Characterization of the Lower Cambrian Shale in the Northwestern Guizhou Province, South China: Implications for Shale-Gas Potential

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1 pubs.acs.org/ef Characterization of the Lower Cambrian Shale in the Northwestern Guizhou Province, South China: Implications for Shale-Gas Potential Junpeng Zhang,, Tailiang Fan,*,, Jing Li, Jinchuan Zhang,, Yifan Li,, Yue Wu,, and Weiwei Xiong School of Energy Sources, China University of Geosciences, Haidian, Beijing , China Key Laboratory of Marine Reservoir Evolution and Hydrocarbon Accumulation Mechanism, Ministry of Education, China University of Geosciences, Beijing , China School of Earth Science and Sources, China University of Geosciences, Haidian, Beijing , China SNTO, Suntown Industrial Park, No.109 Jinxing Road, Changsha, Hunan, China ABSTRACT: The Lower Cambrian shale in the Northwest part of the Guizhou Province (NWG), South China, has recently been considered as a potential shale gas reservoir because of its large distribution and high total organic carbon (TOC) content. An integrated characterization about this shale succession is provided in this study to illustrate its shale gas potential. The shale in the NWG area is characterized by high TOC content and high thermal maturity. The mineralogical composition and lithofacies assemblage of the NWG shale are compared with hot shales for analogy and found to be greatly similar to the Barnett shales. Five different genetic types of pores have been identified by scanning electron microscopy. The porosity shows no correlation with the quartz and clay ratios, but it correlates well with the TOC content, suggesting that organic matter pores have contributed a lot to the total porosity. The pore size distribution is evaluated by pore volume and surface area based on diameter, indicating that the micropores and mesopores are the major pore sizes. The methane sorption isotherms conducted on representative samples with different TOC and clay contents certify the assumption that microporous organic matter in high-maturity shales provides a large internal surface area for the adsorbed gas. After comprehensive analysis, the lower part of the studied shale in the NWG, with high TOC contents, is proposed as a target for shale-gas production. 1. INTRODUCTION The remarkable success of shale-gas production has inspired more extensive exploration activity in other countries, such as China and Australia, especially after the United States achieved its energy independence transitioning from import to export of nature gas (EIA, 2015). To accommodate the national energy demand, a variety of exploration strategies have been carried out by the Ministry of Land and Resources (MLR) in South China, in an attempt to achieve commercial production of shale gas. It has been reported that the geologic reserves of shale gas in the Guizhou province could amount to 1048 billion m 3 (MLR, Thus, the MLR cooperated with the state of Guizhou province and China University of Geosciences in Beijing (CUGB) and has constructed more than 75 drilling wells from 2013 to the present. The Northwestern area of Guizhou province (NWG) was selected as the priority because the shale is of considerable thickness and was found to have a higher TOC content in the early exploration stage. Quite a few wells have been drilled in the NWG before, except the Cenye-1 well operated in 2012 in the Northeast part of the Guizhou province (NEG). 1,2 This study is an overall investigation report on the RY1 well and the RY2 well in Renhuai city in the NWG area. These two geological investigation wells have depths of 1400 and 960 m, respectively. The NWG area is viewed as an intrashelf basin located in the Upper Yangtze Block, where shallow sea sedimentary environments occurred in the Early Cambrian. 2 4 With the occurrence of the second major marine transgression from the Southeast to the Northwest, the sea level rise of the Yangtze Sea promoted high productivity in the surface water and anoxic conditions in the bottom water in the open marine and continental shelf environments. Thus, organic matter accumulated within the marine mudstone or chert, covering the Sinian dolomite with a submerged unconformity. 2 4 The Tongwan tectonic movement at the end of the Proterozoic caused this disconformity between the Ediacaran and lower Cambrian strata. 4 The strata of mainly shales for this interval are usually named the Niutitang Formation, with a total thickness ranging from 24 to 200 m in the south and north Sichuan Basin, west Hunan and Hubei Provinces, and north Guizhou and Yunnan Provinces (Figure 1). 3,4 The Lower Cambrian in the NWG area mainly consists of chert, shales, and carbonate rocks, the shale interval of which has been investigated as one of the important Phanerozoic source rocks for conventional oil and gas sources. 2 5 Recently, the lower part of the Niutitang Formation has been reported as a potential for shale gas according to geochemical analysis of samples from the Cenye-1 well and some outcrops in the NEG. 1,6 The shale distribution, organic matter richness, thermal maturity and mineralogical composition can be totally compared to the Barnett shale, which is often selected as an exploitation model in previous studies. 2,4 Here Received: July 29, 2015 Revised: September 14, 2015 Published: September 15, American Chemical Society 6383

2 Figure 1. Locations of the investigated wells and stratigraphic column of the Cambrian in the NWG. The biota data is from Zhang et al. (2013). we provide a comprehensive characterization of the Lower Cambrian shale in the NWG, including investigation of geochemical characteristics, mineralogical composition, porosity analysis, and gas adsorption capacity, which contributes to an improved evaluation of the shale gas potential. 2. MATERIALS AND METHODS 2.1. Samples. A total of 98 samples were collected from both the RY1 well and the RY2 well based on core observation and log response, including chert, siliceous mudstone, calcareous mudstone, and silty mudstone samples and also a phosphatic nodule from the basal strata. All experiments below were conducted in standard procedures to ensure their analytical accuracy Methods. To achieve a comprehensive characterization of the NWG shale, total organic carbon (TOC), vitrinite reflectance (Ro), kerogen type index (TI), mineralogy (X-ray diffraction, XRD), porosity, pore size distribution, and gas adsorption capacity (methane adsorption experiments) were determined (Table 1). Meanwhile, visual evaluation via thin section and scanning electron microscopy (SEM) were performed at the China University of Petroleum, Beijing (CUPB). The well log data were shared from the MLR. Herein, TOC contents of all 98 samples were determined by a TL851-5A type high frequency infrared carbon and sulfur analyzer and reported on a raw sample basis as percent. Rock- Eval pyrolysis was performed on only 10 samples. Visual measurements of organic macerals and Ro were also conducted on 20 samples. All geochemical experiments above were completed in the Petro China, Huabei Oilfield Branch (PC- HOB). A total of 31 samples were analyzed by an XRD analyzer to determine the mineralogical composition, including one chert sample and one limestone sample. The primary minerals like quartz, feldspar, calcite, dolomite, pyrite, and clay were determined. The settings were 40 kv and 30 ma. Measured data were then analyzed qualitatively using the EVA (Bruker) software and quantitatively using the AutoQuant software. This Table 1. Investigated Samples and Applied Measurements (except TOC, as all 98 samples were analyzed for TOC) Ro XRD porosity and permeability N 2 gas adsorption methane sorption isotherm (n = 20) (n = 31) (n = 18) (n = 11) (n =5) RY1-49 RY1-47 RY2-48 RY1-45 RY1-49 RY1-41 RY1-40 RY1-35 RY2-43 RY1-37 RY1-35 RY1-30 RY1-38 RY1-29 RY2-39 RY1-29 RY1-28 RY1-24 RY1-34 RY1-28 RY2-36 RY1-24 RY1-22 RY1-13 RY1-26 RY1-22 RY2-33 RY1-22 RY1-09 RY1-02 RY1-22 RY1-21 RY2-31 RY1-13 RY2-26 RY1-19 RY1-17 RY2-28 RY1-09 RY2-12 RY1-16 RY1-13 RY2-26 RY1-04 RY2-10 RY1-07 RY1-09 RY2-25 RY2-26 RY2-07 RY1-02 RY1-08 RY2-14 RY2-23 RY2-05 RY2-5 RY1-07 RY2-08 RY2-18 RY2-03 RY2-38 RY1-06 RY2-12 RY2-14 RY2-36 RY1-04 RY2-10 RY2-12 RY2-31 RY1-02 RY2-07 RY2-10 RY2-26 RY2-05 RY2-09 RY2-23 RY2-03 RY2-07 RY2-18 RY2-01 RY2-05 RY2-12 RY2-03 RY2-07 RY2-03 experiment was conducted at the Analytical Laboratory of the Beijing Research Institute of Uranium Geology (AL-BRIUG). Porosity was determined by Hg porosimetry using an Autopore IV 9510 series porosimeter. Pore size distribution was evaluated by N 2 gas adsorption, and the methods of Brunauer Emmett Teller (BET) and Barrett Joyner Halenda (BJH) were employed for calculation. 7,8 Pores were divided into three types according to their diameter: micropore (<2 nm), mesopore (2 50 nm), and macropore (>50 nm). 9 Methane sorption isotherms were conducted on five representative samples from the RY1 well with different TOC 6384

3 Table 2. TOC and Ro of the Lower Cambrian Shale in the NWG samples depth (m) TOC (%) Ro (%) samples depth (m) TOC (%) Ro (%) RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY and clay contents under a modeled reservoir temperature of 49 C. The Langmuir isotherm method was employed to model the gas adsorption capacity, V = V L P/(P L + P), where V is the volume of absorbed gas, V L is the Langmuir volume which is the maximum adsorption capacity of the absorbent, P is the gas pressure, and P L is the Langmuir pressure, at which the absorbed gas content (V) is equal to half of the Langmuir volume (V L ). 10 These three experiments were conducted at the Research Institute of Petroleum Exploration and Development, Langfang Branch, China (RIPED-LB). 3. RESULTS AND DISCUSSION 3.1. Geochemical Characteristics. Total organic carbon (TOC) contents and bitumen reflectance values for samples from the RY1 well and RY2 well in the NWG are presented in Table 2. TOC concentrations vary from 0.37% to 14.68% for the RY1 core with an average of 4.8% and range from 0.37% to 11.83% for the RY2 core with a mean value of 5.91%, highly similar to those of the Lower Cambrian shale in Sichuan Basin, South China. 16 TOC contents for both cores show a decreasing trend upward, achieving peak values in the lower part of the 6385

4 Figure 2. Lithological column of the RY1 and RY2 wells with log curves. MXS: Mingxisi Formation; DY: Dengying Formation. from 2% to 3.11%, which are lower than those of the RY1 core, probably due to the smaller burial depth. To determine the kerogen type of the organic matter in the shale, maceral analyses were carried out on 11 samples from the lower and middle parts of both cores. Visual assessments of the trend (Figure 2). The interval composed of mainly siliceous and calcareous mudstone has high TOC contents with average values more than 6%. Ro values for the RY1 core vary from 3.07% to 4.56%, indicating a thermal maturity of gas window or over-matured. Similarly, Ro values for the RY2 core range 6386

5 Table 3. Rock-Eval Results of Core Samples (Tmax = (Ro )/0.018) samples depth (m) TOC (%) S1 (mg/g) S2 (mg/g) HI (mg HC/g TOC) Tmax ( C) Ro (%) caculated from Tmax Measured Ro (%) RY RY RY RY RY RY RY RY RY RY Table 4. Mineralogical Analysis Results for Core Samples samples depth (m) quartz (%) feldspar (%) calcite (%) dolomite (%) pyrite (%) clay (%) RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY kerogen reveal the presence of 95 98% amorphous organic matter with a mainly sapropelic substance. A small amount (1 5%) of terrestrial organics may also be found. The kerogen type index (TI) ranges from 90.5 to 96.5, confirming sapropelic (Type I) as the kerogen type. Here the TI is used as an index counting percentage compositions of different macerals to decide the kerogen type. However, with the maturity of organic matter above 2.5%, original maceral structures are usually hard to differentiate leading to the uncertainty of TI calculation. 4 Anyway, it is consistent with the interpretation of the kerogen type by isotopic carbon analysis. Previous studies found the kerogen δ 13 C in shale ranges from to 35.79, suggesting Type I as the kerogen type of the organic matter. 5,6 Two basic approaches exist to determine the thermal maturity: visual and chemical methods. 11,12 Determination of vitrinite reflectance, as discussed above, was completed via microscopic examination of kerogen or whole rock mounts. As the vitrinite should not be present in sediments before Devonian times, another approach to calculate Ro via bitumen reflectance (Rb) was proposed. The calculation formula according to Feng and Chen (1988) is presented below: 15 Ro = Rb Considering the pitfalls among identification of the indigenous vitrinite, Rock-Evel Tmax is used as an additional chemical assessment to provide confirmation of the visual measurements The Ro calculated from Tmax (Table 3) seems coincident with that measured by bitumen reflectance. 6387

6 Figure 3. Ternary plots of shale mineralogy: (a) USA Hot shales, modified from Han et al. (2013); (b) lower Cambrian shale in the NWG. Figure 4. Thin section and core pictures: (a) siliceous mudstone (RY1-09, the dark is organic matter and the light is minerals); (b) calcareous mudstone with sponge spicules (RY2-21); (c) phosphatic rocks (RY1-01, the light is apatite and the dark is organic matter); and (d) silty mudstone (RY2, 894 m). However, present investigated samples yield quite low S2 (<65 mg HC/g rock) and consequently low HI (<100 mg HC/g TOC), which suggests that Tmax values are not reliable to indicate thermal maturity levels Bulk Mineralogy and Lithofacies. Mineralogical data for the Lower Cambrian shale in the NWG are shown in Table 4. As the results indicated, the primary minerals are quartz and clay. Quartz concentrations vary from 8.9% to 73.2% (average of 49.29%) for the RY1 core and from 25.4% to 96.4% (average of 50.61%) for the RY2 core. Two higher values, 94.6% and 81.47%, from samples of the RY2 core are probably cherts in the bottom section. Clay concentrations vary from 5.1% to 48.6% (average of 29.14%) for the RY1 core and from 9.01 to 50.75% (average of 24.7%) for the RY2 core. One lower value, 5.1%, from a sample of the RY1 core is likely limestone in the middle strata. Most samples contain less than 12% calcite and dolomite (except the limestone sample RY1-17 and the calcareous or dolomitic mudstone). A plain comparison of the mineralogical characteristics between the Lower Cambrian shale and hot shales in the U.S. are provided in the ternary plots (Figure 3). The Bossier shales are characterized by relatively higher concentrations of calcite and dolomite, compared with the Ohio shales. The wellknown Barnett shales are characterized by clearly higher contents of quartz, feldspar, and pyrite, compared with the Ohio and Bossier shales. As the diagram indicates, the NWG 6388

7 Table 5. Identified Lithofacies with Thickness and TOC Compared with Those of the Barnett Shales lithofacies of Barnett shales in the Fort Worth Basin lithofacies of the Lower Cambrian shales in the NWG lithofacies thickness (%) TOC (%) lithofacies thickness (%) TOC (%) siliceous noncalcareous mudstone siliceous noncalcareous mudstone siliceous calcareous mudstone siliceous calcareous mudstone dolomitic mudstone dolomitic mudstone silty shaly interlaminated mudstone silty shaly interlaminated mudstone calcareous laminae calcareous laminae concretion horizons concretion horizons reworked shelly deposits phosphatic rocks phosphatic rocks resedimented spiculitic mudstone resedimented spiculitic mudstone lag deposits shales are highly similar to the Barnett shales in mineralogical composition, the lithofacies of which are mainly siliceous mudstone containing little calcite and dolomite. On the basis of thin sections (Figure 4) and XRD analysis, the lithofacies characterization of the Lower Cambrian shale in the NWG can be mainly summarized as laminated and nonlaminated siliceous mudstone, calcareous mudstone, and phosphatic rock. Laminated siliceous mudstone is the most common lithoface in the Lower Cambrian shales, which is well laminated due to the orientation of quartz and organic matter bonds Nonlaminated siliceous mudstone is less common, exhibiting a homogeneous matrix of quartz, clay, and organic matter. Calcareous mudstone is found in less than 3 samples and features higher concentrations of dolomite or calcite than clay minerals. Phosphatic rock is quite low and only found in the lower strata, mainly composed of phosphatic concretions and nodules. More lithofacies of the NWG shale were identified according to cores observations and outcrop descriptions (Table 5). Compared with the Barnett shales, silty interlaminated mudstone occupies a larger proportion in the lithofacies stacking of the NWG shale As we all know, organic-rich siliceous mudstone is a priority for shale-gas production due to the difficulty in creating effective fracture networks when high concentrations of clay minerals are present Lithofacies like calcareous mudstone, dolomitic mudstone, and silty interlaminated mudstone have a high potential for fracture stimulation, providing pathways connecting organic-rich lithofacies and the borehole. 22 Thus, the Lower Cambrian shale in the NWG yields a shale-gas potential judging by the lithofacies assemblage, which is similar to that of the Barnett shales in the North Fort Worth Basin Porosity and Pores. Porosity and permeability of the Lower Cambrian shale in the NWG are presented in Table 6. Most porosities vary between 1% and 3% with an average of 1.85%, showing a poor correlation with the relevant permeabilities. Porosities in this study exhibit higher average values than those of samples (average <1%) in other areas of the Upper Yangtz Block but similar to the lower Cambrian shales (average of 2.2%) in Australia. 20 As Tan et al. 20 (2014) suggested, Hg porosity may be generally lower than He porosity due to mineral constituents and small pores (<3.7 nm) which cannot be accessed by the former. Permeability values range from to md, which are restricted to matrix permeability, excluding the effect of fractures in the shale. BET theory was used to evaluate the pore diameter and surface area. As shown in Table 7, the mean value of the pore surface area is about m 2 /g (range from to m 2 /g), while the pore volume varies from to ml/g with an 6389 Table 6. Rock Density, Porosity, and Permeability of the Lower Cambrian Shale in the NWG samples depth (m) density (g/cm 3 ) porosity (%) permeability (md) RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY RY Table 7. BET Surface Area and BJH Pore Volume of the Lower Cambrian Shale in the NWG samples depth (m) BET surface area (m 2 /g) BJH volume (ml/g) pore diameter (nm) RY RY RY RY RY RY RY RY RY RY RY average of ml/g. Most of the BET surface area is associated with pores less than 50 nm in diameter, confirming that micropores and mesopores are the main pore types (Figure 5). However, pores of diameter less than 2 nm were not analyzed due to the limitations of the experimental instrument. Compared with other shales in the U.S. (Table 8), the Lower Cambrian shale in the NWG yields a higher median pore diameter, suggesting more pore volume contributed by mesopores (range from 2 to 10 nm)

8 Figure 5. (a) BET surface area vs pore size distribution; (b) cumulative pore volume vs pore size distribution. Table 8. Reservoir Characteristic of the Lower Cambrian Shale in the NWG Compared with USA Hot Shales (modified from Chalmers, 2012) shale sample depth (m) total porosity (%) micropore volume (ml/100 g) mesopore/macropore volume (ml/100 g) median pore diameter (nm) Haynesville Woodford Marcellus Barnett NWG TOC (%) Ro (%) Five types of pores are identified in the Lower Cambrian shale in the NWG according to their origin Organic matter (OM) pores (Figure 6a,b) subsequently form when hydrocarbon gets away from OM in the thermal maturity process, which is often observed in high maturity shales. OM pores in the NWG shale are abundant in the lower part of the Niutitang Formation where TOC contents are relatively high (average 6%). Intraparticle (IntraP) pores (Figure 6b,d) are often found between grains and crystals in the shale, but their sizes and geometries differ significantly, making it difficult to predict. Interparticle (InterP) pores (Figure 6c,e,f) are usually identified in clay minerals, carbonate crystals, and pyrite framboids. InterP pores in clay minerals form due to flocculation of clay minerals during the diagenesis after burial, while interp pores in calcite or dolomite crystals appear as partial dissolution occurs. 26,28 The size of these pores evaluated via SEM may suggest mesopores and macropores as the main pore types, in contrast with the pore size distribution discussed before. However, porosity contributions from such macropores of all measured samples are very low, and their influences on total porosity of any measured sample are within the error margin. Here we prefer the former pore size analysis via N 2 gas sorption. 23,24 In addition, the SEM evaluation of pore types illustrates that pores in the NWG shale are mostly OM pores and interp pores, which implies that there might be a relationship between porosity and TOC (clay and quartz). Plots of porosity and TOC/mineralogical composition are presented to illustrate the potential relationship (Figure 7) As Figure 7 indicates, porosity shows a strong correlation (R 2 = 0.744) with TOC contents, indicating that OM pores contribute significantly to the total porosity of the shale. It is in agreement with previous studies that high maturity organic matter is generally microporous due to the discharge of hydrocarbons. 1,17,20 However, porosity does not seem to be 6390 closely related to quartz and clay ratios as reported by other researches, which would be attributed to diagenesis after burial. 29, Gas Adsorption Capacity. Gas exists in shales in three different forms: (1) free gas controlled by rock porosity; (2) absorbed gas associated with organic and inorganic components; and (3) dissolved gas in hydrocarbons or fluids. 12,13 The methane adsorption experiments were conducted on five dry samples with different TOC and clay contents from the RY1 core, in order to determine the gas adsorption capacity of the Lower Cambrian shale in the NWG. As shown in Table 9 and Figure 8, the gas adsorption capacities, at 6.21 MPa, vary from to m 3 /ton with a mean value of 2.28 m 3 /ton. Compared with methane sorption capacity of the Lower Cambrian shale from Sichuan Basin (2.8 m 3 /ton on average), the Lower Cambrian shale in the NWG yields relatively lower values without consideration of different experimental conditions. 37,41 A compilation of methane sorption capacity of marine shales from China, Europe, Canada, and the U.S. correlated with their corresponding TOC contents are provided below (Figure 9). As illustrated in Figure 9, the organic matter richness has a significant effect on the methane sorption capacity of marine shales. This strong positive correlation between the methane sorption isotherms and their TOC contents has been proved by measured marine shales around the world In this study, the methane sorption isotherms yield a clear and strong positive correlation with TOC contents, which is consistent with the Lower Cambrian shale in Sichuan Basin according to previous studies. 37 The effect of the organic matter on the gas sorption capacity is not only caused by TOC contents but also by its type and thermal maturity. 37,38 Gasparik et al. 39 and Tan et al. 37 reported that the sorption isotherms of overmature samples were generally higher than those of low thermal

9 Figure 6. SEM photographs of core samples: (a) OM pores, with energy spectrum test ensuring its components (RY1-05, average > 100 nm); (b) OM pores (RY2-03, average < 100 nm); (c) cleavage-wedge pores due to shrinkage of clay minerals (RY1-17, nm); and (d) IntraP pores in pyrite famboids (RY2-09, average < 100 nm). Figure 7. (a) Plot of porosity vs TOC; (b) plot of porosity vs quartz/clay ratio. maturity. Previous research attributed this phenomenon to structural transformation of organic matter, creation of new sorption sites, and/or heterogeneity decrease of pore surface upon thermal maturation Also the positive correlation between methane sorption capacity and thermal maturity was related to micropores in the organic matter. Considering the correlation of porosity and TOC content, it is suggested that microporous organic matter in the NWG shale may contribute greatly to the gas adsorption capacity. Despite the limited pore size, high maturity organic matter has provided large internal surface area for the adsorbed gas, though Tan et al.37 has Table 9. Methane Sorption Capacities of the Lower Cambrian Shale in the NWG samples depth (m) VL (cm3/g) PL (Mpa) asorption capacity at 6 MPa (m3/ton) TOC (%) clay (%) RY1-41 RY1-30 RY1-24 RY1-13 RY

10 than large pores. 37 More total porosity and surface area formation have been attributed to micropores in organic matter based on investigations performed on the Paleozoic shales in the Sichuan Basin and NWG. 1,37,41 Within measured samples of high thermal maturity, organic matter would create more micorpores, correspondingly enhancing the sorption capacity of shale. Figure 8. Methane adsorption isotherms (at 49 C) for core samples. suggested that the TOC content shows more effects on the methane sorption capacity than other factors like clay compostion, moisture content, pores, and particle size. Some research has reported that clay minerals, especially Illite, contribute greatly to the gas adsorption capacity. 32,34,38 However, a strong negative association is identified between the gas sorption capacity and the clay mineral contents in this study, which is consistent with the investigation on the Paleozoic marine shales from Sichuan Basin, South China. 37,41 Within samples containing moisture, the sorption capacity might be irrelevant because the moisture would block and occupy a large proportion of pores where the adsorbed gas could have accumulated In fact, the pore size and structure have been shown to have the most direct effect on the methane sorption capacity of shales. Compared with other factors, micropores related to organic matter and clay minerals can offer more surface area and have greater sorption energy 4. CONCLUSION A variety of experiments have been conducted on the Lower Cambrian shale in the NWG to illustrate its shale gas potential. (1) The Niutitang Formation in this study area exists as a thick (80 m) succession of marine shales, the lower part of which displays high TOC contents (average 6%). The kerogen type determined by δ 13 C is sapropelic (Type I), suggesting a high potential for gas generation. Ro values range from 3.07% to 3.68% for the RY1 core and from 2% to 3.11% for the RY2 core. (2) The mineralogical composition of the NWG shale compared with hot shales in the U.S. indicates it is highly similar to the Barnett shales and primary minerals of quartz and clay (average 48% and 27%, respectively). The lithofacies consist of mainly siliceous mudstone and calcareous mudstone, which makes it suitable for fracture stimulation. (3) The porosities of samples from both cores vary from 1.02% to 3.69%, correlating well with the TOC contents. Many OM pores identified via SEM evaluation may provide an explanation. The pore size distribution of the NWG shale reveals that micropores and mesopores are the main pore types, indicating limited pore volume compared with other high gas production shales. (4) The gas adsorption capacity was determined by the methane sorption experiments and was found to have a range from to m 3 /ton at 6.21 MPa under experimental conditions. Meanwhile, the adsorptive capacity shows a strong positive correlation with TOC contents, confirming the significant contribution of microporous organic matter to gas adsorption. Thus, the Lower Cambrian shale in the NWG is thought to have great shale-gas Figure 9. Comparison of methane sorption capacity of marine shales from China and other countries shows a positive correlation with their TOC contents. (Alum shale from Scandinavia, Posidonia in Germany, Barnett shale from the U.S., and Devonian-Mississippian and Jurassic shales from Canada). UYB: the Upper Yangtz Block. 6392

11 potential due to high TOC contents, favorable mineralogical composition, and considerable potential gas accumulation. AUTHOR INFORMATION Corresponding Author *(Tailiang Fan) Telephone: foxmail.com. Notes The authors declare no competing financial interest. ACKNOWLEDGMENTS This work is financially supported by the National Oil and Gas Strategic Investigation Program (Grant 2009GYXQ-15), the National Natural Science Foundation Research (Grant ), and the Shale Gas Resources Investigation and Evaluation Program, Guizhou Province (Grant 2012GYYQ- 01). We also appreciate the experimental supports from those institutes, like CUPB, PC-HOB, AL-BRIUG, and RIPED-LB. Editor Weber and two reviewers are gratefully thanked for their help to improve this article. REFERENCES (1) Han, S. B.; Zhang, J. C.; LI, Y. X.; Horsfield, B.; Tang, X.; Jiang, W. L.; Chen, Q. Energy Fuels 2013, 27, (2) Zhang, J. C.; Lin, L. M.; Li, Y. X.; Jiang, S. L.; Liu, J. X.; Jiang, W. L.; Tang, X.; Han, S. B. Earth Sci. Front. 2012, 19, (in Chinese with English abstract). (3) Zhang, J. P.; Fan, T. L.; Zhang, J. C.; Li, Y. F.; Wu, Y. Geosciences 2013, No. 4, (in Chinese with English abstract). (4) Tan, J. Q.; Horsfield, B.; Mahlstedt, N.; Zhang, J. C.; di Primio, R.; Vu, T. A. T.; Boreham, C. J.; van Graas, G.; Tocher, B. A. Mar. Pet. Geol. 2013, 48, (5) Liang, D. G.; Guo, T.; Chen, J.; Bian, L.; Zhao, Z. Marine Petrol. 2009, 14, 1 19 (Chinese edition with English abstract). (6) He, X. Y.; Yao, G. S.; Cai, C. F.; Shen, A.J.; Wu, J. W.; Huang, L.; Chen, Z. D. Acta Sedimentol. Sin. 2012, 30, (in Chinese edition with English abstract). (7) Brunauer, S.; Emmett, P. H.; Teller, E. J. J. Am. Chem. Soc. 1938, 60, (8) Barrett, E. P.; Joyner, L. G.; Halenda, P. P. J. J. Am. Chem. Soc. 1951, 73, (9) Rouquerol, J.; Avnir, D.; Fairbridge, C. W.; Everett, D. H.; Haynes, J. H.; Pernicone, N.; Ramsay, J. D. F.; Sing, K. S. W.; Unger, K. Pure Appl. Chem. 1994, 66, (10) Langmuir, I. J. J. Am. Chem. Soc. 1918, 40, (11) Pollastro, R. M.; Jarvie, D. M.; Hill, R. J.; Adams, C. W. AAPG Bull. 2007, 91, (12) Jarvie, D. M.; Hill, R. J.; Ruble, T. E.; Pollastro, R. M. AAPG Bull. 2007, 91, (13) Curtis, J. B. AAPG Bull. 2002, 86, (14) Kinley, T. J.; Cook, L. W.; Breyer, J. A.; Jarvie, D. M.; Busbey, A. B. AAPG Bull. 2008, 92, (15) Feng, G.; Chen, S. Nat. Gas Ind. 1988, 8, (in Chinese with English abstract). (16) Tan, J. Q.; Horsfield, B.; Mahlstedt, N.; Zhang, J. C.; Primio, R. D.; Vu, T. A. T.; Boreham, C. J.; Hippler, D.; van Graas, G.; Tocher, B. A. Int. Geol. Rev. 2015, 57, (17) Singh, P. Ph.D. thesis, University of Oklahoma, Norman, (18) Aplin, A. C.; Macquaker, J. H. S. AAPG Bull. 2011, 95, (19) Abouelresh, M. O.; Slatt, R. M. AAPG Bull. 2012, 96, (20) Tan, J. Q.; Horsfield, B.; Fink, R.; Krooss, B.; Schulz, H. M.; Rybacki, E.; Zhang, J. C.; Boreham, C. J.; van Graas, G. V.; Tocher, B. A. Energy Fuels 2014, 28, (21) Zhou, J.; Rush, P. F.; Sridhar, A.; Miller, R. AAPG Search and Discovery 2012, (22) Wang, C. G.; Carr, T. R. Comput. Geosci. 2012, 49, (23) Hickey, J. J.; Henk, B. AAPG Bull. 2007, 91, (24) Chalmers, G. R.; Bustin, R. M.; Power, I. M. AAPG Bull. 2012, 96, (25) Dong, H.; Peacor, D. R. Clays Clay Miner. 1996, 44, (26) Heath, J. E.; Dewers, T. A.; McPherson, B. J.; Petrusak, R.; Chidsey, T. C.; Rinehart, A. J.; Mozley, P. S. Geosphere 2011, 7, (27) Slatt, R. M.; O Brien, N. R. AAPG Bull. 2011, 95, (28) Loucks, R. G.; Reed, R. M.; Ruppel, S. C.; Hammes, U. AAPG Bull. 2012, 96, (29) Wu, Y.; Fan, T. L.; Zhang, J. C.; Jiang, S.; Li, Y. F.; Zhang, J. P.; Xie, C. Energy Fuels 2014, 28, (30) Ross, D. J. K.; Bustin, R. M. Bull. Can. Pet. Geol. 2007, 55, (31) Mastalerz, M.; Schimmelmann, A.; Drobniak, A.; Chen, Y. Y. AAPG Bull. 2013, 97, (32) Gasparik, M.; Ghanizadeh, A.; Bertier, P.; Gensterblum, Y.; Bouw, S.; Krooss, B. M. Energy Fuels 2012, 26, (33) Ross, D. J. K.; Bustin, R. M. AAPG Bull. 2008, 92, (34) Lu, X. C.; Li, F. C.; Watson, A. T. SPE Form. Eval. 1995, 10, (35) Clarkson, C. R.; Jensen, J. L.; Pedersen, P. K.; Freeman, M. AAPG Bull. 2012, 96, (36) Ross, D. J. K.; Bustin, R. M. Mar. Pet. Geol. 2009, 26, (37) Tan, J. Q.; Weniger, P.; Krooss, B.; Merkel, A.; Horsfield, B.; Zhang, J. C.; Boreham, C. J.; Graas, G. V.; Tocher, B. A. Fuel 2014, 129, (38) Ross, D. J.; Bustin, R. M. Mar. Pet. Geol. 2009, 26, (39) Gasparik, M.; Bertier, P.; Gensterblum, Y.; Ghanizadeh, A.; Krooss, B. M.; Littke, R. Int. J. Coal Geol. 2014, 123, (40) Chalmers, G. R. L.; Bustin, R. M. Bull. Can. Pet. Geol. 2008, 56, (41) Wang, S. B.; Song, Z. G.; Cao, T. T.; Song, X. Mar. Pet. Geol. 2013, 44,