Distribution, Origin, and Impact on Diagenesis of Organic Acids in Representative Continental Shale Oil

Abstract

This investigation focuses on the prevalent continental oil shale within the Triassic Chang 7, a member of the Yanchang Formation in the Ordos Basin and the Permian Lucaogou Formation in the Junggar Basin of western China, and delves into the impacts of hydrocarbon generation and the derived organic acids on the physical attributes of oil shale reservoirs. Water-soluble organic acids (WSOAs) were extracted via Soxhlet extraction and analyzed by a 940 ion chromatograph (Metrohm AG), supplemented with core observations, thin-section analyses, pyrolysis, and trace element assays, as well as the qualitative observation of pore structures via FIB-SEM scanning electron microscopy. The study discloses substantial disparities in the types and abundances of organic acids within the oil shale strata of the two regions, with mono-acids being conspicuously more prevalent than dicarboxylic acids. The spatial distribution of organic acids within the oil shale strata in the two regions is non-uniform, and their generation is inextricably correlated with the type of organic matter, thermal maturity, and depth at which they are buried. During diverse stages of diagenesis, the hydrocarbons and organic acids produced from the pyrolysis of organic matter not only exert an impact on the properties of pore fluids but also interact with diagenetic processes such as compaction, dissolution, and metasomatism to enhance the reservoir quality of oil shale. The synergy between chemical interactions and physical alterations collectively governs the migration and distribution patterns of organic acids as well as the characteristics of oil shale reservoirs. Furthermore, the sources of organic acids within the oil shale series in the two regions demonstrate pronounced dissimilarities, which are intimately associated with the peculiarities of their sedimentary milieu. The oil shale of the Yanchang Formation was formed in a warm and humid freshwater lacustrine basin environment, while the oil shale of the Lucaogou Formation was deposited in a brackish to saline lacustrine setting under an arid to semi-arid climatic regime. These variances not only illuminate the intricacy and multiplicity of the sedimentary attributes of oil shale but also accentuate the impact of the sedimentary environment on the genesis and distribution of organic acids, especially the transformation and optimization of reservoir dissolution by organic acids generated during hydrocarbon generation—a factor of paramount significance for the precise identification and effective development of the “sweet spot” area of shale oil. These areas, characterized by an abundance of organic matter, their maturity, and superior reservoir properties, are the foci of the efficient exploration and development of continental shale oil.

1. Introduction

In China’s energy landscape, the exploration and exploitation of unconventional oil and gas resources has emerged as a prominent area of scholarly inquiry. Among these resources, oil shale stands out as a crucial unconventional source with increasingly recognized value. While North America predominantly extracts shale gas from Paleozoic or Mesozoic Marine organic-rich shale formations such as Eagle Ford shale [1] and Bakken shale [2], China also contains widely distributed continental organic-rich oil shale formations with substantial exploration potential. Across western to eastern China, several continental oil shale formations have been identified, including the Permian Lucaogou Formation [3] in Malang Sag, the Santanghu Basin, the Permian Lucaogou Formation in Junggar Basin [4,5], Triassic Chang 7 [6,7,8] member of the Yanchang Formation in the Ordos Basin, the Cretaceous Qingshankou Formation [9,10] in the Songliao Basin, and the gray oil shale interlayers [11,12] and the gypsum-rich oil shale [13,14] of the Paleogene Shahejie Formation in the Bohai Bay Basin. These discoveries have yielded initial success and remarkable achievements in the exploration of shale oil and gas resources. The identification and exploration of these continental oil shale series not only reveal the vast potential of our country’s shale oil and gas resources but also attract extensive attention as a subject for further research by domestic and international scholars, as well as within the petroleum industry.

As the exploration and development of oil shale reservoirs and related theoretical studies continue to deepen, more and more scholars are paying attention to the dissolution of unstable minerals such as feldspar, calcite, clasts, and dolomite to form dissolution pores [15,16], and it has also been confirmed that these minerals undergo dissolution under specific geological conditions to form unique dissolution pore structures [17,18]. Furthermore, dissolution pores are one of the most important reservoir spaces in the oil shale reservoir system [19]. During the maturation and hydrocarbon generation process of organic-rich oil shale, organic matter undergoes a series of intricate chemical reactions to produce organic acids and CO₂ [20]. Organic acids exhibit a strong ability to dissolve carbonate minerals and other soluble minerals in oil shale, thereby facilitating the formation and evolution of solvent pores. Secondary dissolution pores are extensively distributed from the main body of oil shale to dense tuff and sandstone, with thin interlayers of transitional shale between them; this significantly contributes to the enhancement in the overall reservoir physical properties of shale formations. The formation and release of organic acids during diagenesis not only influence the properties of pore fluids but also enhance the reservoir capacity of oil shale through dissolution processes. These chemical and physical transformations significantly impact the migration and distribution of organic acids, as well as the reservoir characteristics of oil shale. Nevertheless, our current understanding regarding the specific properties, origin, and distribution mechanisms of organic acids in shale formations remains relatively ambiguous—undoubtedly impeding a comprehensive grasp on the formation mechanisms and distribution laws governing the reservoir space within oil shale formations—and consequently constrains further advancements in exploration and development efforts for shale oil and gas resources. Therefore, it is imperative to conduct urgent investigations into the types and abundance levels of the organic acids present in China’s continental oil shales, their mineral dissolution degrees, and their developmental characteristics pertaining to secondary dissolution pores, as well as the reaction mechanisms and distribution laws governing organic acids.

The mineral composition, sedimentary environment, organic matter maturity, and diagenesis of organic acids exhibit a heightened intricacy in the deposition of continental organic-rich shale formations currently undergoing preliminary exploration in China. Consequently, this study focuses on two exemplary continental organic-rich shale formations in western China: the Chang 7 member of the Yanchang Formation in the Ordos Basin (mainly intercalated shale formations) and the Permian Lucaogou Formation (mainly black shale formations) in the Junggar Basin. This research primarily delves into organic–inorganic interactions during diagenetic processes based on conventional diagenetic studies. Specifically, it scrutinizes the influence of organic acid fluids on the thermal evolution of organic matter and aims to provide a geological foundation for the exploration of oil and gas in continental oil shale formations in China by exploring the development, characteristics, and genetic mechanisms of reservoir spaces undergoing a dissolution transformation.

Geological Overview of Sample Study Area

The Ordos Basin represents a pivotal shale oil exploration area in China, being strategically positioned at the confluence of multiple tectonic units and having undergone intricate orogenic processes. It encompasses six primary tectonic units: the western margin thrust belt, the Tianhuan depression, the Yishan Slope, the West Jinxi Flexural fold belt, the Yimeng Uplift, and the Weibei Uplift. During the Mesozoic era, extensive inland depression led to the formation of oil-bearing strata predominantly characterized by the Yanchang Formation of the Upper Triassic Series [21,22,23]. This formation primarily comprises continental clastic rock series deposited in deltaic and lacustrine environments with a thickness ranging from 1000 to 1300 m [24,25]. The target sample is situated in Yijun County on the lower margin of the Yishan slope, spreading southwest–northeast in the southern margin of Ordos Basin within the Chang 7 member [26]. The lithology mainly consists of mud shale with sandy laminae, with tuffaceous laminae interbedded with organic-rich mud shale in sweet sections. Furthermore, the Chang 7 oil shale can be further divided into three subseries members—Chang 7-1, Chang 7-2, and Chang 7-3—which are lacustrine oil shales [27]. The Junggar Basin, situated in western China, is a significant, large, oil-bearing basin. The Fukang Sag is located at the northern foothills of Bogda Mountain on the southeast margin of the Junggar Basin and represents a secondary sag within this region [28]. It serves as an important hydrocarbon-generating sag and acts as the sole conduit for oil and gas migration. Geological profiles and drilling data indicate that the Fukang Sag encompasses Carboniferous, Permian, Triassic, Jurassic, Cretaceous, Paleogene, Neogene, and Quaternary strata from the bottom to the top [29]. Among these strata, Permian, Triassic, and Jurassic formations are the most widely distributed, with oil shale predominantly found in the Permian Lucaogou Formation [30]. The uplift of the Permian Lucaogou oil shale occurred concurrently with the Bogda Mountains’ uplift due to extensive thrust faults, resulting in its establishment as a substantial distribution belt for Permian oil shale ore at the northern foothills of the Bogda Mountains [31]. Based on its sequence stratigraphic characteristics, regional structural features, and sedimentary environment considerations, the Lucaogou Formation can be divided into two lithologic segments: grayish-black mudstone with thin layers of carbonaceous siltstone is the primary material in the first segment, while interbedded light gray siltstone and gray black mudstone characterize the second member, where the thickness of downward mudstone tends to increase.

The abundant terrestrial oil shale mineral resources in the western region of China display distinctive complexity in their sedimentary characteristics, their diagenetic environment, and the maturity of their organic matter. Hence, this paper specifically selects the Chang 7 member of the Yanchang Formation in the Ordos Basin (marked by interbedded mud shale) and the Lucaogou Formation of the Permian System in the Junggar Basin (characterized by black mud shale), two typical terrestrial oil shale strata, as the research focus, conducting an in-depth analysis of the dissolution effect of the interaction between organic acids and minerals in oil shale on the reservoir space during the diagenesis process. Compared with type I and type II organic matter in shale, type III organic matter has a higher content of organic acids, and the distribution of WSOA among different organic matters is significantly different. Soxhlet extraction was carried out on two typical terrestrial oil shales with different diagenetic periods and thermal maturities in China, and seven different organic acid components were determined, including four monocarboxylic acids and three dicarboxylic acids. Furthermore, this investigation delves into the distribution of WSOA within oil shale, the variances in WSOA among diverse organic matter types, and the solubilization of organic acids in the pore spaces of shale. Ultimately, it explores the underlying mechanisms governing the release of organic acids during the thermal evolution of organic matter in oil shale. This work can enhance the fundamental theory of organic chemistry, offer crucial geological evidence for the exploration of terrestrial shale oil in China, and facilitate the precise exploration and efficient development of unconventional oil and gas resources.

2. Materials and Methods

2.1. Analysis Methods of Oil Shale

To facilitate a comparative analysis of the organic acid characteristics of the Chang 7 reservoir in the Yijun area and the Lucaogou Formation reservoir in the Fukang Sag, this study collected oil shale core samples from two basins: Ordos and Junggar. The sampling locations are illustrated in Figure 1. Sample collection adhered to standardized geological procedures to ensure both representativeness and comparability. Following collection, samples were crushed, screened, and ground to achieve an appropriate particle size for subsequent analysis. Core observations, thin section analyses, pyrolysis experiments, and trace element determinations were conducted using these samples. Microscopic examinations utilized a ZEISS optical microscope while scanning electron microscopy (FIB-SEM) was employed for a qualitative assessment of pore structures within the shale reservoirs and the classification of pore types. The ROCKEVAL-VI standard pyrolyzer facilitated pyrolysis experiments conducted according to the national standards outlined in “Rock Pyrolysis Analysis: GB/T 18602-2012” [32]. Trace elements were analyzed according to the national guidelines specified in “Methods for Chemical Analysis of Silicate Rocks Part 30: Determination of 44 Elements: GB/T 14506.30-2010” [33].

2.2. Extraction of Organic Acids

In this investigation, the Soxhlet extraction method was employed to extract organic acids from core samples. This widely used method effectively separates organic acids from the core samples. Prior to grinding, the weathered layer on the surface was first removed. Fresh oil shale samples were powdered and sieved, and powder samples with a size less than 200 mesh were freeze-dried for 48 h to remove moisture using a Scientz-10 N freeze-dryer. The specific procedure is as follows: (a) 10 g of a mechanically broken core sample was placed into a filter paper bag to ensure even distribution without large pieces remaining; (b) the filter paper bag was then inserted into the extraction chamber of the Soxhlet extractor, which was connected to the condensing tube and collection bottle; (c) 250 mL of deionized water was added to the collection bottle; (d) the deionized water was heated until it evaporated and rose into the condensing tube, before it condensed and dripped into the extraction chamber; (e) once the liquid level in the extraction chamber reached a certain height, solvent drops were collected in the collection bottle; (f) these steps were repeated for a total of 72 h to ensure the complete extraction of all organic acids; (g) after extraction, the resulting liquid product underwent testing using a 0.45 µm needle filter membrane.

2.3. Analysis Methods for Organic Acids

Organic acids, including monocarboxylic acids such as formate, acetate, propionate, and butyrate, and dicarboxylic acids, such as oxalate, malonate, and succinate, were measured using 940 ion chromatography (produced by Metrohm AG, Herisau, Switzerland). The detection limit was 0.001 mg/L. This equipment comprised an intelligent conductivity detector with a detection range of 0–15,000 µs/cm and an MSMII chemical suppressor coupled with a CO₂ suppressor. The components of the oil shale extracts were measured quantitatively based on the established calibration curves, and the correlation coefficients were greater than 0.995 for each organic acid. As shown in

Table 1. Chromatographic conditions for determining organic acids.

Conditions	Case I	Case II
Chromatographic column	Metrosep A Supp 17–250/4.0	Metrosep Organic Acids-250/7.8
Eluent	A: 6 mM NaOH, B: 5 mM Na2CO3 + 0.2 mM NaHCO3	2 mM H2SO4 + 100 mM LiCl
Flowrate	0.6 mL/min	0.5 mL/min
Columntemperature	45 °C	30 °C
WSOA types	Oxalate	Formate, acetate, propionate, butyrate, malonate, succinate

, seven organic acids were detected using two chromatographic conditions. For case I, eluent A was used for eluting oil shale extracts and was held for 18 min. After 18 min, eluent A was terminated and eluent B was used. At 48 min, eluent A was again used for 22 min.

3. Results and Discussion

3.1. Organic Acid Distribution Characteristics in the Yanchang Formation Chang 7 Member of the Yijun Area, Ordos Basin, and the Lucaogou Formation of the Fukang Sag, Junggar Basin

In the spatial distribution analysis, the abundance of organic acids within the oil shale system of the Chang 7 member of the Yanchang Formation in the Yijun area and the shale layer of the Lucaogou Formation in the Fukang Sag exhibits notable inhomogeneity. The types of organic acids present in these two regions, as illustrated in Figure 2, are comparable, predominantly including formate, acetate, propionate, butyrate, oxalate, malonate, and succinate, which pertain to water-soluble organic acids. From the perspective of diversity regarding organic acid types, it is observed that this diversity increases with thermal maturity; specifically, four distinct organic acids characterize Chang 7 oil shale, while five types are identified within the Lucaogou Formation. The content of monocarboxylic acids in the Chang 7 oil shale is notably high—ranging from 69% to 97%, with an average value of around 80%. Conversely, dibasic acids exhibit lower concentrations—accounting for between 11% and 67%, averaging at approximately 20%. In terms of the monophyletic carboxylic acids found within Chang 7 member oil shale, these predominately consist of formate, acetate and propionate, whereas dyadic carboxylic acids primarily include succinate—with malonate being absent—and propionate constitutes about 51% of the total organic acidity. In contrast to this is the pattern observed in the Lucaogou Formation, where monocarboxylic acids mainly comprise formate and acetate alongside propionate (which accounts for roughly 58%); the dicarboxylic counterparts are chiefly represented by oxalate and succinate. In conclusion, both of the studied oil shale systems predominantly feature mono-acids, with propionate being the most prevalent, followed by formate and acetate; additionally, succinate emerges as a significant diprotic component.

In investigating the impact of thermal maturity on the distribution of organic acids in oil shale, it has been observed that as thermal maturity increases, the total concentration of organic acids in the Chang 7 member shale exhibits a pattern characterized by an initial sharp rise followed by a rapid decline. Conversely, the total concentration of organic acids in the Lucaogou Formation demonstrates a trend of gradual increase. Although the content of organic acids in the Lucaogou Formation surpasses that found in the Chang 7 member, this concentration advantage diminishes when normalized against total organic carbon (TOC). The average concentration of organic acids within the Chang 7 member shale is recorded at 1.91 mg/g TOC, while that for the Lucaogou Formation oil shale stands at 3.37 mg/g TOC, indicating relatively low production levels of organic acids within the Chang 7 member oil shale. Regardless of the variations in thermal maturity shown in Figure 3, monocarboxylic acid concentrations remain overwhelmingly dominant and are significantly greater than dicarboxylic acid concentrations. According to the literature [34], acetate predominates in oilfield water across various basins once local layer temperatures exceed 80 °C. Furthermore, Li’s [35] and Zhu’s [36] study deliberated upon the compositional changes in different organic acids during the thermal evolution process and particularly highlighted shifts in formate/acetate ratios. The results indicate that with increasing thermal maturity, there is a marked increase in single carboxylic acid proportions—most notably, formic acid proportionally rises as well. Additionally, black shales from both the Bakken Formation (USA) and the Duvernay Formation (Canada) exhibit formate/acetate ratios below one, which decrease with rising thermal maturity; this suggests a significant increase in acetate ratio concurrent with enhanced thermal maturation. In Figure 4a, the formate/acetate ratio of Chang 7 oil shale exceeds 1, indicating that the formate proportion increases with thermal maturity. Conversely, the ratio for Lucaogou Formation is below 1, suggesting a significant increase in acetate proportion as thermal maturity rises. In Figure 4b, the proportion of propionate within monocarboxylic acids is 55%, underscoring its significance as a crucial component. The comparative ratios of propionate/monocarboxylic acid and formate/acetate in the oil shale from the two basins exhibit notable differences, suggesting that the composition of organic acids may be influenced by the nature of the organic matter. The Chang 7 formation is situated at a shallow depth of approximately 2000 m, placing it in an early diagenetic stage. The reservoir’s pore system remains open, and infiltration from atmospheric freshwater enhances the thermal evolution of organic matter. Under conditions characterized by shallow buried depths, bacterial and microbial activity is pronounced, leading to the rapid oxidation and consumption of generated organic acids; consequently, this results in relatively low production levels for these acids. Conversely, the Lucaogou Formation resides at ultra-deep depths exceeding 5000 m, where the increased temperature and pressure facilitate kerogen’s transition into the oil generation window, thereby accelerating hydrocarbon generation processes. This substantial generation of oil and gas coincides with the elevated production levels of organic acids and CO₂; thus, their concentrations are markedly higher than those observed in the Chang 7 member. Therefore, burial depth emerges as a critical factor influencing the distribution patterns of organic acids within oil shale formations; deeper conditions are more favorable for both their formation and preservation.

3.2. Origin Analysis of Organic Acid in the Yanchang Formation Chang 7 Member of the Ordos Basin, and the Lucaogou Formation of the Fukang Sag, Junggar Basin

In this study, the characteristics, trace elements, and water environment of oil shale in the Yijun area of Ordos Basin were analyzed from an organic geochemistry perspective. The impact of paleoenvironmental evolution on organic acids was investigated to elucidate their source and analyze the geological environment in terms of oil shale development, a crucial factor in organic acid formation. It was observed that high-quality oil shale is significantly influenced by a favorable sedimentary environment [37,38]. Both domestic and international scholars have investigated the process of acid generation through the pyrolysis of various types of organic matter, revealing that organic matter with a high oxygen content produces a greater concentration of organic acids. Upon reaching the mature stage, as thermal maturity increases alongside organic acid production [35], significant variations in the concentration of organic acids generated by different types of organic matter are observed. This study demonstrates that the concentration of organic acids in type III organic matter is substantially higher than that found in type II and type I organic matter (

Table 2. Basic geological parameters of the studied samples.

Well No.	Formation	Buried Depth/m	Formate (mg/L)	Acetate (mg/L)	Propionate (mg/L)	Butyrate (mg/L)	Oxalate (mg/L)	Malona te(mg/L)	Succinate (mg/L)	WSOAs (mg/L)	TOC/%	Permeability (mD)	Tmax (°C)	Types
M20-1	Chang73	2154.7	2.06	1.46	2.27	0.00	0.00	0.00	2.15	7.94	5.25	0.0001	448.00	I
M20-2	Chang73	2160.82	1.89	1.56	5.09	0.00	0.00	0.00	0.91	9.45	15.83	0.0012	444.00	I
M20-3	Chang73	2161.9	1.05	1.05	6.95	0.00	0.00	0.00	0.32	9.37	9.36	0.0011	442.00	I
M20-4	Chang73	2165	1.28	1.84	2.84	0.00	0.65	0.00	0.25	6.85	4.17	0.001	451.00	I
M20-5	Chang73	2170.3	1.58	1.12	2.28	0.00	0.00	0.00	2.28	7.25	2.16	0.001	451.00	II2
M20-6	Chang73	2176.32	1.53	1.37	2.19	0.00	0.00	0.00	1.54	6.62	2.89	0.013	450.00	II2
M20-7	Chang73	2177.6	1.02	1.22	2.22	0.92	0.00	0.00	0.86	6.25	3.93	0.001	456.00	II1
M20-8	Chang73	2179.6	1.56	1.46	2.45	0.69	0.00	0.00	1.09	7.24	3.21	0.001	446.00	II1
Fu50	P2l	5336.8	0.86	1.54	0.00	0.00	3.39	0.00	1.47	7.25	6.06	0.018	448.00	II1
Fu49-1	P2l	5624.6	1.11	1.13	5.18	0.00	0.84	0.00	0.70	8.96	3.05	0.011	462.00	II1
Fu49-2	P2l	5625.9	1.25	1.37	6.90	0.00	0.75	0.00	0.91	11.17	3.46	0.09	460.00	II1
KT5	P2l	5829	1.18	2.45	7.64	0.00	0.79	0.16	2.56	14.79	2.72	0.021	452.00	II2
KT3	P2l	6185.2	12.33	3.22	4.28	0.00	2.54	0.00	2.90	25.27	3.05	0.001	486.00	III

). Zeng JianHui [39] suggests that the thermal maturation of kerogen primarily leads to the production of organic acids; however, their yield depends on kerogen type and maturity level. Humic-type and sapropelic-type kerogens with high O/C ratios serve as good parent materials for the production of organic acids. Conversely, sapropelic kerogens with low O/C ratios result in lower yields. A comparison between the Chang 7 member and the Lucaogou Formation reveals significantly larger amounts of organics are produced by humic-type (III) organic matter in the Lucaogou Formation than those generated by type II or type I organics in the Chang 7 member’s oil shale composition. Notably, only type I organics exist within the Chang 7 member’s composition. The relatively higher concentration may be attributed to late-stage geological processes such as atmospheric leaching, fluid migration, and microbial activities.

Based on the results of the pyrolysis analysis and the intersection plot of hydrogen index (HI), it is evident that the majority of core samples from the Chang 7 oil shale in the Yanchang Formation, Ordos, fall within the type I and type II₁ ranges (Figure 5). Additionally, most core samples from the Lucaogou Formation in the Fukang Sag are situated within the type II₂ and type III ranges. Zhao Yande et al. [40] investigated the correlation between the carbon isotopes of kerogen (δ¹³C kerogen) and their organic parent material, demonstrating that δ¹³C kerogen < −29‰ indicates type I kerogen, while δ¹³C kerogen > −26‰ indicates type III kerogen, with median values representing type II kerogen [41]. The δ¹³C values for the Chang 7 member of the Yanchang Formation range from −29.8‰ to −27.3‰ (

Table 3. Trace elements and δ¹³C data in the Chang 7 member of the Ordos Basin and the Lucaogou Formation in the Fukang Sag in the Junggar Basin.

Well No.	Buried Depth/m	Mn/Sr	Ba	δCe	V/(V + Ni)	V/Cr	Sr/Cu	Sr/Ba	δ13C
N55-10	2154.7	5.1	239.25	0.89	0.73	6.2	3.7	0.25	−28.3
N55-11	2161.9	4.9	101.87	0.94	0.74	5.4	4.6	0.24	−29.8
N55-12	2176.62	8.1	136.51	0.93	0.82	6.5	6.8	0.34	−29.6
N55-13	2177.3	5.8	95.95	0.92	0.83	6.7	1.4	0.23	−28.7
N55-14	2179.6	2.6	89.2	0.9	0.72	4.8	3.0	0.19	−27.6
Fu50	4336.8	1.55	119.0	0.88	0.82	2.63	18.1	4.07	−34.76
Fu49-1	5624.6	3.14	160.7	0.93	0.59	2.37	10.16	1.43	−34.58
Fu49-2	5625.9	1.91	234.1	0.89	0.67	2.89	6.3	1.36	−33.04
KT5-4	5829	1.9	234.1	0.85	0.7	2.9	6.8	1.4	34.98
KT3	6185.2	3.70	511.5	0.9	0.81	2.58	9.1	0.84	−38.14

), with an average value of −28.8‰. The predominant organic matter types are primarily categorized as types I and II₁. Liu Wenhui et al. [42] extensively discussed the relationship between δ¹³C values and hydrocarbon-forming organisms, suggesting that organic matter with δ¹³C > −30‰ was predominantly formed by planktic algae, while those with δ¹³C < −34‰ were derived from benthic algae sources. Most shale core samples from the Chang 7 member in this study fall within the planktonian algal region, indicating that the parent material for Chang 7 oil shale mainly originated from planktonic and benthic algae.

The ancient redox environment is pivotal in the genesis of oil shale and is a determining factor in organic matter preservation. Anoxic conditions are conducive to organic matter preservation [43]. Within anoxic environments, trace elements such as Mo, U, and V that are sensitive to redox conditions are commonly enriched in sediments. Therefore, the V/(V+Ni) ratio serves as a significant indicator for identifying the redox conditions of sedimentary water bodies. A V/(V+Ni) ratio of less than 0.45 indicates an oxygen-rich environment; a ratio between 0.45 and 0.60 suggests poor oxygen levels; a ratio greater than 0.60 signifies an anoxic environment [44,45]. The V/(V+Ni) ratio of core samples from the Chang 7 member ranges from 0.72 to 0.83, with an average of 0.77, indicating a weakly stratified anaerobic reducing environment in the ancient water body, whereas core samples from the Lucaogou Formation exhibit a range of 0.59 to 0.82 with an average of 0.72, indicating a weakly stratified anaerobic reducing environment. Furthermore, the anomaly of the rare earth element Ce can serve as a crucial indicator for discerning oxidation-reduction conditions. Studies have revealed that when Ce elements exhibit a negative anomaly (δCe < 1), this signifies an oxygen-deficient environment, whereas a positive anomaly (δCe > 1) indicates an oxygen-rich environment [46]. The δCe values for the Chang 7 core samples range from 0.89 to 0.95, with an average of 0.91, while those for the Lucaogou Formation core samples range from 0.85 to 0.93, with an average of 0.89. These data collectively suggest that both sets of samples indicate deposition under oxygen-deficient reducing conditions. Previous researchers commonly utilized indicators such as V/Cr to investigate ancient oxidation-reduction environments: V/Cr < 2.00 suggests an oxidizing environment, while 2.00 < V/Cr < 4.25 indicates a weakly oxidizing–weakly reducing environment, and V/Cr > 4.25 denotes a poorly oxygenated reducing environment [47]. In Figure 6, the V/Cr ratio for the Chang 7 member ranges from 0.89 to 0.95, exceeding 4.25, indicating anaerobic reducing conditions; meanwhile, the Lucaogou Formation samples display ratios between 2.37 and 2.9, suggesting that this sedimentary period was characterized by weakly oxidizing–weakly reducing conditions.

The productivity of lake basins was influenced by the paleoclimate as well as by terrigenous material supply and redox conditions within water bodies, consequently impacting the sediment mineral composition, elemental distribution, and content. Variations in sediment elemental enrichment characteristics were observed under different climatic conditions, which effectively reflect the paleoclimates during deposition periods through trace element ratios. The Sr/Cu ratio exhibits a strong correlation with the paleoclimate: values between 1 and 10 indicate warm and humid climates while those exceeding 10 suggest dry and hot climates [48]. As shown in Figure 6, samples from the Chang 7 member displayed maximum Sr/Cu values at 6.8 and minimum values at 1.4, with all values predominantly falling below 10. The sedimentary period of the Chang 7 member in the study area was characterized by warm and humid paleoclimatic conditions, creating an ideal growth environment for hydrocarbon source materials. However, the Lucaogou Formation exhibited Sr/Cu values ranging from 6.3 to 18.1, with an average value of 10.1, indicating an arid to semi-arid climate during its formation.

Ancient salinity serves as a crucial discriminant index for reconstructing paleoenvironments, with its levels effectively reflecting the environmental characteristics of ancient water bodies. The Sr/Ba ratio stands as the most widely utilized indicator for characterizing water salinity. A Sr/Ba value below 0.5 signifies a freshwater sedimentary environment, while a value between 0.5 and 1.0 indicates a semi-saline sedimentary environment; values exceeding 1 indicate a marine saline sedimentary environment [49]. In Figure 6, the Sr/Ba values for the samples in this study range from 0.14 to 0.45, averaging at 0.3; all ratios fall below 0.5, indicating that the Chang 7 member within the study area is situated in a freshwater sedimentary environment. Conversely, within core samples of the Lucaogou Formation, only one sample exhibits an Sr/Ba value of 0.84, whereas others range between 1.36 and 4.07—all surpassing the threshold of 0.5—indicating that the Lucaogou Formation resides in a semi-saline to saline environment.

The oil shale in the study area of the Triassic Yanchang Formation, the Chang 7 member, was deposited under a warm and humid climate, with low-level aquatic planktonic algae serving as the primary organic materials. This deposition occurred within an anoxic-reducing environment in the deep portions of freshwater lake basins. In contrast, the oil shale in the Lucaogou Formation formed under a dry–semi-arid climate within semi-saline to saline lake environments, specifically in deep-lake and sub-deep-lake regions. The organic materials for this formation consisted of low-level benthic algae and remnants of higher plants that were deposited under weak oxidation-reduction conditions. It is evident that oil shale deposition is significantly influenced by climatic factors. A humid environment favors the accumulation of aquatic algae, while a dry environment involves more diverse sources of organic acids and sedimentary conditions.

3.3. The Influence of Organic Acids on Reservoir Space Development during the Hydrocarbon Generation Process in the Chang 7 Member of the Yijun Area, Ordos Basin and the Lucaogou Formation in the Fukang Sag in the Junggar Basin

Previous experiments have demonstrated that the acid-generating capacity of organic matter during aqueous pyrolysis is closely correlated with its thermal maturity [50]. Specifically, lower thermal maturity results in a stronger acid-generating capacity. The formation of organic acids during hydrocarbon generation can enhance the porosity of mud shale and adjacent reservoirs, leading to the creation of economically valuable oil and gas under thermal stress. Simultaneously, a certain concentration of acidic fluid is generated. The early stage of acidic fluid formed during thermal evolution can dissolve minerals, facilitating oil and gas migration and providing space for their occurrence. While many scholars attribute shale pore evolution to the coupling of kerogen transformation, hydrocarbon discharge, and bitumen/tar retention, Hu Wenxuan [51] argued that acidic fluids play a crucial role in unconventional oil and gas reservoir pore evolution. They identified solution pores in oil shale samples using scanning electron microscopy. This study explores how organic acid fluid generates a significant number of secondary pore reservoir spaces through examining the distribution characteristics of organic acid fluid and organic pores resulting from the thermal evolution process of the Chang 7 member of the Yanchang Formation and the Lucaogou Formation in the Fukang Sag as examples. Consequently, based on an analysis of shale sample pore development characteristics (Table 2), we categorized the organic acid evolution stages into three phases of typical Mesozoic oil shale formations in West China.

• Immature stage

In the initial diagenetic stage, when shallowly buried, organic matter is immature (Ro < 0.5%) and predominantly consists of biogas and immature oil. As organic matter evolves from mudstone to oil shale, a significant amount of organic acids are released, including a diverse range of monocarboxylic and dicarboxylic acids. Monocarboxylic acid is primarily composed of formic acid, acetic acid, and propionic acid, with propionic acid exhibiting the highest concentration, followed by formic acid and acetic acid. Dicarboxylic acid is dominated by oxalic acid. During this stage, compaction results in the release of a substantial amount of water, leading to the generation of water-soluble organic components from the organic matter. The migration of the acidic fluid can allow it to interact with minerals along dominant migration channels, thereby reducing resistance to oil and gas migration. Simultaneously, migrating acidic fluid can alter the reservoir’s physical properties while providing pore space for oil and gas enrichment.

2.

Low maturity—mature stage

① In the second stage, the organic matter is at a low maturity stage (Ro = 0.5~0.7%), corresponding to meso-diagenetic stage A. This stage is characterized by the evolution of organic matter associated with oil and gas, with a relatively limited generation of liquid hydrocarbons and a relatively high concentration of organic acids, mainly monocarboxylic acids. Additionally, the dissolution of carbonate minerals and feldspar is taking place. In the oil shale of the Chang 7 member of the Yanchang Formation, early carbonate cements fill interstitial spaces with a high amount of content and weak compaction, resulting in suspended or point-contact particles. The rock exhibits a dense lithology and poor porosity–permeability characteristics. Later, organic acid dissolution creates intergranular pores, improving permeability. During the dissolution–compaction diagenesis stage, mineral particles exhibit close contact with linear–concave interfaces. Intergranular dissolution pores dominate over intragranular ones, contributing to the significant compaction strength. This dissolution is attributed to the abundant organic acids near hydrocarbon generation centers in mudstone adjacent to the reservoir.

In the shale oil reservoir of the Lucaogou Formation in the Fukang Sag, organic acids corrode the tight reservoir, resulting in alterations in the mineral physical properties of the oil shale. With the increase in burial depth, the intensity of the thermal evolution of organic matter intensifies, and a large amount of organic acids are produced, along with hydrocarbon generation. At this stage, not only do feldspar and laumontite dissolve, but montmorillonite also transforms into illite, and carbonate minerals undergo complex dissolution and precipitation, leading to significant changes in the grain size, structure, and distribution of minerals, and reorganizing the microstructure of the oil shale [52]. During the hydrocarbon generation process, the dissolution effect of organic acids is complementary to the local increase in formation pressure, facilitating the formation and opening of bedding fractures and providing early migration channels for formation fluids. Firstly, organic acids not only form intragranular and intergranular fractures in oil shale but also optimize the connectivity of the fractures [53]. Especially in the early stages of fracture formation, the continuous dissolution of organic acids enhances the effectiveness of fractures. Secondly, the dissolution effect of organic acids plays a catalytic role during hydrocarbon generation, particularly in the adjacent areas of organic matter and illite or illite-smectite mixed layers, where minerals recrystallize to form new pore structures. This process is accompanied by the generation of formation water, enhancing the catalytic activity of minerals, accelerating hydrocarbon generation, and thus generating more organic fractures. Therefore, the dissolution effect of organic acids remodels the pore structure of shale oil reservoirs, increasing the number of intergranular pores, dissolution pores, diagenetic shrinkage fractures, and structural fractures, causing fractures to extend along specific weak planes (such as bedding planes) to form more permeable fracture networks. These newly generated fractures and dissolution pores provide low-resistance flow paths for shale oil, significantly improving its mobility and enhancing the migration and accumulation capabilities of oil and gas molecules. In conclusion, through complex dissolution effects in the shale oil reservoir of the Lucaogou Formation, organic acids not only significantly enhance the reservoir space but also optimize the mobility and recovery factor of shale oil.

② Mature stage (Ro = 0.7%~1.3%): This phase represents the B stage of middle diagenesis and is particularly significant in the context of hydrocarbon generation within the Chang 7 member of the Yanchang Formation in the Ordos Basin. Here, black and grayish-black mud shale prevails, boasting an average organic carbon content of 5.85% and reaching a maximum of 15.83%. The predominant organic matter types are type I and II₁, with Ro values ranging from 0.8% to 1.05%, averaging at 0.91% during this mature evolution stage. When Ro exceeds 0.7%, hydrocarbon generation from organic matter as well as its associated organic acid fluid leads to high pressure, effectively mitigating mechanical compaction due to the increased formation pressure within the oil shale of the Chang 7 member of the Yanchang Formation. Simultaneously, there is an evident transformation from montmorillonite to illite; complete illitization occurs with a noticeable increase in pore diameter within the oil shale layer. Furthermore, the enhanced dissolution of unstable minerals by organic acid fluid strengthens the overall effective porosity within intercalated sandstone reservoirs (Figure 7A–F). The Lucaogou Formation itself constitutes a crucial oil shale group in the Fukang area, characterized by predominantly lacustrine sedimentation, featuring thick, dark mudstone layers exhibiting an average organic carbon content of 3.7%, peaking at 6.06%. These mud shales exhibit medium to good abundance levels for organic matter, primarily consisting of types II₂ and III. During the process of thermal maturation, oil shale generates a significant quantity of organic acids. These acidic fluids are vertically transported through the fractures and fissures induced by abnormal high pressure, and subsequently undergo short-distance migration to reach nearby sandstone reservoirs for dissolution and modification. Based on observations from thin rock slices, cast body slices, and scanning electron microscopy, corrosion is predominantly observed in the Lucaogou Formation, primarily affecting feldspar, cuttings, and turbidized zeolite (Figure 8A–D). Various types of volcanic cuttings in the Lucaogou formation lead to the formation of a wide range of intragranular dissolution pores. The dissolution of feldspar grain margins and turbidites results in a certain amount of intergranular dissolution pores within the Lucaogou Formation; additionally, strong intergranular dissolution occurs in zeolite cement. A certain amount of calcite cement is also dissolved. The development of this corrosion significantly enhances the physical properties of the deep oil shale within the Lucaogou Formation in the Fukang Sag and plays a crucial role in promoting the formation of a reservoir space. As thermal evolution progresses to an Ro value reaching 0.9%, pyrolysis generates the largest amount of hydrocarbons, accompanied by organic matter dissolution and pore development. With the increase in buried depth and the degree of thermal evolution for organic matter production, large amounts of organic acid are generated and internally formed pores gradually transition from small to large diameters. The development of dissolved pores within organic matter increases mud shale porosity, ultimately leading to enhanced effective porosity across the entire mud shale reservoir (Figure 8E,F).

3.

High maturity–overmature stage

During the advanced maturity stage (Ro = 1.3~2.0%), the oil generation attributes of oil shale gradually evolve towards dry gas production. The oil shale of member 7 of the Yanchang Formation has not reached the high maturity stage, and thus is not involved in this discussion. At this juncture, the core samples from the Lucaogou Formation demonstrate elevated maturity, featuring a relatively elevated concentration of organic acids, particularly monocarboxylic acids. Among them, the concentration of formic acid is conspicuously higher than that of acetic acid, while the concentration of binary carboxylic acids is comparatively lower. This disparity is intricately associated with the type of organic matter: type III organic matter has a propensity for enrichment in formic acid, whereas type II organic matter exhibits a preference for acetic acid accumulation. Such tendencies are directly related to the macromolecular architectures inherent in different types of organic matter. According to the chemical model of kerogen proposed by Behar and Vandenbroucke [54] in 1987, type III kerogen possesses greater oxygen content and shorter side chains compared to types I and II, which renders it more conducive to formic acid formation. Additionally, type III organic matter serves as a paradigmatic gas precursor; upon reaching a high maturity stage, it can generate CH₄ gas reservoirs with an exceptionally high drying coefficient through thermal cracking processes. In deep environments characterized by elevated temperature and pressure conditions, methane undergoes thermochemical oxidation, resulting in the production of a substantial quantity of formic acid, accounting for why the concentration of formic acid significantly exceeds that of acetic acid. In Figure 9, the correlation coefficient between the concentration of organic acids and effective porosity is low, indicating that the organic acidic solutions generated from the organic matter in oil shale have approached saturation, thereby signifying that the liquid fluid concentration within the formation has peaked. As these organic acidic fluids are discharged, a multitude of nanoscale pores formed through gas generation within the oil shale matrix are preserved. However, there is no corresponding increase in the reservoir pore radius within this layer, which explains the absence of a significant correlation between organic acids and effective porosity, as depicted in Figure 8.

After reaching the mature stage (Ro > 2.0%), which signifies the late phase of diagenesis, the pore system stabilizes. During this period, the peak hydrocarbon generation from organic matter has passed, leading to only a minimal amount of residual organic matter undergoing cracking reactions and producing organic acids at their lowest levels. At this advanced stage of diagenesis, rock experiences significantly enhanced pressure resistance and skeleton stability. Consequently, compaction exerts little influence on the rock’s pore structure due to the relatively stable fluid environment reducing inorganic pore development within mineral interiors. Overall, the pore system remains relatively stable, with minimal changes in porosity [55].

4. Conclusions

The research on the distribution characteristics, sources, and diagenesis of organic acids in typical continental oil shale sequences in the western region of China exhibits certain particularities when compared with marine shale oil layers. Therefore, based on two actual examples of oil shale in the Chang 7 member of the Yanchang Formation within the Ordos Basin and the Lucaogou Formation of the Junggar Basin, the following conclusions are drawn:

(1)

With the increase in thermal maturity, the total concentration of organic acids in the Chang 7 member shows a pattern of “sharply rising first and then rapidly declining”, while the Lucaogou Formation shows a gradually increasing trend. In both shale formations, the concentration of monocarboxylic acids predominates, and the concentration of monocarboxylic acids is significantly greater than that of dicarboxylic acids. In the Chang 7 member of the Yanchang Formation, propionate is the main component, supplemented by formate and acetate, and the dicarboxylic acid is mainly succinate. In the Lucaogou Formation, formate, acetate, and propionate are the main monocarboxylic acids, and the dicarboxylic acids are mainly oxalate and succinate.

(2)

The origin of organic acids in the oil shale of the Chang 7 member of the Yanchang Formation in the Ordos Basin differs from that in the Lucaogou Formation within the Fukang Sag, and is associated with the sedimentary environment during their formation. During the Triassic period, a significant proliferation of aquatic algae occurred in freshwater lake basins characterized by warm and humid climatic conditions. Following the death of algal organisms, the organic matter within these basins underwent deposition and transformation into oil shale of the Yanchang Formation under anaerobic reducing environments. In contrast, the oil shale of the Lucaogou Formation was formed through deposition by benthic algae and higher plant residues under the weak oxidation-reduction conditions within a brackish–saline lake in an arid–semi-arid climate.

(3)

According to the acid-generation mechanism of organic matter thermal evolution and the influence of diagenesis, the evolutionary pattern of organic acids is categorized into three stages. These three stages are, respectively, the immature stage, low maturity–mature stage, and high maturity–overmature stage.

The variations in the types and concentrations of organic acids within the typical terrestrial oil shale sequences in western China not only reflect the diversity of sedimentary environments but also disclose the significant impact of hydrocarbon generation on the formation of organic acids in oil shale. An in-depth understanding of the generation and distribution patterns of organic acids and further amplification of the positive effects of organic acids are of vital importance for identifying and developing the “sweet spots” of shale oil reservoirs, which could pave the way for the economic and effective exploitation of shale oil.