Characterization of the Lower Cambrian Shale in the NorthwesternGuizhou Province, South China: Implications for Shale-Gas PotentialJunpeng Zhang,†,‡ Tailiang Fan,*,†,‡ Jing Li,§ Jinchuan Zhang,†,‡ Yifan Li,†,‡ Yue Wu,†,‡

and Weiwei Xiong∥

†School of Energy Sources, China University of Geosciences, Haidian, Beijing 100083, China‡Key Laboratory of Marine Reservoir Evolution and Hydrocarbon Accumulation Mechanism, Ministry of Education, China Universityof Geosciences, Beijing 100083, China§School of Earth Science and Sources, China University of Geosciences, Haidian, Beijing 100083, 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 recentlybeen 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 inthe NWG area is characterized by high TOC content and high thermal maturity. The mineralogical composition and lithofaciesassemblage of the NWG shale are compared with hot shales for analogy and found to be greatly similar to the Barnett shales. Fivedifferent genetic types of pores have been identified by scanning electron microscopy. The porosity shows no correlation with thequartz and clay ratios, but it correlates well with the TOC content, suggesting that organic matter pores have contributed a lot tothe total porosity. The pore size distribution is evaluated by pore volume and surface area based on diameter, indicating that themicropores and mesopores are the major pore sizes. The methane sorption isotherms conducted on representative samples withdifferent TOC and clay contents certify the assumption that microporous organic matter in high-maturity shales provides a largeinternal surface area for the adsorbed gas. After comprehensive analysis, the lower part of the studied shale in the NWG, withhigh TOC contents, is proposed as a target for shale-gas production.

1. INTRODUCTION

The remarkable success of shale-gas production has inspiredmore extensive exploration activity in other countries, such asChina and Australia, especially after the United States achievedits “energy independence”transitioning from import toexport of nature gas (EIA, 2015). To accommodate thenational energy demand, a variety of exploration strategies havebeen carried out by the Ministry of Land and Resources (MLR)in South China, in an attempt to achieve commercialproduction of shale gas. It has been reported that the geologicreserves of shale gas in the Guizhou province could amount to1048 billion m3 (MLR, www.mlr.gov.cn). Thus, the MLRcooperated with the state of Guizhou province and ChinaUniversity of Geosciences in Beijing (CUGB) and hasconstructed more than 75 drilling wells from 2013 to thepresent. The Northwestern area of Guizhou province (NWG)was selected as the priority because the shale is of considerablethickness and was found to have a higher TOC content in theearly exploration stage. Quite a few wells have been drilled inthe NWG before, except the Cenye-1 well operated in 2012 inthe Northeast part of the Guizhou province (NEG).1,2 Thisstudy is an overall investigation report on the RY1 well and theRY2 well in Renhuai city in the NWG area. These twogeological 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 environ-ments occurred in the Early Cambrian.2−4 With the occurrence

of the second major marine transgression from the Southeast tothe Northwest, the sea level rise of the Yangtze Sea promotedhigh productivity in the surface water and anoxic conditions inthe bottom water in the open marine and continental shelfenvironments. Thus, organic matter accumulated within themarine mudstone or chert, covering the Sinian dolomite with asubmerged unconformity.2−4 The Tongwan tectonic move-ment at the end of the Proterozoic caused this disconformitybetween the Ediacaran and lower Cambrian strata.4 The strataof mainly shales for this interval are usually named theNiutitang Formation, with a total thickness ranging from 24 to200 m in the south and north Sichuan Basin, west Hunan andHubei Provinces, and north Guizhou and Yunnan Provinces(Figure 1).3,4 The Lower Cambrian in the NWG area mainlyconsists of chert, shales, and carbonate rocks, the shale intervalof which has been investigated as one of the importantPhanerozoic source rocks for conventional oil and gassources.2−5 Recently, the lower part of the Niutitang Formationhas been reported as a potential for shale gas according togeochemical analysis of samples from the Cenye-1 well andsome outcrops in the NEG.1,6 The shale distribution, organicmatter richness, thermal maturity and mineralogical composi-tion can be totally compared to the Barnett shale, which is oftenselected as an exploitation model in previous studies.2,4 Here

Received: July 29, 2015Revised: September 14, 2015Published: September 15, 2015

Article

pubs.acs.org/EF

© 2015 American Chemical Society 6383 DOI: 10.1021/acs.energyfuels.5b01732Energy Fuels 2015, 29, 6383−6393

we provide a comprehensive characterization of the LowerCambrian shale in the NWG, including investigation ofgeochemical characteristics, mineralogical composition, poros-ity analysis, and gas adsorption capacity, which contributes toan improved evaluation of the shale gas potential.

2. MATERIALS AND METHODS

2.1. Samples. A total of 98 samples were collected fromboth the RY1 well and the RY2 well based on core observationand log response, including chert, siliceous mudstone,calcareous mudstone, and silty mudstone samples and also aphosphatic nodule from the basal strata. All experiments belowwere conducted in standard procedures to ensure theiranalytical accuracy.2.2. Methods. To achieve a comprehensive characterization

of the NWG shale, total organic carbon (TOC), vitrinitereflectance (Ro), kerogen type index (TI), mineralogy (X-raydiffraction, XRD), porosity, pore size distribution, and gasadsorption capacity (methane adsorption experiments) weredetermined (Table 1). Meanwhile, visual evaluation via thinsection and scanning electron microscopy (SEM) wereperformed 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 sulfuranalyzer and reported on a raw sample basis as percent. Rock-Eval pyrolysis was performed on only 10 samples. Visualmeasurements of organic macerals and Ro were also conductedon 20 samples. All geochemical experiments above werecompleted 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 chertsample and one limestone sample. The primary minerals likequartz, feldspar, calcite, dolomite, pyrite, and clay weredetermined. The settings were 40 kV and 30 mA. Measureddata were then analyzed qualitatively using the EVA (Bruker)software and quantitatively using the AutoQuant software. This

experiment was conducted at the Analytical Laboratory of theBeijing Research Institute of Uranium Geology (AL-BRIUG).Porosity was determined by Hg porosimetry using an

Autopore IV 9510 series porosimeter. Pore size distributionwas evaluated by N2 gas adsorption, and the methods ofBrunauer−Emmett−Teller (BET) and Barrett−Joyner−Halen-da (BJH) were employed for calculation.7,8 Pores were dividedinto three types according to their diameter: micropore (<2nm), mesopore (2−50 nm), and macropore (>50 nm).9

Methane sorption isotherms were conducted on fiverepresentative samples from the RY1 well with different TOC

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).

Table 1. Investigated Samples and Applied Measurements(except TOC, as all 98 samples were analyzed for TOC)

Ro XRDporosity andpermeability

N2 gasadsorption

methanesorptionisotherm

(n = 20) (n = 31) (n = 18) (n = 11) (n = 5)

RY1-49 RY1-47 RY2-48 RY1-45 RY1-49 RY1-41RY1-40 RY1-35 RY2-43 RY1-37 RY1-35 RY1-30RY1-38 RY1-29 RY2-39 RY1-29 RY1-28 RY1-24RY1-34 RY1-28 RY2-36 RY1-24 RY1-22 RY1-13RY1-26 RY1-22 RY2-33 RY1-22 RY1-09 RY1-02RY1-22 RY1-21 RY2-31 RY1-13 RY2-26RY1-19 RY1-17 RY2-28 RY1-09 RY2-12RY1-16 RY1-13 RY2-26 RY1-04 RY2-10RY1-07 RY1-09 RY2-25 RY2-26 RY2-07RY1-02 RY1-08 RY2-14 RY2-23 RY2-05RY2-5 RY1-07 RY2-08 RY2-18 RY2-03RY2-38 RY1-06 RY2-12 RY2-14RY2-36 RY1-04 RY2-10 RY2-12RY2-31 RY1-02 RY2-07 RY2-10RY2-26 RY2-05 RY2-09RY2-23 RY2-03 RY2-07RY2-18 RY2-01 RY2-05RY2-12 RY2-03RY2-07RY2-03

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and clay contents under a modeled reservoir temperature of 49°C. The Langmuir isotherm method was employed to modelthe gas adsorption capacity, V = VLP/(PL + P), where V is thevolume of absorbed gas, VL is the Langmuir volume which isthe maximum adsorption capacity of the absorbent, P is the gaspressure, and PL is the Langmuir pressure, at which theabsorbed gas content (V) is equal to half of the Langmuirvolume (VL).

10 These three experiments were conducted at theResearch 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 samplesfrom the RY1 well and RY2 well in the NWG are presented inTable 2. TOC concentrations vary from 0.37% to 14.68% forthe RY1 core with an average of 4.8% and range from 0.37% to11.83% for the RY2 core with a mean value of 5.91%, highlysimilar to those of the Lower Cambrian shale in Sichuan Basin,South China.16 TOC contents for both cores show a decreasingtrend upward, achieving peak values in the lower part of the

Table 2. TOC and Ro of the Lower Cambrian Shale in the NWG

samples depth (m) TOC (%) Ro (%) samples depth (m) TOC (%) Ro (%)

RY1-49 1265.0 0.41 3.07 RY2-49 848.9 1.66RY1-48 1266.0 0.54 RY2-48 850.5 0.89RY1-47 1267.4 0.38 RY2-47 852.8 2.24RY1-46 1268.1 0.41 RY2-46 853.9 1.28RY1-45 1269.3 0.44 RY2-45 855.6 2.59 2.00RY1-44 1270.1 0.37 RY2-44 857.9 2.36RY1-43 1272.5 0.44 RY2-43 861.9 2.56RY1-42 1273.4 0.52 RY2-42 864.5 3.61RY1-41 1275.9 0.82 RY2-41 867.8 3.20RY1-40 1277.1 0.82 3.50 RY2-40 870.7 4.65RY1-39 1280.2 0.68 RY2-39 873.6 4.76RY1-38 1281.4 1.09 3.10 RY2-38 876.3 4.57 2.01RY1-37 1284.7 1.09 RY2-37 880.1 3.88RY1-36 1287.5 0.58 RY2-36 884.1 5.75 2.21RY1-35 1289.3 0.68 RY2-35 887.5 4.86RY1-34 1290.2 0.48 3.68 RY2-34 890.9 5.93RY1-33 1292.1 2.72 RY2-33 891.8 11.83RY1-32 1293.8 2.72 RY2-32 894.0 4.26RY1-31 1296.0 2.72 RY2-31 896.6 4.55 2.31RY1-30 1299.1 3.40 RY2-30 898.9 5.56RY1-29 1300.2 5.98 RY2-29 899.6 5.78RY1-28 1304.1 3.24 RY2-28 900.4 7.62RY1-27 1305.7 3.67 RY2-27 902.2 8.38RY1-26 1308.3 4.62 3.56 RY2-26 903.2 9.16 2.70RY1-25 1309.0 3.54 RY2-25 904.3 7.56RY1-24 1310.1 4.76 RY2-24 905.5 7.14RY1-23 1313.4 5.85 RY2-23 906.6 5.31 3.09RY1-22 1315.6 6.12 3.19 RY2-22 907.5 6.89RY1-21 1317.3 5.03 RY2-21 908.2 7.10RY1-20 1319.2 5.71 RY2-20 909.1 6.71RY1-19 1321.9 4.90 3.40 RY2-19 910.1 6.46RY1-18 1323.6 6.26 RY2-18 910.9 9.42 2.74RY1-17 1325.0 7.89 RY2-17 912.1 7.04RY1-16 1326.1 8.16 3.40 RY2-16 913.6 9.42RY1-15 1327.2 4.76 RY2-15 914.5 9.04RY1-14 1328.7 7.07 RY2-14 916.1 10.44RY1-13 1330.5 8.43 RY2-13 917.4 11.48RY1-12 1332.0 7.62 RY2-12 919.1 9.37 3.01RY1-11 1333.1 8.57 RY2-11 920.2 11.20RY1-10 1334.3 10.34 RY2-10 920.5 5.17RY1-09 1335.0 8.43 RY2-09 921.9 4.39RY1-08 1336.1 11.70 RY2-08 922.1 5.81RY1-07 1337.8 11.02 3.34 RY2-07 922.5 6.76 3.11RY1-06 1340.4 8.57 RY2-06 923.2 6.95RY1-05 1341.3 5.17 RY2-05 923.9 2.72RY1-04 1342.1 11.29 RY2-04 925.5 7.70RY1-03 1344.2 11.56 RY2-03 926.7 8.47 2.96RY1-02 1345.6 9.11 3.16 RY2-02 928.2 0.37RY1-01 1347.0 14.69 RY2-01 928.9 4.98

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trend (Figure 2). The interval composed of mainly siliceousand calcareous mudstone has high TOC contents with averagevalues more than 6%. Ro values for the RY1 core vary from3.07% to 4.56%, indicating a thermal maturity of “gas window”or “over-matured”. Similarly, Ro values for the RY2 core range

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

Figure 2. Lithological column of the RY1 and RY2 wells with log curves. MXS: Mingxisi Formation; DY: Dengying Formation.

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kerogen reveal the presence of 95−98% amorphous organicmatter with a mainly sapropelic substance. A small amount (1−5%) of terrestrial organics may also be found. The kerogen typeindex (TI) ranges from 90.5 to 96.5, confirming sapropelic(Type I) as the kerogen type. Here the TI is used as an indexcounting percentage compositions of different macerals todecide the kerogen type. However, with the maturity of organicmatter above 2.5%, original maceral structures are usually hardto differentiate leading to the uncertainty of TI calculation.4

Anyway, it is consistent with the interpretation of the kerogentype by isotopic carbon analysis. Previous studies found thekerogen δ13 C in shale ranges from −29.88‰ to −35.79‰,suggesting Type I as the kerogen type of the organic matter.5,6

Two basic approaches exist to determine the thermalmaturity: visual and chemical methods.11,12 Determination ofvitrinite reflectance, as discussed above, was completed viamicroscopic examination of kerogen or whole rock mounts. Asthe vitrinite should not be present in sediments beforeDevonian times, another approach to calculate Ro via bitumenreflectance (Rb) was proposed. The calculation formulaaccording to Feng and Chen (1988) is presented below:15

= +Ro 0.3195 0.6790Rb

Considering the pitfalls among identification of theindigenous vitrinite, Rock-Evel Tmax is used as an additionalchemical assessment to provide confirmation of the visualmeasurements.12−14 The Ro calculated from Tmax (Table 3)seems coincident with that measured by bitumen reflectance.

Table 3. Rock-Eval Results of Core Samples (Tmax = (Ro + 7.16)/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 (%)

RY1-02 1345.6 9.11 0.06 0.14 2 570 3.10 3.16RY1-07 1337.8 11.02 0.10 0.22 3 586 3.39 3.34RY1-16 1326.1 8.16 0.05 0.13 2 585 3.37 3.40RY1-22 1315.6 6.12 0.03 0.08 2 573 3.15 3.19RY1-38 1281.4 1.09 0.01 0.02 3 566 3.03 3.10RY2-03 926.7 8.47 0.07 0.13 2 569 3.08 2.96RY2-12 919.1 9.37 0.05 0.11 2 561 2.94 3.01RY2-23 906.6 5.31 0.03 0.07 2 568 3.06 3.09RY2-31 896.6 4.55 0.01 0.03 1 521 2.22 2.31RY2-45 855.6 2.59 0.01 0.02 1 508 1.98 2.00

Table 4. Mineralogical Analysis Results for Core Samples

samples depth (m) quartz (%) feldspar (%) calcite (%) dolomite (%) pyrite (%) clay (%)

RY1-47 1267.0 50.50 3.90 3.50 0.00 2.10 40.00RY1-35 1289.0 51.00 8.90 3.10 0.00 1.90 35.10RY1-29 1300.6 29.50 11.80 7.30 0.00 2.80 48.60RY1-28 1304.0 51.30 6.80 4.40 0.00 3.80 33.70RY1-22 1315.0 53.60 6.60 3.90 2.10 3.40 30.40RY1-21 1317.0 33.20 10.10 5.90 9.90 2.30 38.60RY1-17 1325.4 8.90 3.50 73.70 5.90 2.90 5.10RY1-13 1330.9 41.00 9.70 0.00 11.40 6.10 31.80RY1-09 1335.0 62.20 7.10 4.80 6.30 4.70 14.90RY1-08 1336.5 42.20 8.40 8.40 14.30 4.80 21.90RY1-07 1337.8 73.20 0.00 0.00 0.00 2.90 23.90RY1-06 1340.5 62.70 2.10 0.00 0.00 5.60 29.60RY1-04 1342.1 70.60 0.00 0.00 0.00 4.80 24.60RY1-02 1345.6 60.10 2.40 1.40 2.40 4.00 29.70RY2-48 850.7 25.40 10.60 3.60 0.00 18.10 42.30RY2-43 861.9 33.54 8.92 6.13 0.00 0.67 50.75RY2-39 873.6 33.80 13.40 6.90 0.00 4.40 41.50RY2-36 884.1 39.31 10.34 8.32 0.00 4.03 37.63RY2-33 891.4 33.10 14.50 11.20 0.00 6.10 35.10RY2-31 896.6 37.51 31.10 0.00 0.00 7.04 24.35RY2-28 900.8 33.40 6.20 28.70 16.90 4.50 10.30RY2-26 903.4 44.70 17.20 4.50 4.60 6.60 22.40RY2-25 904.4 42.70 19.40 0.00 8.70 6.20 23.00RY2-14 910.9 53.81 13.66 0.88 6.16 4.29 19.63RY2-08 916.1 70.85 5.05 3.02 3.35 3.18 11.63RY2-12 919.1 81.47 2.57 2.26 1.28 2.58 9.01RY2-10 920.5 54.02 9.58 0.00 6.74 6.64 22.15RY2-07 922.5 54.00 16.10 0.57 6.21 6.87 15.79RY2-05 923.9 54.57 18.14 0.54 7.40 5.57 13.30RY2-03 926.7 73.64 3.07 1.31 2.05 2.23 16.38RY2-01 928.6 94.60 0.00 0.00 5.40 0.00 0.00

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However, present investigated samples yield quite low S2 (<65mg HC/g rock) and consequently low HI (<100 mg HC/gTOC), which suggests that Tmax values are not reliable toindicate thermal maturity levels.16

3.2. Bulk Mineralogy and Lithofacies. Mineralogical datafor the Lower Cambrian shale in the NWG are shown in Table4. As the results indicated, the primary minerals are quartz andclay. Quartz concentrations vary from 8.9% to 73.2% (averageof 49.29%) for the RY1 core and from 25.4% to 96.4% (averageof 50.61%) for the RY2 core. Two higher values, 94.6% and81.47%, from samples of the RY2 core are probably cherts inthe bottom section. Clay concentrations vary from 5.1% to48.6% (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 themiddle strata. Most samples contain less than 12% calcite anddolomite (except the limestone sample RY1-17 and thecalcareous or dolomitic mudstone).A plain comparison of the mineralogical characteristics

between the Lower Cambrian shale and hot shales in theU.S. are provided in the ternary plots (Figure 3). The Bossiershales are characterized by relatively higher concentrations ofcalcite and dolomite, compared with the Ohio shales. The well-known Barnett shales are characterized by clearly highercontents of quartz, feldspar, and pyrite, compared with theOhio and Bossier shales. As the diagram indicates, the NWG

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) calcareousmudstone 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).

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shales are highly similar to the Barnett shales in mineralogicalcomposition, the lithofacies of which are mainly siliceousmudstone containing little calcite and dolomite.On the basis of thin sections (Figure 4) and XRD analysis,

the lithofacies characterization of the Lower Cambrian shale inthe NWG can be mainly summarized as laminated andnonlaminated siliceous mudstone, calcareous mudstone, andphosphatic rock. Laminated siliceous mudstone is the mostcommon lithoface in the Lower Cambrian shales, which is welllaminated due to the orientation of quartz and organic matterbonds.18−20 Nonlaminated siliceous mudstone is less common,exhibiting a homogeneous matrix of quartz, clay, and organicmatter. Calcareous mudstone is found in less than 3 samplesand features higher concentrations of dolomite or calcite thanclay minerals. Phosphatic rock is quite low and only found inthe lower strata, mainly composed of phosphatic concretionsand nodules. More lithofacies of the NWG shale were identifiedaccording to cores observations and outcrop descriptions(Table 5). Compared with the Barnett shales, silty inter-laminated mudstone occupies a larger proportion in thelithofacies stacking of the NWG shale.18−22 As we all know,organic-rich siliceous mudstone is a priority for shale-gasproduction due to the difficulty in creating effective fracturenetworks when high concentrations of clay minerals arepresent.20−22 Lithofacies like calcareous mudstone, dolomiticmudstone, and silty interlaminated mudstone have a highpotential for fracture stimulation, providing pathways connect-ing organic-rich lithofacies and the borehole.22 Thus, the LowerCambrian shale in the NWG yields a shale-gas potential judgingby the lithofacies assemblage, which is similar to that of theBarnett shales in the North Fort Worth Basin.3.3. 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 of1.85%, showing a poor correlation with the relevantpermeabilities. Porosities in this study exhibit higher averagevalues than those of samples (average <1%) in other areas ofthe Upper Yangtz Block but similar to the lower Cambrianshales (average of 2.2%) in Australia.20 As Tan et al.20 (2014)suggested, Hg porosity may be generally lower than Heporosity due to mineral constituents and small pores (<3.7 nm)which cannot be accessed by the former. Permeability valuesrange from 0.0031 to 0.0069 md, which are restricted to matrixpermeability, excluding the effect of fractures in the shale. BETtheory was used to evaluate the pore diameter and surface area.As shown in Table 7, the mean value of the pore surface area isabout 7.192 m2/g (range from 2.193 to 20.013 m2/g), while thepore volume varies from 0.0031 to 0.0156 mL/g with an

average of 0.0072 mL/g. Most of the BET surface area isassociated with pores less than 50 nm in diameter, confirmingthat micropores and mesopores are the main pore types (Figure5). However, pores of diameter less than 2 nm were notanalyzed due to the limitations of the experimental instrument.Compared with other shales in the U.S. (Table 8), the LowerCambrian shale in the NWG yields a higher median porediameter, suggesting more pore volume contributed bymesopores (range from 2 to 10 nm).23−25

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 48.6 4.20 siliceous noncalcareous mudstone 49.1 8.18siliceous calcareous mudstone 24.5 3.22 siliceous calcareous mudstone 19.4 6.32dolomitic mudstone 7.1 1.79 dolomitic mudstone 9.7 5.80silty shaly interlaminated mudstone 3.7 2.20 silty shaly interlaminated mudstone 6.3 1.71calcareous laminae 2.5 0.56 calcareous laminae 6.5 5.80concretion horizons 2.9 1.35 concretion horizons 0.7 3.90reworked shelly deposits 0.8 4.39phosphatic rocks 0.7 3.60 phosphatic rocks 1.1 8.50resedimented spiculitic mudstone 8.3 2.01 resedimented spiculitic mudstone 7.3 4.12lag deposits 0.9 3.57

Table 6. Rock Density, Porosity, and Permeability of theLower Cambrian Shale in the NWG

samples depth (m) density (g/cm3) porosity (%) permeability (md)

RY1-45 1269.3 2.71 1.02 0.0059RY1-37 1284.7 2.74 1.13 0.0049RY1-29 1300.2 2.65 2.49 0.0039RY1-24 1310.2 2.67 1.98 0.0038RY1-22 1315.5 2.72 2.81 0.0053RY1-13 1330.6 2.67 2.91 0.0046RY1-09 1335.0 2.74 3.11 0.0052RY1-04 1342.1 2.66 3.69 0.0043RY2-26 903.2 2.63 2.54 0.0069RY2-23 906.6 2.69 1.33 0.0048RY2-18 910.9 2.72 1.77 0.0047RY2-14 916.1 2.68 3.13 0.0045RY2-12 919.1 2.71 2.34 0.0045RY2-10 920.5 2.66 1.62 0.0046RY2-09 921.9 2.72 2.01 0.0047RY2-07 922.5 2.71 2.07 0.0041RY2-05 923.9 2.65 1.02 0.0044RY2-03 926.7 2.63 2.13 0.0031

Table 7. BET Surface Area and BJH Pore Volume of theLower Cambrian Shale in the NWG

samplesdepth(m)

BET surface area(m2/g)

BJH volume(mL/g)

pore diameter(nm)

RY1-49 1265.2 3.338 0.0033 10.02RY1-35 1289.4 5.994 0.0054 17.98RY1-28 1304.2 12.378 0.0061 37.13RY1-22 1315.7 20.013 0.0156 60.04RY1-09 1335.1 11.221 0.0076 33.66RY2-26 903.2 2.193 0.0031 6.58RY2-12 919.1 3.893 0.0054 11.68RY2-10 920.5 9.587 0.0142 28.76RY2-07 922.5 4.605 0.0076 13.82RY2-05 923.9 2.924 0.0043 8.77RY2-03 926.7 2.968 0.0071 8.90

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Five types of pores are identified in the Lower Cambrianshale in the NWG according to their origin.20−22 Organicmatter (OM) pores (Figure 6a,b) subsequently form whenhydrocarbon gets away from OM in the thermal maturityprocess, which is often observed in high maturity shales. OMpores in the NWG shale are abundant in the lower part of theNiutitang Formation where TOC contents are relatively high(average 6%). Intraparticle (IntraP) pores (Figure 6b,d) areoften found between grains and crystals in the shale, but theirsizes and geometries differ significantly, making it difficult topredict. Interparticle (InterP) pores (Figure 6c,e,f) are usuallyidentified in clay minerals, carbonate crystals, and pyriteframboids. InterP pores in clay minerals form due toflocculation of clay minerals during the diagenesis after burial,while interP pores in calcite or dolomite crystals appear aspartial dissolution occurs.26,28 The size of these pores evaluatedvia SEM may suggest mesopores and macropores as the mainpore types, in contrast with the pore size distribution discussedbefore. However, porosity contributions from such macroporesof all measured samples are very low, and their influences ontotal porosity of any measured sample are within the errormargin. Here we prefer the former pore size analysis via N2 gassorption.23,24 In addition, the SEM evaluation of pore typesillustrates that pores in the NWG shale are mostly OM poresand interP pores, which implies that there might be arelationship between porosity and TOC (clay and quartz).Plots of porosity and TOC/mineralogical composition are

presented to illustrate the potential relationship (Figure7).29−31 As Figure 7 indicates, porosity shows a strongcorrelation (R2 = 0.744) with TOC contents, indicating thatOM pores contribute significantly to the total porosity of theshale. It is in agreement with previous studies that high maturityorganic matter is generally microporous due to the discharge ofhydrocarbons.1,17,20 However, porosity does not seem to be

closely related to quartz and clay ratios as reported by otherresearches, which would be attributed to diagenesis afterburial.29,31

3.4. Gas Adsorption Capacity. Gas exists in shales inthree different forms: (1) free gas controlled by rock porosity;(2) absorbed gas associated with organic and inorganiccomponents; and (3) dissolved gas in hydrocarbons orfluids.12,13 The methane adsorption experiments were con-ducted on five dry samples with different TOC and claycontents from the RY1 core, in order to determine the gasadsorption 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 0.527 to 5.254 m3/ton with a meanvalue of 2.28 m3/ton. Compared with methane sorptioncapacity of the Lower Cambrian shale from Sichuan Basin (2.8m3/ton on average), the Lower Cambrian shale in the NWGyields relatively lower values without consideration of differentexperimental conditions.37,41

A compilation of methane sorption capacity of marine shalesfrom China, Europe, Canada, and the U.S. correlated with theircorresponding TOC contents are provided below (Figure 9).As illustrated in Figure 9, the organic matter richness has asignificant effect on the methane sorption capacity of marineshales. This strong positive correlation between the methanesorption isotherms and their TOC contents has been proved bymeasured marine shales around the world.37−40 In this study,the methane sorption isotherms yield a clear and strongpositive correlation with TOC contents, which is consistentwith the Lower Cambrian shale in Sichuan Basin according toprevious studies.37 The effect of the organic matter on the gassorption capacity is not only caused by TOC contents but alsoby its type and thermal maturity.37,38 Gasparik et al.39 and Tanet al.37 reported that the sorption isotherms of overmaturesamples were generally higher than those of low thermal

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 fromChalmers, 2012)

shale sampledepth(m)

total porosity(%)

micropore volume(mL/100 g)

mesopore/macropore volume(mL/100 g)

median pore diameter(nm)

TOC(%)

Ro(%)

Haynesville 4000 6.2 0.1 2.6 4.9 4.2 2.37Woodford 3721 4.7 0.6 1.9 5.5 2.0 1.51Marcellus 2583 3.7 0.8 1.4 3.9 3.8 1.56Barnett 1957 3.0 0.4 1.3 4.0 3.2 2.25NWG 1315 2.8 0.5 1.6 6.5 6.1 3.19

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maturity. Previous research attributed this phenomenon tostructural transformation of organic matter, creation of newsorption sites, and/or heterogeneity decrease of pore surfaceupon thermal maturation.27−40 Also the positive correlationbetween methane sorption capacity and thermal maturity wasrelated to micropores in the organic matter. Considering thecorrelation of porosity and TOC content, it is suggested thatmicroporous organic matter in the NWG shale may contributegreatly to the gas adsorption capacity. Despite the limited poresize, high maturity organic matter has provided large internalsurface area for the adsorbed gas, though Tan et al.37 has

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, 10−700 nm); and (d) IntraP pores inpyrite famboids (RY2-09, average < 100 nm).

Figure 7. (a) Plot of porosity vs TOC; (b) plot of porosity vs quartz/clay ratio.

Table 9. Methane Sorption Capacities of the LowerCambrian Shale in the NWG

samplesdepth(m)

VL(cm3/g)

PL(Mpa)

asorptioncapacity at

6 MPa (m3/ton)TOC(%)

clay(%)

RY1-41 1275.8 0.68 1.86 0.527 0.82 40.0RY1-30 1299.0 0.64 1.04 0.548 3.40 35.1RY1-24 1310.2 2.73 2.48 1.948 4.76 33.7RY1-13 1330.4 4.18 2.09 3.124 8.43 31.8RY1-02 1345.3 7.17 2.27 5.254 9.11 29.7

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suggested that the TOC content shows more effects on themethane sorption capacity than other factors like claycompostion, moisture content, pores, and particle size. Someresearch has reported that clay minerals, especially Illite,contribute greatly to the gas adsorption capacity.32,34,38

However, a strong negative association is identified betweenthe gas sorption capacity and the clay mineral contents in thisstudy, which is consistent with the investigation on thePaleozoic marine shales from Sichuan Basin, SouthChina.37,41 Within samples containing moisture, the sorptioncapacity might be irrelevant because the moisture would blockand occupy a large proportion of pores where the adsorbed gascould have accumulated.34−36 In fact, the pore size andstructure have been shown to have the most direct effect onthe methane sorption capacity of shales. Compared with otherfactors, micropores related to organic matter and clay mineralscan offer more surface area and have greater sorption energy

than large pores.37 More total porosity and surface areaformation have been attributed to micropores in organic matterbased on investigations performed on the Paleozoic shales inthe Sichuan Basin and NWG.1,37,41 Within measured samples ofhigh thermal maturity, organic matter would create moremicorpores, correspondingly enhancing the sorption capacity ofshale.

4. CONCLUSION

A variety of experiments have been conducted on the LowerCambrian 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 whichdisplays high TOC contents (average 6%). The kerogen typedetermined by δ13 C is sapropelic (Type I), suggesting a highpotential for gas generation. Ro values range from 3.07% to3.68% for the RY1 core and from 2% to 3.11% for the RY2core. (2) The mineralogical composition of the NWG shalecompared with hot shales in the U.S. indicates it is highlysimilar to the Barnett shales and primary minerals of quartz andclay (average 48% and 27%, respectively). The lithofaciesconsist of mainly siliceous mudstone and calcareous mudstone,which makes it suitable for fracture stimulation. (3) Theporosities of samples from both cores vary from 1.02% to3.69%, correlating well with the TOC contents. Many OMpores identified via SEM evaluation may provide anexplanation. The pore size distribution of the NWG shalereveals that micropores and mesopores are the main pore types,indicating limited pore volume compared with other high gasproduction shales. (4) The gas adsorption capacity wasdetermined by the methane sorption experiments and wasfound to have a range from 0.527 to 5.254 m3/ton at 6.21 MPaunder experimental conditions. Meanwhile, the adsorptivecapacity shows a strong positive correlation with TOCcontents, confirming the significant contribution of micro-porous organic matter to gas adsorption. Thus, the LowerCambrian shale in the NWG is thought to have great shale-gas

Figure 8. Methane adsorption isotherms (at 49 °C) for core samples.

Figure 9. Comparison of methane sorption capacity of marine shales from China and other countries shows a positive correlation with their TOCcontents. (Alum shale from Scandinavia, Posidonia in Germany, Barnett shale from the U.S., and Devonian-Mississippian and Jurassic shales fromCanada). UYB: the Upper Yangtz Block.

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potential due to high TOC contents, favorable mineralogicalcomposition, and considerable potential gas accumulation.

■ AUTHOR INFORMATIONCorresponding Author*(Tailiang Fan) Telephone: 010-82321559. E-mail: phdoffan@foxmail.com.NotesThe authors declare no competing financial interest.

■ ACKNOWLEDGMENTSThis work is financially supported by the National Oil and GasStrategic Investigation Program (Grant 2009GYXQ-15), theNational Natural Science Foundation Research (Grant40672087), and the Shale Gas Resources Investigation andEvaluation Program, Guizhou Province (Grant 2012GYYQ-01). We also appreciate the experimental supports from thoseinstitutes, like CUPB, PC-HOB, AL-BRIUG, and RIPED-LB.Editor Weber and two reviewers are gratefully thanked for theirhelp to improve this article.

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