Analysis of the Geological Conditions for Shale Gas Accumulation

Keywords: geological conditions, shale gas, Carboniferous, marine-continental. 24 transitional facies, Bayanhot Basin. 25. 1. Introduction. 26. Shale ...
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Analysis of the Geological Conditions for Shale Gas Accumulation: Two Different Carboniferous Marine-Continental Transitional Facies in the Bayanhot Basin, China Hongliang Wang,*,† Jintong Liang,† Xiaohui Li,‡ Xinyuan Ji,† Qixian Zhang,† and Rongjie Huang† †

School of Energy Resources, China University of Geosciences (Beijing), Beijing 100083, China Bohai Oil Research Institute, Tianjin Branch of CNOOC Ltd., Tianjin 300452, China

‡

ABSTRACT: The sedimentary environment plays an important role in the enrichment of shale gas resources. In this paper, the characteristics of the marine-continental transitional sedimentary environments in the Bayanhot Basin are studied via laboratory analysis, scanning electron microscopy, and comparative analyses of field data. A differential analysis of the shale gas enrichment conditions was conducted by comparing the shale organic geochemical characteristics and performing a petrophysical analysis of the southern and northern sedimentary environments in the Bayanhot Basin. The findings showed that (1) the hydrocarbongenerating potential of the shale in the northern delta sedimentary environment is better than that of the shale in the southern combined sedimentary system based on the total organic carbon content and organic matter type and (2) the shale in the southern Bayanhot Basin, which has better shale petrophysical microcharacteristics, presents superior gas accumulation and fracturing operation characteristics compared to the shale in the northern part.

1. INTRODUCTION Shale gas is an unconventional type of natural gas that is generated and stored in shale and is extensively developed throughout China.1,2 With the success of shale gas exploration in America,3−5 a breakthrough has been made in the exploration of marine and continental shale formations in China.1,6,7 Previous investigations2,5,8,−10,13 revealed that shale deposited in marinecontinental transitional sedimentary facies was mainly formed during the Carboniferous and Permian,8 which has recently been the subject of heated discussions because of the wide distribution of shale gas in northwest China and northeast China, such as in the Sichuan Basin, Ordos Basin, and Qaidam Basin.1,2,11−13 Most of the published studies of the Bayanhot Basin and regional tectonic characteristics have focused on the organic geochemical and petrophysical characteristics of shale reservoirs and shale gas accumulation mechanisms and controlling factors. However, because of the lateral variability of the sedimentary environment and the vertical variability of the lithology, the characteristics of shale gas accumulation and properties of shale reservoirs in marine-continental transitional sedimentary facies have not been well studied. Therefore, a systematic understanding of shale gas accumulation in different marine-continental transitional sedimentary facies in the Bayanhot Basin has not been established, and further studies of the differences in the depositional systems and their potential impact on shale gas generation and accumulation must be performed. Such studies would provide reference values for the exploration and exploitation of mineral resources in shale. The Bayanhot Basin developed a series of sedimentary facies in the Carboniferous that provide favorable conditions for oil and gas generation and accumulation.14,15 Recently, considerable attention has focused on the types and characteristics of Carboniferous shale reservoirs to determine the controlling effects of sedimentary facies on shale gas accumulation. In this study, we present data on the organic geochemical characteristics © XXXX American Chemical Society

and reservoir petrophysical characteristics of shale samples collected from delta sedimentary facies (DSF) and a combined sedimentary system (CSS) of barrier islands, lagoons, and tidal flats. These data together with information on outcrops are used to (1) compare the organic geochemical characteristics and reservoir petrophysical characteristics of the shale from two marine-continental transitional facies and (2) analyze the differences in the geological conditions of the shale in these two facies. In this study, our results emphasize how different marine-continental transitional facies affect the generation and accumulation of shale gas. Specifically, the DSF provides a better setting than the CSS in terms of shale gas generation conditions. However, the CSS shale has better permeability than the DSF shale, which makes the CSS more suitable for shale gas accumulation.

2. GEOLOGICAL SETTING Bayanhot Basin, developed on the crystalline basement of the North China Block, has a total area of approximately 1.8 × 104 km2 and is located at the junction of three geotectonic formations: the Ordos Block, Alashan Block, and Qilianshan Mountains Fold belt (Figure 1). This basin shows an “L” pattern in its tectonic framework, which is characterized by a double superimposition of a Carboniferous inland depression and Mesozoic fault-depression.16 Regarding the control of the basin basement characteristics and paleogeographical pattern, Luozishan divides the basin into two different sedimentary facies, which are known as the DSF in the northern area and the CSS in the southern area (Figures 1 and 2). Received: February 28, 2017 Revised: September 4, 2017 Published: September 19, 2017 A

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Figure 1. Map showing the location and the Carboniferous sedimentary system of the Bayanhot Basin. Part A shows the location of the Bayanhot Basin. Part B shows the regional tectonic framework in North China. Part C shows the Carboniferous sedimentary system of the Bayanhot Basin, which consists of the north DSF and the south CSS. Locations of the sampling sites (S1−S10) are also marked. For some sites, more than one sample was collected. the northern DSF shale and the southern CSS shale were utilized to create Venn diagrams. Based on these ternary diagrams and Venn diagrams, the organic matter types in the shale samples were identified. The organic matter maturity of these shale samples was determined by the vitrinite reflectance (Ro) using the GB/T 19145−2003 standard.17 The above methods were used to analyze the effects of the shale geochemical characteristics on shale gas generation in different Carboniferous marine-continental transitional sedimentary facies. 3.3. Shale Petrophysical Analysis. Because the shale petrophysical condition is controlled by the mineral components and internal flow channels, this study utilized X-ray diffraction experiments to determine the mineral components of the shale samples and clarify how they affect the shale gas storage capacity. In addition to the mineral analysis, we also used scanning electron microscopy (SEM) to identify the sizes and types of micropores. The above methods were used to analyze the effects of shale geochemical characteristics on shale gas accumulation in different Carboniferous marine-continental transitional sedimentary facies.

Bayanhot Basin experienced three developmental stages in the Carboniferous: evaporation of the sea basin in the earlier period, a shallow sea basin in the middle period, and an extensive sea and continental margin in the later period.14 Concurrently, a series of strata that include the Former Heishan formation, Chouniugou formation, Jingyuan formation, Yanghugou formation, and Taiyuan formation were developed. Shales can be found in each formation in the basin. Specifically, these shales are mainly deposited in carbonate rocks and clastic rocks. In these sedimentary rocks, dark mudstone, coal, and bioclastic limestone, which are rich in biogenic organic matter, are the main types of gas source rocks (Figure 3). Bioclastic limestones are mostly formed in the CSS, whereas clastic rocks are mostly developed in the DSF. The average thickness of the shales is between 300 and 500 m, and the thickest formation developed in the northeast basin at a depth of approximately 700 m. However, the vertical thickness and horizontal distribution in each formation show large differences. The northern sample 2 developed brownyellow and dark gray cross layers, medium sandstones, to sandstones and mudstones with coal and shale layers, whereas the southern sample 9 mainly developed dark carbonaceous mudstones and shales with grayish green and silty mudstone.

4. RESULTS 4.1. Shale Organic Geochemical Characteristics. The type, abundance, and maturity of organic matter are the three important indices for evaluating shale gas accumulation.18,19 Therefore, we compared the organic geochemical characteristics of shale in the DSF and the CSS by qualitatively and quantitatively evaluating these three indices. 4.1.1. Organic Matter. The abundance of organic matter can be described by the TOC content; therefore, the abundance analysis in this study consisted of analyzing the TOC values. The TOC analysis detected obvious differences between the shale samples from the DSF and the CSS (Table 1). The average TOC contents in the northern delta shale vary from 2.25% to 5.59%, and the highest TOC content of a single sample can reach 8.31%. In comparison, the average TOC contents in the southern lagoon (the CSS) shale are relatively low. The TOC contents of sample 6 and 8 are below 1%, and the content of sample 7 is only 1.76%. This comparison indicates that organic matter is more abundant in the northern DSF shale than in the southern CSS shale. 4.1.2. Organic Matter Type. The results of the shale kerogen analysis show that the Carboniferous types of organic matter in the Bayanhot Basin are mainly composed of vitrinite and exinite

3. DATA AND METHODS 3.1. Data. The data used in this paper include organic geochemical data and petrophysical data on 432 shale samples. All of the samples were collected from typical field sections of the Bayanhot Basin. Of these, 85 samples were collected in the Bayanhot Basin for this study, and 347 samples were collected in previous studies. All samples were sent to be tested in the Energy Resources Laboratory of the China University of Geosciences (Beijing), and the data analysis was also performed at this laboratory. 3.2. Shale Organic Geochemical Analysis. We analyzed the shale organic matter abundance by comparing the total organic carbon (TOC) contents of the northern DSF shale samples and the southern CSS shale samples. This experiment was performed with a TOC analyzer using the standard GB/T 19145−2003.17 Based on the kerogen maceral data of the northern DSF shale and the southern CSS shale, data points were plotted in ternary diagrams. The contents of H, C, and O in B

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the data points distributed around the exinite + amorphous part, with the contents ranging from 60% to 90%. This maceral distribution indicates that types II1−II2 kerogens are the main types of organic matter in the southern CSS shale. The kerogen elemental composition in the southern Bayanhot Basin shows that the shale consists of type II and III kerogen (Figure 5b). 4.1.3. Organic Matter Maturity. Because the Ro index can show the maturity of organic matter, this study examines 19 shale samples from both the northern and southern sections in terms of their Ro values (Table 2). The Ro values of the northern DSF shale vary from 0.97% to 2.52%, and those of sample 1 and sample 2 are above 1%. Similarly, the Ro values of the southern CSS shale range from 0.88% to 2.54, and most are higher than 1%. The Ro data analysis indicates that 85% of the samples have values ranging from 1.3% to 2.55%, which means that the organic matter in most of the samples is in the maturation to high maturation stage. For the northern and southern parts of the Bayanhot Basin, significant differences were not observed in the Ro values of the shale samples. Thus, the sedimentary environments did not play a decisive role in the evolution of the organic matter, which was likely controlled by factors that include the sediment deposition time and burial depth. 4.2. Shale Petrophysical Characteristics. In the study of conventional reservoirs, the controlling factors of reservoir storage capacity are determined by analyzing the petrophysical characteristics. This method is also applicable for the study of shale reservoirs. This chapter mainly presents the mineral and petrophysical characteristics of the shale in the northern DSF and the southern CSS. 4.2.1. Mineral Characteristics. The X-ray diffraction results show that the shale in the Bayanhot Basin presents a series of complex mineral components in the following order: clay mineral content > brittle mineral content (including quart, calcite, dolomite, and feldspar) > pyrite and siderite content. In the northern DSF (Figure 6), clay minerals account for 46% to 95% of the total mineral content, with an average rate of 70.01%. Quartz accounts for 20% to 35% of the total content, whereas other minerals account for less than 5%. In the southern CSS (Figure 7), the clay minerals account for 43% to 75% of the total mineral content, with an average rate of 57.4%. Brittle minerals account for 25% to 45%, with quartz accounting for the highest proportion at 20% to 30%. Other brittle minerals, such as potassium feldspar and plagioclase, are also found. Pyrite and siderite are also distributed in both the northern DSF and the southern CSS, although the contents of these minerals in the southern basin are higher than that in the northern basin, and the content of carbonate minerals has a similar distribution. 4.2.2. Porosity and Permeability Characteristics. The petrophysical characteristics of the shales show that the effective porosities of all samples vary from 6% to 9.5%, and the permeability is approximately 0.01 × 10−3 μm2 (Table 3). A significant difference in porosity and permeability is not observed between the northern DSF and southern CSS, although differences in the microscopic characteristics of the shale samples in the two sedimentary facies can be observed in the SEM images (Figure 8). Microcracks are widely developed in the shale samples. Specifically, the scales of the fractures and pores are at the microsize, and the width and length fall within the micrometer to tens-of-micrometer range. However, the southern CSS develops more micropores, which have diameters greater than 10 μm, than the northern DSF. Moreover, the pore diameters in the southern CSS range from 10 to 100 μm, with the majority between 30 and 40 μm.

Figure 2. Synthetic stratigraphic column of the Carboniferous Bayanhot Basin. The column data consists of three profiles collected in the Bayanhot Basin. Form. = Formation; Thk = Thickness; S.S. = Sedimentary structure; S.F. = Sedimentary Facies; S.L. = Sampling location.

+ amorphous components (Figures 4 and 5), and the contents vary over a wide range. The ternary diagram of the kerogen maceral in the northern DSF shale can be divided into two parts (Figure 4a). Approximately 70% of the data points are centrally distributed around the vitrinite part, with vitrinite contents ranging from 65% to 90%. Approximately 30% of the data points are distributed around the exinite + amorphous part, with contents varying from 55% to 90%. This distribution generally indicates that the organic matter in the northern DSF shale is mainly composed of type III kerogen. The kerogen elemental composition data for the northern Bayanhot Basin also show the same kerogen type (Figure 5a). The data distribution of the kerogen maceral in the southern CSS shale is relatively simple (Figure 4b), with more than 90% of C

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Figure 3. Comparison of stratigraphic combination and their vertical variation from two wells. Well 9 is located in the CSS and well 2 is located in the DSF. Form. = Formation; Thk = Thickness.

4.3. Gas-Bearing Analysis. In this study, four shale samples were used to simulate isothermal adsorption (Figure 9). The results show that when the pressure is greater than 10.16 MPa, the absorption content tends to equilibrate. In the DSF, the absorption content values of shale samples 1 and 2 are both approximately 2 m3/t. Sample 1 shows an absorption content value of 2.32 m3/t, whereas sample 2 shows a value of 2.20 m3/t, and obvious differences in the absorption content were not observed for the DSF. The two samples from the CSS have higher absorption contents than the DSF samples. Sample 9 shows a particularly high value of 7.22 m3/t, and sample 10 has a value of 3.70 m3/t. One shortcoming of the database used in this study is that real absorption values are not available. Nevertheless, the results of the isothermal adsorption simulation can generally reflect the real gas absorption capacity. Studies have shown that real absorption values are 0.5 to 1 times the magnitude of simulated

Table 1. Average TOC Content in Different Carboniferous Sedimentary Environment Shales in the Bayanhot Basina sedimentary facies

sample

TOC (%)

DSF

1 2 3 4 5 6 7 8

2.71(103) 2.39(22) 5.59(107) 5.41(18) 2.25(2) 0.81(133) 1.76(39) 0.62(8)

CSS

a

The numbers of samples used in the calculation of a given sample (well) are shown in brackets. All samples were collected from wells and sites from sections in the basin. See Figure 1 for the sampling location.

D

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Figure 4. Ternary diagrams showing the kerogen maceral of shale samples in the Bayanhot Basin. The green data points in part a show the northern DSF shale samples, which are mainly one of two types. The blue data points in part b show the organic matter types of the southern CSS shale samples.

Figure 5. Venn diagrams showing the kerogen elemental compositions of the shale samples in the Bayanhot Basin. The green data points in part a represent shale samples in the northern DSF, and the blue data points in part b represent the samples in the southern CSS.

5. DISCUSSION 5.1. Impacts of the Shale Geochemical Characteristics on Shale Gas Generation in Different Sedimentary Facies. It is widely accepted that in a certain geological period, the development of biological species can be determined by the biological evolutionary processes. Furthermore, the species diversity and conservation of organic matter are also controlled by the sedimentary environment (Figure 3). Consequently, the organic matter type and maturity vary according to the sedimentary environment. In addition, the distribution of mudrich shale is affected by changes in the sedimentary facies zone in the transverse and vertical directions. Analyses of the controlling effects of sedimentary facies on shale characteristics indicate that shelf-margin delta shale accumulates more gas than lagoon shale. The direct comparison of the organic matter abundance in our study supports this insight by demonstrating that the northern DSF is a more favorable area for shale gas exploration than the southern CSS. As

Table 2. Average Ro Range in Different Carboniferous Sedimentary Environment Shales in the Bayanhot Basina sedimentary facies

sample

Ro (%)

DSF

1 2 5 6 7 8

1.03−1.95 0.97−1.48 2.29−2.52 2.32−2.54 0.88−2.0 1.36−1.37

CSS

a

All samples were collected from wells and sites from the sections in the basin. See Figure 1 for the sampling locations.

values. Therefore, the shales in the CSS have better conditions for gas accumulation than the shales in the DSF. E

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Figure 6. Bar chart of whole rock-mineral analysis of the northern DSF. All the samples are selected from sampling site 1, 2 and 5 (see Figure 1 for sample location). Of all the samples, they are mainly composed of clay minerals while the content of brittle minerals varies from sample to sample. For each sampling site, more than one sample was collected. S5-001 means sample 1 collected at sampling site 5.

Figure 7. Bar chart of whole rock-mineral analysis of the southern CSS. All the samples are selected from sampling site 6 (see Figure 1 for sample location). S6-002 means sample 2 collected at sampling point 6. Compared with samples in the northern DSF, they are more kind of brittle minerals varies with varied range of content.

and southern basins are likely responsible for the distribution of organic matter. Based on the results of our study, the following conclusions can be drawn: 1. Because the DSF is to the north of the CSS (Figure 1), it was more likely to be affected by a continental sedimentary environment during periodic water level fluctuations.14,20,21 Although the analysis of the organic matter type indicated that most of the data points from the CSS and DSF shale are distributed in the type III area (Figure 5), most of the data from the CSS shale should be calibrated to the original type II area if the surface weathering is considered in the kerogen degradation. 2. The organic matter maturity analyses did not identify significant differences between the DSF shale and the CSS shale (Table.2), which is likely because of the lack of direct and obvious connections between the sedimentary facies and Ro values. However, certain factors, such as the subsurface temperature and burial depth, may play major roles in the process of organic matter maturation. 5.2. Impacts of the Shale Petrophysical Characteristics on Shale Gas Accumulation in Different Sedimentary Facies. Although the sedimentary environment, ancient water depth, sedimentary type, and paleoclimate directly affect the development of shale, the sedimentary environment is the most important for the shale formation process.24,25 In this study, the sedimentary environment is the main controlling factor for the development of organic shale. Under a predominantly sedimentary environment, less clay minerals and more brittle

Table 3. Petrophysical Characteristics of Carboniferous Shale Samples in the Bayanhot Basina section

sample

density (g/cm3)

effective porosity (%)

permeability (10−3μm2)

1

1−004 1−029 6−015 6−016 6−027 6−038

2.5 2.15 2.22 2.44 2.13 2.31

9.2 6.9 6.3 7.5 6.1 6.2

0.07 0.0086 0.9112 0.0165 0.0153 0.0148

6

The first two samples are selected from sample 1 (see Figure 1 for sampling location) from the northern DSF and the other samples are selected from sample 6 (see Figure 1 for sampling location).

a

explained by the organic geochemical characteristics of the shale in the Bayanhot Basin, the shales in the northern DSS is characterized by higher organic carbon contents (8.31%) and hydrocarbon potential. However, the organic carbon content is relatively low (1.76%) in the southern CSS. A reasonable explanation for this phenomenon may be found in the sediment sources of these two sedimentary systems. The sediment source of the CSS in the southern basin is lower aquatic organisms, whereas the sediment source of the DSF in the northern basin is primarily terrigenous clastic sediments as well as lower aquatic organisms. The multiple sediment sources provide more possibilities for the northern basin to accumulate more organic carbon. Therefore, the different sediment sources of the northern F

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Because the content of quartz is correlated with the gas accumulation,1,22 the southern CSS shale has the better conditions for gas preservation than the northern DSF shale. Although a positive correlation is observed between the content of clay and gas accumulation in a limited range, this correlation becomes invalid once the content of clay exceeds a certain threshold. Consequently, the good gas preservation area in this study is selected regardless of the content of clay. 2. The proper content of brittle minerals is crucial in the fracturing process during shale gas exploitation. Experiments23 have shown that the optimal content of brittle minerals in shale that benefits shale gas exploitation ranges from 30% to 40%. The average content of brittle minerals in the DSF shale is approximately less than 20%, whereas the content of the CSS shale ranges from 30% to 40%. In brief, the CSS shale in the southern basin is more suitable for preserving gas because of the content of brittle minerals. 3. Pyrite, siderite, and anhydrite are usually retained in a reducing environment, and the content of these minerals was higher in the southern basin; thus, the CSS is characterized by a salty lagoon and reducing environment. A reducing environment could protect organic matter from oxidation. The mineral distribution in the southern and northern basins suggests that the CSS is a more suitable gas preservation area. 4. The space for the accumulation of gas, especially free gas in shale is composed of pores, throats, and fractures of various sizes and their interconnections.2 Compared with the northern DSF, the southern CSS developed more micropores of different sizes, which led to its high permeability. In addition, the high content of brittle minerals retains the high permeability because these minerals have good anticompaction characteristics. Therefore, the southern CSS can absorb more shale gas, especially free gas.

Figure 8. SEM images of typical shale samples in the Bayanhot Basin. Sample A (S10-002), Sample C (S10-007) and Sample D (S6-003) were selected from the southern CSS. Sample B (S1-012) was selected from the northern DSF. Sample A: SPD = 1−16 μm, CPD = 30−70 μm. Pyrite crystallite can also be found in sample A. Sample B: SPD = 1−10 μm. Micropores are widely developed in sample B. Sample C has widely developed cleavage cracks, SPD = 1−7 μm, CCD = 1−2 μm. Sample D: SPD = 1−6 μm, CPD = 35−100 μm, CCD = 1−2 μm. (CPD = composite pore diameter; SPD = single pore diameter; LPD = larger pore diameter; CCD = cleavage crack width).

minerals are developed in the CSS. Studies have also indicated that microfractures controlled by brittle minerals provide good accumulation conditions for shale gas in a reducing environment (developed in the CSS). Shale gas output varies according to the mineral composition and petrophysical characteristics. With the southward transition of sedimentary environments from continental to marine, the shale petrophysical characteristics also change. As a result, the following conclusions were drawn: 1. In this transition of facies from continental to marine sedimentary environments, the shale in the southern CSS developed more quartz than the shale in the northern DSF.

6. CONCLUSIONS In this study, the comparison of the geochemical and petrophysical characteristics of shale in the different facies provided the most relevant information on the shale gas accumulation conditions in the two different Carboniferous marine-continental transition facies. Considering all available data, the following conclusions were drawn:

Figure 9. Simulated isothermal adsorption. Samples 9 and 10 were collected from the CSS, and sample 1 was collected from the DSF. See Figure 1 for sampling locations. G

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(8) Jarvie, D. M.; Hill, R. J.; Ruble, T. E.; Pollastro, R. M. Unconventional shale-gas systems: The Mississippian Barnett Shale of north-central Texas as one model for thermogenic shale-gas assessment. AAPG Bull. 2007, 91 (4), 475−499. (9) Kharaka, Y. K. Petroleum formation and occurrence: a new approach to oil and gas exploration. Earth-Sci. Rev. 1980, 16, 372−373. (10) Bao, S. J.; Lin, T.; Nie, H. K.; Ren, S. M. Preliminary study of the transitional facies shale gas reservoir characteristics: Taking Permian in the Xiangzhong depression as an example. Earth Science Frontiers 2016, 23 (1), 44−53. (11) Shao, L. Y.; Li, M.; Li, Y. H.; Zhang, Y. P.; Lu, J.; Zhang, W. L.; Tian, Z.; Wen, H. J. Geological characteristics and controlling factors of shale gas in the Jurassic of the northern Qaidam Basin. Earth Science Frontiers 2014, 21 (4), 311−322. (12) Yan, D. Y.; Huang, W. H.; Zhang, J. C. Characteristics of marinecontinental transitional organic-rich shale in the Ordos Basin and its shale gas significance. Earth Science Frontiers 2015, 22 (6), 198−206. (13) Zhou, S.; Chen, S. B.; Si, Q. H.; Han, Y. F.; Zhang, C. Taiyuan shale gas accumulation characteristics in eastern Ordos Basin. Special Oil and Gas Reservoirs 2016, 23 (1), 38−43. (14) Wei, P. S.; Li, T. S.; Li, A. C.; Wang, J. G. Carboniferous Sedimentary Evolution and Reservoir Estimation in BayanhotBasin. Acta Sedimentologica Sinica 2005, 23 (2), 239−246. (15) Gao, B. S.; Wang, G. Evolution Characteristics and Petroliferous Evaluation in Bayanhaote Basin. Journal of Chongqing University of Science and Technology (Natural Science Edition) 2011, 13 (4), 22−25. (16) Wei, P. S.; Tan, K. J. Characteristics and estimate of carboniferous source rocks in BayanHot Basin. Petroleum Geology and Experiment 2009, 31 (6), 615−627. (17) Determination of total organic carbon in sedimentary rock, 2003; China National Standard GB/T 19145−2003. (18) Fan, C. Y.; Wang, Z. L. Geological factors and process in enrichment and high production of shale gas. Petroleum Geology and Experiment 2010, 32 (5), 465−469. (19) Wang, X.; Liu, Y. H.; Zhang, M.; Hu, S. Y.; Liu, H. J. Conditions of formation and accumulation for shale gas. Natural Gas Geoscience 2010, 21 (2), 350−256. (20) Liang, D.; Guo, T.; Bian, L.; Chen, J.; Zhao, Z. Some progresses on studies of hydrocarbon generation and accumulation in marine sedimentary regions, southern china (part 3): controlling factors on the sedimentary facies and development of palaeozoic marine source rocks. Marine Origin Petroleum Geology 2009, 14 (2), 1−19. (21) Wei, J. S.; Lu, J. C.; Wei, X. Y.; Han, W.; Jiang, T. The influence of intense weathering on the evaluation indexes of hydrocarbon. Geological Bulletin of China 2012, 31 (10), 1715−1723. (22) Zhang, J. C.; Jin, Z. J.; Yuan, M. S. Reservoiring mechanism of shale gas and its distribution. Natural Gas Industry 2004, 24 (7), 15−17. (23) Li, Q. H.; Chen, M.; Jin, Y.; Hou, B.; Zhang, J. Z. Rock mechanical properties and brittleneses evaluation of shale gas reservoir. Petroleum Drilling Techniques 2012, 40 (4), 17−22. (24) Loucks, R. G.; Reed, R. M.; Ruppel, S. C.; Jarvie, D. M. Morphology, genesis, and distribution of nanometer-scale pores in siliceous mudstones of the Mississippian Barnett shale. J. Sediment. Res. 2009, 79 (11−12), 846−861. (25) Curtis, J. B. Fractured Shale-Gas Systems. AAPG Bull. 2002, 86 (11), 1921−1938.

(1) Compared with the southern CSS shale of the Bayanhot Basin, the shale in the northern DSF is characterized by a higher abundance of organic matter, which is predominantly type III. Consequently, the northern DSF shale has better hydrocarbon-generating conditions under the same organic matter maturity conditions. (2) Regarding the composition of minerals, the southern CSS shale contains a moderate content of clay minerals and a high content of brittle minerals compared with the northern DSF shale. This mineral composition leads us to conclude that the CSS shale is more suitable for gas accumulation. (3) Because of the diversity in pore structures and the combination of pores of different sizes in the shale in the southern basin, the CSS shale has better reservoir quality compared with the DSF shale because of the superior permeability and gas storage capacity. (4) Under the control of a sedimentary environment, two Carboniferous marine-continental transition facies developed different shales with different shale gas generation and accumulation abilities. Therefore, shale gas exploration and exploitation in the Bayanhot Basin should be undertaken according to the local geological conditions.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. ORCID

Jintong Liang: 0000-0002-3787-177X Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This study was partially funded by the National Science and Technology Major Project (Grant No. 2016ZX05033-002), Key Laboratory of Marine Reservoir Evolution and Hydrocarbon Accumulation Mechanism, Ministry of Education; Key laboratory of strategy evaluation for Shale gas, Ministry of Land and Resources. We thank ACS ChemWorx for its linguistic assistance during the preparation.

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REFERENCES

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DOI: 10.1021/acs.energyfuels.7b00611 Energy Fuels XXXX, XXX, XXX−XXX