lable at ScienceDirect

Journal of Natural Gas Science and Engineering 33 (2016) 81e96

Contents lists avai

Journal of Natural Gas Science and Engineering

journal homepage: www.elsevier .com/locate/ jngse

Characteristics and dominant controlling factors of organic-richmarine shales with high thermal maturity: A case study of the LowerCambrian Niutitang Formation in the Cen’gong block, southern China

Ruyue Wang a, b, c, Yang Gu a, b, c, *, Wenlong Ding a, b, c, Dajian Gong d, e, Shuai Yin a, b, c,Xinghua Wang a, b, c, Xuehui Zhou a, b, c, Ang Li a, b, c, Zikang Xiao a, b, c, Zixian Cui a, b, c

a School of Energy Resources, China University of Geosciences, Beijing 100083, Chinab Key Laboratory for Marine Reservoir Evolution and Hydrocarbon Abundance Mechanism, Ministry of Education, China University of Geosciences, Beijing100083, Chinac Key Laboratory for Shale Gas Exploration and Assessment, Ministry of Land and Resources, China University of Geosciences, Beijing 100083, Chinad China Energy Reserve Corporation, Beijing 100107, Chinae Tongren Sino-Energy Natural Gas Corporation, Tongren 554300, China

a r t i c l e i n f o

Article history:Received 13 November 2015Received in revised form4 May 2016Accepted 5 May 2016Available online 6 May 2016

Keywords:Shale gasPore structureMethane sorption capacityBrittlenessFractureLower Cambrian

* Corresponding author. School of Energy Resourcsciences, Beijing 100083, China.

E-mail address: 450742659@qq.com (Y. Gu).

http://dx.doi.org/10.1016/j.jngse.2016.05.0091875-5100/© 2016 Elsevier B.V. All rights reserved.

a b s t r a c t

The Lower Cambrian organic-rich marine shale, which is a significant source of China’s shale gas, iswidely distributed in southern China. An integrated characterization of the Niutitang shale is provided inthis study in terms of organic geochemistry, mineralogy, pore characterization, methane sorption ca-pacity, rock mechanical properties, fractures and gas content based on samples from three wells. Theresults indicate that the Lower Cambrian Niutitang shale is thermally over-mature and has rich shale gasresources, with a total organic carbon content (TOC) between 0.51% and 10.49% and a high quartz contentbetween 35.3% and 78.5%. Compared to the major gas-producing shales in the U.S. and China, most of theorganic matter (OM)-hosted pores in the Niutitang shale are generally smaller than 5 nm, significantlyaffecting the methane sorption capacity. The inter-particle and intra-particle pores and fractures are theprimary sources of storage space, especially for free gas. For samples with TOC values less than 6.5%, TOCis positively correlated with the total porosity, total pore volume, brittleness (Young’s modulus), corefracture density, free gas content and Langmuir pressure; however, for samples with TOC values greaterthan 6.5%, the positive correlations become negative. These characteristics are due to the ductility andlow hydrocarbon generation potential of organic matter in high thermal maturity shales that arevulnerable to compaction. Thus, TOC has a significant impact on the macroscopic (e.g., brittleness) andmicroscopic (e.g., pore structure and sorption capacity) properties of shale reservoirs, potentially con-trolling the enrichment and productivity of shale gas. These results can be used to optimize drilling andfracturing stimulation intervals during shale gas exploration and development.

© 2016 Elsevier B.V. All rights reserved.

1. Introduction

The success of the “shale gas revolution” in North Americaresulted in the exploitation of many shale hydrocarbon reservoirswith physical and chemical properties that were conducive todevelopment (Curtis, 2002; Montgomery et al., 2005; Jarvie et al.,2007; Pollastro, 2007). However, as the revolution has expanded

es, China University of Geo-

within North America and into countries such as China, shale unitswith varying and sometimes marginal chemical and physicalproperties are now being evaluated (Zou et al., 2010; Ding et al.,2013a, 2013b; Guo, 2013; Tian et al., 2013, 2015; Wang et al.,2013a, 2013b; Tan et al., 2013, 2014; Pan et al., 2015; Zhang et al.,2015; Xia et al., 2015; Wang et al., 2016a). Recently, the commer-cial development of the Jiaoshiba shale gas field of the LowerSilurian Longmaxi shale in Chongqing indicates that southernChina is an important area for shale gas production in China. Incomparison with North American shales, Paleozoic organic-richmarine shales in southern China have multiple strata; old forma-tion ages; high thermal maturities; multi-stage tectonic

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e9682

movements; and complex surface, stress state and preservationconditions (Kang, 2012; Wang et al., 2016b). High TOC, high brit-tleness, high formation pressure, well-developed fractures andfavorable preservation are dominant factors associated withenrichment and high yield in the Jiaoshiba shale gas field (Guo,2013; Guo and Zhang, 2014; Hu et al., 2014). Compared with theLongmaxi shale, the Lower Cambrian Niutitang shale has greaterTOC, brittleness, thermal maturity and a higher degree of fracturedevelopment with greater depositional thickness and wider dis-tribution areas. Thus, it is another significant shale gas stratum in

Fig. 1. (A) The location of the study area. The maps show the area’s structural features. Thesections of the TM-1, TX-1 and CY-1 wells at the locations shown in (A).

China (Zou et al., 2010). In this context, the most noteworthyquestions include determining whether the over-mature organic-rich shales can be effectively exploited and determining thedominant factors that control the enrichment and high yield ofshale gas. The Lower Cambrian shales likely have the greatestproduction potential in southern China.

In this study, the Lower Cambrian Niutitang shale in the Cen’-gong block in Guizhou province, southern China is systematicallyinvestigated to determinewhether over-mature organic-rich shaleshave development potential and determine the dominant factors in

Early Cambrian sedimentary faces data are from Wang et al. (2013b). (B) Seismic cross-

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e96 83

shale reservoirs that control the enrichment and productivity ofshale gas in terms of organic geochemistry, mineralogy, porecharacterization, methane sorption capacity, rock mechanicalproperties, fractures, gas content and their interrelationships. TheCY-1 and TX-1 wells in the study area are two wells at which shalegas has been successfully ignited after fracture stimulation of theLower Cambrian Niutitang shale (Fig.1), exhibiting a great potentialfor shale gas production. The results of our research may not onlyimprove geological theories of shale gas in complex structural areasin high thermal maturity marine shales but also have practicalsignificance for shale gas evaluation, exploration and developmentin Paleozoic marine organic-rich shales.

2. Geological setting

The Cen’gong block study area is located in the southwesternpart of Tongren city in northeastern Guizhou province (Fig. 1),covering a total area of 914 km2 in the Qianbei area. The tectoniclocation of the study area is in the trough-like fold belt of westernHunan-Hubei province on the southeastern margin of the UpperYangtze plate, where the structural conditions and stress fields arecomplicated due to multi-stage tectonic movements and de-formations. The study area experienced Xuefeng (Neoproterozoic),Caledonian, Yanshanian (Jurassic-Cretaceous) and Himalayanmulti-phase tectonic movements, and the Yanshanian movementlaid the foundation for the current geological structures and land-forms (Ma et al., 2004). Complex structures are developed in thestudy area and are mainly NE and NNE trending. The main struc-tural characteristics of the study area are as follows: (1) folds andfaults often have “S” or anti-“S” shapes on the plane, reflecting acompressional and strike-slip setting (Fig. 1A); (2) synclinalmountains, anticlinal valleys and trough-like folds are well devel-oped (Fig. 1B); and (3) most faults are thrust faults with high dip-angles of 50e80�, largely controlling the depth and distributionof the strata (Fig.1B). As shown in Fig. 2, themain strata in the studyarea are Sinian, Cambrian and partial Lower Ordovician (Nie et al.,2013).

Fig. 2. The lithological and stratigraphic system of the study area (colored) in the Qianbeireferred to the web version of this article.)

3. Samples and methods

3.1. Samples

In this study, 220 core samples were obtained from three ver-tical shale gas wells in the study area (Fig. 1). The CY-1 well reacheda depth of 1526.00 m with a core from 1179.27 to 1471.50 m,revealing the Lower Cambrian Niutitang Formation from 1398 to1457 m. The TX-1 well reached a depth of 1897.60 m and was coredfrom 1769 to 1818 m, revealing the Niutitang Formation from 1757to 1816 m. The TM-1 well reached a depth of 1530.0 m and wascored from 1350 to 1530m, revealing the Niutitang Formation from1401 to 1470 m.

3.2. Methods

The total organic carbon contents (TOC) of the 220 samples weremeasured using a LECO “CS-230” carbon and sulfur analyzer at theExperimental Center of the Department of Geochemistry at YangtzeUniversity. Maceral observations of one-side polished blocks weremade using a Leica MPV microscope with reflected white andfluorescent light, and the macerals in the shales were identifiedbased on Stach et al. (1982) and Taylor et al. (1998). Because of thelack of vitrinite in Lower Cambrian shales, the bitumen reflectancewas measured and converted to its equivalent vitrinite reflectance(Ro) using the equation proposed by Schoenherr et al. (2007).Thermal pyrolysis of the shale samples was performed using aRock-Eval 6 pyrolyzer. Details of the rock evaluation process, theparameters acquired and interpretive guidelines are provided inthe references (Lafargue et al., 1998; Behar et al., 2001).

X-ray diffraction and mineral analyses of 213 samples wereconducted using a Panalytical X’Pert PRO MPDX-ray diffractometer(XRD) with Cu Ka radiation (l ¼ 1.5406 for CuKa1). Stepwisescanning measurements were performed at a rate of 4�/min in therange of 3�e85� (2q). The relative mineral percentages were esti-mated semi-quantitatively using the area under the curve based onthe major peaks of each mineral and corrected for Lorentz

area. (For interpretation of the references to colour in this figure legend, the reader is

Fig. 3. (A) The vertical distribution of minerals in the Niutitang shale in well TX-1; (B)The clay mineral composition of the Niutitang shale in well TX-1; (C) Mineralogicalternary diagram of the major gas-producing shales in the U.S. (Li et al., 2009) and theNiutitang shale in the study area.

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e9684

polarization (Pecharsky and Zavalij, 2003).The helium porosity of each shale sample was determined using

its bulk density in combination with its skeletal density (Chalmerset al., 2012). Samples (40e50 g) were crushed between meshes ofsize 20 and 40 (830 and 380 mm) and dried at 110 �C in a vacuumfor 24 h. They were used to determine the skeletal density usinghelium pycnometry at a pressure of less than 25 psia. To measurethe bulk density, the samples were weighed in air before and afterbeing coated with paraffin of known density. Then, the paraffin-coated samples were weighed both in air and in water of knowndensity to determine the sample’s bulk volume. Finally, the bulkdensity was calculated using the weight in air and the bulk volume(Tian et al., 2013).

Low-pressure nitrogen-adsorption isotherms were measuredusing a Quadrasorb SI surface area and porosimetry analyzer, whichwas able to measure pore sizes between 0.35 and 400 nm. Thesamples were pretreated for 3.5 h in a vacuum at a temperature of300 �C, and the adsorbent was nitrogen with a purity of greaterthan 99.999%. The nitrogen adsorption and desorption isotherms ofdifferent pressures were measured at a temperature of �195.8 �C,and the specific surface area, total pore volume and pore size dis-tribution were calculated using the BET equation (Brunauer et al.,1938), DR equation (Dubinin, 1975) and BJH method (Barrettet al., 1951).

High-pressure methane sorption measurements were madeusing a PCT Pro E&E Siverts high-pressure gas sorption anddesorption instrument. The experimental standards and testmethods that were employed were in accordance with Chinesenational standard GB/T 19560-2008. The high-pressure methanesorption isotherms were measured using moisture-equilibratedsamples (120e150 g) that had been crushed and sieved until theparticle size was smaller than size 60 mesh. Moisture equilibrationwas achieved in an evacuated desiccator with a controlled relativehumidity (RH) using saturated salt solutions of K2SO4 (97% RH). Thesamples were weighed once every 24 h until the weight becameconstant, which occurred after 3 days.

Mechanical tests were conducted using a TAW-1000 triaxialrock testing machine at the State Key Laboratory of RockMechanicsin the Institute of Civil and Environmental Engineering at BeijingUniversity of Science and Technology. The test samples werecollected from the TM-1 and TX-1 well cores. Each sample wasprepared as a cylinder with a diameter of 2.5 cm and a height of5 cm. Each sample had a parallelism error of less than 5 mm be-tween its top and bottom surfaces, a verticality error of less than0.1� and a surface smoothness with a grade of no less than 5(3.2 mm). The tests were conducted in accordance with Chinesenational standard GB/T 23561.7e2009.

4. Results

4.1. Petrography and mineralogy

The Lower Cambrian Niutitang Formation, which developedstably in the study area, has a thickness of 50e70 m, averaging60 m, and represents a deep shelf depositional environment(Fig. 1A; Wang et al., 2013b). The lithology of the Niutitang For-mation primarily consists of gray-to-black shale and siliceous shale,which is in blocks or flakes and is commonly observed with localpyrite enrichment. The XRD data from 213 samples from threewells in the study area show that the major components of Niuti-tang shale are quartz and clay minerals (Fig. 3A). The averagemineral contents of quartz, clay, feldspar, pyrite and carbonate are52.7%, 21.2%, 10.1%, 9.3% and 6.7%, respectively. The clay mineralsmainly consist of illite and illite-smectite mixed layers (Fig. 3B),accounting for more than 90% of the total clay minerals, and the

illite crystallinity ranges from 0.35 to 0.51, indicating a late diage-netic stage. In comparison with the major gas-producing shales inthe U.S., the brittle mineral content of Niutitang shale is similar tothat of the Barnett shale (Fig. 3C).

4.2. Organic geochemistry

The TOC values of the samples from the three wells ranged from0.51% to 10.49%, with an average of 4.6%, and 86.7% of values were

Fig. 4. (A) Distribution frequency of the TOC of the Niutitang shale; (B) Relationship between the TOC and quartz contents; (C) Relationship between the TOC and clay mineralcontents; (D) Relationship between the TOC and porosity, showing that when the TOC is greater than a certain degree, the positive correlation becomes negative (data points indashed ovals).

Table 1The maceral composition, TOC content and pyrolysis parameters of the Niutitang shale in the study area.

Sample no. Well name Maceral composition (%) KTI Kerogen type TOC (%) Tmax (�C) S1 (mg/grock) S2 (mg/grock) HI (mg/gTOC)

Sapropelinite Exinite

1 TX-1 90.0 10.0 95.0 I 3.35 486 0.02 0.03 12 TX-1 97.0 3.0 98.5 I 4.11 452 0.03 0.03 13 TX-1 98.0 2.0 99.0 I 5.92 429 0.05 0.07 14 TX-1 98.0 2.0 99.0 I 4.68 505 0.03 0.05 15 TX-1 97.0 3.0 98.5 I 3.99 600 0.07 0.22 66 TX-1 90.0 10.0 95.0 I 6.54 600 0.07 0.26 47 TX-1 97.5 2.5 98.8 I 5.40 600 0.05 0.10 28 TX-1 92.0 8.0 96.0 I 4.41 441 0.05 0.05 19 TM-1 94.0 6.0 97.0 I 9.07 417 0.02 0.06 110 TM-1 99.0 1.0 99.5 I 5.54 534 0.01 0.04 111 TM-1 95.0 5.0 97.5 I 5.40 540 0.02 0.07 112 TM-1 96.0 4.0 98.0 I 4.36 564 0.01 0.04 113 TM-1 97.0 3.0 98.5 I 5.18 547 0.03 0.06 114 TM-1 97.5 2.5 98.8 I 2.33 600 0.03 0.09 415 TM-1 98.0 2.0 99.0 I 4.53 561 0.02 0.07 216 TM-1 97.0 3.0 98.5 I 4.42 462 0.03 0.09 2

Note: KTI-kerogen type index; S1-free hydrocarbon content, mg HC/grock; S2-residual hydrocarbon content, mg HC/grock; Tmax-temperature at the maximum of the S2 peak;HI-hydrogen index, S2/TOC � 100, mg HC/gTOC.

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e96 85

greater than 2% (Fig. 4A). The primarymaceral in the organicmatter(OM) is sapropelinite, accounting for more than 90% and indicatinga Type I kerogen (Table 1). The measured bitumen reflectancevalues vary from 2.04% to 4.19%, averaging of 2.72%, and thecalculated equivalent vitrinite reflectance (Ro) is between 2.27% and4.42%. The values of Tmax are between 417 �C and 600 �C, with mostvalues greater than 500 �C, indicating a high-maturity or over-mature status. The hydrogen index (HI) and S2 values are close tonil and range from 1 to 6 mg/gTOC and 0.03e0.26 mg/grock (Table 1),respectively, indicating that the Lower Cambrian Niutitang shale inthe study area has a high maturity and a poor hydrocarbon gen-eration potential. Moreover, similar to many other organic-richmarine shales, TOC is positively correlated with the quartz con-tent and negatively correlated with the clay mineral content(Fig. 4B, C).

4.3. FE-SEM observations and pore types

Based on their occurrences, micropores in shales can be classi-fied as inter-particle and intra-particle pores (Chalmers et al., 2012;Loucks et al., 2012), the diameters of which are generally between0.01 and 10 mm in the Niutitang shale (Fig. 5). Compared to majorgas-producing shales in the U.S. and China, such as the Barnett andLongmaxi shales, the diameters of OM-hosted pores in the Niuti-tang shale are generally less than 50 nm (Tian et al., 2015) and aredifficult to find at low resolutions (Fig. 5AeC). Hu et al. (2015)proposed that a significant increase in 2e6 nm OM-hosted poresoccurs in the processes of maximum oil generation and oil crackingto gas. Therefore, in the over-mature Niutitang shale, the sizes andquantities of OM-hosted pores are relatively poor (Wang et al.,2013a; Tian et al., 2015). The inter-particle pores observed

Fig. 5. FE-SEM images of the Niutitang shale. (A) Well TX-1, 1794.3 m, organic matter with obvious deformations due to compaction and OM-hosted pores that cannot be observedat low resolution; intra-particle pores and fractures can be found in pyrites; (B) Well CY-1, 1424.5 m, the inter-particle and intra-particle pores and fractures are abundant in clayaggregates; (C) Well TM-1, 1437.2 m, most of the OM-hosted pores are less than 50 nm in size; (D) Well TM-1, 1423.6 m, nano-scale pores and gaps are abundant on the wavy surfaceof alginite; (E) Well TM-1, 1449.5 m, inter-particle pores are abundant in quartz; (F) Well TM-1, 1428.4 m, moldic pores and inter-particle pores in pyrite framboids; (G) Well TX-1,1780.7 m, inter-particle pores and fractures between soft to rigid particles; (H) Well TX-1, 1813.7 m, cleavage, dissolved pores and fractures in barytocalcite.

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e9686

between particles range from soft and ductile (e.g., clay mineralsand organic matter) to rigid (e.g., quartz and pyrite) and exhibit avariety of shapes. The inter-particle pores and fractures betweenorganic matter and clay minerals (Fig. 5B) are likely related tovolume reductions during hydrocarbon generation and diagenesis.

Intra-particle pores generally occur in clay minerals, pyrites andorganic matter. Moreover, large amounts of alginites can be foundin the Niutitang shale (Fig. 5D), and nano-scale pores and gaps areabundant on their wavy surfaces, providing storage spaces andspecific surface areas for shale gas. Inter-particle pores and

Table 2The BET surface area and BJH pore volume of the Lower Cambrian Niutitang shale in the study area.

Well no. Depth (m) BET surface area (m2/g) Most probable pore size (nm) Total pore volume (10�3 cm3/g) TOC content (%)

TX1 1783.18e1783.46 22.6358 4.4396 16.337 5.5TX1 1791.08e1791.36 19.9006 4.474 14.267 8.0TX1 1800.12e1801.38 21.3582 4.3504 4.522 4.8TM1 1405.20e1409.84 6.781 4.05 10.45 1.1TM1 1409.51e1409.57 9.31 4.073 14.06 1.1TM1 1412.52e1412.56 6.502 4.06 13.84 1.3TM1 1415.11e1417.77 12.495 3.821 17.58 1.67TM1 1417.51e1417.61 10.051 3.824 14.3 1.7TM1 1420.29e1421.54 10.107 4.063 10.74 1.77TM1 1423.30e1423.46 7.991 4.04 9.152 2.56TM1 1428.55e1430.73 21.877 3.821 15.94 4.0TM1 1433.72e1433.98 25.483 3.832 27.77 4.5TM1 1435.97e1436.22 13.63 3.827 9.701 3.9TM1 1441.63e1441.68 19.979 3.848 15.64 5.6TM1 1446.62e1446.89 30.37 3.827 30.65 5.5TM1 1451.27e1451.38 28.137 3.828 18.48 8.5TM1 1453.61e1453.87 23.983 3.837 14.69 7.68TM1 1457.24e1457.34 21.224 3.824 15.51 5.2TM1 1461.77e1462.03 24.131 3.614 16.41 5.63TM1 1466.76e1466.83 19.905 3.621 15.22 4.5TM1 1469.06e1472.13 21.264 3.823 15.07 4.7

Fig. 6. Adsorption and desorption isotherms of nitrogen at the temperature of liquidnitrogen.

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e96 87

fractures are particularly well developed in quartz and pyriteframboids and have large areal porosities (Fig. 5EeG) because therigid particles favor the development and preservation of micro-pores and fractures (Wang et al., 2013a). In addition, cleavage,dissolved pores and fractures, which increase the numbers ofstorage spaces and seepage pathways in the matrix and the cementof fractures in shales, can be found in carbonate minerals such asbarytocalcite and calcite (Fig. 5H).

4.4. Helium porosity

The helium porosity of the Niutitang shale in the study arearanges from 0.62% to 3.59%, mainly ranging between 1% and 3%. TheTOC and porosity are piecewise linearly correlated (Fig. 4D), i.e.,when the TOC is greater than a certain degree, the positive corre-lation between the TOC and porosity becomes negative (data pointsin dashed ovals), which is similar to the results of Marcellus shalefrom the U.S. (Milliken et al., 2013), Permian shales from easternChina (Pan et al., 2015) and Niutitang shale from the Qianbei(northern Guizhou) area (Xia et al., 2015).

4.5. Pore structure of nitrogen adsorption

The nitrogen adsorption and desorption isotherms at the tem-perature of liquid nitrogen (�195.8 �C) based on 21 samples areused to determine the specific surface area, total pore volume andprobable pore size of the Niutitang shale in the study area (Table 2).The isotherms have hysteresis patterns (Fig. 6) that are similar totypes D and E in the classification system of Broekhoff and De Boer(1968) and types H3 and H4 in the classification system of the In-ternational Union of Pure and Applied Chemistry (Sing et al., 1985),corresponding to pore types that have splint or ink-bottle shapeswith narrow throats. Under severe compaction, the narrow porethroats may close to form isolated pores and smaller pores beyondthe detection limit.

The specific surface areas (SBET) of 21 samples calculated usingthe BET equation are between 6.78 m2/g and 30.37 m2/g (Table 2)and are positively correlated with the TOC and quartz contents andnegatively correlated with the clay mineral content (Fig. 7AeC).These results are similar to those of the Niutitang shale in theQiannan depression in Guizhou province (Tian et al., 2015).

The total pore volume calculated using the DR equation rangesfrom 4.52 10�3 cm3/g to 30.65 10�3 cm3/g (Table 2), and its corre-lationswith the TOC, quartz and claymineral contents are similar tothose of helium porosity (Fig. 4), i.e., the total pore volume haspiecewise linear correlations with the TOC and quartz contents anda negative correlation with the clay mineral content (Fig. 7DeF).This phenomenon also can be found in the Niutitang shale samplesfrom Qianbei area (Xia et al., 2015).

The most probable pore size in the Niutitang shale calculated bythe BJH model varies from 3.61 nm to 4.47 nm (Table 2). Note thatthe most probable pore size is negatively correlated with the TOCand quartz contents and positively correlated with the clay mineralcontent (Fig. 7GeI), indicating that OM-hosted pores account for alarge proportion of the small pores within the <5 nm pore-sizeinterval in the total pore volume (Kuila et al., 2014; Hu et al.,2015). Tian et al. (2015) proposed that there some narrow poressmaller than 0.7 nm exist in the Niutitang shale from the Qiannandepression in Guizhou province. Rexer et al. (2013) reported shalessamples from Denmark whose micropores are dominated by nar-row pores smaller than 0.7 nm. Mosher et al. (2013) proposed thatshale samples containing 0.4 nm and 0.8 nm pores may contain 3.3and 2.8 times, respectively, the methane sorption volume at 12MPa

Fig. 7. Relationships between the TOC, quartz and clay mineral contents and SBET, total pore volume and most probable pore size for the Niutitang shale in the study area (datapoints in dashed ovals represent the negative correlations between the TOC and quartz contents and reservoir parameters).

Table 3The methane sorption capacity and the corresponding parameters of the Niutitang shale reservoirs in the study area.

Sample no. BET surface area (m2/g) Total pore volume (10�3 cm3/g) Langmuir volume (m3/t) Langmuir pressure (MPa) TOC (%) Quartz (%) Clay (%)

1 6.781 10.45 1.87 2.51 1.2 27.1 33.32 12.495 17.58 1.91 3.69 1.67 36.1 35.33 10.107 10.74 2.37 2.34 1.77 33.7 30.54 7.991 9.152 3.02 3.72 2.56 40.5 33.65 21.877 15.94 4.15 4.59 4 39.7 29.36 25.483 27.77 4.98 6.01 4.5 43.2 23.97 19.979 15.64 5.79 3.51 5.6 64.1 16.78 28.137 18.48 7.75 2.92 8.5 62.2 14.29 23.983 14.69 7.58 4.33 7.68 68.3 13.310 24.131 16.41 5.47 3.5 5.63 49.5 17.511 19.905 15.22 4.48 2.33 4.5 47.5 20.512 21.264 15.07 3.85 1.99 4.7 43.3 21.3

Fig. 8. The methane sorption isotherms of 12 samples from the Niutitang shale in the study area.

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e9688

Fig. 9. Comparison of methane sorption capacities of shale samples from China andother countries, showing a positive correlation with their TOC contents.

Fig. 10. Correlation between TOC and Langmuir pressure (PL) of the Niutitang shale inthe study area (data points in dashed ovals represent negative correlations betweenTOC and PL).

Table 4The mechanical parameters of the Niutitang shale in the study area.

Well name Depth (m) Static Young’s elasticmodulus (GPa)

Poisson’s ratio (m) W

Single value Average Single value Average

TX-1 1770.00e1776.38 24.1 27.8 0.18 0.19 T32.3 0.2127.1 0.19

TX-1 1779.80e1785.66 23.2 23.6 0.23 0.21 T26.6 0.1920.9 0.20

TX-1 1785.91e1791.80 29.2 27.4 0.20 0.19 T25.6 0.1827.3 0.19

TX-1 1795.81e1796.33 20.5 21.7 0.17 0.19 T23.8 0.1920.8 0.21

TX-1 1801.54e1802.37 24.5 25.6 0.21 0.22 T25.4 0.2026.8 0.24

TX-1 1808.19e1812.70 30.2 31.3 0.20 0.22 T32.2 0.2131.5 0.24

TM-1 1405.20e1409.84 31.5 33.5 0.15 0.17 T33.1 0.1735.8 0.19

TM-1 1415.11e1417.77 29.0 27.7 0.14 0.1627.8 0.1826.4 0.15

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e96 89

than a sample containing 9 nm pores, and the ratio even reaches18.9 and 9.3 times higher at 1 MPa.

4.6. Isothermal methane sorption

To estimate the gas sorption capacity of the Niutitang shale, thisstudy includes methane sorption experiments using samples from12 different depths inwell TM-1, with TOC values ranging from 1.2%to 8.5% (Table 3). The results show that the high-pressure methanesorption capacity of the Niutitang shale samples varies from1.87 m3/t for organic-poor samples to 7.75 m3/t for organic-richsamples (Table 3, Fig. 8). A compilation of methane sorption ca-pacities of organic-rich shales from southern and central China,Europe and the U.S. correlated with their corresponding TOC valuesare provided in Fig. 9. As shown in Fig. 9, organic matter has asignificant control on the methane sorption capacities of marineand lacustrine shales (Gasparik et al., 2014; Ji et al., 2014; Tan et al.,2014; Zhang et al., 2015), and the specific surface area attributed toorganic matter and OM-hosted pores controls the methane sorp-tion capacity significantly, rather than clay minerals, as revealed byprevious studies (Chalmers and Bustin, 2008; Gasparik et al., 2014;Ross and Bustin, 2007, 2009; Zhang et al., 2012; Ji et al., 2014).

Langmuir pressure (PL) is typically used to indicate the affinitybetween methane and adsorbents and is an important parameterfor evaluating the feasibility of gas desorption under reservoirpressure (Ross and Bustin, 2007; Zhang et al., 2012; Ji et al., 2012),i.e., methane adsorbs more readily at lower PL. Fig. 10 also showsthat when the TOC is greater than a certain degree, the positivecorrelation between TOC and PL becomes negative (data points inthe dashed oval), which is similar to trends in other reservoir pa-rameters (porosity and total pore volume) that have piecewisecorrelations with TOC (Figs. 4D and 7D).

4.7. Rock mechanical properties and fractures

In shale gas exploration and development around theworld, it isgenerally accepted that a higher brittle mineral (quartz, feldspar,

ell name Depth (m) Static Young’s elasticmodulus (GPa)

Poisson’s ratio (m)

Single value Average Single value Average

M-1 1420.29e1421.54 28.7 28.4 0.14 0.1325.5 0.1431.0 0.12

M-1 1428.55e1432.73 33.6 34.3 0.12 0.1233.4 0.1035.9 0.14

M-1 1434.54e1437.64 36.4 32.7 0.10 0.1136.7 0.1225.1 0.11

M-1 1447.62e1449.94 21.8 24.7 0.11 0.1027.9 0.1024.4 0.10

M-1 1453.03e1456.23 27.1 25.1 0.13 0.1522.3 0.1625.8 0.15

M-1 1461.46e1463.68 29.3 28.5 0.09 0.1124.5 0.1131.8 0.14

M-1 1469.06e1472.13 34.5 32.5 0.10 0.1031.7 0.0931.4 0.10

Fig. 11. Columnar sections of the shale reservoir characteristics from three wells in the study area.

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e9690

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e96 91

pyrite and carbonate) content corresponds to a higher brittlenessand greater fracture development (Jarvie et al., 2007; Wang, 2008;Rickman et al., 2008; Ding et al., 2012; Guo, 2013; Guo and Zhang,2014). Under the same stress conditions, shale with a low Poissonratio and a high Young’s elastic modulus has a high brittleness(Grieser and Bray, 2007; Rickman et al., 2008), favoring the gen-eration of natural and induced fractures. To estimate the brittlenessof the Niutitang shale in the study area, the static and dynamicmechanical properties of the rock were determined by uniaxial andtriaxial compression tests (Table 4) and cross-dipole array acousticlogging (Fig. 11B). Numerous studies (Kuhlman et al., 1993; Yale,1994) have shown that there are generally linear correlations be-tween the static and dynamic mechanical parameters of rock,indicating that the twomethods can be combined to determine thevertical variations in the brittleness of the Niutitang shale (Fig. 11B,C).

Fig. 11 shows that the brittleness of the Niutitang shale in thestudy area generally increases with the quartz content in the ver-tical direction, and the natural gamma-ray (GR), TOC and quartzcontents are positively correlated. However, there are two low-brittleness sections of the Niutitang shale (shaded sections A andB in Fig. 11). Section A has high clay mineral (low brittle mineral)content, and Section B has low clay mineral content and high TOC,reflecting the fact that the brittleness of the Niutitang shale isinfluenced by TOC and mineral contents. Moreover, the fracturedensity from the core observation is positively correlated with the

Fig. 12. Correlation between TOC and fracture density in the Niutitang shale.

Fig. 13. Relationships between the dynamic rock mechanical param

brittleness. The correlations between the fracture density and otherparameters (TOC, GR and quartz contents) are generally positive,except in sections A and B (Fig. 11). The relationship between thefracture density and TOC also shows a piecewise correlation(Fig. 12).

The relationships between the mechanical parameters and theTOC and mineral contents (Fig. 13) show that when the TOC andquartz contents are lower than a certain degree (in this paper, theinflection points of the TOC and quartz contents are approximately6.5% and 65%, respectively, based on the method of exhaustion),Young’s modulus is positively correlated with the TOC and quartzcontents. When the TOC or quartz content is greater than 6.5% (or65%), Young’s modulus is negatively correlated with the TOC andquartz contents (Fig. 13A, C), causing the brittleness and fracturedensity to decrease. In addition, the inflection points of the TOC andquartz contents are applicable to correlations with other reservoirparameters (Figs. 4D, 7D, E, 10 and 12).

Fractures in the Niutitang shale are observed based on cores,thin sections and FE-SEM (Fig. 14). The main types of fractures arehigh dip-angle structural fractures, slip fractures and interlayerfractures. Although most of the fractures are sealed, multiple typesof secondary pores and fractures can be found in the cements offractures and have effectively improved the specific surface areaand some storage spaces (Fig. 14DeI). In addition, a statisticalanalysis of the gas content and fracture density in the Niutitangshale from the TX-1 well shows that they are positively correlated(Fig. 15A), i.e., the total and desorbed gas contents generally in-crease with the fracture density (Fig. 15B and C). The pore sizedistribution based on the nitrogen adsorption and permeability ofpores in the Niutitang shale shows that a proportion of pores havesizes larger than 10 nm in the well-developed fracture sections(Fig. 15D), contributing to the largest proportion of permeabilityand providing a portion of the storage space for the shale reservoir(Fig. 15E).

5. Discussion

The pore structure of the Lower Cambrian Niutitang shale inthe study area exhibits splint or ink-bottle shapes with narrowthroats. High thermal maturity (poor hydrocarbon generationpotential) and severe diagenetic compaction increase thenumbers of isolated, ineffective and narrow pores as a result ofdecreasing pore throat sizes and a decrease in the number andsize of OM-hosted pores (Fig. 16; Milliken et al., 2013; Wang

eters, TOC content and mineral contents of the Niutitang shale.

Fig. 14. Fractures in the Niutitang shale. (A) Well TM-1, 1452.1 m, high dip-angle structural fractures and interlayer fractures sealed with calcite; (B) Well TX-1, 1809.8 m, verticalcompression-shear fractures sealed with calcite and clay exhibit obvious scratches caused by mylonitic minerals that developed on the early formed vertical fractures that are sealedwith calcite; (C) Well TX-1, 1791.6 m, horizontal slip fracture with a smooth mirror; (D) Well TX-1, 1777.8 m, fracture sealed with calcite, pyrite and quartz and cleavages anddissolved pores in the calcite; (E) Well CY-1, 1445.1 m, inter-particle and intra-particle pores and fractures developed in the quartz and calcite of siliceous sponge spicule; (F) WellTX-1, 1812.1 m, secondary unsealed fractures are well developed in quartz cement; (G) Well TX-1, 1813.7 m, dissolved pores, cleavages and intra-particle fractures in carbonateminerals; (H) Well TX-1, 1791.9 m, frictional pores and fractures developed on the slickenside of a slip fracture; (I) An enlarged drawing of part of figure H showing that inter-particlepores and fractures are abundant in mylonitic minerals.

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e9692

et al., 2013a; Tian et al., 2013, 2015). The positive correlationbetween the TOC and quartz contents suggests that high TOC isfrequently associated with high quartz content, which usuallyfavors the development and preservation of inter-particle poresbetween rigid mineral particles (Wang et al., 2013a) and leadsto high brittleness, producing structural and induced fractures.Unlike the major gas-producing shales in the U.S. and theLower Silurian Longmaxi shale in southern China (Fig. 16),which have large quantities of OM-hosted pores, the inter-particle and intra-particle pores and fractures, especially theinter-particle pores between rigid mineral particles (Fig. 5EeG),are the main sources of storage spaces in the Lower CambrianNiutitang shale. However, the large quantities of OM-hostedpores with diameters less than 5 nm in organic matter pro-vide large specific surface areas (Fig. 7), which are significantfor the methane sorption capacity of the Niutitang shale (Huet al., 2015; Mosher et al., 2013).

The positive correlation between the TOC and quartz contentssuggests that their correlations with other parameters of theshale reservoir are similar (Figs. 4, 7 and 13). When the TOC is

less than 6.5%, the brittleness caused by brittle minerals in-creases faster than the ductility caused by TOC (Fig. 13), resultingin positive correlations between the TOC and quartz contentsand other reservoir parameters. Moreover, the positive correla-tion between TOC and fracture density suggests that fracturesprovide more storage spaces and seepage pathways for free gas,corresponding with simultaneous increases in Langmuir pressure(Figs. 10, 12 and 15). When the TOC is greater than 6.5%, thepositive correlations become negative due to rapid ductility in-crease caused by TOC. The decreased brittleness makes the shalemore vulnerable to compaction, decreasing the pore size, frac-ture density and free gas content and increasing the number ofnarrow pores and specific surface areas that adsorb shale gasreadily at low Langmuir pressure (Figs. 4, 7 and 10). Therefore,TOC significantly influences the macroscopic (e.g., brittleness)and microscopic (e.g., porosity, pore structure and sorption ca-pacity) reservoir properties of organic-rich shales. This infor-mation can be used to guide the exploration and development ofshale gas and optimize intervals in drilling and fracturingstimulations.

Fig. 15. (A) Histogram of the linear fracture density and gas content in Niutitang shale based on well TX-1; (B) Relationship between the total gas content and fracture density inwell TX-1; (C) Relationship between the desorbed gas content and fracture density in well TX-1; (D) Shale samples with high fracture densities have larger proportions of mesoporeswith sizes greater than 10 nm; (E) Mesopores with sizes that range from 14 to 100 nm contribute to the largest proportion of shale permeability. Figure E is from Yang et al. (2013).

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e96 93

6. Conclusions

(1) The Lower Cambrian Niutitang shale in the study area has ahigh TOC, ranging from 0.51% to 10.49% and averaging 4.6%,and high thermal maturity, with an equivalent Ro greaterthan 2.2%. The mineralogical composition is dominated byquartz and clay minerals averaging 52.7% and 21.2%,respectively. The total specific surface area varies from 6.78to 30.37 m2/g, and the Langmuir volume ranges from1.87 cm3/g to 7.75 cm3/g. Both of these parameters arepositively correlated with TOC, indicating that organic mat-ter has a significant control on the methane sorptioncapacity.

(2) FE-SEM observations and nitrogen adsorption studies revealthat the OM-hosted pores in the Niutitang shale are rela-tively undeveloped and generally smaller than 5 nm;

however, they contribute significantly to the methane sorp-tion capacity. Inter-particle and intra-particle pores andfractures are the main sources of storage spaces and seepagepathways in over-mature marine shales. In addition, the highquartz content (rigid minerals) associated with high TOCfavors the development and preservation of micropores andthe enrichment of free and adsorbed gas.

(3) When the TOC is less than 6.5%, the TOC is positivelycorrelated with the porosity, total pore volume, brittleness(Young’s modulus), core fracture density, Langmuir pres-sure and free gas content; however, when the TOC isgreater than 6.5%, the TOC becomes negatively correlatedwith these parameters due to increases in ductility andcompaction, indicating that TOC significantly impacts themacroscopic (e.g., brittleness) and microscopic (e.g., porestructure and sorption capacity) properties of shale

Fig. 16. A comparison of OM-hosted pores in different shales and the relationship between the porosity and maturity of organic-rich shales (Wang et al., 2013a; Tian et al., 2013,2015). (A) Lower Silurian Longmaxi shale from the Changxin-1 well with a TOC of 4.5% and an equivalent Ro of 2.15%; (B) Lower Cambrian Niutitang (also called Qiongzhusi) shalefrom the Wei-001 well with a TOC of 1.5% and an equivalent Ro of 2.9%; (C) Lower Silurian Longmaxi shale from the Pengye-1 well with a TOC of 1.3% and an equivalent Ro of 2.19%;(D) Lower Cambrian Niutitang shale from the Huangye-1 well with a TOC of 6.92% and an equivalent Ro of 3.17%; (E) The relationship between the porosity and maturity of organic-rich shales; (F) A conceptual model of the evolution of shale porosity.

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e9694

reservoirs, potentially controlling the enrichment andproductivity of shale gas.

Acknowledgment

This research was supported by the National Natural ScienceFoundation of China (Project No. 41372139 and 41072098)

and the National Science and Technology Major Project ofChina (No. 2016ZX05046-003-001, 2011ZX05018-001-002 and2011ZX05033-004). The authors would like to thank the staff ofall of the laboratories that cooperated in performing the tests andanalyses. We are grateful to the valuable comments of the editorand reviewers that improved the manuscript.

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e96 95

References

Barrett, E.P., Joyner, L.G., Halenda, P.P., 1951. The determination of pore volume andarea distributions in porous substances. I. Computations from nitrogen iso-therms. J. Am. Chem. Soc. 73 (1), 373e380.

Behar, F., Beaumont, V., De, B., Penteado, H.L., 2001. Rock-Eval 6 technology: per-formances and developments. Oil Gas Sci. Technol. Rev. IFP 56, 111e134.

Broekhoff, J.C.P., De Boer, J.H., 1968. Studies on pore systems in catalysts: XIII. Poredistributions from the desorption branch of a nitrogen sorption isotherm in thecase of cylindrical pores B. Applications. J. Catal. 10 (4), 377e390.

Brunauer, S., Emmett, P.H., Teller, E., 1938. Adsorption of gases in multimolecularlayers. J. Am. Chem. Soc. 60 (2), 309e319.

Chalmers, G.R., Bustin, R.M., 2008. Lower Cretaceous gas shales in northeasternBritish Columbia, Part I: geological controls on methane sorption capacity. Bull.Can. Pet. Geol. 56, 1e21.

Chalmers, G.R., Bustin, R.M., Power, I.M., 2012. Characterization of gas shale poresystems by porosimetry, pycnometry, surface area, and field emission scanningelectron microscopy/transmission electron microscopy image analyses: exam-ples from the Barnett, Woodford, Haynesville, Marcellus, and Doig units. AAPGBull. 96, 1099e1119.

Curtis, J.B., 2002. Fractured shale-gas systems. AAPG Bull. 86, 1921e1938.Ding, W.L., Li, C., Li, C.Y., Xu, C.C., Jiu, K., Zeng, W.T., Wu, L.M., 2012. Fracture

development in shale and its relationship to gas accumulation. Geosci. Front. 3(1), 97e105.

Ding, W., Wan, H., Zhang, Y., Han, G., 2013a. Characteristics of the Middle Jurassicmarine source rocks and prediction of favorable source rock kitchens in theQiangtang Basin of Tibet. J. Asian Earth Sci. 66, 63e72.

Ding, W., Zhu, D., Cai, J., Gong, M., Chen, F., 2013b. Analysis of the developmentalcharacteristics and major regulating factors of fractures in marineecontinentaltransitional shale-gas reservoirs: a case study of the CarboniferousePermianstrata in the southeastern Ordos Basin, central China. Mar. Pet. Geol. 45,121e133.

Dubinin, M.M., 1975. Physical adsorption of gases and vapors in micropores. Prog-ress in Surface and Membrane Science. Academic Press, pp. 1e70.

Gasparik, M., Bertier, P., Gensterblum, Y., Ghanizadeh, A., Krooss, B.M., Littke, R.,2014. Geological controls on the methane storage capacity in organic-richshales. Int. J. Coal Geol. 123, 34e51.

Grieser, W.V., Bray, J.M., 2007. Identification of Production Potential in Unconven-tional Reservoirs. Society of Petroleum Engineers. http://dx.doi.org/10.2118/106623-MS.

Guo, T., 2013. Evaluation of highly thermally mature shale-gas reservoirs in com-plex structural parts of the Sichuan Basin. J. Earth Sci. 24 (6), 863e873.

Guo, T., Zhang, H., 2014. Formation and enrichment mode of Jiaoshiba shale gasfield, Sichuan Basin. Pet. Explor. Dev. 41 (1), 31e40.

Hu, D., Zhang, H., Ni, K., Yu, G., 2014. Preservation conditions for marine shale gas atthe southeastern margin of the Sichuan Basin and their controlling factors. Nat.Gas Ind. B 1 (2), 178e184.

Hu, H., Zhang, T., Wiggins-Camacho, J.D., Ellis, G.S., Lewan, M.D., Zhang, X., 2015.Experimental investigation of changes in methane adsorption of bitumen-freeWoodford Shale with thermal maturation induced by hydrous pyrolysis. Mar.Pet. Geol. 59, 114e128.

Jarvie, D.M., Hill, R.J., Ruble, T.E., Pollastro, R.M., 2007. Unconventional shale-gassystems: the Mississippian Barnett Shale of north-central Texas as one modelfor thermogenic shale-gas assessment. AAPG Bull. 91, 475e499.

Ji, L., Zhang, T., Milliken, K.L., Qu, J., Zhang, X., 2012. Experimental investigation ofmain controls to methane adsorption in clay-rich rocks. Appl. Geochem. 27 (12),2533e2545.

Ji, W., Song, Y., Jiang, Z., Wang, X., Bai, Y., Xing, J., 2014. Geological controls andestimation algorithms of lacustrine shale gas adsorption capacity: a case studyof the Triassic strata in the southeastern Ordos Basin, China. Int. J. Coal Geol.134e135, 61e73.

Kang, Y., 2012. Characteristics and exploration prospect of unconventional shale gasreservoirs in China. Nat. Gas Ind. 32 (4), 1e5 (in Chinese with English abstract).

Kuhlman, R.D., Heemstra, T.R., Ray, T.G., Lin, P., Chariez, P.A., 1993. Field Tests ofDownhole Extensometer Used to Obtain Formation In-situ Stress Data. Societyof Petroleum Engineers. http://dx.doi.org/10.2118/25905-MS.

Kuila, U., McCarty, D.K., Derkowski, A., Fischer, T.B., Top�or, T., Prasad, M., 2014. Nano-scale texture and porosity of organic matter and clay minerals in organic-richmudrocks. Fuel 135, 359e373.

Lafargue, E., Marquis, F., Pillot, D., 1998. Rock-Eval 6 applications in hydrocarbonexploration, production, and soil contamination studies. Oil Gas Sci. Technol. 53(4), 421e437.

Li, X., Lu, Z., Dong, D., Cheng, K., 2009. Geologic controls on accumulation of shalegas in North America. Nat. Gas Ind. 29 (5), 27e32 (in Chinese with Englishabstract).

Loucks, R.G., Reed, R.M., Ruppel, S.C., Hammes, U., 2012. Spectrum of pore types andnetworks in mudrocks and a descriptive classification for matrix-relatedmudrock pores. AAPG Bull. 96, 1071e1098.

Ma, L., Chen, H., Gan, K., Xu, K., Xu, X., Wu, G., Ye, Z., Liang, X., Wu, S., Qiu, Y.,Zhang, P., Ge, P., 2004. Geotectonics and Petroleum Geology of Marine Sedi-mentary Rocks in Southern China (in Chinese). Geological Publishing House,Beijing, China, pp. 3e50.

Milliken, K.L., Rudnicki, M., Awwiller, D.N., Zhang, T., 2013. Organic matter-hostedpore system, Marcellus formation (Devonian), Pennsylvania. AAPG Bull. 97,

177e200.Montgomery, S.L., Jarvie, D.M., Bowker, K.A., Pollastro, R.M., 2005. Mississippian

Barnett Shale, Fort Worth Basin, north-central Texas: gas-shale play withmultitrillion cubic foot potential. AAPG Bull. 89, 155e175.

Mosher, K., He, J., Liu, Y., Rupp, R., Wilcox, J., 2013. Molecular simulation of methaneadsorption in micro- and mesoporous carbons with applications to coal and gasshale systems. Int. J. Coal Geol. 109e110, 36e44.

Nie, Y., Leng, J., Han, J., Sun, L., Shen, G., 2013. Exploration potential of shale gas inCen’gong block, southeastern Guizhou province. Oil Gas Geol. 34 (2), 274e280(in Chinese with English abstract).

Pan, L., Xiao, X., Tian, H., Zhou, Q., Chen, J., Li, T., Wei, Q., 2015. A preliminary studyon the characterization and controlling factors of porosity and pore structure ofthe Permian shales in Lower Yangtze region, Eastern China. Int. J. Coal Geol. 146,68e78.

Pecharsky, V.K., Zavalij, P.Y., 2003. Fundamentals of Powder Diffraction and Struc-tural Characterization of Minerals. Kluwer Academic Publishers, New York, 713pp.

Pollastro, R.M., 2007. Total petroleum system assessment of undiscovered resourcesin the giant Barnett Shale continuous (unconventional) gas accumulation, FortWorth Basin. Tex. AAPG Bull. 91, 551e578.

Rexer, T.F.T., Benham, M.J., Aplin, A.C., Thomas, K.M., 2013. Methane adsorption onshale under simulated geological temperature and pressure conditions. EnergyFuels 27, 3099e3109.

Rickman, R., Mullen, M., Petre, E., Grieser, B., Kundert, D., 2008. A Practical Use ofShale Petrophysics for Stimulation Design Optimization: All Shale Plays are notClones of the Barnett Shale. Society of Petroleum Engineers. http://dx.doi.org/10.2118/115258-MS.

Ross, D.J., Bustin, R.M., 2007. Shale gas potential of the lower Jurassic Gordondalemember, northeastern British Columbia, Canada. Bull. Can. Pet. Geol. 55, 51e75.

Ross, D.J., Bustin, R.M., 2009. The importance of shale composition and porestructure upon gas storage potential of shale gas reservoirs. Mar. Pet. Geol. 26,916e927.

Schoenherr, J., Littke, R., Urai, J.L., Kukla, P.A., Rawahi, Z., 2007. Polyphase thermalevolution in the Infra-Cambrian Ara group (South Oman salt basin) as deducedby maturity of solid reservoir bitumen. Org. Geochem. 38, 1293e1318.

Sing, K., Everett, D., Haul, R., Moscou, L., Pierotti, R., Rouquerol, J., Siemieniewska, T.,1985. Pure Appl. Chem. 57, 603e619.

Stach, E., Mackowsky, M.-T., Teichmüller, M., Taylor, G.H., Chandra, D.,Teichmüller, R., 1982. Stach’s Textbook of Coal Petrology. Gebrüder Borntraeger,Stuttgart.

Tan, J., Horsfield, B., Mahlstedt, N., Zhang, J., di Primio, R., Vu, T.A.T., Boreham, C.J.,van Graas, G., Tocher, B.A., 2013. Physical properties of petroleum formedduring maturation of Lower Cambrian shale in the upper Yangtze Platform,South China, as inferred from Phase Kinetics modelling. Mar. Pet. Geol. 48,47e56.

Tan, J., Weniger, P., Krooss, B., Merkel, A., Horsfield, B., Zhang, J., Boreham, C.J.,Graas, Gv, Tocher, B.A., 2014. Shale gas potential of the major marine shaleformations in the Upper Yangtze Platform, South China, Part II: methanesorption capacity. Fuel 129, 204e218.

Taylor, H., Teichmüller, M., Davis, A., Diessel, C.F.K., Littke, R., Robert, P., 1998.Organic Petrology. Borntraeger, Berlin-Stuttgart.

Tian, H., Pan, L., Xiao, X., Wilkins, R.W.T., Meng, Z., Huang, B., 2013. A preliminarystudy on the pore characterization of Lower Silurian black shales in theChuandong Thrust Fold Belt, southwestern China using low pressure nitrogenadsorption and FE-SEM methods. Mar. Pet. Geol. 48, 8e19.

Tian, H., Pan, L., Zhang, T., Xiao, X., Meng, Z., Huang, B., 2015. Pore characterizationof organic-rich Lower Cambrian shales in Qiannan depression of Guizhouprovince, southwestern China. Mar. Pet. Geol. 62, 28e43.

Wang, F.P., 2008. Production fairway: speed rails in gas shale. 7th Annual Gas ShaleSummit, Dallas, Texas, 6e7 May.

Wang, F., Guan, J., Feng, W., Bao, L., 2013a. Evolution of overmature marine shaleporosity and implication to the free gas volume. Pet. Explor. Dev. 40 (6),819e824.

Wang, L., Jiu, K., Zeng, W., Fu, J., Zhao, S., 2013b. Characteristics of Lower Cambrianmarine black shales and evaluation of shale gas prospective area in Qianbeiarea, Upper Yangtze region. Acta Petrol. Sin. 29 (9), 3263e3278 (in Chinese withEnglish abstract).

Wang, R., Ding, W., Zhang, Y., Wang, Z., Wang, X., He, J., Zeng, W., Dai, P., 2016a.Analysis of developmental characteristics and dominant factors of fractures inLower Cambrian marine shale reservoirs: a case study of Niutitang formation inCen’gong block, southern China. J. Pet. Sci. Eng. 138, 31e49.

Wang, R., Ding, W., Gong, D., Leng, J., Wang, X., Yin, S., Sun, Y., 2016b. Gas preser-vation conditions of marine shale in northern Guizhou area: a case study of theLower Cambrian Niutitang Formation in the Cen’gong block, Guizhou Province.Oil Gas Geol. 37 (1), 45e55 (in Chinese with English abstract).

Xia, J., Wang, S., Cao, T., Yang, J., Song, Z., 2015. The characteristics of pore structureand its gas storage capability of the Lower Cambrian shales from northernGuizhou Province. Nat. Gas Geosci. 26 (9), 1744e1754 (in Chinese with Englishabstract).

Yale, D.P., 1994. Static and Dynamic Rock Mechanical Properties in the Hugoton andPanoma Fields. Society of Petroleum Engineers, Kansas. http://dx.doi.org/10.2118/27939-MS.

Yang, F., Ning, Z., Hu, C., Wang, B., Peng, K., Liu, H., 2013. Characterization ofmicroscopic pore structures in shale reservoirs. Acta Pet. Sin. 34 (2), 301e311(in Chinese with English abstract).

R. Wang et al. / Journal of Natural Gas Science and Engineering 33 (2016) 81e9696

Zhang, J., Fan, T., Li, J., Zhang, J., Li, Y., Wu, Y., Xiong, W., 2015. Characterization of theLower Cambrian shale in the Northwestern Guizhou province, South China:implications for shale-gas potential. Energy Fuels 29, 6383e6393.

Zhang, T., Ellis, G.S., Ruppel, S.C., Milliken, K., Yang, R., 2012. Effect of organic-mattertype and thermal maturity on methane adsorption in shale-gas systems. Org.

Geochem 47, 120e131.Zou, C., Dong, D., Wang, S., Li, J., Li, X., Wang, Y., Li, D., Cheng, K., 2010. Geological

characteristics, formation mechanism and resource potential of shale gas inChina. Pet. Explor. Dev. 37 (6), 641e653.