Journal of Earth Science  2017, Vol. 28 Issue (6): 963-976   PDF    
Classification of Hydrocarbon-Bearing Fine-Grained Sedimentary Rocks
Zaixing Jiang1, Hongjie Duan1, Chao Liang2, Jing Wu3, Wenzhao Zhang4, Jianguo Zhang1    
1. College of Energy, China University of Geosciences, Beijing 100083, China;
2. School of Geosciences, China University of Petroleum, Qingdao 266000, China;
3. Exploration and Production Research Institute, SINOPEC, Beijing 100083, China;
4. Research Center of China National Offshore Oil Corporation, Beijing 100027, China
Abstract: Fine-grained sedimentary rocks are defined as rocks which mainly compose of fine grains ( < 62.5 μm). The detailed studies on these rocks have revealed the need of a more unified, comprehensive and inclusive classification. The study focuses on fine-grained rocks has turned from the differences of inorganic mineral components to the significance of organic matter and microorganisms. The proposed classification is based on mineral composition, and it is noted that organic matters have been taken as a very important parameter in this classification scheme. Thus, four parameters, the TOC content, silica (quartz plus feldspars), clay minerals and carbonate minerals, are considered to divide the fine-grained sedimentary rocks into eight categories, and the further classification within every category is refined depending on subordinate mineral composition. The nomenclature consists of a root name preceded by a primary adjective. The root names reflect mineral constituent of the rock, including low organic (TOC < 2%), middle organic (2% < TOC < 4%), high organic (TOC > 4%) claystone, siliceous mudstone, limestone, and mixed mudstone. Primary adjectives convey structure and organic content information, including massive or limanited. The lithofacies are closely related to the reservoir storage space, porosity, permeability, hydrocarbon potential and shale oil/gas sweet spot, and are the key factor for the shale oil and gas exploration. The classification helps to systematically and practicably describe variability within fine-grained sedimentary rocks, what's more, it helps to guide the hydrocarbon exploration.
Keywords: fine-grained sedimentary rocks    classification    mineral composition    TOC content    shale oil and gas    

Fine grained sedimentary rocks mostly comprise grains smaller than 62.5 μm, accounting for approximately two thirds of the stratigraphic record (Macquaker and Adams, 2003; Tucker, 2001; Aplin et al., 1999). However, it has been often overlooked as it may appear simple. Meanwhile, due to the limitation of ultra-microcosmic experimental conditions, deposition and diagenesis of fine-grained sediments remain a relatively weak research field in sedimentology (Jiang et al., 2013; Peltonen et al., 2009; Tripsanas et al., 2008; Potter et al., 2005; Schieber et al., 2000; Arthur and Sageman, 1994). With the exploration and development of shale oil and gas, the study of fine-grained sedimentary rocks becomes an increasingly urgent issue (Aplin and Macquaker, 2011).

Fine grained sedimentary rocks which primarily composed of clay minerals and silts, include a range of rock types vary from pure carbonates and siliceous to siliciclastic muds (Macquaker and Adams, 2003; Kranck et al., 1996; Picard, 1971). Over the past decades, many scholars have put forward various classification schemes of fine-grained sedimentary rocks, among them some are suitable for fieldwork and some are based on laboratory analysis. Many authors have attempted to systematically describe either all or a subset of these diverse sediments according to their various color, grain size, texture, heavy-mineral composition, bulk composition, presence or absence of lamination, fossil content, fissility, and organinc richness (Aplin et al., 1999; Wignall, 1994; Weaver, 1989; Potter et al., 1980). Recent years, due to shale gas exploration and production, researches on shale lithofacies analyses have increased (Abouelresh and Slatt, 2012; Liang et al., 2012; Liu et al., 2011; Loucks and Ruppel, 2007; Hickey and Henk, 2007). On the basis of mineralogy, fabric, biota, and texture, Loucks and Ruppel (2007) identified three general lithofacies in Barnett Shale: (1) laminated siliceous mudstone; (2) laminated argillaceous lime mudstone (marl); and (3) skeletal, argillaceous lime packstone. Through petrographic study of conventional core samples, Hickey and Henk (2007) recognized the lower part of the Barnett as the following rock types: organic-rich black shale, fossiliferous shale, dolomite rhomb shale, dolomitic shale, phosphatic shale, and concretionary carbonate.

Although the classifications of the shales mentioned above could be easily measured and useful for similar shale measurement, however, the classification of fine-grained sedimentary rocks for a broad applicable has not formed. Meanwhile, the existed classification mostly focused on composition of inorganic minerals, and the organic matters has often been overlooked (Liu et al., 2013; Loucks and Ruppel, 2007). In fact, the organic matters are of great significance on the deposition process, diagenesis and reservoir formation of fine-grained sedimentary rocks, especially for rocks which are rich in carbonate minerals (Jiang, 2011). Therefore, a more comprehensive, informative and unified classification is needed to describe and compare all fine-grained sedimentary rocks. In this paper, we propose an effective, broad applicable classification for gas/oil bearing fine-grained sedimentary rocks placing emphasis on organic matter as well as mineral composition. We take the TOC content as an important parameter in this classification. The rock type classified is concerned with its genesis, reservoir property and hydrocarbon potential.


In the study, five cored wells from different intervals of three basins are used. The basic data in this study include 853 m of cores, 1 206 thin sections, SEM observations from 47 samples, X-ray diffraction data from 1 391 samples, source rock data (vitrinite reflectance, TOC, maceral compositions) from 515 samples (Table 1). Core samples were studied at the hand-specimen, thin-section, and scanning electron microscope (SEM) scales. A centimeter-scale core description of sedimentary structures and textures forms the primary basis of petrology characterization. Lots of thin sections were prepared from samples trimmed from core and analyzed for rock fabric, texture, biotic content and mineralogy. The quantitative mineral composition analyses were conducted by X-ray diffraction XRD. These analyses coupled with measuring total organic carbon (TOC) content by combustion, provide the basis for identifying and classifying fine-grained sedimentary rocks based on fabric and compositional features. Also the related data of some top foreign shales are obtained through literature research for reference and comparison.

Table 1 The basic data used in this study

Clay minerals, quartz, feldspar and carbonate are the most abundant minerals in fine-grained sedimentary rocks. A variety of other minerals may occur in these rocks in minor quantities, including zeolites, iron oxides, heavy minerals, sulfates and sulfides, as well as fine-size organic matter (Table 2). The statistics show that the average content of silica (quartz plus feldspar) in the fine-grained sedimentary rocks ranges from about 15% to 60%, average clay-mineral content ranges between about 15% and 38%, average carbonate (calcite plus dolomite) content ranges from less than 5% to more than 63%. The abundance of siderite and pyrite, which are secondary minerals are relatively low. The average content of organic carbon present in fine-grained sedimentary rocks ranges from about 1.95% to 5.80%.

Table 2 The mineral composition, TOC and Ro of different mudstones
3.1 The Significance of Organic Matter—Why the TOC Content is Taken into the Classification Scheme?

Most of the organic matters in fine-grained sedimentary rocks are fine-size sapropel, which consists largely of the remains of phytoplankton, zooplankton, spores, pollen, and the macerated fragments from higher plants. Organic matter is one indispensable part of fine-grained sedimentary rocks.

3.1.1 Supplement of sediments

As mentioned above, the fine-grained sedimentary rocks in the Zhanhua and Dongying depressions are rich in carbonate minerals. In fact, the deposition of these carbonate and carbonate-rich fine-grained rocks are closely related to the organic matters. Photosynthesis by planktonic algae and microbial processes can absorbs the CO2 and reduce waterbody pH value, thereby promoting the precipitation of CaCO3 (Wang et al., 2011; Reid et al., 2000).

3.1.2 Influences on the morphology of calcite crystals

The observation of a large number of thin section shows that the calcite in the shale mainly occurs as three forms, micrite, microspar, and sparry occurrence. Statistics data reveals that these occurrences are closely related to TOC content. As the TOC is less than 2%, calcite exists in micrite, when TOC is more than 2%, calcite begins to recrystal as microspar or granular sparry occurrence, and when TOC is greater than 4%, calcite exists as needle-like sparry occurrence (Fig. 1). That is to say, in the shale, the degree of calcite's crystallization increases with the increasing of total organic carbon content. This phenomenon is related to the thermal evolution degree and organic matter content of the shale. As organic matter matures and hydrocarbon expulses, organic acid releases, which can dissolve the micritic calcite, and promote the recrystallization process (Jiang et al., 2013). The higher TOC content means more released organic acid, which means higher recrystallization degree.

Figure 1. Carbonate mineral crystal morphology vs. TOC. (a) Micritic calcite, TOC=1.74%, Well BYHF1, 2 425.4 m; (b) granular microspar calcite, TOC=3.67%, Well BYHF1, 2 435.6 m; (c) needle sparry calcite, TOC=4.05%, Well BYHF1, 2 440.7 m.
3.1.3 Hydrocarbon generation potential

Organic matter (OM) is the material basis for hydrocarbon, which richness decides the hydrocarbon-generation potential and in-situ oil content. And total organic carbon (TOC) value is a parameter which measures the abundance of organic matter present in a sediment sample. Researches prove that when the TOCo (original organic carbon) value is low, the hydrocarbon generated from source rock is mainly adsorbed in organic matters and minerals themselves; as the TOCo increases, the hydrocarbon generated can be expelled out and fill in the matrix pore or proceed secondary migration in a large number. Chloroform asphalt "A" extracted from source rock and rock geochemical pyrolysis analysis parameter "S1" (volatile hydrocarbon content) are good indications of oil content. The positive correlation relationship between "A" and "S1" with TOC reveals that organic matter content determines the oil content of shale (Figs. 2a, 2b).

Figure 2. Diagrams showing the relationship between chloroform bitumen "A", S1, fratures density, porosity and TOC content.
3.1.4 Effect on the storage capacity for shale gas/oil

In addition, high organic carbon content can provide extra high storage capacity for gas and oil (Fig. 3). Organic pores in gas shales has been well documented since they been first identified in the Barnett Shale (Loucks et al., 2009). These pores are generated during burial and maturation of organic material. When the Ro level of approximately 0.6% or higher, the OM pores occur, and the amount of porosity within an OM particle in a single sample ranges from 0 to 40% (Loucks et al., 2012, 2009). In the process of OM evolution, a shale of which TOC is 7%, consumes 35% of the organic carbon will lead to a 4.9% increase of its porosity (Jarvie et al., 2007). The relationship of porosity with TOC shows that the higher the organic matter content is, the better the storage capacity it has (Figs. 2c, 2d), provided similar mineral composition, kerogen type and its maturity (Liang et al., 2014). The pores related to organic matters evolution is not limited to organic pores. As mentioned above, organic acid expelled during the organic matters evolution dissolved carbonate minerals and feldspar, generating dissolution pores. Meanwhile, organic matters evolution prone to cause recrystallization, accompanied by a large intercrystal pores, which common occur in the recrystallization calcite and dolomite. The dissolution and recrystallization caused by the hydrocarbon generation, on the one hand provides recrystallization intercrystal pores, dissolution pores and inter-layer storage space, improving the porosity to a certain extent, what's more, change mechanical properties of rocks and increase rock brittleness, which is very beneficial for shale reservoir fracturing (Figs. 2c, 2d).

Figure 3. Proposed classification scheme for fine-grained sedimentary rocks. (a) Ⅰ. Claystone; Ⅱ. siliceous mudstone/siltstone; Ⅲ. calcareous rock/limestone; Ⅳ. mixed mudstone, (b) a. claystone; b. silty claystone; c. calcareous claystone; d. siltstone; e. clayey siltstone; f. calcareous siltstone; g. limestone; h. argillaceous limestone; i. silty limestone; j. mixed fine-grained sedimentary rock.
3.1.5 Effect on the shale oil production

Statistics show that, shale oil production (or test oil production) is closely related to the TOC content (Table 3). The relationship can be generally described as (1) it is invalid reservoir and basically does not produce shale oil even after artificial fracturing when TOC content is lower than 2.0%, (2) when 2.0% < TOC < 4.0%, it can be low abundance reservoir with natural low yield potential, and can reach industrial oil flow after fracturing, (3) it acts as high abundant reservoir with certain natural capacity, even up to industrial oil flow, and can gain stable high shale oil production when the TOC content if greater than about 4.0%.

Table 3 The lacustrine shale oil yield of different depression in China
3.2 Classification Principle

Several aspects are considered in the paper to choose parameters for classification of fine-grained rocks. Firstly, the parameters need to be objective, easy to identify or acquire, and can reflect the genesis of the rock. Secondly, the classification should be suitable for both field work and laboratory research. Besides, as we discussing the gas/oil bearing fine-grained sedimentary rock here, the classification need to be useful for the petroleum prospecting, especially reservoir prospecting.

As a result, we propose a classification scheme which taking TOC, silica (quartz plus feldspars), clay minerals and carbonate minerals as the four end-members.

(1) The majority of clay minerals and silt-sized quartz in fine-grained sedimentary rocks are terrigenous siliciclastic particles generated through the disintegration of pre-existing rocks surrounding the basin. Thus the silts & clay content represents terrigenous clasts input intensity. While carbonate minerals are mostly autochthonous through chemical precipitation or biochemical process within the basin, which is related to the climate and water conditions. Thus the carbonate mineral content can reflect the climate and water depth.

(2) The TOC content not only relies on the original productivity of organic matter, but also depends on preservation conditions. Fast deposition rate and strong reducibility are good for preservation of organic carbon. The original productivity is closely related to the climate and nutrients, and the TOC content can reflect the physical and chemical condition (Lu et al., 2004). As mentioned above, the TOC content is closely related to the shale oil yield and the reservoir properties (including calcite crystallinity, porosity, permeability and fracture development), and the sharp boundaries are 2% and 4%. Therefore, the TOC content is considered and TOC being 2% and 4% are used in the mudstone classification.

3.3 Classification Scheme and Nomenclature

According to Fig. 3a, based on of TOC content, taking 2% and 4% as the boundary values, the fine-grained rocks are divided into three broad classes, which are low organic (TOC < 2%), middle organic (2% < TOC < 4%) and high organic (TOC > 4%) ones. In samples where clay, silica or carbonate exceed 50%, the rocks should be given the appropriate root name of the dominant constituent, including argillaceous mudstone/claystone, siliceous mudstone/siltstone, calcareous rock/limestone. Within every class, further classification can refer to Fig. 3b, which depends on subordinate mineral taking the frequently-used 25% as a limit value. However, this classification is based on the main components, without considering the secondary minerals and special mineral, if fine-grained rock contains some, additional name can be appended. Also sedimentary structure information should be incorporated into this scheme by prefixing the rock name with descriptions such as "massive" or "laminated".

For mudstones there is no dominant mineral inside, and all the three compositions (clay, silt or carbonate) are less than 50%, which were so-called "mixed mudstone", we suggest incorporate the quartz, feldspar and clay as the terrigenous siliceous clastic fraction, together with the carbonate to form a binary classification. Here we adopt siliceous clastic fraction exceeding 65% or carbonate fraction exceeding 35% as the boundary, rocks in which clay and silt together exceed 65% can be named siliciclast-type mixed mudstone, otherwise named carbonate-type mixed mudstone. Appropriate descriptive terms would be included with the rock name. Moreover, the total organic carbon evaluation is also involved. For example, a blocky rock of which the clay content is 27%, quartz and feldspars content is 34%, carbonate content is 39% and TOC content is 1.8% can be named as a massive organic-poor carbonate-type mixed mudstone.

3.4 Practical Applications and Descriptions of Fine-Grained Sedimentary Rocks

To illustrate the above nomenclature scheme which is based on TOC and mineral abundance, we provide a number of examples from five wells cores. Ternary diagrams of mineralogical constituents of these cores from five wells show relative proportions of clay, carbonate and terrigenous silica (Fig. 4; Table 4). These three depressions generally contain less than 50% clay minerals in which the Biyang depression contains less calcite and more silica than the other two depressions. Table 3 shows that calcareous mudstone is the predominant lithoface in the Zhanhua and Dongying depressions and mixed mudstone take the second place, while in Biyang depression, the mixed mudstone is the predominant lithoface and siliceous mudstone is the secondary lithoface. These lithofacies in the lithology classification (Fig. 3) may not well developed in one strata. Therefore, the description is mainly based on the typical lithofacies in different shale formations.

Figure 4. Ternary diagrams of mineral composition from different depression.
Table 4 Mineralogical analysis of four key well cores based on XRD data
3.4.1 Claystone Low organic claystone

The calystones in the well cores are mainly gray/blue-gray (Figs. 3a3c), massive distributed or occasionally developing in distinct horizontal bedding. Massive claystones abruptly contracts with overlying laminated shale or siltstone (Fig. 5a).

Figure 5. (a) The massive low organic claystone abruptly contacts with overlying laminated shale, Well FY1, 3 394.24 m, Es4s Formation, Eocene; (b) massive claystone, Well NY1, 3 473.7 m, Es4s Formation, Eocene; (c) gray massive claystone, Well YY1, 17.6 m, S1l Formation, Lower Silurian; (d) massive low organicr claystone with detrital angular quartz grains and ostracode fossil fragments. Well L69, 2 937.6 m, Es3x Formation, Eocene; (e) massive low organic claystone with detrital silt quartz grains and pyrite dispersed distributed in the matrix, Well L69, 3 019.3 m, Es3x Formation, Eocene; (f) clay minerals are dominated in the lithology, and fractures, Well NY1, 3 474.55 m, Es4s Formation, Eocene.

The mineral composition of claystones are mainly clay minerals (more than 50%), calcium (ranging from 10% to 30%) and terrigenous debris (ranging from 10% to 20%), fine-grained framboidal pyrite also present in most samples. In addition, a little ostracods debris and orientated carbon dust can be found in claystones. The massive claystones contain poor organic matters, with TOC content ranging from 0.4% to 1.2%. All minerals are disorganized and chaotic in optical light. The quartzes are always angular, and range from several to a dozen of micrometers (Figs. 5d, 5e). Organic type is mainly types Ⅱ–Ⅲ, indicating the leading role of terrigenous organic matter.

The massive claystones are characterized as massive structure, disorganized, chaotic detrital grains and low TOC content, which are obviously different from the laminated mudstones. Previous study shows that the long axis of the detrital grains will be horizontally arranged in the slow suspension settling (Potter et al., 2005). The massive structure and disorganized detrital grains suggest a rapid depositional process of massive mudstone, which is different from the suspension settling. Here, the massive claystone is interpreted to be deposited by turbidity current. The low TOC content of the massive mudstone can be interpreted as the result of the turbidity current carrying a large amount of oxygen into the ocean bottom (Potter et al., 2005). Middle-high organic claystone

Compared with the low organic massive claystone, the high organic claystone is dark colored, mainly black and dark gray. These rocks contain clay minerals ranging from 47% to 59% and up to 30% silt with minor calcite ( < 20%). Also fine-grained framboidal pyrite is present in most samples. The lithology is mostly laminated, and the laminar boundaries can be sharp or blurring (Figs. 6a6c). The laminas can be silt laminas, clay laminas, organic laminas, carbonate laminas, etc. and the clay laminas are dominated in this lithology. Organic type is mainly Type Ⅰ, indicating the leading role of planktonic organic matters, which can be confirmed by the blue-green algae, dino flagellates. The formation of the laminas is related to the water stratification and cyclical climate change. The development of laminas, rich in clay minerals, a scarcity of large debris and a composition rich in pyrite and organic matters. These characteristics indicate that they were formed by suspension deposition in a quiet deep-water region with a low deposition rate. As the differences of minerals composition, high organic silty claystone (Fig. 6b) and calcareous claystone (Fig. 6c) can be further classified. Massive high organic claystone can be seen (Figs. 6d, 6e), and different from organic laminated claystone and low organic massive claystone, they deposited with a low deposition rate and high TOC content. Previous studies suggested they formed related to tsunami (McHugh et al., 2006). These rocks are characterized by high TOC content and Type-Ⅰ prone kerogen, as other parameters (Ro, thickness, etc.) meet the requirements, these rocks can act as good source rock.

Figure 6. (a) Laminated high organic claystone with sharp laminas boundary, Well CH2, 2 772.96 m, Eh3s Formation, Eocene; (b) laminated high organic silty claystone with blurring laminas, Well NY1, 3 387.8 m, Es4s Formation, Eocene; (c) laminated high organic calcareous claystone with recrystallized sparry calcaite layer, Well CH2, 2 813.08 m, Es3s Formation, Eocene; (d) massive high organic claystone with few quartz and feldspar, Well NY1, 3 494.1 m, Es4s Formation, Eocene; (e) massive low organic claystone with detrital silt quartz grains and pyrite dispersed distributed in the matrix, Well L69, 3 019.3 m, Es3x Formation, Eocene; (f) laminated high organic claystone with sharp laminas boundary, Well BY1, 2 428.6 m, Es3s Formation, Eocene.
3.4.2 Siliceous mudstone Low organic siliceous mudstone

The low organic siliceous mudstone are well developed in the lake basin (Biyang, Zhanhua and Dongying depressions) and as the turbidity in marine shale in the Sichuan Basin. Organic poor siliceous mudstone is mainly composed of silt-size quartz and feldspar (41%–74%) with some clay (ave. 26.0%) and carbonate (ave. 14.5%), in addition to minor organic matter (ave. TOC is 1.57%) and pyrite. Detrital quartz and feldspar silt is a major component of the siliceous mudstone (Figs. 7a, 7b). Microcrystalline silica is also present (Figs. 7c, 7d) which is probably a diagenetic product, but it's far less abundant than detrital silica. Siliceous mudstones range from calcareous to nearly total noncalcareous. The majority of this rock type presents absence of lamination, while a few show graded bedding, which exhibits upward-fining couplets on a millimeter scale that are composed of silt-rich mudstones at their bases and clay-rich mudstones towards their tops (Figs. 7e, 7f).

Figure 7. Photographs of siltstone. (a) Massive low organic siltstone, the size of quartzs are mostly under 70 μm, Well YY1, 178.6 m, S1l Formation, Silurian; (b) massive low organic calcareous siltstone, Well L69, 3 135.95 m, Es3x Formation, Eocene; (c) massive low organic muddy siltstone, Well L69, 2 942.89 m, Es3x Formation, Eocene; (d) massive low organic siliceous mudstone, Well NY1, 3387.8 m, Es4s formation, Eocene; (e) laminated low organic muddy siltstone, detrital silt grains half orientated in layers upword-fining, Well CH2, 2 820.57 m, Eh3s Formation, Eocene; (f) laminated low organic muddy siltstone. Silt laminas and clay laminas alternate frequently, Well CH2, 2 820.57 m, Eh3s Formation, Eocene; (g) laminated middle organic argillaceous siltstone, Well YY1, 201.6 m, S1l Formation, Silurian; (h) middle organic argillaceous siltstone with silt grains ranging from 10–30 μm, in which carbonized organic matters (black in the photo) are abundant, Well YY1, 201.6 m, S1l Formation, Silurian. Middle organic siliceous mudstone

However, not all siliceous mudstone are organic poor. In the Sichuan Basin, the Longmaxi Shale, Silurian, are mainly middle organic siliceous mudstone. The organic rich siliceous mudstone are dark colored and laminated (Fig. 7g). In this lithology, quartz is dominant, with minor clay minerals. The quartz grains sizes are very small, mainly ranging of 10–20 μm, partly up to 40 μm (Fig. 7h). These small quartz grains are from terrestrial transport and autogenous, while the ratio of the two origin quartz is uncertain. Studies suggest that the organic matters are mainly from planktonic algae and are carbonized because of strong diagenesis and thermal evolution (Ro > 2%). Middle organic siliceous mudstone (main Longmaxi Shale) characterizes as high TOC content and high quartz, which means high brittleness. These rocks act as an important source rock and gas shale interval (Liang et al., 2016; Li et al., 2009). What's more, SINOPEC has gained industrial shale gas flow in Longmaxi Shale of the Jiaoshiba experiment area (Wang, 2014). The middle organic siliceous mudstone has considerable industrial value for hydrocarbon exploration and development.

3.4.3 Limestone

Calcareous mudstone is the predominant rock type within Dongying and Zhanhua depressions and is highly variable in character. These rocks are complex and studies show that their characteristics (calcite crystal size and conformation) are closely related to the TOC content. Low organic limestone

The low organic limestone is light colored, mainly light gray and gray. The laminas are continuous or wavelike, with relative blurred laminas boundaries (Figs. 8a8c). Carbonate minerals are mainly micritic calcite (Figs. 8g, 8i), accounting for 50%–70%. Laminas are well developed and distributed horizontal or wavy (Fig. 8d). The light laminas are mainly micritic calcite with subordinate silts, while the dark laminas mainly consist of clay and organic matters (Figs. 8e, 8f). The organic rich laminas are thin and the organic matters are dispersed (Fig. 8h). The test data show that TOC content is relatively low, mainly lower than 2.0%. The cores and thin sections show that the calcite laminas are dominant with great thickness. Some calcite laminas are lenticular (Fig. 8e), suggesting it maybe receive a certain degree of water disturbance.

Figure 8. Photographs of low organic limestone. (a) Light gray low organic laminated limestone, Well L69, 3 102.85 m, Es3x Formation, Eocene; (b) gray low organic limestone with blurred laminas boundaries, Well FY1, 3 211.78 m, Es3x Formation, Eocene; (c) gray low organic limestone with blurred laminas boundaries, Well LY1, 3 631.5 m, Es3x Formation, Eocene; (d) laminated and lenticular micritic calcite, Well L69, 3 112.9 m, Es3x Formation, Eocene; (e) lenticular micritic calcite with a small amount of quartz, Well FY1, 3 211.78 m, Es3x Formation, Eocene; (f) very thin organic and clay laminas (black laminas), Well LY1, 3 631.5 m, Es3x Formation, Eocene; (g) micritic calcite of (f), Well LY1, 3 631.5 m, Es3x Formation, Eocene; (h) dispersed organic matters in the fluorescent thin section, Well L69, 3 100.9 m, Es3x Formation, Eocene; (i) very small automorphic calcite crystals showed in the SEM photo, with crystals size about 2–4 μm, Well L69, 3 117.65 m, Es3x Formation, Eocene. Middle organic limestone

In these rocks the calcite laminas may recrystallize partly along the calcite laminas boundaries (Fig. 9a). As the increasing of the clay minerals and silt, decreasing of calcite and TOC, the layering becomes weakened. The middle organic argillaceous limestone (Figs. 9b, 9c) and silty limestone can be furtherly classified according to the clay minerals and silt content.

Figure 9. (a) Organic rich laminated limestone, lenticular calcite, Well LY1, 3 661.96 m, Es3x Formation, Eocene; (b) organic rich laminated limestone, Well L67, 3 347.8 m, Es3x Formation, Eocene; (c) organic rich laminated argillaceous limestone, Well L69, 3 056.81 m, Es3x Formation, Eocene; (d) massive organic rich limestone, Well L69, 2 996.71 m, Es3x Formation, Eocene; (e) granular calcite with high euhedral crystals as a result of recrystallization, Well LY1, 3 662.1 m, Es3x Formation, Eocene. (f) columnar calcite crystals with clear laminas boundaries, interlayer fractures well developed, Well FY1, 3 325.49 m, Es4s Formation, Eocene; (g) the fluorescent thin section of (k) show the organic matters laminas with fluorescence; (h) massive organic rich limestone with sharply angular quartz, Well L69, 2 992.50 m, Es3x Formation, Eocene; (i) well layering micritic calcite and organic rich laminas, Well FY1, 3 385.54 m, Es3x Formation, Eocene; (j) laminated organic rich argillaceous limestone, micrite calcite layers are interbeded with OM laminas and pyrite framboids are enriched distributed in OM laminas, Es4s Formation, Well NY1, 3 390.1 m, Es3s Formation, Eocene; (k) laminated organic rich silty limestone, micrite calcite laminas are interbeded with OM laminas and pyrite framboids are dispersedly distributed in OM laminas, Well BYHF1, 2 425.4 m, Eh3s Formation, Eocene; (l) the fluorescent thin section show the dispersed organic matters in massive limestone, Well L69, 2 983.94 m, Es3x Formation, Eocene.

Massive limestone also can be seen occasionally, in which, sharply angular quartz grains are common and organic matters are dispersed distributed (Figs. 9d9f). The organic matters are mainly planktonic. The disorganized detrital grains suggest a rapid depositional process deposited in the agitated waterbody, which is different from the laminated limestone. High organic limestone

Organic rich laminated limestone characterizes by dark colored, high carbonate content (up to 80 wt.%) and high TOC content (2.0 wt.%–9.8 wt.%), while clay minerals and terrigenous silts are rare. The cores and thin sections show the clear laminar boundaries, and laminas have pure components (Figs. 9g9i). The light laminas are mainly composed by recrystallization calcite, which mainly occur as "needle" or grain crystal closely packed (Figs. 9j, 9k). The dark laminas are rich in organic matters and pyrite, and with strong fluorescence (Fig. 9l).

3.4.4 Mixed mudstone

Mixed mudstone are those do not contain 50% clay, silt or carbonate, in which the mineral abundance is a kind of homogeneous and none is predominant. These rocks are dominant in the Eh3 shale of Biyang depression. In order to study these rocks well, we classify these rocks into two types: (1) siliciclastic mixed mudstone, in which siliciclastic content (including quartz, feldspar and clay minerals) is greater than 65% (Figs. 10a10d); and (2) carbonate mixed mudstone, in which carbonate content is greater than 35% (Figs. 10e10f).

Figure 10. Photographs of mixed fine-grained sedimentary rock. (a) Massive organic-poor carbonate-type mixed fine-grained rock, Well L69, 2 939.6 m, Es3x Formation, Eocene; (b) massive organic-poor siliciclast-type mixed fine-grained rock with striped organic matter scattered in the matrix, Well BY1, 2 442.5 m, Eh3s Formation, Eocene; (c) laminated organic rich carbonate-type mixed fine-grained rock, Well CH2, 2 787.89 m, Eh3s Formation, Eocene; (d) laminated organic rich siliciclast-type mixed fine-grained rock, Well BY1, 2 421.6 m, Eh3s Formation, Eocene; (e) massive organic rich carbonate-type mixed fine-grained rock, rhombhedral calcite recrystallize within organic matter fragment, Well NY1, 3 370.15 m, Ess4 Formation, Eocene; (f) massive organic-rich siliciclast-type mixed fine-grained rock, Well L69, 2 934.63 m, Es3x Formation, Eocene.

Shale oil and gas have now become important exploration targets (Liang et al., 2014; Jarvie et al., 2007). In North America, the discovery of Bakken Shale play, Eagle Ford Shale paly, Haynesville Shale play etc., have proven that fine-grained sedimentary rocks have a huge hydrocarbon potential to secure world energy in the future. In these organic rich fine-grained sedimentary rocks, a porosity network is well interconnected, and the porosity and permeability are high. Additionally, these rocks have high brittle minerals content (quartz/calcite), especially the organic rich siliceous mudstones and limestone, which is conductive to artificial fracturing. In fact, these fine-grained sedimentary rocks have gained industrial oil/gas flow, such as shale oil and gas.

Here we discuss the lithofacies and the shale oil/gas exploration, taking the Es4Es3x shale in Dongying depression as an example. In the study of Es4s–Es3x shale in Dongying depression, further lithofacies dividing has been made in the aforementioned classification system: high organic laminated limestone (HLL), middle organic laminated limestone (MLL), low organic limestone (LLL), middle organic laminated marl (MLM), middle organic laminated calcareous mudstone (MLCM), low organic laminated dolomite mudstone (LLDM), low organic laminated gypsum mudstone (LLGM), low organic massive mudstone (LMM). We discuss the storage space, hydrocarbon generating potential, sweet spot and shale oil exploration with the main lithofacies.

The fine-grained reservoir is closely associated with lithofacies, which is mainly reflected in the storage space types and abundance, porosity and permeability. Structural fractures mainly occur in these lithofacies with high brittleness, and statistics show that the structural fractures density has a positive correlation with the brittle minerals (refer to the calcite in Dongying depression Es4s–Es3x Shale and quartz in the Sichuan Basin Longmaxi Shale) content. Interlaminated fractures mainly develop in organic-rich laminated lithofacies. Laminated shale shows much heterogeneity in sedimentary structure, organic matters, mineral composition, and so on, which lead to aeolotropism in physical properties. Organic pores are abundant in the organic-rich laminated mudstone, while rare in these organic-poor lithofacies. Floccules pores are rich in the clay-rich lithofacies, such as laminated calcareous claystone, laminated claystone and massive mudstone. Recrystallization intercrystal pores are rich in these lithofacies with recrystallization, especially the high organic laminated limestone, in which the calcite with strong recrystallization. The development of pyrite intercrystal pores is related to the pyrite content. The inter-particle pores are rich in these lithofacies with high debris grains content. Statistics suggest the big differences of reservoir space type and abundance in different lithofacies (Fig. 11). The high organic laminated limestone contains abundant reservoir space, such as recrystallization intercrystal pores, organic pores, interlaminated fractures, etc. and higher porosity and permeability. Meanwhile, HLL has high TOC content, chloroform bitumen "A" and brittle minerals content (ave. 70 wt.%). These characteristics make the HLL act as the shale oil exploration dessert. The cumulative thickness of HLL can be 36 m in the Es4s of Well NY1 and single thickness is ca. 2–6 m (Fig. 12).

Figure 11. The relative content of different storage space of different lithofacies in Es4s–Es3x shale, Dongying depression. SF. Structural fractures; APF. abnormal pressure fractures; MCF. mineral contraction fractures; IF. interlaminated fractures; OP. organic pores; FP. floccules pores; RIP. recrystallization intercrystal pores; PIP. pyrite intercrystal pores; IP. interparticle pores; HLL. high organic laminated limestone; MLM. middle organic laminated marl; MLCC. middle organic laminated calcareous mudstone; MLL. low organic laminated limestone; LLGM. low organic laminated gypsum mudstone; LLDM. low organic laminated dolomite mudstone; LMM. low organic massive mudstone.
Figure 12. The vertical lithofacies distribution of Well NY1.

In addition, the HLL is always associated with those lithofacies which has relative good reservoir properties and hydrocarbon potential, such as high organic laminated calcareous mudstone (HLCM) and laminated marl (MLM). The favorable lithofacies assemblages can form great thickness vertically. The "sweet spot" lithofacies (HLL) and the assemblages with MLCC and MMLM occur as certain regularity in the vertical. Evidence from element geochemistry suggests that the lithofacies are always corresponds to once lake level rise, that is the flooding surface (Wu et al., 2015, 2014).

The different thickness reflects the difference of flooding degrees. The sequence and parasequence groups division of Well NY1 (the detailed division principle and basis will be discussed in another paper, and the results was directly used here) shows that the organic-rich laminated limestone is concentrated in the transgressive systems tract (TST) and mainly developed in the top of the parasequence groups, such as PS4, PS5 and PS6 (Fig. 12).

Therefore, on the basis of regional stratigraphic framework, it is easy to find out the developed interval of the shale oil reservoir "sweet spot" and its plane distribution characteristics. While selecting favorable zone of shale oil exploration, the main controlling factors of shale reservoir mentioned above should be taken into account. Overall, there is little difference in diagenesis degree of the study area (little variety of Ro).

As a result, the diagenesis has little impact on the favorable zone prediction and can be ignored here. The controlment of tectonic activity is mainly reflected on its impact on the development of natural fractures, which are very important for the storage and immigration of shale oil. The preferred exploration zone should be near the fault belts. The preferred zone of the TOC content needs more work. Firstly, based on the detailed the TOC content test data of key well cored wells (here Well NY1 and Well FY1 are used), the well log interpretation of the TOC content was analyzed.The calibration of the interpretation results was constructed to establish the accurate interpretation model of the TOC content. Then, the TOC content of non-coring wells can be calculated by the model. A mass of wells analysis of the TOC content helps to achieve the high TOC content zones. The dessert lithofacies (HLL) has been selected after comprehensive analysis, and the dessert interval will be analyzed in the wells. Then, it is easy to predict the favorable lithofacies zones based on the stratigraphic framework of the study area. Under the guidance of the idea, the favorable zones can be predicted based on the comprehensive analysis.


The proposed classification of hydrocarbon-bearing fine-grained sedimentary rocks in this paper is based on mineral composition of the rocks, which takes TOC content, silica (quartz plus feldspars), clay minerals and carbonate minerals as parameters, fine-grained sedimentary rocks were divided into four categories based on the dominant minerals, and within every category further classification is refined depending on subordinate mineral. The nomenclature consists of a root name preceded by a primary adjective. The root names reflect mineral constituent of the rock, including argillaceous mudstone/claystone, siliceous mudstone/siltstone, calcareous rock/limestone, and mixed fine-grained sedimentary rock. Primary adjectives convey structure and organic content information, including massive or limanited and organic-poor, organic-rich. Such a classification helps to systematically and practicably describe variability within fine-grained sedimentary rocks. What's more, the classification provides an important method to help us study the hydrocarbon exploration, especially shale oil and gas.


The work presented in this paper was supported by the Certificate of China Postdoctoral Science Foundation (No. 2015M582165), the National Natural Science Foundation of China (Nos. 41602142, 41772090), the National Science and Technology Special (No. 2017ZX05009-002). We are grateful to the Geoscience Institute of the Shengli Oilfield, SINOPEC, for permission to access their in-house database. The final publication is available at Springer via

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