To verify the differences in the hydrocarbon generation performance of different hydrocarbon-generating source materials, a source rock sample from the Fengcheng Formation with an Ro of only 0.69% was selected. This sample had a TOC of 1.53 wt. %, S1 of 1.36 mg/g, S2 of 7.69 mg/g, and hydrogen index (HI) of 501 mg/g (Table 2). Using the burial history and thermal evolution history of Well Maye 1 in the Mahu Sag as geological constraints, the lithostatic pressure and formation fluid pressure values were calculated for eight simulated temperature points at different stages of evolution. The sample was pressurized with water to simulate formation pressure, with the pressure was set at 34, 39, 44, 48, 52, 56, 58, and 61 MPa, corresponding to thermal simulation temperatures (T) of 300, 320, 330, 340, 350, 360, 370, and 380 °C, respectively. After reaching the set temperature points, the samples were held at a constant temperature for 72 h. The expelled oil was subsequently collected for biomarker analysis. The residue was collected to measure Ro, and the measured Ro was corrected [41]. Figure 14 shows that there is a good positive correlation between thermal simulation temperature and Easy Ro.
The thermal simulation results reveal that shale oil is already being generated at the lowest temperature (T = 300 °C, Ro = 0.75%) used in the experiment (Figure 15), while gaseous hydrocarbons are not produced. As the temperature increases and the thermal maturity (Ro) rises, two peaks of oil generation are reached in succession. The gaseous hydrocarbon production rate starts to increase after reaching the first peak of oil generation, but the production rate is relatively low. According to the biomarker characteristics of the expelled oil, before the first peak of hydrocarbon generation, the maximum peak of the total ion chromatogram (TIC) of the expelled oil is C23, and the β-carotenane index is generally greater than 0.5, which are typical biomarker characteristics of Dunaliella [39,42]. This indicates that Dunaliella has a low activation energy requirement and generates hydrocarbons at an early stage. The main 7–8+-monomethylheptadecane/n-alkane peak (abbreviated as 7–8+-MI) indicates typical characteristics of cyanobacteria as the source [43]. Throughout the entire hydrocarbon generation process, the 7–8+-MI index remains stable. Before reaching the second peak of hydrocarbon generation, the 7–8+-MI index begins to increase, accompanied by a lighter maximum peak in the TIC, indicating that cyanobacteria contribute to hydrocarbon generation throughout the entire process and that, at high maturity, hydrocarbon generation is mainly attributed to cyanobacteria. The results of the thermal simulation show that the hydrocarbon generation performance of cyanobacteria is better than that of Dunaliella. According to the development patterns of cyanobacteria and Dunaliella, from the distal delta front to the semi-deep and deep lacustrine, the abundance of cyanobacteria gradually decreases, while the abundance of Dunaliella increases. This leads to a higher hydrocarbon potential per unit of organic matter richness in terrigenous clastic lithofacies source rocks compared to dolomitic mixed lithofacies source rocks and alkaline mineral-bearing mixed lithofacies source rocks. Further, in the Hashan area, the Ro of the source rocks is mostly greater than 0.9%, indicating that they derive from Dunaliella and have already generated large amounts of hydrocarbons or that the stage of massive hydrocarbon generation has ended. This also results in a generally higher hydrocarbon potential per unit of organic matter richness in terrigenous clastic lithofacies source rocks compared to dolomitic mixed lithofacies source rocks (Figure 11).
The hydrocarbon generation simulation experiments and the identification of hydrocarbon-generating source materials show that the differences between the findings of previous studies of the hydrocarbon generation performance of the source rocks in the Fengcheng Formation may be related to differences in the hydrocarbon-generating source materials contained in the selected samples, as well as other effects of the experimental processes.

6.3. Maturity

Maturity does not directly affect the quality of source rocks, but it can influence the assessment of source rock quality. A comparison of the same lithofacies in the middle and western parts of the Hashan area reveals that, compared to the western area, the middle area (Well HS5) has lower organic matter richness and poorer organic matter type (Figure 4, Figure 5 and Figure 6), primarily due to differences in maturity between the two regions. A comparison of the hydrocarbon potential per unit of organic matter under different maturities in the same lithofacies (Figure 11) shows that, as Ro increases from 0.9% to 1.3%, the hydrocarbon potential per unit of the organic matter in both terrigenous clastic lithofacies and dolomitic mixed lithofacies decreases, resulting in a deterioration in the quality of source rocks. Hydrocarbon generation simulation (Figure 15) indicates that the western part of the Hashan area has just entered peak hydrocarbon generation, while the middle part is already at the end of the peak, resulting in lower measured organic carbon values and poorer organic matter type discrimination for the source rocks in the middle part of the Hashan area.
Therefore, when assessing organic matter richness and type, the impact of maturity needs to be fully considered. Long-term exploration has shown that, at low maturity, the density of produced oil is relatively high [44]. As maturity increases, the oil quality becomes lighter, and, because they experience extensive hydrocarbon generation stages at higher maturity, high-maturity areas may be more favorable for oil and gas exploration.

7. Conclusions

The shale of the Fengcheng Formation in the Hashan area can be classified into four lithofacies: terrigenous clastic lithofacies, dolomitic mixed lithofacies, alkaline mineral-bearing mixed lithofacies, and tephra-bearing mixed lithofacies. There are differences in the quality of source rocks between the different lithofacies. The tephra-bearing mixed source rocks have the best quality, with an average TOC generally exceeding 1.36 wt. % and an average hydrocarbon potential exceeding 6 mg/g. The organic matter is mostly type I and type II1. This is followed by terrigenous clastic lithofacies and dolomitic mixed lithofacies. The source rock quality of alkaline mineral-bearing mixed lithofacies is poor. The source rock quality varies significantly between different depositional environments in terrigenous clastic lithofacies.
The quality of the source rocks in the Fengcheng Formation in the Hashan area is mainly controlled by the sedimentary environment (including factors such as paleoenvironment, alkaline minerals, and volcanic activity), the hydrocarbon-generating source material, and maturity. The organic matter in the dolomitic mixed lithofacies and alkaline mineral-bearing mixed lithofacies is more concentrated in deep water, reducing environments with medium to high salinity and arid conditions. The main biological source material is green algae (Dunaliella). Organic matter in the terrigenous clastic lithofacies is more concentrated in relatively shallow water, in oxygen-depleted, low-salinity, and arid to semi-arid environments, with the main biological source being cyanobacteria. Moderate volcanic activity provided favorable conditions for organic matter accumulation. Maturity affects the assessment of source rock quality.
Green algae (Dunaliella) have the characteristics of early hydrocarbon generation and a high transformation ratio of hydrocarbon generation, allowing for rapid hydrocarbon generation at low maturity. Cyanobacteria have the characteristics of long hydrocarbon generation periods and a high hydrocarbon potential, with the peak of hydrocarbon generation occurring later than that of green algae (Dunaliella). Due to the differences in hydrocarbon-generating source materials among the different lithofacies, there are significant differences in the hydrocarbon generation characteristics of the source rocks.

Author Contributions

Z.S. (Zhongliang Sun): Data curation, Formal analysis, Investigation, Writing—original draft. Z.L.: Methodology and Writing—review & editing. K.Z.: Methodology and Resources. Z.S. (Zhenxiang Song) and H.Y.: Project administration. B.W.: Review and Editing. M.S. and T.C.: Resources. All authors have read and agreed to the published version of the manuscript.

Funding

This research received funding from the National Natural Science Foundation of China (Grant No. 42090020), national key laboratory project (KLP24017).

Data Availability Statement

The data for this study are available in this manuscript.

Conflicts of Interest

All authors were employed by the company SINOPEC. The authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

References

  1. Carroll, A.R.; Bohacs, K.M. Lake-type controls on petroleum source rock potential in nonmarine basins. Am. Assoc. Pet. Geol. 2001, 85, 1033–1053. [Google Scholar]
  2. Katz, B.J. Significance of ODP results on deepwater hydrocarbon exploration—Eastern equatorial Atlantic region. J. Afr. Earth Sci. 2006, 46, 331–345. [Google Scholar] [CrossRef]
  3. Warren, J.K. Evaporites: A Geological Compendium; Springer: Berlin/Heidelberg, Germany, 2016. [Google Scholar]
  4. Cao, J.; Lei, D.; Li, Y.; Tang, Y.; Chang, Q.; Abulimit, W.T. Ancient high-quality alkaline lacustrine source rocks discovered in the Lower Permian Fengcheng Formation, Junggar Basin. Acta Pet. Sin. 2015, 36, 781–790. [Google Scholar]
  5. Jin, Q.; Huang, X.H. Studies on origin of the early tertiary salt lake Dongpu Depression—A postulated deep water model. East China Pet. J. 1985, 9, 1–11. [Google Scholar]
  6. Jiang, J.G.; Guo, S.Y.; Fu, J.M. Discovery of immature high sulfur crude oil and its significance in gypsum salt bearing sedimentary basin. Exp. Pet. Geol. 1988, 10, 337–343. [Google Scholar]
  7. Horsfield, B.; Curry, D.; Bohacs, K.; Littke, R.; Rullkötter, J.; Schenk, H.; Radke, M.; Schaefer, R.; Carroll, A.; Isaksen, G.; et al. Organic geochemistry of freshwater and alkaline lacustrine sediments in the Green River Formation of the Washakie Basin, Wyoming, USA. Org. Geochem. 1994, 22, 415–440. [Google Scholar] [CrossRef]
  8. Ruble, T.E.; Lewan, M.D.; Philp, R.P. New insights on the Green River petroleum system in the Uinta basin from hydrous pyrolysis experiments. Am. Assoc. Pet. Geol. Bull. 2001, 85, 1333–1371. [Google Scholar] [CrossRef]
  9. Francavilla, M.; Kamaterou, P.; Intini, S.; Monteleone, M.; Zabaniotou, A. Cascading microalgae biorefinery: First pyrolysis of Dunaliellatertiolecta lipid extracted-residue. Algal Res. 2015, 11, 184–193. [Google Scholar] [CrossRef]
  10. Rüdiger, W. Chlorophyll metabolism: From outer space down to the molecular level. Phytochemistry 1997, 7, 1151–1167. [Google Scholar] [CrossRef]
  11. Peters, K.E.; Walters, C.C.; Moldowan, J.M. The Biomarker Guide: Biomarkers and Isotopes in the Environment and Human History; Cambridge University Press: Cambridge, UK, 2005; p. 1155. [Google Scholar]
  12. Yu, K.; Cao, Y.; Qiu, L.; Sun, P. Depositional environments in an arid, closed basin and their implications for oil and gas exploration: The lower Permian Fengcheng Formation in the Junggar Basin, China. Aapg Bull. 2019, 103, 2073–2115. [Google Scholar] [CrossRef]
  13. Zhang, K.; Sun, Z.; Zhang, G.; Song, Z.; Yu, H.; Zhou, J.; Cao, T.; Song, M.; Wang, B.; Li, Z. Shale lithofacies and shale oil enrichment model of Fengcheng Formation in Hashan area, Junggar Basin. Pet. Geol. Exp. 2023, 45, 593–605. [Google Scholar]
  14. Liu, H.M.; Wen, H.G.; Zhang, K.H.; Guo, P.; Zhang, G.L.; Yu, H.Z.; Xiong, W.; Zhou, J.; Xu, W.L.; Song, M.Y.; et al. Geological characteristics and exploration prospects of alkaline lake shale oil of Fengcheng Formation, Hashan area, NW Junggar Basin. J. Palaeogeogr. 2024, 26, 1017–1036. [Google Scholar]
  15. Hou, M.; Qu, J.; Zha, M.; Swennen, R.; Ding, X.; Imin, A.; Liu, H.; Bian, B. Significant contribution of haloalkaliphilic cyanobacteria to organic matter in an ancient alkaline lacustrine source rock: A case study from the Permian Fengcheng Formation, Junggar Basin, China. Mar. Pet. Geol. 2022, 138, 105546. [Google Scholar] [CrossRef]
  16. Meng, Y.; Wang, J.; Ma, W.Y.; Lei, H.Y.; Sun, P.C.; Fang, S.; Ding, C.; Wang, Z.; Tao, L.X. Evaluation of Hydrocarbon Source Rock Characteristics of Lower Permian Fengcheng Formation in Mahu Sag Based on Fine Grained Sedimentary Rock Type. J. Jilin Univ. 2022, 52, 1735–1746. [Google Scholar]
  17. Wang, X.J.; Wang, T.T.; Cao, J. Basic Characteristics and Highly Efficient Hydrocarbon Generation of Alkaline. LacustrineSource Rocks in Fengcheng Formation of Mahu Sag. Xinjiang Pet. Geol. 2018, 39, 9–15. [Google Scholar]
  18. Zhi, D.M.; Cao, J.; Xiang, B.L.; Qin, Z.; Wang, T.T. Fengcheng alkaline lacustrine source rocks of Lower Permian in Mahu Sag in Junggar Basin: Hydrocarbon generation mechanism and petroleum resources reestimation. Xinjiang Pet. Geol. 2016, 37, 499–506. [Google Scholar]
  19. Liu, D.G.; Zhou, L.; Li, S.H.; Ma, W.Y.; Guo, W.J. Characteristics of Source Rocks and Hydrocarbon Generation Modelsof Fengcheng Formation in Mahu Depression. Acta Sedimentol. 2020, 38, 946–955. [Google Scholar]
  20. Bai, Y.; Wang, F.; Niu, Z.; Jin, K.; Li, P.; Xu, D.; Chen, G. Hydrocarbon generation kinetics of source rocks of Permian FengchengFormation in Mahu Sag, Junggar Basin. Lithol. Reserv. 2022, 34, 116–127. [Google Scholar]
  21. Zhang, S.W. Identification and its petroleum geologic significance of the Fengcheng Formationsource rocks in Hala’alt area, the northern margin of Junggar Basin. Oil Gas Geol. 2013, 34, 145–152. [Google Scholar]
  22. Yu, H.Z.; Wang, Y.; Zhou, J.; Xue, Y. Sedimentary System of Permian Fengcheng Formation in Hashan Area in Northwestern Margin of Junggar Basin. Xin Jiang Pet. Geol. 2022, 43, 396–402. [Google Scholar]
  23. Zeng, Z.; Liu, Z.; Zhao, L.; Li, Y.; Wang, C.; Gao, P. Shale oil reservoir characteristics and controlling factors of Permian Fengcheng Formation in Hashan area, northwestern margin of Junggar Basin. Lithol. Reserv. 2023, 35, 25–35. [Google Scholar]
  24. GB/T 18602-2012; Rock Pyrolysis Analysis. General Administration of Quality Supervision, Inspection and Quarantine of the People’s Republic of China: Beijing, China, 2012.
  25. Zhang, Y.S.; Yang, Y.Q.; Qi, Z.X.; Qiao, Y.D.; Yuan, H.R. Sedimentary characteristics and environments of the salt-bearing of qianjiang formation of the paleogene in qianjiang sag of jianghan basin. J. Palaeogeogr. 2003, 5, 29–35. [Google Scholar]
  26. Tang, Y.; Zheng, M.L.; Wang, X.T.; Wang, T.; Xie, Z.; Qin, Z.; Hei, C.; Cheng, H.; Gao, Y.; Tao, H. Sedimentary paleoenvironment of source rocks of Fengcheng Formation in Mahu Sag, Junggar Basin. Nat. Gas Geosci. 2022, 33, 677–692. [Google Scholar]
  27. Awan, R.S.; Liu, C.; Gong, H.; Dun, C.; Tong, C.; Chamssidini, L.G. Paleo-sedimentary environment in relation to enrichment of organic matter of Early Cambrian black rocks of Niutitang Formation from Xiangxi area China. Mar. Pet. Geol. 2020, 112, 104057. [Google Scholar] [CrossRef]
  28. Cullers, R.L.; Podkovyrov, V.N. Geochemistry of the Mesoproterozoic Lakhanda shales in southeastern Yakutia, Russia: Implications for mineralogical and provenance control, and recycling. Precambrian Res. 2000, 104, 77–93. [Google Scholar] [CrossRef]
  29. Zheng, R.C.; Liu, M.Q. Study on paleo-salinity of Chang 6 oil-bearing formation in Ordos Basin. Oil Gas Geol. 1999, 20, 22–27. [Google Scholar]
  30. Chen, X.; Xu, Q.; Qin, Y.; Chen, R.; Wang, Y.; Shi, D.; Bai, J.; Yuan, K.; Cen, W.; Li, F.; et al. Effect of Paleoenvironmental Conditions on the Distribution of Lower Carboniferous Shale in Yaziluo Rift Trough, South China: Insights from Major/Trace Elements and Shale Composition. Minerals 2024, 14, 659. [Google Scholar] [CrossRef]
  31. Fu, J.; Li, S.; Xu, L.; Niu, X. Paleo-sedimentary environmental restoration and its significance of Chang 7 Member of Triassic Yanchang Formation in Ordos Basin, NW China. Pet. Explor. Dev. 2018, 45, 936–946. [Google Scholar] [CrossRef]
  32. Yandoka, B.M.S.; Abdullah, W.H.; Abubakar, M.; Hakimi, M.H.; Adegoke, A.K. Geochemical characterisation of Early Cretaceous lacustrine sediments of Bima Formation, Yola Sub-basin, Northern Benue Trough, NE Nigeria: Organic matter input, preservation, paleoenvironment and palaeoclimatic conditions. Mar. Pet. Geol. 2015, 61, 82–94. [Google Scholar] [CrossRef]
  33. Tissot, B.P.; Welte, D.H. Petroleum Formation and Occurrence; Springer: Berlin, Germany, 1984; Earth-Sci. Rev. [Google Scholar]
  34. Song, Z.Z.; Ge, B.F.; Wang, W.Z.; Tian, X.W. Quantitative Characterization of Ultra-Deep Paleo-Oil Reservoirs and Its Indication for Deep Gas Accumulation: A Case Study on the Dengying Formation, the North Slope of Central Sichuan Paleo-Uplift. Earth Sci. 2023, 48, 517–532. [Google Scholar]
  35. Wang, S.R.; Song, D.F.; He, D.F. The enrichment effect of organic materials by volcanic ash in sediments of theSantanghu Basin and the evolutionary pattern of tuffaceous source rocks. Acta Pet. Sin. 2013, 34, 1077–1087. [Google Scholar]
  36. Kamo, S.L.; Czamanske, G.K.; Amelin, Y.; A Fedorenko, V.; Davis, D.; Trofimov, V. Rapid eruption of Siberian flood-volcanic rocks and evidence for coincidence with the Permian–Triassic boundary and mass extinction at 251 Ma. Earth Planet. Sci. Lett. 2003, 214, 75–91. [Google Scholar] [CrossRef]
  37. Zhang, J.; Cao, J.; Xiang, B.; Zhou, N.; Ma, W.; He, D. Constraining multi-stage and protracted oil generation of alkaline lacustrine source rocks by heteroatomic compounds. Org. Geochem. 2023, 184, 104668. [Google Scholar] [CrossRef]
  38. Xia, L.; Cao, J.; Bian, L.; Hu, W.; Wang, T.; Zhi, D.; Tang, Y.; Li, E. Co-evolution of paleo-environment and bio-precursors in a Permian alkaline lake, Mahu mega-oil province, Junggar Basin: Implications for oil sources. Sci. China Earth Sci. 2022, 52, 732–746. [Google Scholar] [CrossRef]
  39. Xia, L.W.; Cao, J.; Lee, C.; Stüeken, E.E.; Zhi, D.; Love, G.D. A newconstraint on the antiquity of ancient haloalkaliphilic green algaethat flourished in a ca. 300 Ma Paleozoic lake. Geobiology 2021, 19, 147–161. [Google Scholar] [CrossRef]
  40. Zhi, D.; Tang, Y.; He, W.; Guo, X.; Zheng, M.; Huang, L. Orderly coexistence and accumulation models of conventional and unconventional hydrocarbons in Lower Permian Fengcheng Formation, Mahu sag, Junggar Basin. Pet. Explor. Dev. 2021, 48, 38–51. [Google Scholar] [CrossRef]
  41. Que, Y.Q.; Zheng, L.J.; Cheng, Q.Q.; Qin, J.Z.; Qiu, N.S. Vitrinite reflectance correction of residues in organic matter pyrolysis simulation experiments. Pet. Geol. Exp. 2015, 37, 506–517. [Google Scholar]
  42. Pehr, K.; Love, G.D.; Kuznetsov, A.; Podkovyrov, V.; Junium, C.K.; Shumlyanskyy, L.; Sokur, T.; Bekker, A. Ediacara biotaflourished in oligotrophic and bacterially dominated marineenvironments across Baltica. Nat. Commun. 2018, 9, 1807. [Google Scholar] [CrossRef]
  43. Ding, W.; Hou, D.; Jiang, L.; Jiang, Y.; Wu, P. High abundance ofcarotanes in the brackish-saline lacustrine sediments:Apossiblecyanobacteria source? Int. J. Coal Geol. 2020, 219, 103373. [Google Scholar] [CrossRef]
  44. Li, S.J.; Liu, X.; Wang, Y.Z.; Cai, H.X.; Cui, X.H. Heavy-oil Properties and Genesis in Hashan. Spec. Oil Gas Reserv. 2016, 23, 29–33. [Google Scholar]
Minerals 15 00606 g001
Figure 1. Regional location (A), stratigraphic column and sedimentary facies (B), and geological section passing through points A and A’ (C) of Hashan area, Junggar Basin.
Figure 1. Regional location (A), stratigraphic column and sedimentary facies (B), and geological section passing through points A and A’ (C) of Hashan area, Junggar Basin.
Minerals 15 00606 g001
Minerals 15 00606 g002
Figure 2. Distribution of sedimentary facies at each well location in Hashan area, Junggar Basin.
Figure 2. Distribution of sedimentary facies at each well location in Hashan area, Junggar Basin.
Minerals 15 00606 g002
Minerals 15 00606 g003
Figure 3. Lithofacies association characteristics and developmental horizon in Hashan area, Junggar Basin. (A1,A2) Argillaceous siltsone, HS5, 3926.42 m; (B1,B2) Silty mudstone, HS5, 3928.98 m; (C1,C2) Dolomitic mudstone, HS5, 4466.91 m; (D1,D2) Dolomitic siltstone, HS5, 4463.36 m; (E1,E2) Dolomitic mudstone containing alkaline mineral, HS5, 4638.77 m; (F1,F2) Tuffaceous mudstone, HS5, 5130.6 m.
Figure 3. Lithofacies association characteristics and developmental horizon in Hashan area, Junggar Basin. (A1,A2) Argillaceous siltsone, HS5, 3926.42 m; (B1,B2) Silty mudstone, HS5, 3928.98 m; (C1,C2) Dolomitic mudstone, HS5, 4466.91 m; (D1,D2) Dolomitic siltstone, HS5, 4463.36 m; (E1,E2) Dolomitic mudstone containing alkaline mineral, HS5, 4638.77 m; (F1,F2) Tuffaceous mudstone, HS5, 5130.6 m.
Minerals 15 00606 g003
Minerals 15 00606 g004
Figure 4. Mineral composition characteristics of different lithofacies in the Hashan area, Junggar Basin. ((A) Terrigenous clastic lithofacies; (B) dolomitic mixed lithofacies; (C) alkaline mineral-bearing mixed lithofacies; (D) tephra-bearing mixed lithofacies).
Figure 4. Mineral composition characteristics of different lithofacies in the Hashan area, Junggar Basin. ((A) Terrigenous clastic lithofacies; (B) dolomitic mixed lithofacies; (C) alkaline mineral-bearing mixed lithofacies; (D) tephra-bearing mixed lithofacies).
Minerals 15 00606 g004
Minerals 15 00606 g005
Figure 5. Organic matter richness of source rocks in the Fengcheng Formation, Hashan area, Junggar Basin.
Figure 5. Organic matter richness of source rocks in the Fengcheng Formation, Hashan area, Junggar Basin.
Minerals 15 00606 g005
Minerals 15 00606 g006
Figure 6. Hydrocarbon potential of source rocks in the Fengcheng Formation, Hashan area, Junggar Basin.
Figure 6. Hydrocarbon potential of source rocks in the Fengcheng Formation, Hashan area, Junggar Basin.
Minerals 15 00606 g006
Minerals 15 00606 g007
Figure 7. Organic matter type characteristics of the source rocks of the Fengcheng Formation in the Hashan area, Junggar Basin.
Figure 7. Organic matter type characteristics of the source rocks of the Fengcheng Formation in the Hashan area, Junggar Basin.
Minerals 15 00606 g007
Minerals 15 00606 g008
Figure 8. Maturity characteristics of shale in Fengcheng Formation, Hashan area, Junggar Basin.
Figure 8. Maturity characteristics of shale in Fengcheng Formation, Hashan area, Junggar Basin.
Minerals 15 00606 g008
Minerals 15 00606 g009
Figure 9. Paleoenvironmental characteristics of different lithofacies of the Fengcheng Formation in the Hashan area, Junggar Basin.
Figure 9. Paleoenvironmental characteristics of different lithofacies of the Fengcheng Formation in the Hashan area, Junggar Basin.
Minerals 15 00606 g009
Minerals 15 00606 g010
Figure 10. Influence of the special environment of the Fengcheng Formation on organic matter richness in the Hashan area, Junggar Basin. ((A) Effect of volcanism on organic matter enrichment. (B) Effect of alkaline minerals on organic matter enrichment).
Figure 10. Influence of the special environment of the Fengcheng Formation on organic matter richness in the Hashan area, Junggar Basin. ((A) Effect of volcanism on organic matter enrichment. (B) Effect of alkaline minerals on organic matter enrichment).
Minerals 15 00606 g010
Minerals 15 00606 g011
Figure 11. Maturity of organic matter and the hydrocarbon potential of source rocks in the Fengcheng Formation in the Hashan area, Junggar Basin.
Figure 11. Maturity of organic matter and the hydrocarbon potential of source rocks in the Fengcheng Formation in the Hashan area, Junggar Basin.
Minerals 15 00606 g011
Minerals 15 00606 g012
Figure 12. Hydrocarbon organisms in Fengcheng in Hasan area, Junggar Basin. (A) Higher plant fragments, Well HS5, 4186.4 m, terrigenous clastic lithofacies; (B) Higher plant fragments, Well HS5, 4642.8 m, alkaline mineral-bearing mixed lithofacies; (C) Telalginite and Lamalginite, Well HS5, 3929.28 m, terrigenous clastic lithofacies; (D) Amorphous, Well HS5, 4458.45 m, dolomitic mixed lithofacies; (E) Dunaliella, Well FN7, 4340 m, dolomitic mixed lithofacies [38]; (F) Dunaliella, Well HS5, 4455.95 m, dolomitic mixed lithofacies.
Figure 12. Hydrocarbon organisms in Fengcheng in Hasan area, Junggar Basin. (A) Higher plant fragments, Well HS5, 4186.4 m, terrigenous clastic lithofacies; (B) Higher plant fragments, Well HS5, 4642.8 m, alkaline mineral-bearing mixed lithofacies; (C) Telalginite and Lamalginite, Well HS5, 3929.28 m, terrigenous clastic lithofacies; (D) Amorphous, Well HS5, 4458.45 m, dolomitic mixed lithofacies; (E) Dunaliella, Well FN7, 4340 m, dolomitic mixed lithofacies [38]; (F) Dunaliella, Well HS5, 4455.95 m, dolomitic mixed lithofacies.
Minerals 15 00606 g012
Minerals 15 00606 g013
Figure 13. Bioenvironmental co-evolution model of Fengcheng Formation in Hashan area, Junggar Basin (modified from Xia, et al., 2022 [38]).
Figure 13. Bioenvironmental co-evolution model of Fengcheng Formation in Hashan area, Junggar Basin (modified from Xia, et al., 2022 [38]).
Minerals 15 00606 g013
Minerals 15 00606 g014
Figure 14. Correlation between thermal simulation temperature and Easy Ro.
Figure 14. Correlation between thermal simulation temperature and Easy Ro.
Minerals 15 00606 g014
Minerals 15 00606 g015
Figure 15. Simulation characteristics of hydrocarbon generation in low-maturity samples from Fengcheng Formation.
Figure 15. Simulation characteristics of hydrocarbon generation in low-maturity samples from Fengcheng Formation.
Minerals 15 00606 g015
Table 1. Organic petrological characteristics of shale with different lithofacies in Hashan area, Junggar Basin.
Table 1. Organic petrological characteristics of shale with different lithofacies in Hashan area, Junggar Basin.
Sedimentary
Facies 		Lithofacies LithologyDepth
(m)		Sapropelite (%)Vitrinite
(%)		Inertinite
(%)		Exinite
(%)		Solid Asphalt
(%)
Distal delta frontTerrigenous clastic
lithofacies		Argillaceous siltstone3924.9018.46.1 75.5
Silty mudstone3927.31081.410.7 7.9
Mudstone3929.2847.628.710.86.7
Mudstone3930.2446.328.314.13.87.5
Shore-shallow lacustrineDolomitic-mixed lithofaciesDolomitic mudstone4455.95561.130.28.7
Dolomitic mudstone4470.15074.517.607.9
Shore-shallow lacustrineTephra-bearing mixed lithofaciesTuffaceous mudstone5130.75067.5205.6
Tuffaceous dolomitic mudstone5131.69061.724.43.510.4
Semi-deep
lacustrine		Alkaline mineral-bearing mixed lithofaciesDolomitic mudstone containing alkaline mineral4642.8066.316.9016.8
Dolomitic mudstone containing alkaline mineral4645048.527.3024.2
Table 2. Organic geochemical information of hydrocarbon generation simulation experiment samples.
Table 2. Organic geochemical information of hydrocarbon generation simulation experiment samples.
WellsDepth(m)FormationLithologyTOC
(%)		S1
(mg/g)		S2
(mg/g)		HI
(mg/g)		Ro
(%)
F53221.45P1fBlack mudstone1.531.367.695010.69
Disclaimer/Publisher’s Note: The statements, opinions and data contained in all publications are solely those of the individual author(s) and contributor(s) and not of MDPI and/or the editor(s). MDPI and/or the editor(s) disclaim responsibility for any injury to people or property resulting from any ideas, methods, instructions or products referred to in the content.

Share and Cite

MDPI and ACS Style

Sun, Z.; Li, Z.; Zhang, K.; Song, Z.; Yu, H.; Wang, B.; Song, M.; Cao, T. Classification Evaluation and Genetic Analysis of Source Rocks of Lower Permian Fengcheng Formation in Hashan Area, Junggar Basin, China. Minerals 2025, 15, 606. https://doi.org/10.3390/min15060606

AMA Style

Sun Z, Li Z, Zhang K, Song Z, Yu H, Wang B, Song M, Cao T. Classification Evaluation and Genetic Analysis of Source Rocks of Lower Permian Fengcheng Formation in Hashan Area, Junggar Basin, China. Minerals. 2025; 15(6):606. https://doi.org/10.3390/min15060606

Chicago/Turabian Style

Sun, Zhongliang, Zhiming Li, Kuihua Zhang, Zhenxiang Song, Hongzhou Yu, Bin Wang, Meiyuan Song, and Tingting Cao. 2025. "Classification Evaluation and Genetic Analysis of Source Rocks of Lower Permian Fengcheng Formation in Hashan Area, Junggar Basin, China" Minerals 15, no. 6: 606. https://doi.org/10.3390/min15060606

APA Style

Sun, Z., Li, Z., Zhang, K., Song, Z., Yu, H., Wang, B., Song, M., & Cao, T. (2025). Classification Evaluation and Genetic Analysis of Source Rocks of Lower Permian Fengcheng Formation in Hashan Area, Junggar Basin, China. Minerals, 15(6), 606. https://doi.org/10.3390/min15060606

Note that from the first issue of 2016, this journal uses article numbers instead of page numbers. See further details here.

Article Metrics

Back to TopTop