Controlling effect of saline sedimentary environment on enrichment and exploitation of shale gas and oil in lacustrine basin

The salinity of continental lacustrine basin has a great influence on the properties of shale. The main objective of this paper is to present the characteristics of shale in different saline stages. In this study, we restored the saline process by the Kauchi method and evaluated the hydrocarbon generation capacity, reservoir property, oiliness and exploitability of shale in different saline stages. The sources of organic matter and paleoproductivity may vary among saline stages. Organic matter mainly originates from coccolithophyta and dinoflagellate in the saltwater stage, demonstrating the highest paleoproductivity. Meanwhile, paleosalinity has an important effect on the lithologic assemblage and mineral composition of shale, which controls its reservoir properties, oiliness and compressibility. The lithology in the saltwater stage is dominated by lamellar argillaceous limestone/calcareous mudstone and lamellar limestone, with good original physical properties. The carbonate content in such stage is the highest, making it easy to dissolve into dissolution pores and thus increasing the porosity and saturation of movable fluid. The high hardness of carbonate gives optimum compressibility to shale. Under the same climate conditions, the salinity of continental lacustrine basin is mainly affected by the surrounding drainage system. The salinity of continental lacustrine basin affects the mineral composition and laminar of shale, which control the properties of shale. Under the same climate conditions, the salinity of continental lacustrine basin is mainly affected by the surrounding drainage system. The salinity of continental lacustrine basin affects the mineral composition and laminar of shale, which control the properties of shale.


Introduction
Shale gas is a hot research topic in recent years. The shale gas discovered at present is mainly distributed in marine shale [1][2][3]. There are obvious differences between terrestrial and marine shale in lacustrine basins [4][5][6]. The theories related to marine shale gas is not applicable to terrestrial shale gas, so unique theories are required to support the exploration and development of terrestrial shale gas [7]. Terrigenous oil and gas is a major feature of petroleum geology in China, and shale gas in China has also become the main battlefield of shale gas research in continental lacustrine basin [8].
In addition to coal measure deposits, high-quality source rocks of Meso Cenozoic continental facies in China are related to salinized basin [9]. Many shale formed in salinized environment have become the main source rock series of many oilfields. For example, the upper part of the Shahejie 4 and the lower part of the Shahejie 3 in the Dongying Sag [10], the Qianjiang Formation of Jianghan Basin [7] and the lower Ganchaigou Formation of Paleogene in the Western Qaidam Basin [11] have also successively explored shale gas from shale formed in such sedimentary environment [12,13]. The source rocks formed in different environments vary greatly. Compared with freshwater basin, saline basin has the genetic characteristics of mixed accumulation of terrigenous clasts and endogenous carbonates, with more complex sedimentation and more diverse lithofacies types [14]. At present, there is little systematic research on shale formed in salty environment and its correlation with oil and gas. On the basis of restoring saline process, this paper analyzes the control effect of saline deposition on hydrocarbon generation capacity, reservoir and compressibility of shale. The research results have theoretical and practical significance for guiding the exploration and development of continental shale oil and gas resources.
The remainder of this paper is structured as follows. In Sect. 2, we describe the geological setting of the study area. In Sect. 3, we introduce the data and main methods used in this paper. We provide results in Sect. 4: paleosalinity distribution law (4.1) and mud shale distribution (4.2) of the Shahejie Formation in the Dongying Sag. The discussion and conclusion are presented in Sects. 5 and 6, respectively. Acknowledgement, Data Availability, Author's contribution, Conflict of interest, References are given in last sections.

Geological setting
The Jiyang Depression belongs to the secondary structural unit of the Bohai Bay Basin and is a fault depression superimposed basin formed in the period of Mesozoic and Cenozoic. The Dongying Sag is located in the south of Jiyang Depression. The deep fault in the North contacts Chenjiazhuang Uplift and Binxian Uplift and extends to Southwest Shandong Uplift in the south, Qingtuozi Uplift in the east and Linfanjia low Uplift in the west. It is a Meso Cenozoic dustpan fault depression with fault in the north and super in the south (Fig. 1). During the sedimentary period of the Shahejie Formation in Paleogene, the basin entered the peak period of fault depression, and four sets of effective source rocks were developed: the upper Es 4 , the lower Es 3 , the central Es 3 and Es 1 [15]. Among them, the mud shale of the upper Es 4 deposited in salt and semi salt water environments is mainly distributed in the Dongying and Zhanhua Sag and that in the lower Es 3 deposited in brackish water environment is distributed throughout the region [16].

Data and methods
The data used in this research were provided by the Research Institute of Exploration and Development, Sinopec Shengli Oilfield Company, including core, logging, element, organic geochemistry, thin section, nuclear magnetic resonance, rock mechanical parameters, etc.
At present, there are many ancient salinity restoration methods. Considering the difficulty in identifying a small amount of mud shale inclusions in the research object, combined with data factors, ancient salinity was restored based on the ancient salinity data restored by the kauchi method and combined with the correlation between ancient salinity and Sr/BA ratio.
Trace element ratio method (Sr/Ba) is one of the commonly used methods to restore paleosalinity. Despite the similarity in the chemical properties, strontium and barium are separated due to their difference in the geochemical behavior in different sedimentary environment. Therefore, the strontium barium ratio (Sr/Ba) can be used as a marker of paleosalinity. Due to the strong migration ability of strontium, Ba 2+ in fresh water first combines with SO 4 2− in seawater to form BaSO 4 precipitation in the mixing process between fresh water and seawater, while Sr 2+ continues to migrate to the far sea and precipitate through biological channels. Therefore, the Sr/Ba value increases gradually as it moves away from the coast, which can qualitatively reflect paleosalinity [17,18]. Generally speaking, the Sr/ Ba value in freshwater sediments is less than 1, that in marine sediments is greater than 1, and that in brackish water environment is 1.0-0.6. The kauchi method restores paleosalinity using trace element B, which is also known as boron method. Generally speaking, the boron content in marine environment is 80 × 10 -6 -125 × 10 -6 , while that in freshwater environment is mostly less than 60 × 10 -6 . Walker proposed to convert the "corrected boron content" in pure illite by 8.5% of the theoretical potassium content of illite, that is, the corrected boron content = 8.5 × the measured value of boron (10 -6 ) /K 2 O (%), and the boron content in illite is related to the potassium content. Therefore, for the sake of comparison under the same condition, it is necessary to calculate the boron content equivalent to 5% of K 2 O content, which is known as "equivalent boron content" [19].
The amount of boron absorbed and fixed by clay minerals is related to the concentration of boron in the solution, which is a linear function of salinity. Based on these two relationships, lendcrgren and Carvajal [20] proposed that the boron content absorbed by clay minerals from the water body has a double logarithmic relationship with the salinity of the water body, that is, freundliehadso equation.
where B is the absorbed boron content (10 -6 ), S is the salinity (‰), and C 1 and C 2 are constants. This equation is the theoretical basis for quantitatively calculating paleosalinity by using the content of boron and clay minerals. The boron in the solution will not migrate due to the changes of physical and chemical conditions in the later period once absorbed and fixed by clay mineral, whether it exists in an adsorbed state or enters the lattice of clay minerals. Therefore, the analysis results of boron content in samples in Modern Sedimentation and ancient rock records can be used as a sign of water salinity in the initial sedimentation.
According to Landergren and Carvajal, the variation of profile salinity can be calculated by the following formula according to the isothermal absorption equation of the relationship between mudstone B content and water salinity [20].
where B is the observed B content (10 -6 ), and S is the salinity (‰).
Walker further points out that the content and proportion of clay minerals in sediments and sedimentary rocks affect the boron content of the whole rock [21,22]. Generally, illite has the strongest boron absorption, followed by montmorillonite and chlorite, and kaolinite has the lowest content of boron. Therefore, in the calculation of paleosalinity, it is necessary to consider the difference in the boron absorption capacity of clay mineral types, establish the comparative relationship between clay minerals and boron content, and correct the boron content of samples.
According to the salinity correction formula proposed by Walker, 85% of the theoretical potassium content of illite was used to convert the "adjusted boron content" in pure illite. The calculation correction formula is expressed as: where the contents of B and K 2 O refer to the measured results of the sample (10 -6 ). Since the boron content in illite is related to the potassium content, for the sake of comparison under the same condition, it is necessary to calculate the boron content equivalent to 5% of K 2 0 content, which is called "equivalent boron content". "Equivalent boron content" is to correct the boron content in the sample by the ratio of the theoretical K 2 0 concentration of illite clay rock to the measured K 2 0 content, and then calculate the boron content when the equivalent illite content is 100%. According to the K 2 0 content of the sample and the calculated adjusted B content as well as the theoretical conversion curve published by walker, "equivalent B content" was obtained by the graphic method. The distribution range of paleosalinity was directly determined based on the calculated "equivalent B content", that is, "equivalent B content" in normal marine, low-salinity freshwater, brackish and ultra-salty water environment was between 300 and 400, less than 200, and 200-300 and 400-800. The upper limit of the salinity of marine environment was 800-1000.

Paleosalinity distribution law of the Shahejie formation in the Dongying Sag
During the sedimentary period, the Shahejie Formation in Dongying Sag is generally affected by salt water environment, the lower segment of which is mainly in the salt water high salt water evolution stage, and the upper segment is basically in the brackish water brackish water salt water evolution stage (Fig. 2). Horizontally, most areas of the Dongying Sag were in saline water environment. Only the edge of the sag was affected by the desalination of foreign fresh water, with a sharp decline in paleosalinity (Fig. 3).

Mud shale distribution in the Shahejie formation of Dongying Sag
By studying lithologic evolution sequence in different salinization stages, we found that there was a significant correspondence between salt minerals and paleosalinity. There were three types of salt minerals in the study area, namely carbonate, sulfate and halide. Carbonate deposits mainly contained calcite and dolomite, sulfate deposits mainly contained gypsum and anhydrite, while halide deposits were mainly stone salts. Moreover, salinity played a critical role in controlling the evolutionary sequence of lithology. Basically, the sedimentary characteristics of gypsum rock-mud gypsum rock were mainly developed in the high saline stage. In the saltwater stage, the sedimentary characteristics were mainly carbonate and laminated argillaceous limestone assemblages. The carbonate lamina was most developed when the salinity ranged from 15 to 30 ‰. In brackish water stage, it was mainly composed of bedded calcareous mudstone-massive calcareous mudstone-massive mudstone (Fig. 4).

Characteristics of source rocks in different saline stages
The source of organic matter and paleoproductivity varies among saline stages. On the whole, the contents of TOC and chloroform asphalt A in the salt water stage were relatively high (Fig. 5). The sedimentary lithology in the high saline stage was mainly gypsum mudstone, and the organic matter was mainly derived from cyanobacteria. The paleoproductivity was 900-1200 gCm −2 y −1 the contents of TOC and chloroform "A" were 1.62% and 1.37% (well Niuye 1); in the salt water evolution stage, the sedimentary lithology was dominated by laminar (layered) argillaceous limestone or calcareous mudstone and organic matter mainly came from coccolithophyta and dinoflagellate. The paleoproductivity increased to 1500-4100 gCm −2 y −1 , and the contents of TOC and chloroform "A" were 2.85% and 1.23% (well Niuye 1); the sedimentary lithology of brackish water brackish water stage was mainly massive and laminated mudstone, with many sources of organic matter, such as algae, ostracods, lake bottom trace forming organisms, fish, etc., but its paleoproductivity was reduced to 110-430 gCm −2 y −1 , with 2.67% TOC and 0.43% chloroform "A" (well Niu 38). It can be seen from Fig. 5 that there is a difference in the lithology of source rocks formed in different saline stages, source of organic matter, paleoproductivity, as well as corresponding TOC and chloroform asphalt "A" to be enriched and retained. In general, the paleoproductivity of laminar/layered shale in salt water stage is the highest, accompanied by high TOC and chloroform asphalt "A" to be enriched and retained.

Shale reservoir characteristics in different saline stages
The shale reservoir space in the study area mainly included micro pores (organic pores, intergranular pores and intergranular pores) and micro fractures (bedding fractures, high-pressure fractures, structural fractures and mineral shrinkage fractures).

Intergranular micropore of clay minerals
Clay minerals mainly consisted of illite/smectite and illite with strong orientation. Therefore, intergranular micropores were dominated by sheets (Fig. 6a) with sizes below 5 μm.

Intergranular pore of calcite
Calcite was the main mineral in this layer, mainly characterized by cryptocrystalline structure and some by micro microcrystalline structure. It often forms gray matter lamina or is mixed with argillaceous minerals, and micro crystalline calcite lamina can be locally seen. Black asphaltene was found in the intercrystalline calcite of the gray matter layer under polarized light microscope (Fig. 6b), which is an important pore type; Under the electron microscope, the intergranular micropores of calcite often overlapped with those of clay minerals (Fig. 6c), with size below 5 μm.

Intergranular micropore of pyrite
Pyrite is an authigenic mineral in a reducing environment often dispersed in strawberry like aggregates and has intact crystal form. Therefore, micropores below microns were often developed (Fig. 6c).

Intergranular micropore of sand
Terrigenous sands are often dispersed in argillaceous materials or produced in strips. Intergranular micropores were seen in sand strips under electron microscope. Pore types are closely related to rock composition [23]. Pores with high content of calcite tend to be intergranular while those with high content of clay minerals tend to be flaky. In addition, pore types are also closely related to the evolution of source rocks. Overpressure fractures are more likely to occur in calcareous source rocks rich in organic matter in the process of hydrocarbon generation and pressurization, which is the most favorable zone for the formation of calcite intergranular pores.

Crack
According to the genesis, it can be divided into diagenetic and structural microfractures [24]. The former mainly includes interlayer microfractures and overpressure microfractures (filled with bright calcite or dolomite) and the latter is mainly oblique fractures according to the occurrence, with visible vertical fractures nearby. According to the filling degree, it can be divided into filling, semi-filling and unfilled types. Generally speaking, fracture types are mainly bedding micro fractures, followed by structural fractures.

Interlayer microfracture
Interlayer microfracture tended to be developed between laminae of different components (Fig. 7a, b, c) with a narrow width below 0.02 mm, but its significance lied in the development of potential microfractures and their easy continuation along the layer.

Overpressure microfracture
In the process of hydrocarbon generation and pressurization evolution of source rocks, a large number of drainage and various cations of source rocks resulted in mineral dissolution and reprecipitation, which was manifested in the filling of recrystallized calcite crystals in the bedding fractures generated in the pressurization process (Fig. 7d), and intergranular pores and fractures were developed on the recrystallized crystals.

Structural fracture
The rock is a fracture system formed under the action of tectonic stress. The structural fracture tended to have a relatively straight surface when observed on the core, with lamina dislocation commonly seen. These cracks are generally filled with calcite, but microscopic observation showed that they were filled with residual pores and filled with black asphaltene (Fig. 7e), which is evidence of oil and gas migration and accumulation. In addition, irregular unfilled microfractures were also seen under the polarizing microscope (Fig. 7f ). From the perspective of lithology, different bedding types and rock components had a great impact on the development of microfractures, especially bedding microfractures. Layered mudstone and marl were the most flat, and bedded mudstone and marl and marl were the most poorly developed. The contact area between the layers of straight lamina was smaller than that of wavy lamina, and the adhesion between layers was weak, making it more likely to crack under excessive pressure.
According to the study on the relationship between salinity, lithology and reservoir property, different lithologic combinations are developed in different saline stages, and different reservoir spaces are developed in different lithologic combinations (Fig. 8).
Gypsum mudstone and dolomite are mainly developed in the high saline stage, the main pores in which are anhydrite intercrystalline pores, dolomite intercrystalline pores and some dissolution pores. In terms of sedimentary genesis, gypsum and anhydrite are sulfate minerals (the chemical formula of gypsum is CaSO 4 ⋅2H 2 O, and that of anhydrite is CaSO 4 ), which are plastic to a certain extent. Generally, gypsum can be formed in natural state. It begins to lose water at 80 ℃ ~ 90 ℃ and is transformed into anhydrite to form metastable gypsum at 100 ℃ γ-Anhydrite, formed β-Anhydrite at 150 ℃, formed α-Anhydrite at 193 ℃. Taking the Bonan Sag as an example, if ground temperature gradient was estimated to be 3.5 ℃/100 m, the ground temperature reached 123 ℃ at 3500 m, where all gypsum was transformed into gypsum γ-Anhydrite, and it reached about 158 ℃ at 4500 m where all gypsum was transformed into β-Anhydrite. It can be seen that the gypsum salt layer developed in the deep layer of the Bonan Sag was basically dominated by anhydrite. On the one hand, the formation of anhydrite in the Bonan Sag inhibited the compaction, preserving the primary pores of the reservoir; on the other hand, the presence of gypsum salt layer enhanced fluid rock interaction, especially dissolution, leading to the change in water discharged by gypsum and the dissolution of organic acids, so as to further dissolve rock minerals and form secondary pore zone.
In the salt water stage, laminar argillaceous limestone/calcareous mudstone and layered limestone were mainly developed, accompanied by intergranular pores, dissolution pores and interlayer fractures.
In the brackish water stage, layer/massive calcareous mudstone/mudstone were mainly developed, together with corresponding intergranular pores, biological pores and microfractures.

Oil bearing properties of shale in different saline stages
Oil bearing property is the core parameter to evaluate the enrichment degree of shale oil [25,26]. Different lithology has different physical properties and movable fluid saturation due to different reservoir space. The NMR test results indicated that in the high brine, salt water and brackish water stages, stage, porosity (NMR) was about 4-8%, 2-10% (mostly greater than 6%) and 2-6%, respectively, and the movable fluid saturation was less than 20%, 40-60%, and less than 40%, respectively (Fig. 9). On the whole, the laminar and layered shale in the salt water stage demonstrated good physical properties and high movable fluid saturation. The statistics of oil wells also showed that the oil saturation of layered lithofacies rich in organic matter was generally greater than 40%, much higher than that of other lithology types. According to the observation results of ordinary thin section and fluorescent thin section through environmental scanning electron microscope, oil-bearing display was seen in the laminar lithofacies (Fig. 10).

Relationship between salinity environment and compressibility of shale
The content of brittle minerals is an important factor affecting the development of shale matrix pores and microfractures as well as the compressibility of shale reservoir. The higher the content of brittle minerals such as quartz, feldspar, calcite and dolomite in mud shale, the higher the brittleness of shale, making it easy for shale to form network fractures under the external force of artificial fracturing, which promotes oil and gas discharge area and is conducive to shale oil and gas exploitation. According to our study, the compressibility of shale is different in different salinization stages due to different lithology and lithology combination (Fig. 11).
In terms of the content of brittle minerals, the average value of brittle minerals in brackish water stage (76.9%) was not high on the whole, which, however, significantly increased in salt water stage (about 83.2%). However, the content of brittle minerals only accounted for about 73.7% in the high saline stage, showing a significant downward trend (Fig. 11).
As can be seen from the triaxial mechanical test results of rock, almost all the curves of shale in brackish water stage showed linear elastic segment, with few yield plastic segment when the confining pressure was less than 34 MPa. In addition, the yield point basically coincided with the failure point of peak strength, presenting brittle characteristics. When the confining pressure was increased to more than 51 MPa, the sample yielded after a linear elastic section and presented a long plastic section before failure. At this point, the yield point was at 0.8%-1% strain, while the peak strength failure point was at 1.5-2%. The fracturing properties were much better in the brackish water stage. Even at the confining pressure of 49 MPa in salt water stage, the stress-strain curve was dominated by linear elastic section, basically without any yield plastic section. The maximum failure peak strain was about 0.8%, indicating obvious brittleness. The shale formed in saltwater stage exhibited good compressibility. The plast-bearing strata formed in high saline stage had strong plasticity and low compressibility (Fig. 11).

Conclusions
The purpose of this paper is to clarify the influence of salinity on shale oil and gas enrichment in continental lacustrine basin. Shale deposits are obviously controlled by paleosalinity in continental lacustrine basin. The sedimentary environment of shale is an important factor affecting hydrocarbon generation capacity, reservoir performance, oil content and compressibility. High salinity and low salinity are not conducive to the enrichment and exploitation of shale oil and gas. Bedded argillaceous limestone/calcareous mudstone formed in saltwater period is the most favorable lithology for shale oil and gas development due to its strong hydrocarbon generation capacity, easy dissolution and strong compressibility. The research results have theoretical and practical significance for guiding the exploration of continental shale oil and gas.
Funding This work was supported by National Natural Science Foundation of China (42002165).
Data availability All data are contained in this article.

Conflict of interest
The authors declare no conflict of interest.
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