Methane adsorption capacity of marine-continental transitional facies shales: The case study of the Upper Permian Longtan Formation, northern Guizhou Province, Southwest China

Journal of Petroleum Science and Engineering 183 (2019) 106406

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Methane adsorption capacity of marine-continental transitional facies shales: The case study of the Upper Permian Longtan Formation, northern Guizhou Province, Southwest China

T

Qing Hea, Tian Donga, , Sheng Hea, Gangyi Zhaib ⁎

a b

Key Laboratory of Tectonics and Petroleum Resources of Ministry of Education, China University of Geosciences, Wuhan, 430074, China Oil & Gas Survey Center, China Geological Survey, Beijing, 100029, China

ARTICLE INFO

ABSTRACT

Keywords: Methane adsorption capacity Marine-continental transitional facies shale Moisture content Longtan Formation

Factors influencing the methane adsorption capacity (MAC) of marine-continental transitional facies shales have been identified applying a variety of techniques (e.g., total organic carbon (TOC) content, X-ray diffraction mineralogy, low-pressure CO2 and N2 adsorption, and methane adsorption analyses) on samples from the Upper Permian Longtan Formation, northern Guizhou Province, Southwest China. The TOC contents of the Longtan shale samples ranged between 1.2 and 9.9 wt% (average = 3.5 wt%). The results of the bulk XRD analysis suggested that the mineralogical composition of the studied samples was different from that of typical marine shales: the samples primarily consisted of clay minerals, followed by quartz and feldspar. The Langmuir volumes (VL) of the 14 shale samples ranged from 1.02 ml/g to 5.25 ml/g (average = 2.52 ml/g); moreover, their MAC was positively correlated with the pore volume, surface area, and TOC content, suggesting that organic matter and pore structure were the most critical factors influencing the adsorption capacity of these transitional shales. Our results showed that the MAC was not positively with the clay content; additionally, the MAC tended to increase with increasing pressure, but to decrease with increasing temperature. The presence of moisture greatly reduced the MAC. Overall, the MAC of the transitional Longtan Formation shales resulted to be quite different from that of typical marine shales (e.g., the Lower Silurian Longmaxi Formation in the Sichuan Basin) in terms of mineralogical component and abundance of organic pores. The particularly high abundance of (hydrophilic) clay minerals in the Longtan Formation transitional shales resulted in a higher number of adsorption sites occupied by water molecules than in the Longmaxi Formation and a lower MAC. Finally, the abundance of organic pores in marine shales resulted in a higher MAC than that of transitional shales.

1. Introduction The development of new technologies has allowed the commercial production of shale and oil gas (the most important unconventional resources) in North America and China (Curtis, 2002; Jarvie et al., 2007; Hao et al., 2013; Gao et al., 2017; Guo et al., 2019; Yang et al., 2019). Shale gas resources will account for approximately 50% of China's natural gas production by 2040, rendering the country the world's largest shale gas producer after North America (EIA, 2017). Natural gas occurs in shale reservoirs in three main forms: free gas, adsorbed gas, and gas dissolved in “in-situ” liquid hydrocarbons and formation water (Curtis, 2002; Gasparik et al., 2012; Tan et al., 2014). Adsorbed gas is one of the major components of shale gas systems, accounting for approximately 20%–85% of the total shale gas content (Curtis, 2002; Ross and Bustin, 2009; Zhang et al., 2012). Therefore, ⁎

studies on the MAC of shales and on its controlling factors are critical for a correct evaluation of shale gas enrichment and prediction of the shale gas resource potential. The MAC is influenced by a number of internal (e.g., the TOC content, mineralogical composition, and pore structure of the shales) and external (e.g., pressure, temperature, and moisture content) factors (Ross and Bustin, 2009; Yang et al., 2016; Dang et al., 2017; Hu et al., 2018). The TOC content is critical to the total gas content of shale reservoirs: organic matter can not only generate oil and gas, but can also provide adsorption sites for methane gases (Hill et al., 2007; Andrea and Philp, 2012; Zhang et al., 2012). Previous studies have documented the occurrence of positive correlations between the TOC content and the MAC for several shale formations (Ross and Bustin, 2009; Zhang et al., 2012; Li et al., 2016; Guo et al., 2017). These studies suggest that the organic matter exerts a primary control on the amount of adsorbed

Corresponding author. E-mail address: [email protected] (T. Dong).

https://doi.org/10.1016/j.petrol.2019.106406 Received 12 April 2019; Received in revised form 25 June 2019; Accepted 19 August 2019 Available online 20 August 2019 0920-4105/ © 2019 Elsevier B.V. All rights reserved.

Journal of Petroleum Science and Engineering 183 (2019) 106406

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gas, since it generates a large number of nanometer-scale pores in mature shales (Ross and Bustin, 2007; Loucks et al., 2009; Bernard et al., 2012). The type of organic matter present in the shale has also a great affect on the level of gas adsorption; in fact, the MAC of terrestrial organic matter is higher than that of marine-derived organic matter (Chalmers and Bustin, 2008; Zhang et al., 2012). Inorganic materials, especially clay minerals, exert also a great influence on the MAC of shales, since clay minerals can generate a large number of tiny pores capable of adsorbing gas molecules (Ross and Bustin, 2009; Ji et al., 2012; Gasparik et al., 2014). The effects of other mineralogical components, including quartz, feldspar, and carbonates on the MAC of shales have been rarely reported. In addition to shale composition, the MAC of shales is controlled by pore structure (Ross and Bustin, 2009; Ambrose et al., 2010). According to the International Union of Pure and Applied Chemistry (IUPAC) classification, the pores in shale reservoirs can be classified into three categories: micropores (< 2 nm), mesopores (2–50 nm), and macropores (> 50 nm) (Rouquerol et al., 1994). Micropores have a higher gas adsorption potential than mesopores and macropores due to their larger specific surface area (Yang et al., 2015). Several studies have focused on the influence of temperature, pressure, and moisture content on the methane adsorption capacity (MAC) of numerous shale formations (Chalmers and Bustin, 2007; Ross and Bustin, 2009; Ji et al., 2014; Tan et al., 2014; Yang et al., 2016; Li et al., 2018b). The effect of temperature and pressure on MAC is known for being complex: temperature, pressure, and MAC are not directly related to each other (Ross and Bustin, 2009; Hao et al., 2013; Tan et al., 2014). The presence of moisture in the methane adsorption sites of a shale may cause the swelling of its clay minerals, and hence, a reduction of its MAC (Krooss et al., 2002). However, some studies suggest that water might exert a minimal effect on shale MAC once all adsorption sites have been occupied by water molecules (Levy et al., 1997; Bustin and Clarkson, 1998). Although several studies have focused on the MAC of marine shales (Ross and Bustin, 2009; Ji et al., 2012; Gasparik et al., 2012, 2014; Zhang et al., 2012; Yang et al., 2016), not many have considered the MAC of marine-continental transitional facies shale. We investigated the transitional facies shales of the Upper Permian Longtan Formation (southwest China) by integrating carbon dioxide, nitrogen, and methane adsorption experiments with geochemical data analysis, in order to identify the factors controlling their MAC. Previous studies have indicated that the mineralogical components of transitional facies shale, as well as their organic matter contents are different from those of marine shales; therefore, these two types of shales have probably different methane adsorption capacities and influencing factors. Our results can be applied to the correct evaluation of the shale gas potential of the Upper Permian Longtan Formation, and also support the evaluation of the gas adsorption capacity of other transitional shales across the world.

2018c). Several large-scale transgression events occurred in the Paleozoic stage, triggering the formation of several organic-rich black shales in South China (i.e., the Lower Cambrian Niutitang Formation, the Upper Ordovician-Lower Silurian Wufeng-Longmaxi Formation, the Lower Permian Shanxi Formation, and the Upper Permian Longtan Dalong Formation) (Sander et al., 2018; Zou et al., 2019). The Upper Permian Longtan Formation primarily consists of carbonaceous shale, silty shale, limestone, and coal. The Longtan Formation shales present high TOC values (5.4 wt% on average), primarily type-III kerogen, and a high thermal maturation level (Ro in the range of 1.0%–2.7%), characteristics that encourage shale gas exploration and production (Luo et al., 2018). 3. Methodology 3.1. Samples For this study, we collected 14 shale samples and 5 coal samples from well JSC1 (well location and the sampling strategy shown in Fig. 1 and Table 1, respectively). The sampling well was located in the northern area of the Guizhou Province. The Longtan Formation is approximately 126 m thick, primarily comprising carbonaceous shale, muddy shale, silty shale, argillaceous siltstone, and coal seams (Fig. 2). 3.2. Methods The TOC contents were measured using an Elementary Rapid CS element analyzer. First, the samples were crushed into powder and made react with 10% HCl at 60 °C to remove any carbonate. The combustion temperature was set to automatically increase to 930 °C. The TOC values were calculated from the CO2 peak area generated from the combustion of organic matter and calibrated by standard samples. The analytical accuracy of the instrument was ± 5%. In order to determine the concentration of different mineral components, the powdered samples were then analyzed using an X'Pert PRO MPD X-ray diffractometer. Powders were randomly oriented in a plate and then scanned from 5°–75° (2θ) at a rate of 2°/min. A Quantachrome Autosorb-iQ3 was used to measure low-pressure gas adsorption and desorption. The shale samples were first crushed and sieved through 60–80 mesh (diameter = 250-180 μm). Approximately 1 g of particles was dried in a vacuum oven at 110 °C for 24 h, in order to remove any free water. The critical pore structure parameters (i.e., surface area, pore volume, and pore size distribution) were calculated from the CO2 and N2 isotherms. The CO2 adsorption isotherms were obtained at a temperature of 273.1 K and at a relative pressure (P/P0) of 4 × 10−5 - 3.2 × 10−2 (Ghosal and Smith, 1996; Ross and Bustin, 2009). Micropore volumes were calculated using the Dubinin–Radushkevich (D–R) equation, while the equivalent micropore surface areas were calculated by assuming a CO2 molecule cross-sectional area of 0.17 nm2 (Ross and Bustin, 2009). The nitrogen adsorption isotherms were obtained at a temperature of 77.4 °K and at a relative pressure (P/P0) of 0.001–0.99. The specific mesopores and macropore surface areas were calculated using the BET equation (Gregg and Sing, 1982), while the pore volume and the pore size distribution of mesopores and macropores were calculated using the BJH equation (Barret et al., 1951). Approximately 4 g of desiccated sample particles (250-180 μm in diameter) were analyzed for their MAC using an ISO-200 isothermal adsorption instrument under a range of pressures and temperatures. This instrument had an oil-bathing temperature control precision of 0.1 °C and a pressure measurement accuracy of 0.1 psi. The methane adsorption experiments were conducted under pressures ranging between 0 and 32 MPa and temperatures of 30 °C, 50 °C, 70 °C, and 90 °C, respectively. The methane adsorption experiment was conducted on both dried and wet samples. The dried samples were prepared removing all moisture at a temperature of 110 °C (until their weight stabilized).

2. Geological background The study area includes part of the Upper Yangtze Platform, located within the northern Yunnan-Guizhou Depression (bordered to the northeast by the Wuling Depression and to the south by the central Guizhou Uplift) (Fig. 1). This area experienced multi-stage tectonic movements, including the Xuefeng movement in the Sinian period, the Caledonian movement in the early Paleozoic, the Hercynian movement in the late Paleozoic, the Indosinian and Xishan movements in the Mesozoic, and the Xishan movement in the Cenozoic (Yang et al., 2014; Li et al., 2018a, 2018c). The superposition of multi-period tectonic movements led to variations in the tectonic stress field, resulting in the development of folds, faults, unconformities, paleo-slopes, and paleotectonic highs (Yang et al., 2014). Previous studies have suggested that the tectonic deformation of the study area is dominated by compression and characterized by the presence of strike-slip faults (Li et al., 2018a, 2

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Fig. 1. Tectonic map displaying the location of sampling well in Guizhou Province, Southwest China (modified from Luo et al., 2018). Table 1 TOC content and mineralogical composition (weight percentage) of studied shale and coal samples from Longtan Formation. Samples

lithology

Depth (m)

TOC

Quartz

Feldspar

Carbonates

Rutile

Pyrite

I/S

Chlorite

Total clays

JSC1-1 JSC1-5 JSC1-6 JSC1-10 JSC1-14 JSC1-15 JSC1-17 JSC1-19 JSC1-21 JSC1-22 JSC1-23 JSC1-26 JSC1-27 JSC1-29 JSC1-30 JSC1-32 JSC1-33 JSC1-35 JSC1-36

coal shale shale shale coal coal shale shale coal shale shale shale coal shale shale shale shale shale shale

669.1 685.7 686.3 692.9 704.7 710.2 714.0 718.3 719.3 719.8 725.4 736.6 737.5 740.7 741.3 747.4 748.2 767.7 771.3

52.3 9.9 6.8 2.8 48.1 42.0 1.0 3.5 54.9 2.6 4.9 4.1 46.5 2.2 2.2 2.9 1.3 2.4 2.5

– 12.5 12.4 12.3 – – 8.0 8.7 – 25.3 0.9 17.7 – 19.6 15.2 1.6 8.9 25.4 24.8

– 7.9 5.6 0 – – 0 15.3 – 8.4 10.0 6.7 – 18.4 27.5 0 10.2 15.8 6.0

– 3.5 2.7 20.8 – – 26.1 0 – 0 0 1.8 – 19.0 13.4 0.5 0 7.0 24.7

– 3.0 0 0 – – 0 3.8 – 3.5 1.7 0 – 3.9 3.7 0 4.8 0 0

– 1.8 0.9 0 – – 0 0 – 0 0 1.4 – 3.1 1.7 0.5 0 5.5 0.9

– 69.2 70.0 42.9 – – 63.8 71.2 – 60.1 86.4 68.2 – 28.8 35.2 94.9 75.5 45.4 43.0

– 2.1 8.4 24.0 – – 2.1 1.0 – 2.7 1.0 4.2 – 7.2 3.3 2.5 0.6 0.9 0.6

– 71.3 78.4 66.9 – – 65.9 72.2 – 62.8 87.4 72.4 – 36.0 38.5 97.4 76.1 46.3 43.6

Note: The mineral composition of the coal sample was not determined. I/S refers to illite/smectite mixed layer.

The Langmuir pressure and volume were calculated based on the adsorption principle of the Langmuir monolayer, using the following equation (Langmuir, 1918):

V=

4. Results 4.1. TOC content and mineralogical composition

VL×P PL+P

The TOC contents of the shale samples ranged between 1.2 wt% and 9.9 wt% (average = 3.5 wt%) (Table 1), while that of the coal samples ranged between 42.0 wt% and 54.9 wt% (average = 48.8 wt%). The results of the X-ray diffraction (XRD) bulk mineralogical analysis indicated a dominance of clay minerals over other minerals (i.e., quartz, feldspar, and carbonate) (Table 1). The abundance of clay, quartz, feldspar, and carbonate minerals ranged between 36.0% and 97.4% (average = 65.4%), 0.9%–25.4% (average = 13.8%), 0%–27.5%

where V refers to the adsorption gas content (ml/g) and P refers to the corresponding pressure (MPa). VL refers to the Langmuir volume (ml/ g), which is the maximum adsorption capacity of the analyzed sample. PL refers to the Langmuir pressure (MPa), which is equal to the pressure at which the adsorption capacity reaches half of its maximum. 3

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Fig. 3. Ternary diagram showing the mineralogical composition of the transitional (i.e., Longtan Formation), typical marine (i.e., Qiongzhusi Formation, Longmaxi Formation, Woodford Formation), and continental shales (i.e., Yanchang Formation) (Guo et al., 2014; Kibria et al., 2018; Zhang et al., 2018).

4.2.2. Mesopores and macropores structures The N2 gas adsorption/desorption isotherms were used to document the mesopores and macropore structures (Kuila and Prasad, 2013). Based on the IUPAC classification, these isotherms and the associated hysteresis loops could be classified as H3-Type isotherms (Fig. 5a), which indicates a dominance of slit-shaped pores (Sing et al., 1985). The mesopore surface areas calculated from the BET equation ranged between 2.56 and 10.98 m2/g (average = 8.30 m2/g) (Table 2), while the mesopore volumes ranged between 0.6 and 2.53 cm3/ g × 10−2 (average = 1.77 cm3/g × 10−2). Additionally, the macropore surface areas ranged from 0.27 to 0.75 m2/g, averaging 0.47 m2/g (Table 2). Pore volume of macropores ranged from 0.7 to 1.8 cm3/ g × 10−2 (average = 1.24 cm3/g × 10−2). The pore size distributions obtained from N2 adsorption analysis are displayed in Fig. 5b. The poresize distribution diagram showed multiple peaks, although the size of most pores ranged between 7 and 50 nm.

Fig. 2. Stratigraphic column of the Upper Permian Longtan Formation, showing the lithologies, the sampling location, and the gamma ray log.

(average = 9.4%), and 0%–26.1% (average = 8.5%), respectively. The clay minerals were mainly represented by mixed layer illite/smectite and, secondly, by chlorite. The mineralogical differences between the transitional shale of the Longtan Formation, the continental shale of the Yanchang Formation, and typical marine shales (e.g., the Woodford Formation, the Longmaxi Formation, and the Niutitang Formation) are plotted in Fig. 3. The transitional Longtan shale is mainly composed of clay minerals, whereas typical marine shales were dominated by quartz and feldspar.

4.3. Methane gas adsorption capacity The results of the methane adsorption experiments conducted at different pressures and temperatures are plotted in Fig. 6. The Langmuir parameters, i.e., Langmuir pressure (PL) and Langmuir volume (VL), obtained from the nonlinear fitting of the experimental methane adsorption isotherms for the 14 shale samples and the 5 coal samples, are listed in Table 3. The VL of the 14 shale samples ranged from 1.02 ml/g and 5.25 ml/g (average = 2.52 ml/g), while the PL ranged between 1.22 MPa and 2.41 MPa. Moreover, the VL of the 5 coal samples ranged from 15.52 ml/g to 23.43 ml/g (average = 19.42 ml/g), while the PL ranged from 0.73 MPa to 0.79 MPa (see Table 3). The methane adsorption isotherms were classified into three groups, according to their TOC contents: a first group with TOC contents < 2.5% (Fig. 6a), a second group with TOC contents between 2.5% and 4% (Fig. 6b), and a third group with TOC contents > 4% (Fig. 6c). The methane adsorption isotherms of the coal samples are shown in Fig. 6d. The amount of methane adsorption increased rapidly with increasing pressure (pressure < 5 MPa), it increased slowly between 5 and 15 MPa, and then became constant after a further increase in pressure (pressure > 15 MPa). Notably, the amount of methane adsorbed by coal samples generally increased with the increasing TOC content

4.2. Pore structures as revealed by low-pressure CO2 and N2 absorption analysis 4.2.1. Micropore structure The CO2 adsorption isotherms of the 14 shale samples could be classified as Type I adsorption isotherms (Sing et al., 1985), which suggests the dominance of micropores (Fig. 4a). The calculated micropore volumes and surface areas are listed in Table 2. The micropore volumes ranged from 0.30 to 1.90 cm3/g × 10−2 (average = 0.91 cm3/ g × 10−2), while surface areas ranged from 11.37 to 50.89 m2/g (average = 24.67 m2/g). The calculated pore size distribution displayed multiple peaks in correspondence of 0.33–0.38 nm, 0.41–0.68 nm, and 0.78–0.85 nm (Fig. 4b).

4

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Fig. 4. (a) CO2 adsorption isotherms of the shale samples. (b) Micropore diameter distribution obtained from the CO2 adsorption isotherms.

(Fig. 6d). However, such relationship was not obvious in the case of shale samples (Fig. 6a, b, c). For example, the shale sample JSC1-33 displayed a TOC content of 1.3% and at the same time the highest absorption of methane (Fig. 6a).

from the fact that micropores and mesopores provide more adsorption sites for the methane molecules than macropores; in fact, the specific surface areas of micropores (average = 24.67 m2/g) and mesopores (average = 8.30 m2/g) were considerably higher than those of macropores (average = 0.47 m2/g) (Table 2). Our results could also derive from the fact that the physical sorption of gas molecules in a porous shale reservoir is strongly controlled by the van der Waals forces, which is affected by the distance between the gas molecules and the pore walls (Mosher et al., 2013; Rexer et al., 2014): short distances correspond to more intense van der Waals forces and increased sorption energies (Ross and Bustin, 2009). The distance between the gas molecules and the pore walls is generally short in the case of small-sized pores, leading to intense van der Waals forces and a high physical adsorption of methane gas molecules. In summary, the MAC of shales and coals is affected by both the specific surface area of pores and the van der Waals forces between the gas molecules and the pore walls, which are strongly influenced by pore size. Since small-sized pores have larger surface areas and are interested by more intense van der Waals forces than large-sized pores, their abundances result in higher MAC. Considering simply the pore structure only, we can conclude that micropores were the main contributors to the MAC of the sediments, followed by mesopores (moderate contribution) and macropores (low contribution).

5. Discussion 5.1. Effects of pore structure on the MAC Pore structure, especially pore size, has been regarded as a critical factor affecting the MAC of coals and shales (Chalmers and Bustin, 2008; Ji et al., 2012; Hou et al., 2014). Micropores with diameter < 2 nm have a larger surface area and a greater sorption energy than mesopores (2–50 nm) and macropores (> 50 nm) (Dubinin, 1975; Ross and Bustin, 2009); therefore, micropores are main contributors to the adsorption capacity of coals and shales. The correlations between the VL, the pore volume, and the specific surface area (calculated from the CO2 and N2 adsorption isotherms) of micropores, mesopores, and macropores are shown in Fig. 7. The VL was positively correlated with the micropore and mesopore volumes (Fig. 7a), as well as with the specific surface areas of micropores and mesopores (Fig. 7b). However, neither the pore volumes nor the surface areas of macropores were positively correlated with the VL. These results may indicate that micropores and mesopores had a larger influence than macropores on the MAC. These characteristics could derive Table 2 Pore volume and surface area of micropores, mesopores, and macropores. Samples

JSC1-5 JSC1-6 JSC1-10 JSC1-17 JSC1-19 JSC1-22 JSC1-23 JSC1-26 JSC1-29 JSC1-30 JSC1-32 JSC1-33 JSC1-35 JSC1-36

Depth (m)

685.7 686.3 692.9 714.0 718.3 719.8 725.4 736.6 740.7 741.3 747.4 748.2 767.7 771.3

CO2-adsorption

N2-adsorption

Micropore volume (cm3/g × 10−2)

Micropore surface area (m2/g)

Mesopore volume (cm3/g × 10−2)

Mesopore surface area (m2/g)

Macropore volume (cm3/g × 10−2)

Macropore surface area (m2/g)

1.90 1.20 0.30 0.40 1.00 1.00 1.20 1.20 0.50 0.70 1.00 0.90 0.70 0.70

50.89 31.77 11.37 11.80 27.78 25.93 31.25 32.14 14.02 19.51 25.83 24.78 19.42 18.95

2.13 2.03 0.60 1.12 2.38 2.10 1.86 2.20 0.94 1.40 2.53 2.18 1.84 1.50

10.98 10.04 2.56 4.03 10.76 9.34 9.45 11.73 4.33 7.28 10.1 9.82 8.59 7.13

0.90 1.18 0.70 1.07 1.40 1.45 1.25 1.54 1.05 1.08 1.80 1.17 1.32 1.40

0.36 0.46 0.27 0.42 0.55 0.57 0.44 0.53 0.36 0.37 0.75 0.49 0.51 0.50

5

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Fig. 5. (a) Nitrogen adsorption and desorption isotherms. (b) The micropore (< 2 nm), mesopore (2–50 nm), and macropore (> 50 nm) size distributions obtained from a combination of CO2 and N2 adsorption isotherms.

5.2. Effects of rock composition on the MAC

suggesting that organic matter greatly contribute to the MAC of the transitional shales of the Upper Permian Longtan Formation. A positive correlation between the TOC content and the MAC was also observed in organic-rich marine shales (Chalmers and Bustin, 2008; Tan et al., 2014; Yang et al., 2016). In our coal samples, the MAC was positively

The TOC content has been demonstrated to greatly influence the MAC in shale reservoirs (Dang et al., 2017). The VL of our shale samples was positively correlated with the TOC content (R2 = 0.70) (Fig. 8a),

Fig. 6. Methane adsorption results for the shale (a, b, and c) and coal (d) (dry samples at 30 °C). The methane adsorption curves of the shale samples with TOC content < 2.5%, between 2.5% and 4%, and > 4% are plotted in panels (a), (b), and (c), respectively. 6

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Table 3 Langmuir pressure (PL) and Langmuir volume (VL) of dry shale and coal samples. Samples

JSC1-1 JSC1-5 JSC1-6 JSC1-10 JSC1-14 JSC1-15 JSC1-17 JSC1-19 JSC1-21 JSC1-22

Lithology

coal shale shale shale coal coal shale shale coal shale

Depth (m)

669.1 685.7 686.3 692.9 704.7 710.2 714.0 718.3 719.3 719.8

30 °C

Samples

PL (MPa)

VL (ml/g)

0.77 1.22 1.46 1.36 0.74 0.79 2.41 1.84 0.74 1.81

20.71 5.25 3.27 1.02 18.94 15.52 1.21 3.12 23.43 2.45

JSC1-23 JSC1-26 JSC1-27 JSC1-29 JSC1-30 JSC1-32 JSC1-33 JSC1-35 JSC1-36

Lithology

shale shale coal shale shale shale shale shale shale

Depth (m)

725.4 736.6 737.5 740.7 741.3 747.4 748.2 767.7 771.3

30 °C PL (MPa)

VL (ml/g)

1.56 1.47 0.73 1.50 1.74 2.04 2.18 2.01 1.77

2.81 3.43 18.49 1.36 1.98 2.71 2.72 2.06 1.83

Fig. 7. (a) Correlation between the VL and pore volumes (calculated from BJH model), notably, there was positive correlations between the VL and pore volumes for micropores and mesopores, while no correlation was found for macropores. (b) Correlation between the VL and specific surface area (calculated from BET equation), notably, the surface area of macropores was much lower than those of mesopores and micropores.

Fig. 8. Correlation between the TOC content and VL for the shale samples (a) and coal samples (b).

correlated (R2 = 0.97) with TOC content (Fig. 8b). Notably, the correlation coefficient of the coal samples was higher than that of the shale samples. Possibly, the MAC of the coal samples was mostly controlled by the TOC content, whereas that of the shale samples was controlled by other factors in addition to TOC content. The micropore volumes and surface areas were positively correlated with the TOC contents, whereas the mesopores and macropore volumes and surface areas displayed no obvious correlation with the TOC contents (Fig. 9). The results suggested the generation of micropores was strongly associated with the

presence of organic matter, in accordance with previous studies showing that the thermal maturation of organic matter can result in generation of numerous micropores (Ross and Bustin, 2007; Loucks et al., 2009; Tan et al., 2014; Dong et al., 2015). The generation of micropores in organic matter increases the MAC, since micropores have larger surface areas and greater sorption energies than mesopores and macropores (Ross and Bustin, 2009). Previous studies have suggested that the MAC of shales can be also affected by the content and type of clay minerals (Liu et al., 2013; Yang 7

Journal of Petroleum Science and Engineering 183 (2019) 106406

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Fig. 9. (a) Correlation between TOC content and the pore volumes of micropores, mesopores, and macropores of the studied shale samples. (b) Correlation between TOC content and the specific surface areas of micropores, mesopores, and macropores of the studied shale samples. Notably, there was only positive correlation between TOC content, pore volumes and surface areas for micropores.

Fig. 10. Cross-plots showing the VL and the total clay mineral (a), illite-smectite mixed layer (b), and chlorite mineral (c). No obvious correlations were observed for the highly scattered data.

et al., 2015; Jiang et al., 2016). In fact, smectite has a higher adsorption capacity than kaolinite and illite, followed by chlorite (Li and Wu, 2015). Positive relationships between the clay mineral content and porosity have been reported in several black shales. However, some studies have suggested that those pores associated with clay minerals can be strongly destroyed by diagenetic processes (e.g., compaction, transformation of clay minerals) during the thermal maturation process

(Chen et al., 2016b; Dong et al., 2017). In addition, due to the hydrophilic nature of clay minerals, the adsorption sites can be occupied by water molecules, significantly reducing the MAC (Ross and Bustin, 2009). The VL values were plotted against the total clay mineral contents and the contents of different types of clay minerals (Fig. 10). No significant correlation was identified between the total clay content and 8

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Fig. 11. Methane adsorption results for the Longtan Formation shale samples at temperatures of 30 °C, 50 °C, 70 °C and 90 °C. (a) Sample JSC1-23, (b) Sample JSC133. Table 4 Langmuir Pressure (PL) and Langmuir Volume (VL) of dry shale samples under different temperatures (30, 50, 70 and 90 °C). Samples

JSC1-23 JSC1-33

Depth (m)

725.4 748.2

30 °C

50 °C

70 °C

90 °C

PL (MPa)

VL (ml/g)

PL (MPa)

VL (ml/g)

PL (MPa)

VL (ml/g)

PL (MPa)

VL (ml/g)

1.56 2.18

2.81 2.72

1.66 2.39

2.40 2.25

1.99 2.68

2.19 2.01

2.40 3.36

1.99 1.83

Fig. 12. Variations of the VL as a function of temperature (a); Correlation between the logarithm of PL and temperature (b), based on the methane adsorption isotherms at different temperatures.

the MAC (Fig. 10a); however, a week positive correlation was found between the concentration of illite-smectite mixed layers and the MAC (Fig. 10b), and a week negative correlation was found between the chlorite content and the MAC (Fig. 10c). These results suggest that clay minerals have a limited effect on the MAC, even though they are the dominant constituting components of the Longtan Formation transitional shale (Fig. 3 and Table 1). Luo et al. (2018) reported Ro values of 1.0–2.7% for the Longtan Formation; there, clay minerals were mainly represented by mixed layer illite/smectite, reflecting a later diagenetic stage. In that case, all the smectite minerals had been converted into mixed layer illite/smectite and illite, and the pores associated with clay minerals had been destroyed likely due to compaction and clay mineral conversion. Compared with clay minerals, other mineralogical components (i.e., quartz, carbonate, and pyrite) were less abundant in our samples (Table 1); hence, we did not consider them as important factors controlling the MAC.

5.3. Effects of temperature, pressure, and moisture content on the MAC Under in-situ reservoir conditions, temperature, pressure, and moisture content all have important impacts on the MAC of shale reservoirs. The amount of adsorbed gas in shale reservoirs is strongly associated with their temperature and pressure; in fact, the adsorbed gas may change into free gas during the uplift stage of shale formation, following a decrease in the overburden pressure (Yang et al., 2016). Previous studies have also suggested that the gas adsorption capacity tends to decrease with increasing temperature, due to exothermic processes (Sircar, 1992; Ross and Bustin, 2008; Zhang et al., 2012; Hao et al., 2013). To determine the effect of temperature and pressure on the MAC, we conducted methane adsorption experiments on two shale samples (JSC1-23 and JSC1-33) at four different temperature points (30 °C, 50 °C, 70 °C, and 90 °C) and at a pressure range of 0–32 MPa (Fig. 11, 9

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Fig. 13. Methane adsorption capacity of dry and wet shale samples at 30 °C. (a) Sample JSC1-19, (b) Sample JSC1-22, (c) Sample JSC1-23, (d) Sample JSC1-33.

particular, the moisture content of coal and shale samples has been documented to negatively influence their MAC (Bustin and Clarkson, 1998; Krooss et al., 2002; Day et al., 2008; Ross and Bustin, 2009; Gasparik et al., 2014; Hu et al., 2018). Moisture can reduce the MAC of Devonian-Mississippian marine shales by approximately 60% (Ross and Bustin, 2009), at that of Scandinavian Alum and Posidonia Formation marine shales by 40–60% (Gasparik et al., 2014). Hu et al. (2018) calculated that the moisture reduced MAC of the Paleozoic WufengLongmaxi Formation (in South China) by approximately 20%. . We investigated the effect of moisture on the MAC of four shale samples, finding major differences between the dry and wet samples (Fig. 13). The MAC of the Longtan Formation transitional shales was reduced by approximately 40%–50% (Fig. 13, Table 5), demonstrating the great influence of moisture on the MAC. These shales are rich in clay minerals, whose hydrophilic nature involves a great reduction of the adsorption sites for gas molecules and a large decrease in the MAC. Ross and Bustin (2009) documented how the MAC of clay minerals can be reduced by 80–95% under high moisture conditions. Moisture content may hence be a critical factor controlling the MAC of transitional facies shale reservoirs, which are rich in clay: a high moisture content can hinder the adsorption and accumulation of gas under in-situ reservoir conditions.

Table 5 Langmuir volume of dry and wet shale samples. Sample

JSC1-19 JSC1-22 JSC1-23 JSC1-33

Depth (m)

718.3 719.8 725.4 748.2

VL (ml/g) Dry sample

Wet sample

3.12 2.45 2.81 2.72

1.57 1.33 1.66 1.28

Reduction (ml/g)

Reduced Percentage (%)

1.55 1.12 1.15 1.44

49.68 45.71 40.93 52.94

Table 4). The MAC decreased when the temperature increased from 30 °C to 90 °C under isobaric conditions (Fig. 11), suggesting that its dependence on temperature: low temperatures might have enhanced gas adsorption. The negative correlation between VL and temperature also suggest that low temperatures might have been beneficial for gas adsorption (Fig. 12a), in accord with the results of other studies (Rexer et al., 2013; Ji et al., 2014). In this study, the gas sorption capacity of the shale samples increased with pressure, reaching its maximum at a pressure of approximately 15 MPa (Figs. 6 and 11). A strongly positive relationship was observed between the natural logarithm of PL and temperature as in previous studies (Fig. 12b) (e.g. Gasparik et al., 2012; Ji et al., 2012; Zhang et al., 2012; Rexer et al., 2013). The PL is a proxy for the affinity of gas molecules to material surfaces: low PL values indicate a strong affinity of the gas molecules to material surfaces (Ji et al., 2012; Zhang et al., 2012). Zhang et al. (2012) reported that the moisture content of shale sediments has a large impact on the MAC, because water molecules tend to occupy the adsorption sites and reduce the gas adsorption volume. In

5.4. Comparison between the MACs of typical marine, transitional, and continental shales Shales deposited under different depositional facies have varied mineralogical composition and organic matter content, type, which imply different MACs. Currently, most studies on the MAC are 10

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Table 6 TOC, clay content and Langmuir volume of typical marine, transitional, and continental shales with TOC content between 2 and 5 wt%. Langmuir adsorption volumes were measured on dry samples under the same temperature condition of 30 °C. Marine shales

Age

Sample no.

TOC (wt.%)

Clays (wt.%)

VL (ml/g)

Date source

Besa Formation

Devonian-Mississippian

Lower Silurian

Longmaxi Formation

Lower Silurian

Longmaxi Formation

Lower Silurian

Longmaxi Formation

Lower Silurian

Longmaxi Formation

Lower Silurian

Longmaxi Formation

Lower Silurian

Qiongzhusi Formation

Lower Cambrian

Liujiaping Formation

Lower Cambrian

4.0 4.0 4.9 4.7 3.8 2.1 4.4 2.5 2.0 2.4 4.7 3.5 2.6 4.2 2.2 4.8 3.2 3.1 4.1 4.8 4.4 3.9 2.7 3.5 2.3 2.9 2.9 2.9 2.1 2.1 3.0 3.9 3.7 3.4 4.1 2.4 2.2 2.3 3.7 2.6 3.0 3.2 3.7 3.8 4.4 4.9 2.4 3.1 4.4 2.9 2.2 2.2 2.5 2.8 2.6 3.4 4.7 2.7 4.0 4.5 3.0 2.4 3.0 2.3

16.9 23.0 24.1 22.3 22.9 9.6 6.3 7.9 / / / / / / / / 24.3 20.4 17.5 19.7 21.7 25.2 39.3 26.7 25.4 45.0 31.3 38.3 33.5 36.0 34.5 38.5 27.2 35.1 26.8 55.0 49.1 44.4 39.5 34.0 39.5 30.7 41.0 26.3 55.8 22.5 48.9 37.9 27.7 28.3 29.7 39.8 25.0 15.0 14.0 17.6 18.8 16.0 22.0 15.0 13.0 9.0 5.0 24.0

3.20 3.00 3.50 4.00 3.00 1.60 2.60 1.80 2.46 2.79 3.06 2.76 2.46 2.89 1.77 2.13 2.82 4.31 4.55 5.36 4.77 3.18 2.76 3.64 2.31 2.86 3.21 2.76 2.98 2.58 3.15 4.00 4.97 3.64 2.85 2.64 2.92 3.20 3.65 3.19 3.30 3.60 3.58 4.76 3.85 4.35 4.97 1.90 2.44 2.33 1.96 1.88 0.70 0.05 0.09 0.81 1.70 1.19 1.23 1.41 3.18 1.27 1.20 1.10

Ross and Bustin (2009)

Longmaxi Formation

UBS-C15-1331-5 UBS1331-4 UBS1331-5 UBS1331-6 UBS1331-11 LBM325-5 LBM2563-3 LBM2563-7 LD1-3 LD1-38 LC2-3 LC2-7 LC2-18 LQ-6 LQ-9 GS-7 #4 #5 #6 #7 #8 #9 JY1-03 JY1-04 PY1-02 PY1-03 JY1-3 JY1-4 JY1-7 JY1-9 JY1-11 JY1-12 JY1-13 JY1-14 JY1-15 17 18 21 22 23 24 25 26 27 28 29 30 MY-2 MY-3 MY-5 MY-6 MY-8 C1-1 C1-4 C1-12 C1-13 C1-17 C1-20 C1-22 C1-23 C1-30 C1-31 C1-33 C1-36

Continental shales

Age

sample

TOC(wt.%)

Clays (wt.%)

VL (ml/g)

Data source

Taliqike Formation

Upper Triassic

T3t-2 T3t-3 T3t-5

2.2 2.6 2.4

48.0 49.0 43.0

1.77 2.15 2.08

Guo et al. (2017)

Chen et al. (2016a,b)

Wang et al. (2016) Li et al. (2016)

Yang et al. (2016)

Hu et al. (2018)

Li et al. (2018a,b,c)

Li et al. (2017a,b)

Ma et al. (2015)

(continued on next page)

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Table 6 (continued) Yanchang Formation

Upper Triassic

Yanchang Formation

Upper Triassic

Transitional shales Longtan Formation

Age Upper Permian

2 3 4 6 9 14 HH55-1001 JH6-1002 XF6-1 sample JSC1-10 JSC1-19 JSC1-22 JSC1-23 JSC1-26 JSC1-29 JSC1-30 JSC1-32 JSC1-35 JSC1-36

2.4 5.0 2.8 4.8 4.3 4.6 3.5 2.0 3.3 TOC(wt.%) 2.8 3.5 2.6 4.9 4.1 2.2 2.2 2.9 2.4 2.5

36.7 55.7 32.7 44.3 48.2 45.7 46.0 50.0 68.0 Clays (wt.%) 66.9 72.2 62.8 87.4 72.4 36.0 38.6 97.3 46.2 43.6

1.31 1.53 1.46 1.94 1.73 2.38 1.69 1.06 2.54 VL (ml/g) 1.02 3.12 2.45 2.81 3.43 1.36 1.98 2.71 2.06 1.83

Li et al. (2018a,b,c)

Kou et al. (2016) Data source This study

Fig. 14. Methane adsorption capacity statistics of typical marine shales (from the Besa Formation, Longmaxi Formation, Qiongzhusi Formation, and Lujiaping Formation), transitional shales (from the Longtan Formation), and continental shales (from the Taliqike Formation in the Tarim Basin and the Yanchang Formation in the Ordos Basin) under the same temperature conditions (30 °C). All samples were dry and had TOC contents ranging between 2 and 5%.

conducted on marine and continental shales, while those on transitional facies shales are rare. We collected the available MAC data regarding typical marine shales, mainly including the Lower Cambrian Lujiaping Formation (Ma et al., 2015), the Lower Cambrian Qiongzhusi Formation (Li et al., 2017a), the Lower Silurian Longmaxi Formation in the Yangtze platform, South China (Chen et al., 2016a; Li et al., 2016, 2018b; Wang et al., 2016; Yang et al., 2016; Hu et al., 2018), and the Upper Devonian Besa Formation (Ross and Bustin, 2009), and continental shales (the Upper Triassic Yanchang Formation in the Ordos Basin, Northwestern China (Kou et al., 2016; Li et al., 2018b) and the Taliqike Formation in the Tarim Basin, Northwestern China (Guo et al., 2017). The correspondent TOC content, mineralogical composition, and adsorption capacity data are listed in Table 6. To eliminate the effect of organic matter abundance on the MAC, we selected shale samples with TOC content in the range of 2–5%, and all the marine, transitional, continental shales have comparable TOC contents (Table 6). Under the same temperature conditions (30 °C), the

maximum, minimum, and average MAC values of the transitional shales were found to be lower than those of the marines shales, whereas the continental shales corresponded to the lowest MAC values (Fig. 14). Notably, the MACs of the Lower Cambrian Qiongzhusi Formation and Liujiaping Formation marine shales were lower than those of the Upper Permian Longtan Formation transitional shales. Previous studies have suggested that the Lower Cambrian marine shales experienced enhanced compaction and thermal maturity, resulting in low porosity and MAC (Li et al., 2017a, 2017b; Xu et al., 2017). By comparing the MAC of typical marine, transitional, and continental shales having similar TOC content, under the same temperature conditions, we found that the MAC of transitional shales tends to be lower than that of marine shales and higher than that of continental shales. The high MAC of marine shales can be ascribed to two reasons. First, marine shales are usually rich in quartz and feldspar minerals, whereas transitional and continental shales are relatively rich in clay minerals (Fig. 3 and Table 6). Since clay minerals generally have a higher 12

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Fig. 15. Field emission-scanning electron microscope (FE-SEM) images showing the development of organic pores in typical marine shales of the Longmaxi Formation (Guo et al., 2019), transitional shales of the Longtan Formation, and continental shales of the Ziliujing Formation (Gao et al., 2018). (a, b) Abundance of pores in the organic matter of the Longmaxi Formation; (c, d) less numerous and smaller organic pores in the Longtan Formation; (e, f) absence of organic pores in the Ziliujing Formation, in which most of the organic matter is non-porous. OM: organic matter.

conducted TOC content, XRD mineralogy, low temperature CO2 adsorption, and N2 adsorption, and methane adsorption analyses under varied temperature and pressure conditions, reaching the following conclusions:

moisture content than quartz and feldspar, and increased moisture content will definitely decreases the MAC of transitional shale. Second, the organic pores of marine shales samples were found to be much more abundant and larger than those of transitional and continental shale samples (Fig. 15). Previous studies have documented that the generation of organic pores is strongly associated with the thermal cracking of bitumen and pyrobitumen (Bernard et al., 2012); therefore, marinederived organic matter tends to produce more organic pores than terrestrial organic matter during the thermal maturation process. Limited number of data were collected during our study; hence, these conclusions might be revised in the future following the analyses of additional marine, transitional, and continental shale samples. In our dataset, the MAC of coal samples was much higher than that of shale samples regardless of sedimentary facies. Even if the MAC of the Longtan shale samples was lower than that of the Longmaxi shale samples, the overall MAC potential of the Longtan Formation might be higher than that of the Longmaxi Formation. In fact, the Longtan Formation contains coal seams, which are characterized by a considerably high MAC.

(1) Organic matter abundance should be the most important factor controlling MAC; in fact, the thermal maturation of organic matter can generate a large amount of micropores. Having a small in size but also a large surface area, micropores have more adsorption sites for the gas molecules and largely contribute to the MAC of shales (more than mesopores or macropores). (2) Temperature, pressure, and moisture content all have an important impact on the MAC of the Longtan Formation transitional shales. Temperature tends to be negatively correlated with the MAC, which increases with pressure until this parameter reaches values of approximately 15 MPa. The presence of moisture can greatly reduce the MAC of the Longtan Formation transitional shale, largely due to the hydrophilic nature of clay minerals combined with the high concentration of clay minerals in transitional shales. (3) Typical marine, transitional, and continental shales have significantly different mineral composition. The Longtan Formation transitional shales are mainly composed of clay minerals, whereas typical marine shales (e.g., those of the Longmaxi Formation and Woodford Formation) are dominated by quartz. These mineralogical differences and the type of organic matter result in

6. Conclusions In this study, we investigated the factors influencing the MAC of the marine-continental transitional facies shales of the Upper Permian Longtan Formation through an integrated analysis. In particular, we 13

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different MACs. Finally, the MAC of typical marine, continental and transitional shales is far lower than that of coal.

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