Methane Adsorption Capacities of the Lower Paleozoic Marine Shales in the Yangtze Platform, South China

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1 pubs.acs.org/ef Methane Adsorption Capacities of the Lower Paleozoic Marine Shales in the Yangtze Platform, South China Yue Wu,*, Tailiang Fan, Shu Jiang, Xiaoqun Yang, Huaiyu Ding, Miaomiao Meng, and Duan Wei School of Energy Resources, China University of Geosciences, Beijing , People s Republic of China Energy and Geoscience Institute, University of Utah, Salt Lake City, Utah 84108, United States Liaohe Oilfield Company, PetroChina, Panjin, Liaoning , People s Republic of China ABSTRACT: The adsorption capacities of the Lower Silurian Longamxi and Lower Cambrian Niutitang marine shales in the Yangtze Platform in China were investigated through methane adsorption experiments. The correlations between the adsorption capacities and major factors, e.g., total organic carbon (TOC) contents, thermal maturity, mineral composition, moisture content, pressure, and temperature, were discussed. The isosteric adsorption heat was calculated according to the temperature dependency of the methane adsorption isotherms. The results show that, under the temperature of 30 C and pressure range of 0 12 MPa, the maximum adsorption capacity of the Longmaxi shales ranges between 0.47 and 3.08 m 3 /ton of rock and that of the Niutitang shales ranges between 1.59 and 7.43 m 3 /ton of rock. The Langmuir adsorption capacity varies from 0.54 to 3.84 m 3 /ton of rock for the Longmaxi shales and from 1.98 to 9.73 m 3 /ton of rock for the Niutitang shales. The TOC content shows a significantly positive correlation with the adsorption capacity, indicating that organic matter is responsible for adsorbing gas in the shales. For these high mature shales, the thermal maturity shows no effect on the adsorption capacity. The clay minerals show little contributions to the adsorption capacity in the shales because of the effect of the water content. For the studied shales, the moisture exhibits no distinct correlation with the adsorption capacity. The influence of the pressure on the adsorption capacity varies from sample to sample, while the temperature shows a generally negative effect on the adsorption capacity. The isosteric heat of adsorption ranges from 8.48 to kj/mol, with an average of kj/mol, indicating a dominant physical adsorption behavior of the methane molecule in the shales. 1. INTRODUCTION It is widely known that natural gas can be stored in shale reservoirs as free gas, adsorbed gas, and dissolved gas. 1 6 It was reported that the adsorbed gas can account for 20 85% in total gas amount in some shale gas plays. 3 The methane adsorption capacity of shales is a complex function of geochemistry, mineral composition, pore structure, and reservoir conditions. 1,2,5 8 Organic matter is generally thought to be the principle contributor to the adsorption capacity of shales. 5 9 Type III organic matter has higher gas adsorption capacity than that of type I and type II organic matter because of the higher content of aromatic compounds in type III organic matter. 9 As maturity increases, more micropores (diameter, D < 2 nm) may be developed in the organic matter during the process of kerogen conversion and hydrocarbon generation and expulsion. Thus, the overmature and high total organic carbon (TOC) shale samples generally show larger adsorption capacity than the low mature and low TOC samples. Clay minerals with a porous structure also have a strong impact on gas adsorption capacities in shales. 5 8 The adsorption capacities of montmorillonite and illite/semectite are obviously higher than that of kaolinite, chlorite, and illite in the dry state. 10 However, the adsorption capacities of clay minerals for the methane molecule would be reduced greatly in the presence of moisture. The influences of the water content on the adsorption capacity in shales were investigated by comparing the adsorption capacities between moisture-equilibrated samples and dry samples. A 40% decrease of the adsorption capacity was found in the moistureequilibrated samples. 7,8 Reservoir conditions, e.g., temperature and pressure, have also been recognized as important factors to influence adsorption capacities of shales. The Lower Silurian Longmaxi and Lower Cambrian Niutitang shales with large thickness, high TOC content, and high brittle mineral content are regarded as the most potential shale gas plays in the Yangtze Platform, south China An improved understanding of the adsorption characteristics of these two shale intervals is important and meaningful. The aims of this study are to access the adsorption capacities of the Lower Silurian Longmaxi and Lower Cambrian Niutitang shales in the Yangtze Platform and discuss the key factors influencing the adsorption capacities. Here, some representative shale samples in the Longmaxi and Niutitang Formations from wells or outcrops in the Yangtze Platform were collected for this study. Shale properties, e.g., TOC, vitrinite reflectance (R o ), mineral composition, porosity, and methane adsorption capacities, were measured on the basis of a series of experimental procedures. 2. MATERIALS AND METHODS 2.1. Samples. A total of 14 shale samples with different TOC contents and mineral compositions were collected. Specifically, three Longmaxi shale samples coded CUGB1 CUGB3 are from Doucan1 well in Anhui Province in the Lower Yangtze Platform (note that the Longmaxi Formation is called Gaojiabian Formation in the Lower Received: February 5, 2015 Revised: June 3, 2015 XXXX American Chemical Society A

2 Yangtze Platform); another five Longmaxi shale samples coded CUGB4 CUGB8 are from Xiye1 well in Guizhou Province in the Upper Yangtze Platform; and six Niutitang shale samples coded CUGB9 CUGB14 are from Fenghuang and Yongshun outcrops in Hunan Province in the Upper Yangtze Platform (Figure 1 and Table 1). Figure 1. Locations of the sampled wells and outcrops in the Yangtze Platform, south China (modified with permission from ref 18): (1) Doucan1 well in Anhui Province, (2) Xiye1 well in Guizhou Province, (3) Fenghuang outcrop in Hunan Province, and (4) Yongshun outcrop in Hunan Province. Table 1. Provenance of the Studied Shale Samples and Their Lithostratigraphic Origin a sample ID well/outcrop formation depth (m) CUGB1 Doucan1 LMX 123 CUGB2 Doucan1 LMX 105 CUGB3 Doucan1 LMX 95 CUGB4 Xiye1 LMX CUGB5 Xiye1 LMX CUGB6 Xiye1 LMX 627 CUGB7 Xiye1 LMX CUGB8 Xiye1 LMX CUGB9 Fenghuang NTT 3 CUGB10 Fenghuang NTT 56.9 CUGB11 Fenghuang NTT CUGB12 Yongshun NTT 12 CUGB13 Yongshun NTT 100 CUGB14 Yongshun NTT 106 a LMX = Longmaxi Formation, Lower Silurian. NTT = Niutitang Formation, Lower Cambrian. The locations of wells and outcrops are shown in Figure 1. The depth in outcrop is the distance to the ground Methods TOC and R o. The TOC contents of 14 samples were measured through a LECO CS230 carbon/sulfur analyzer. Samples were first crushed to powder with a particle less than 100 mesh, and then 1 2 g samples were pyrolyzed up to 540 C. The thermal maturity of samples was determined on the basis of the reflectance measurements on pyrobitumen particles. The pyrobitumen reflectance (R b ) was measured through a MVP-3 microscope in nonpolarized light at a wavelength of 546 nm in oil immersion. On each sample, 20 measurements were taken whenever possible. Because of the lack of vitrinite in these early Paleozoic marine shales, R o was calculated from the measured R b on the basis of the following arithmetic formula: 19 Ro = Rb (1) X-ray Diffraction (XRD). Bulk mineralogical composition of shales was derived from the XRD patterns. Eight Longmaxi samples (CUGB1 CUGB8) were first ground into powder, and then XRD analysis was performed on the randomly oriented powder through a Rigaku D/max-2600 diffractometer with Cu Kα radiation, automatic divergent and anti-scatter silts, and a secondary graphite monochromator with a scintillation counter. The generator settings were 40 kv and 40 ma. The diffraction data were recorded from 2 to 76 2θ with a step width of 0.02 and a counting time of 4 s per step. The mineral content was semi-quantitatively determined on the basis of the intensity of specific reflections, the density, and the mass adsorption coefficient (Cu Kα) of the identified mineral phases Porosity. The porosity for eight Longmaxi samples (CUGB1 CUGB8) was measured by mercury injection porosimetry. Samples were dried in an oven for 24 h at 50 C. The measurements were performed using a AutoPore IV 9520 series mercury porosimeter. The mercury pressure was increased continuously from to 200 MPa Methane Adsorption Experiments. Methane adsorption measurements were performed on shale powders with a high-pressure gas adsorption and desorption instrument of PCT Pro E&E Siverts model. Two sets of methane adsorption experiments were designed for different objectives in this study. The first set is that the methane adsorption experiments were conducted on three dry powered samples (CUGB1 CUGB3) under high pressures of up to 30 MPa and different temperatures of 50 and 70 C. The second set is that the adsorption experiments were measured on 11 moisture-equilibrated samples (CUGB4 CUGB14) at a consistent temperature of 30 C and up to a pressure of 12 MPa. Moisture equilibration of samples followed the ASTM procedure (ASTM D ). Ground samples were placed in a sub-atmospheric desiccator over a saturated salt solution of KCl with controlled relative humidity of 80% at 30 C for more than 72 h. Equilibrium moisture occurs at the point when the sample weight remains constant. Moisture content was measured by oven-drying, weight-loss calculations. In the adsorption experiment, the amount of adsorbed gas is calculated on the basis of the following mass balance: 20 madsorbed = mtotal ρ V gas void (2) where m adsorbed is the adsorbed gas content, m total is the total amount of gas introduced into the system, the void volume (V void ) is determined by helium expansion at the measured temperature prior to the adsorption measurement, and the gas density (ρ gas ) in the corresponding pressure and temperature conditions is calculated from the equation of state by Setzman and Wagner. 21 The measured results are presented in volume unit normalized to the rock mass (CH 4 m 3 /ton of rock) or the TOC mass (CH 4 m 3 /ton of TOC) under standard temperature ( K) and standard pressure (10 5 Pa) Parameterization of Adsorption Data. The measured adsorption data can be parametrized using the Langmuir model, which is commonly applied to describe the relations between the adsorbed gas on a solid surface and measured pressure at a fixed temperature 22 P KP V = VL or V = VL PL + P 1 + KP (3) where V is the volume of adsorbed gas, V L is the Langmuir volume (on the basis of the monolayer adsorption), which is the maximum adsorption capacity of the absorbent, P is the gas pressure, P L is the Langmuir pressure, at which the adsorbed gas content (V) is equal to half of the Langmuir volume (V L ), and K is the Langmuir constant, which is the reciprocal of the Langmuir pressure (P L ). 3. RESULTS 3.1. Source Rock Characterization. The results of TOC content and thermal maturity (on the basis of calculated R o ) for 14 samples are listed in Table 2. On the basis of the measured B

3 Table 2. Results of TOC, Calculated R o, Porosity, and XRD Analysis major minerals (wt %) sample ID TOC (%) R o (%) porosity (%) quartz clay carbonate CUGB CUGB CUGB CUGB CUGB CUGB CUGB CUGB CUGB NA a NA NA NA CUGB NA NA NA NA CUGB NA NA NA NA CUGB NA NA NA NA CUGB NA NA NA NA CUGB NA NA NA NA a NA = not available. Table 3. Maxima in the Adsorption Isotherms (30 C) and Langmuir-Fitting Parameters for Samples of CUGB4 CUGB14 a V max sample ID TOC (%) moisture (%) (m 3 /ton of rock) (m 3 /ton of TOC) P max (MPa) (m 3 /ton of rock) (m 3 /ton of TOC) P L (MPa) CUGB CUGB CUGB CUGB CUGB CUGB CUGB CUGB CUGB CUGB CUGB a V max means the maximum adsorption capacity within the measured pressure range, and P max is the corresponding pressure. V L is the Langmuir volume, and P L is the Langmuir pressure. V L values, the TOC content of the Longmaxi shales ranges between 0.52 and 6.05% and that of the Niutitang shales ranges between 1.45 and 8.93%. Most of the samples are organic-rich (TOC > 2%), except for CUGB6, CUGB7, and CUGB8 with TOC contents of lower than 1%. The Niutitang samples generally contain more organic matter than the Longmaxi samples. Both of the Longmaxi shales and Niutitang shales are overmature, with the calculated R o values higher than 2% on average. Additionally, many previous publications reported a sapropelic (type I) and humic sapropelic (type II 1 ) kerogen for the Lower Paleozoic marine shales in the Upper Yangtze Platform Mineralogical Composition and Porosity. The XRD and porosity results for eight Longmaxi samples (CUGB1 CUGB8) are listed in Table 2. On the basis of the XRD data, quartz and clays are the major mineralogical composition for the Longmaxi shales and little carbonate is present. The quartz contents of the samples from Doucan1 well are more than 50% on average, and clay mineral contents are more than 40% on average. Both of the quartz and clay mineral contents of the samples from Xiye1 well are above 30% on average. The samples from Xiye1 well contain more carbonate minerals than the samples from Doucan1 well, which may be caused by their different depositional settings. Most of the samples present a low porosity ranging between 1 and 2%. Two organic-rich samples of CUGB1 and CUGB4 exhibit a large porosity of more than 4% Methane Adsorption Isotherms. The experimentally measured and Langmuir-fitting methane adsorption capacities for samples of CUGB4 CUGB14 are presented in Table 3 and Figure 2. Within the measured pressure range, the maximum methane adsorption capacity ranges between 0.47 and 3.08 m 3 / ton of rock for the Longmaxi shales and between 1.59 and 7.43 m 3 /ton of rock for the Niutitang shales. The Langmuir volumes range from 0.54 to 3.84 m 3 /ton of rock for the Longmaxi shales and from 1.98 to 9.73 m 3 /ton of rock for the Niutitang shales. The Langmuir pressures are between 1.27 and 2.55 MPa for the Longmaxi shales and between 2.15 and 3.23 MPa for the Niutitang shales. The Niutitang shales show a generally larger Langmuir volume and Langmuir pressure than the Longmaxi shales. A comparison of the adsorption capacity between the Lower Paleozoic shales in the Yangtze Platform in China and some hot shales in North America was made (Table 4). Because the experimental conditions and measurement methods for the adsorption capacities are different for all of those samples, the comparison in this paper is simple and preliminary. In comparison to those gas-producing shales in North America, the Lower Paleozoic marine shales in the Yangtze Platform C

4 Figure 2. Methane adsorption isotherms measured at 30 C for samples of CUGB4 CUGB14. Plot A is for the Longmaxi shales, and plot B is for the Niutitang shales. Points are experimentally measured data, and lines are Langmuir-fitting results. show a larger adsorption capacity, indicating a great shale gas potential. 4. DISCUSSION 4.1. Effect of Organic Matter Abundance. It is widely acknowledged that organic matter plays an important role in the adsorption capacity of shales. The relationship between TOC contents and adsorption capacities in shales has been studied by many scholars. 1,2,5 9,26 For example, Ross and Bustin reported that there were positive correlations between the TOC contents and adsorption capacities in shale samples from the Western Canadian Sedimentary Basin. 7,8 The adsorption capacities increased linearly with TOC contents in the Devonian shale samples from basins in northeastern America. 23 Tan et al. and Wang et al. reported a linear correlation between the adsorption capacity and TOC content in the Lower Paleozoic shales in the Upper Yangtze Platform in China. 17,18 The correlations between the TOC contents and adsorption capacities for the studied samples are illustrated in Figure 3. The Langmuir volumes correlate positively with the TOC contents for both the Longmaxi and Niutitang shales, indicating that organic matter made a significant contribution to the adsorption capacity in these samples. Organic matter is usually porous in high-mature shales, with enough surface area onto which natural gas can adsorb. 7,8 Organic matter provides most of the porosity in the Longmaxi samples indicated by the linear correlation between the TOC content and porosity (Figure 4A). Intrapores were largely developed within the organic matter revealed by scanning electron microscopy (SEM) (Figure 4B) Effect of Thermal Maturity. Thermal maturity has been reported to affect the adsorption capacity because of texture changes in organic matter. 5 9 Many micropores are created during thermal decomposition of organic matter, which can enhance the gas adsorption capacity of shales. Ross and Bustin demonstrated that the adsorption capacity increased with thermal maturity in shale samples from the Western Canadian Sedimentary Basin. 7,8 Gasparik et al. reported that adsorption capacity of overmature shales was generally higher than that of low mature or immature shales. 1,2 Tan et al. found that the Langmuir adsorption capacity generally increased from immature to overmature samples. 18 The relationship between the thermal maturity and adsorption capacity for the studied samples is shown in Figure 5. There is no correlation between the TOC-normalized Langmuir volume and thermal maturity. The Niutitang shales with R o values of % show a generally larger adsorption capacity than the Longamxi shales with R o values of %. For these samples within the overmature range, there is limited potential for porous structure creation during the thermal maturation of organic matter Effect of Mineral Composition. In the present study, the correlations between the adsorption capacity and mineral composition were discussed on the Longmaxi samples, and the Niutitang samples may exhibit a similar relationship. The mineral composition of the Longmaxi shales in the Yangtze Platform is dominated by quartz and clay minerals. Quartz may be irrelevant to the adsorption capacity because of its nonadsorptive nature. Clay minerals with high internal surface area and adsorption energy are regarded as a significant factor to affect the adsorption capacity of shales. 5 8 The clay mineral Table 4. Experimental Conditions and Adsorption Capacities for the Compared Shale Samples a experimental condition sample temperature ( C) pressure (MPa) moisture (%) adsorption capacity (m 3 /ton) reference Lower Silurian (UYP) this paper Lower Cambrian (UYP) Lower Silurian (UYP) Tan et al. 18 Lower Cambrian (UYP) Lower Silurian (UYP) Wang et al. 17 Lower Cambrian (UYP) D M (western Canada) Ross and Bustin 8 Jurassic (western Canada) Lower Cretaceous (western Canada) Chalmers and Bustin 6 Barnett (U.S.) Gasparik et al. 2 a UYP = Upper Yangtze Platform. D M = Devonian Mississippian. Unit conversion factor: 1 mmol/g = m 3 /ton. D

5 Figure 4. (A) Linear correlation between the TOC content and porosity in the Longmaxi shales and (B) SEM image showing pores largely developed within the organic matter. Figure 3. Correlation plots between the Langmuir adsorption capacity and TOC content. Plot A contains all measured samples; plot B is for the Longmaxi shales; and plot C is for the Niutitang shales. content correlates negatively with the rock-normalized Langmuir volume in this study (Figure 6A), which may be ascribed to the strong effect of the TOC content; e.g., there are substantially low TOC contents in the clay-rich samples. This phenomenon indicates that organic matter has a more significant impact on the adsorption capacity than clay minerals in the studied samples. To more clearly present the contribution of clay minerals to the adsorption capacity, the adsorption data were normalized to the TOC content. The clay mineral content shows a weakly positive correlation with the TOC-normalized Langmuir volume (Figure 6B), indicating that the clay minerals have little impact on the adsorption capacity in the Longmaxi shales. This phenomenon may be caused by the effect of the water content. The surface of clay minerals has a high affinity of water, which would block the access of methane molecules to the adsorption sites. The contribution of clay minerals to the adsorption capacity in shales may be reduced greatly in the presence of water. Figure 5. Effect of thermal maturity on the adsorption capacity. The adsorption capacity is represented by the TOC-normalized Langmuir volume. The Niutitang shales show a generally larger adsorption capacity than the Longmaxi shales Effect of Moisture Content. The effect of the moisture content on the adsorption capacity was investigated in many shale samples from around the world. 1,2,5 8,27,28 For example, the adsorption capacity was negatively correlated with the moisture content in shale samples from the Western Canadian Sedimentary Basin. 7,8 The presence of water may swell the clay minerals, block the pore system, and occupy E

6 Figure 7. Correlation plots between the moisture content and the (A) rock-normalized Langmuir adsorption capacity and (B) TOCnormalized Langmuir adsorption capacity for the Longmaxi shales. No obvious relationship can be observed. Figure 6. Correlation plots of clay mineral content with the (A) rocknormalized Langmuir adsorption capacity and (B) TOC-normalized Langmuir adsorption capacity for the Longmaxi shales. potential adsorption sites. However, shale samples from northeastern British Columbia, Canada, showed a positive correlation between the adsorption capacity and moisture content, indicating that water and methane molecules may occupy different adsorption sites in shales. 5,6 The Lower Paleozoic shale samples from the Upper Yangtze Platform in China showed that the TOC-normalized adsorption capacity decreased following polynomial-law relations with the moisture content increasing. 18 In this study, the moisture content shows no correlation with the rock-normalized adsorption capacity (Figure 7A). This phenomenon may be caused by the stronger effects from other factors, e.g., TOC content. The samples with higher TOC contents have remarkably larger adsorption capacities (Figure 7A). However, the moisture contents also have no obvious correlation with the TOC-normalized adsorption capacity (Figure 7B). Higher moisture contents of the samples than their critical moisture contents may account for this phenomenon, which could be indicated from the weak effect of clay minerals on the adsorption capacity and the moisture-equilibration condition with a relative humidity of 80% for the samples. Gasparik et al. reported that the critical moisture content could be achieved at the relative humidity of less than 75% for the Upper Cambrian Lower Ordovician Alum shale Effect of Pressure and Temperature. To explore the effects of the pressure and temperature on the adsorption capacity, the methane adsorption experiments were performed on three Longmaxi samples (CUGB1 CUGB3) at the temperatures of 50 and 70 C and under a wide range of pressures of up to 30 MPa. The experimental results are shown in Table 5 and Figure 8. The effects of the pressure on the adsorption capacity are quite complex. Figure 8A shows that the adsorbed gas content increases consistently with the increase of the pressure. The adsorption isotherms in Figure 2 also show a monotonous increase of the adsorption capacity with a pressure increase, but the pressures applied in those measurements are relatively low (<12 MPa). Plots B and C of Figure 8 show that the adsorbed gas contents increase first and then decrease over the measured pressure range. The effects of the temperature on adsorption capacity have been summarized by Yee et al. 29 A negative correlation between the temperature and adsorption capacity was observed in the studied samples. The adsorption capacities measured at 50 C are generally larger than those measured at 70 C (Figure 8). The methane adsorption process is exothermic, and higher temperatures are favorable for more gas in the free state than in the adsorbed state. In addition, we can find that the impact of the temperature on the adsorption capacity was reduced by the TOC content. In comparison to the samples of CUGB2 and CUGB3, the sample of CUGB1 with a higher TOC content shows less difference between the adsorption capacities measured at 50 and 70 C (Figure 8) Isosteric Heat of Adsorption. Isosteric heat of adsorption is an important thermodynamic parameter and can be used to characterize the methane adsorption behavior in shales. The concept of isosteric heat of adsorption has been discussed by many authors before The isosteric adsorption heat can be determined on the basis of adsorption isotherms and the following equation: 34 = Δ Hs ln P L + C RT (4) where P L is the Langmuir pressure, ΔH s is the isosteric adsorption heat, R is the universal gas constant, equal to J F

7 Table 5. Methane Adsorption Capacities for Samples of CUGB1 CUGB3 at Different Temperatures 50 C 70 C P (MPa) CH 4 (m 3 /ton of rock) P (MPa) CH 4 (m 3 /ton of rock) Sample of CUGB Sample of CUGB Sample of CUGB mol 1 K 1 in this paper, T is the measured temperature, C is a constant, and the negative symbol shows that the adsorption process is exothermic. In the present study, the isosteric heats for samples of CUGB1 CUGB3 are summarized in Table 6. The isosteric adsorption heat varies from 8.48 to kj/mol, with an average of kj/mol. This indicates that the dominant methane adsorption behavior in the shales is physical adsorption because chemical adsorption usually shows an isosteric heat of kj/mol. 35,36 5. CONCLUSION In this paper, methane adsorption experiments were conducted on some representative shale samples from the Lower Silurian and Lower Cambrian Formations in the Yangtze Platform in China. Some conclusions from this study are summarized as follows: (1) Under the measured temperature of 30 C and the pressure range of 0 12 MPa, the maximum adsorption capacity of the Longmaxi shales ranges between 0.47 and 3.08 m 3 /ton of rock and that of the Niutitang shales ranges between 1.59 and 7.43 m 3 /ton of rock. The Langmuir adsorption capacity varies from 0.54 to 3.84 m 3 /ton of rock for the Longmaxi shales and from 1.98 to 9.73 m 3 /ton of rock for the Niutitang shales. The Longmuir pressures are between 1.27 and 2.55 MPa for the Longmaxi shales and between 2.15 and 3.23 MPa for the Niutitang shales. In comparison to those hot shales in North America, the studied shales in the Yangtze Platform in China show a larger adsorption capacity. (2) For the Longmaxi and Niutitang shales in the Yangtze Platform, TOC is the primary Figure 8. Methane adsorption isotherms at temperatures of 50 and 70 C for samples of CUGB1 CUGB3. control on the adsorption capacity. Thermal maturity, clay minerals, and moisture show slight or no effects on the adsorption capacity. Therefore, the TOC content can be used as a proxy to determine the intervals with potentially large adsorbed gas content in the Yangtze Platform. Specifically, (a) the TOC content shows a significantly positive correlation with the adsorption capacity, indicating that organic matter is responsible for adsorbing gas in the shales; (b) the thermal maturity has no obvious effect on the adsorption capacity for these high mature shales; (c) the contribution of clay minerals to the adsorption capacity may be irrelevant because of the effect of the water content; and (d) the moisture exhibits no correlation with the adsorption capacity in the shales. (3) The pressure can help to increase the adsorption capacity to some extent, while the temperature may decrease the adsorption capacity. The effects of the pressure and temperature on the adsorption capacity in the shales can be used as guidance for G

8 Table 6. Calculated Isosteric Heat of Adsorption for Samples of CUGB1 CUGB3 50 C 70 C sample ID V L (m 3 /ton) P L (MPa) V L (m 3 /ton) P L (MPa) isosteric heat (kj/mol) CUGB CUGB CUGB gas desorption in the shale gas production stage. (4) The adsorption behavior of methane molecules in the shales belongs to physical adsorption, with an average isosteric adsorption heat of kj/mol, ranging from 8.48 to kj/mol. The research results from this study can provide some useful information to characterize the gas adsorption capacity of the Lower Paleozoic marine shales in the Yangtze Platform in China. However, some questions still exist, and further research is necessary. For example, the experimental temperature and pressure for the adsorption measurements are much lower than those in reservoir conditions. The effects of the pressure and temperature on the adsorption capacity of shales should be taken into account together. Some experimental uncertainties exist in the measured adsorption data, such as the reproducibility of measurements and experimental methods. More samples and more systematic measurements are needed. AUTHOR INFORMATION Corresponding Author *Telephone: wuyue0906@gmail. com. Notes The authors declare no competing financial interest. ACKNOWLEDGMENTS This work is supported by the National Oil and Gas Strategic Investigation Program (Grant 2009GYXQ-15), the National Natural Science Foundation Research (Grant ), and the Shale Gas Resource Investigation and Evaluation Program, Guizhou Province (Grant 2012GYYQ-01). The authors also sincerely appreciate the support from the Energy & Geoscience Institute (EGI) of the University of Utah. REFERENCES (1) Gasparik, M.; Ghanizadeh, A.; Bertier, P.; Gensterblum, Y.; Bouw, S.; Krooss, B. M. Energy Fuels 2012, 26, (2) Gasparik, M.; Bertier, P.; Gensterblum, Y.; Ghanizadeh, A.; Krooss, B. M.; Littke, R. Int. J. Coal Geol. 2014, 123, (3) Curtis, J. B. AAPG Bull. 2002, 86, (4) Jarvie, D. M.; Hill, R. J.; Ruble, T. E.; Pollastro, R. M. AAPG Bull. 2007, 91, (5) Chalmers, G. R. L.; Bustin, R. M. Int. J. Coal Geol. 2007, 70, (6) Chalmers, G. R. L.; Bustin, R. M. Bull. Can. Pet. Geol. 2008, 56, (7) Ross, D. J. K.; Bustin, R. M. AAPG Bull. 2008, 92, (8) Ross, D. J. K.; Bustin, R. M. Mar. Pet. Geol. 2009, 26, (9) Zhang, T.; Ellis, G. S.; Ruppel, S. C.; Milliken, K.; Yang, R. Org. Geochem. 2012, 47, (10) Ji, L.; Zhang, T.; Milliken, K. L.; Qu, J.; Zhang, X. Appl. Geochem. 2012, 27, (11) Wu, Y.; Fan, T.; Zhang, J.; Jiang, S.; Li, Y.; Zhang, J.; Xie, C. Energy Fuels 2014, 28, (12) Li, Y. X.; Nie, H. K.; Long, P. Y. Nat. Gas Ind. 2009, 29, H (13) Zou, C.; Dong, D.; Wang, S.; Li, J.; Li, X.; Wang, Y.; Li, D.; Cheng, K. Pet. Explor. Dev. 2010, 37, (14) Tan, J.; Horsfield, B.; Mahlstedt, N.; Zhang, J.; di Primio, R.; Vu, T. A. T.; Boreham, C. J.; van Grass, G.; Tocher, B. A. Mar. Pet. Geol. 2013, 48, (15) Tan, J.; Horsfield, B.; Fink, R.; Krooss, B. M.; Schulz, H. M.; Rybacki, E.; Zhang, J.; Boreham, C. J.; Grass, G. V.; Tocher, B. A. Energy Fuels 2014, 28, (16) Tan, J.; Horsfield, B.; Mahlstedt, N.; Zhang, J.; Boreham, C. J.; Hippler, D.; Grass, G. V.; Tocher, B. A. Int. Geol. Rev. 2015, 57, (17) Wang, S.; Song, Z.; Cao, T.; Song, X. Mar. Pet. Geol. 2013, 44, (18) Tan, J.; Weniger, P.; Krooss, B. M.; Merkel, A.; Horsfield, B.; Zhang, J.; Boreham, C. J.; Grass, G. V.; Tocher, B. A. Fuel 2014, 129, (19) Feng, G.; Chen, S. Nat. Gas Ind. 1988, 8, (20) Gensterblum, Y.; Hemert, P.; Billemont, P.; Busch, A.; Charriere, D.; Li, D.; Krooss, B. M.; Werireld, G.; Prinz, D.; Wolf, K. H. Carbon 2009, 47, (21) Setzman, U.; Wagner, W.; Pruss, A. J. Phys. Chem. Ref. Data 1991, 20, (22) Langmuir, I. J. Am. Chem. Soc. 1918, 40, (23) Li, W. Pet. Geol. Exp. 1990, 12, (24) Wang, S.; Dai, H.; Wang, H.; Huang, Q. Nat. Gas Geosci. 2000, 11, (25) Chen, S.; Pi, D. China Pet. Explor. 2009, 3, (26) Lu, X.; Li, F.; Watson, A. Fuel 1995, 74, (27) Day, S.; Sakurovs, R.; Weir, S. Int. J. Coal Geol. 2008, 74, (28) Clarkson, C. R.; Bustin, R. M. Int. J. Coal Geol. 2000, 42, (29) Yee, D.; Seidle, J. P.; Hanson, W. B. AAPG Stud. Geol. 1993, 38, (30) Xia, X.; Tang, Y. Geochim. Cosmochim. Acta 2012, 77, (31) Xia, X.; Litvinov, S.; Muhler, M. Langmuir 2006, 22, (32) Al-Muhtaseb, S. A.; Ritter, J. A. J. Phys. Chem., B 1999, 103, (33) Do, D. D.; Do, H. D. Chem. Eng. Sci. 1997, 52, (34) Myers, A. L.; Monson, P. A. Langmuir 2002, 18, (35) Yang, F.; Ning, Z.; Zhang, R.; Zhao, H.; Zhao, T.; He, B. J. China Coal Soc. 2014, 39, (36) Yang, F.; Ning, Z.; Wang, Q.; Liu, H.; Kong, D. J. Cent. South Univ. 2014, 45,