energies

Article Nanostructure Effect on Adsorption Capacity of with Type III Kerogen

Yong Han 1,2 , Yanming Zhu 1,2,*, Yu Liu 1,2, Yang Wang 1,2, Han Zhang 1,3 and Wenlong Yu 1,2 1 Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process, Ministry of Education, China University of Mining and Technology, Xuzhou 221008, Jiangsu, China; [email protected] (Y.H.); [email protected] (Y.L.); [email protected] (Y.W.); [email protected] (H.Z.); [email protected] (W.Y.) 2 School of Resources and Earth Science, China University of Mining and Technology, Xuzhou 221116, Jiangsu, China 3 College of Mining Engineering, Taiyuan University of Technology, Taiyuan 030024, Shanxi, China * Correspondence: [email protected]

 Received: 8 February 2020; Accepted: 24 March 2020; Published: 3 April 2020 

Abstract: This study focuses on the nanostructure of shale samples with type III kerogen and its effect on methane adsorption capacity. The composition, pore size distribution, and methane adsorption capacities of 12 shale samples were analyzed by using the high-pressure mercury injection experiment, low-temperature N2/CO2 adsorption experiments, and the isothermal methane adsorption experiment. The results show that the total organic (TOC) content of the 12 shale samples ranges from 0.70% to ~35.84%. In with type III kerogen, clay minerals and tend to be deposited simultaneously. When the TOC content is higher than 10%, the clay minerals in these shale samples contribute more than 70% of the total inorganic matter. The CO2 adsorption experimental results show that micropores in shales with type III kerogen are mainly formed in organic matter. However, mesopores and macropores are significantly affected by the contents of clay minerals and quartz. The methane isothermal capacity experimental results show that the Langmuir volume, indicating the maximum methane adsorption capacity, of all the shale samples is between 0.78 cm3/g and 9.26 cm3/g. Moreover, methane is mainly adsorbed in micropores and developed in organic matter, whereas the influence of mesopores and macropores on the methane adsorption capacity of shale with type III kerogen is small. At different stages, the influencing factors of methane adsorption capacity are different. When the TOC content is <1.4% or >4.5%, the methane adsorption capacity is positively correlated with the TOC content. When the TOC content is in the range of 1.4–4.5%, clay minerals have obviously positive effects on the methane adsorption capacity.

Keywords: shale gas; type III kerogen; nanopore structure; methane adsorption capacity

1. Introduction Shale gas is becoming one of the most important resources in the US, China, and other countries [1,2]. Shale gas is mainly composed of adsorbed gas and free gas [2,3], and adsorbed gas is mainly located on the pore surface of shale [4,5]. The pore system in shale reservoirs is quite complex because of its heterogeneity and multiple scale effect [6–10]. It has been proven that there are large amounts of micropores (<2 nm), mesopores (2–50 nm), and macropores (>50 nm) in organic shale [11]. Among the various pores, pores with diameters smaller than 10 nm are considered to contribute most of the total surface area [12–14]. Moreover, based on the formation types, pores in shale can be mainly divided into organic pores, clay pores, interparticle pores, and intraparticle mineral pores [15], and organic pores are proven to contribute the largest proportion of the total pore volume and total surface area [16,17].

Energies 2020, 13, 1690; doi:10.3390/en13071690 www.mdpi.com/journal/energies Energies 2020, 13, 1690 2 of 23

As adsorbed gas is considered to be adsorbed on the surface of pores in shale [4,5], the nanopore structure and shale composition have significant effects on the methane adsorption capacity [18–20]. It has been proven that a higher organic matter content brings a larger surface area and a larger methane adsorption capacity [21–25]. With increasing (TOC) content, the methane adsorption capacity increases linearly [18,21,26–30]. Comparably, related studies have found that quartz and carbonate have a negative effect on the methane adsorption capacity in shale [25,27,31]. Currently, it is still debated whether clay minerals have a positive effect on methane adsorption capacity in shale. Some studies have found that with increasing the clay mineral content, the methane adsorption capacity substantially increases, especially in the low TOC shales [25,29,32]. However, other studies proposed that clay minerals have a weak [12,23,28,30] or even negative effect on methane adsorption capacity [21,33,34]. Shales can be divided into three types based on their depositional environments: marine facies shale, marine-terrigenous facies shale, and lacustrine facies shale [35]. Marine-terrigenous facies shale is believed to have a large amount of shale gas resources [35]. Currently, the most successful shale gas development is mainly in marine facies shales, such as the Longmaxi formation shale in South China [8,21,30,34], the Marcellus shale [8,21,30,34,36,37], and the Barnett shale in the US [38]. The organic matter type of marine shales is type I or type II [39–41]. Additionally, research on shale gas reservoirs has mainly focused on organic shale with type I or type II kerogen [42–44]. A comparison of the shale with type III kerogen and the shale with type I kerogen shows that the sedimentary environment and organic matter are different, causing the differences in the nanostructure and methane adsorption capacity [45]. Based on previous studies, type III kerogen has a larger O/C ratio and a smaller H/C ratio than type I or type II kerogen [46]. In addition, due to the different sedimentary environments, shale with type III kerogen has a higher clay content and lower quartz content than shales with type I and type II kerogens [46]. As the mineral composition and organic matter of shale with type III kerogen are different from those of shale with types I and II kerogens [46], the pore structure and methane adsorption behavior of shale with type III kerogen are different from those of shale samples with type I or type II kerogen [26,45]. Although the pore structure and methane adsorption behavior of shale samples with type I and type II kerogen have been well studied [42–44], those of shale samples with type III kerogen still need further study. This study aims to investigate how composition and nanopore structure affect the methane adsorption capacity in shale with type III kerogen. Twelve shale samples with type III kerogen were collected from a sample well in China. A high-pressure mercury injection experiment, a low-pressure N2 adsorption experiment, and a low-pressure CO2 adsorption experiment were used to characterize the nanopore structure of the shale samples. In addition, the methane adsorption capacity of these shale samples was obtained by using the methane adsorption isothermal experiment.

2. Samples and Experiment

2.1. Sample Information In this study, 12 shale samples were collected from the same well in the Huoxi field of Shanxi Province, China, and these shale samples were from the Carboniferous–Permian strata. All the shale samples had similar thermal maturities, and the reflectance values (Ro) were approximately 1.3%. In addition, the organic matter in these shale samples is type III. Their TOC content, mineral components, and clay components are listed in Table1. The TOC content of the shale samples ranges from 0.70% to 35.84%. Because of the higher TOC content, samples T-11 and T-12 are regarded as carbonaceous shale. It is obvious that quartz and clay minerals were the main mineral components of the samples. The quartz content ranged from 20% to 44%, with an average of 32%, and the total clay mineral content ranged from 47% to 73%, with an average of 62.5%. The clay minerals of all the samples were mainly composed of illite, kaolinite, and mixed-layer illite/smectite. Energies 2020, 13, 1690 3 of 23

Table 1. Sample information.

Mineral Components (wt %) Clay Components (wt %) Sample TOC Total Mixed-Layer ID (wt %) Quartz Plagioclase Dolomite Siderite Pyrite Illite Kaolinite Clay Illite/Smectite T-1 1.45 27 0 0 0 0 73 24 62 14 T-2 1.42 44 3 0 1 0 52 26 51 23 T-3 2.33 33 0 0 0 0 67 21 58 21 T-4 4.50 41 0 0 5 0 54 37 43 20 T-5 0.70 37 12 0 4 0 47 34 35 31 T-6 3.64 26 4 0 0 0 70 26 41 33 T-7 6.96 42 4 0 0 0 54 36 31 33 T-8 3.25 30 3 0 0 0 67 25 41 34 T-9 1.29 34 5 0 3 0 58 35 38 27 T-10 0.92 29 3 0 3 0 65 51 44 5 T-11 35.84 21 0 3 0 3 73 8 92 0 T-12 23.96 20 0 0 0 10 70 44 47 9

2.2. Experiments

2.2.1. Low-Temperature Adsorption Experiment

The low-temperature CO2 adsorption experiment was conducted at 0 ◦C using MicroActive for ASAP 2460 Version 2.01 from Micromeritics. In this experiment, the particle size of these shale samples was 60–80 mesh with a mass of 1.4 g to 1.5 g. All samples were dried and degassed before the analysis. During the experiment, the equilibration interval was 45 s. The CO2 adsorption analysis was mainly used to characterize the micropores in the shale reservoir [11]. All the shale samples’ pore characteristics (0.4–1.1 nm) were obtained by using a density functional theory (DFT) model [47].

2.2.2. Low-Temperature Adsorption Experiment The low-temperature N adsorption experiment was conducted at 196 C using MicroActive for 2 − ◦ ASAP 2460 Version 2.01 from Micromeritics following the China standard GB/T 19587-2004. This is suitable to interpret the mesopore structure [11]. The shale samples were pulverized to 60–80 mesh and then dried and degassed before the experiment. In this experiment, the sample masses were about 1.5 g, and the equilibration interval was 30 s. The duration of each experiment was different: the longest experiment was approximately 20 h, while the shortest experiment was approximately 7.5 h. The pore surface (2–200 nm) areas were calculated from the adsorption curves by employing the Brunauer-Emmett-Teller (BET) model [48], and the pore volumes (2–200 nm) were also obtained from the adsorption curves through the Barrett-Joyner-Halenda (BJH) model [49].

2.2.3. High-Pressure Mercury Injection Experiment (HPMI) The high-pressure mercury injection (HPMI) experiment was performed by using Autopore 9500 from Micromeritics to measure the pore size distribution (5–100,000 nm) according to the China standard GB/T 21650.1-2008. The highest pressure in the HPMI experiment was 230 MPa. Before the experiment, all the shale samples needed to be crushed to about 1 cm3 in volume and dried at 70 ◦C. It should be noted that the HPMI experiment analyzes the pore throat radius instead of the pore diameters.

2.2.4. Methane Adsorption Experiment The methane adsorption experiment was conducted by using a Rubotherm IsoSorp-HP Static II gas adsorption analyzer. All shale samples were tested at 55 ◦C with the pressure ranging from 0–27 MPa. In this experiment, we measured the excess adsorption through the gravimetric method. There are many ways to convert “measured excess adsorbed amount” to “absolute adsorbed amount” and there has been much work on this topic [50]. Considering the density of the adsorbed phase (ρa), Energies 2020, 13, x FOR PEER REVIEW 4 of 24

It should be noted that the HPMI experiment analyzes the pore throat radius instead of the pore diameters.

2.2.4. Methane Adsorption Experiment The methane adsorption experiment was conducted by using a Rubotherm IsoSorp-HP Static II Energiesgas adsorption2020, 13, 1690 analyzer. All shale samples were tested at 55 °C with the pressure ranging from4 0–27 of 23 MPa. In this experiment, we measured the excess adsorption through the gravimetric method. There are many ways to convert “measured excess adsorbed amount” to "absolute adsorbed amount" and we used an adapted three-parameter Langmuir fitting function (Equation (1)) to directly obtain the there has been much work on this topic [50]. Considering the density of the adsorbed phase (ρa), we V P usedLangmuir an adapted volume three-parameter ( L) and the Langmuir Langmuir pressure fitting ( Lfunction)[32,51]. (Equation (1)) to directly obtain the Langmuir volume (VL) and the Langmuir pressure (PL) [32,51]. Vex = V P/(P + P) (1 ρg/ρa), (1) L · L · − Vex=VL·P/(PL + P)·(1 − ρg/ρa), (1) where Vex is the volume of gas excess adsorbed (mL/g STP); P is the equilibrium gas pressure (MPa); where Vex is the volume of gas excess adsorbed (mL/g STP); P is the equilibrium gas pressure (MPa); VL is the Langmuir volume (mL/g STP); PL is the Langmuir pressure (MPa), but many researchers use VL is the Langmuir volume (mL/g STP); PL is the Langmuir1 pressure (MPa), but many researchers use the Langmuir constant (K) instead of it (PL = K− ); ρg is the gas phase density (g/mL); and ρa is the the Langmuir constant (K) instead of it (PL = K−1); ρg is the gas phase density (g/mL); and ρa is the adsorption phase density (g/mL). In this experiment, VL is considered equivalent to the maximum adsorption phase density (g/mL). In this experiment, VL is considered equivalent to the maximum methane adsorption, which can be used to measure the methane adsorption capacity. methane adsorption, which can be used to measure the methane adsorption capacity. 3. Results 3. Results 3.1. Results of the Low-Temperature Carbon Dioxide Adsorption Experiment 3.1. Results of the Low-Temperature Carbon Dioxide Adsorption Experiment Figure1a,b illustrate the results of the low-temperature carbon dioxide adsorption experiment. The relativeFigure 1a,b pressure illustrate (P/P0 the) in results the low-temperature of the low-temperature CO2 adsorption carbon experiment dioxide adsorption is between experiment. 0 and 0.03. TheIt can relative be seen pressure that the (P CO/P0)2 inadsorption the low-temperature volumes of CO these2 adsorption 12 shale samplesexperiment increase is between with 0 increasing and 0.03. Itthe can relative be seen pressure that the (COP/P20 adsorption), and when volumes the relative of these pressure 12 shale is samples 0.03, the increase CO2 adsorbed with increasing volumes the of relativethese 12 pressure shale samples (P/P0), range and when from the 0.5 relative cm3/g to pressure 6.5 cm3/ gis (standard0.03, the CO temperature2 adsorbed andvolumes pressure of these (STP)). 12 3 3 3 shaleSample samples T-5 has range the smallest from 0.5 CO cm2 adsorbed/g to 6.5 cm volume/g (standard (<0.6 cm temperature/g), whereas and samples pressure T-11 (STP)). and T-12 Sample have 3 3 T-5relatively has the high smallest CO2 adsorbed CO2 adsorbed volumes, volume which (<0.6 are more cm /g), than whereas 3 cm /g. samples Moreover, T-11 the and CO 2T-12adsorbed have relativelycapacity of high the otherCO2 adsorbed nine samples volumes, is between which 1 are cm 3more/g and than 2 cm 3 3cm/g.3 The/g. Moreover, reason for the this CO phenomenon2 adsorbed capacitymay be that of the the other TOC contentnine samples of the sampleis between T-5 is1 thecm3 smallest/g and 2 andcm3/g. that The of samplereason T-11for this and phenomenon T-12 is much mayhigher be than that thatthe ofTOC other content samples of the (Table sample1). T-5 is the smallest and that of sample T-11 and T-12 is much higher than that of other samples (Table 1). 2.0 T-1 a 1.8

) T-2 1.6 T-3 T-4

/g STP 1.4 3 T-5

cm 1.2 ( T-6 1.0 0.8 0.6 0.4 Adsorbed volume 0.2 0.0 0.000 0.005 0.010 0.015 0.020 0.025 0.030 Relative pressure (P/P ) 0 Figure 1. Cont.

Energies 2020, 13, 1690 5 of 23 Energies 2020, 13, x FOR PEER REVIEW 5 of 24

7 T-7 b

) 6 T-8 T-9 5 T-10 /g STP 3 T-11 cm ( 4 T-12

3

2

Adsorbed volume volume Adsorbed 1

0 0.000 0.005 0.010 0.015 0.020 0.025 0.030 Relative pressure (P/P ) 0 Figure 1. CarbonCarbon dioxide adsorption isotherms at 0 °C◦C for the 12 shale samples: (a) (a) The first first six shale samples, (b) (b) The last six shale samples. In the low-temperature carbon dioxide adsorption experiment, pores with scales of 0.4–1.1 nm in In the low-temperature carbon dioxide adsorption experiment, pores with scales of 0.4–1.1 nm the shale samples were characterized as shown in Figure2. From the results of Figure2, it can be seen in the shale samples were characterized as shown in Figure 2. From the results of Figure 2, it can be that pores with a scale of 0.5–0.6 nm have the largest incremental pore volumes, and it indicates that seen that pores with a scale of 0.5–0.6 nm have the largest incremental pore volumes, and it indicates there are many pores with a scale of 0.5–0.6 nm in the tested shale samples. Energiesthat there 2020 are, 13, manyx FOR PEER pores REVIEW with a scale of 0.5–0.6 nm in the tested shale samples. 2 of 20 For samples T-11 and T-12, at each stage, their incremental volumes are much larger than those 0.0035 of other shale samples, which is probably due to the much higher TOC content of T-11 and T-12 (Table 1). When the pore width is 0.4–0.7 nm, the incremental volume T-1 of T-2 sample T-5T-3 is the smallest, which 0.0030 T-4 T-5 T-6 may be because T-5 ) has the lowest TOC content (Table 1). The incremental volume of 0.8–1.1 nm

/g T-7 T-8 T-9 pores in T-4, T-8, and3 T-10 is almost 0 cm3/g, indicating that there are no 0.8–1.1 nm pores in these 0.0025 T-10 T-11 T-12 cm shale samples. ( 0.00350.0020 T-1 T-2 T-3 0.0030 T-4 T-5 T-6

) 0.0015

/g T-7 T-8 T-9 3 0.0025 T-10 T-11 T-12

cm 0.0010 ( Incremental volume volume Incremental 0.00200.0005

0.00150.0000 0.4-0.5 0.5-0.6 0.6-0.7 0.7-0.8 0.8-1.1 0.0010 Pore width (nm) Incremental volume Incremental volume Figure 2. PorePore size size0.0005 distribution distribution obtained obtained from from the low-temperature carbon dioxide adsorption experiments for the 12 shale samples. 0.0000 For samples T-11 and T-12, at each stage, their incremental volumes are much larger than those of 3.2. Results of the Low-Temperature0.4-0.5 Nitrogen Adsorption 0.5-0.6 0.6-0.7Experiment 0.7-0.8 0.8-1.1 other shale samples, which is probably due to thePore much width higher (nm) TOC content of T-11 and T-12 (Table1). WhenAs the shown pore widthin Figure is 0.4–0.7 3a,b, when nm, the the incremental relative pressure volume (P of/P sample0) is too T-5 high, is the the smallest, N2 adsorbed which volumes may be 3 3 ofbecause theseFigure T-512 2.shale has Pore the samples size lowest distribution TOCrange content from obtained 2 (Tablecm /gfrom1 ).to The the13 cm incrementallow-temperature/g (STP). volumeSample carbon of T-11 0.8–1.1dioxide has nm theadsorption poressmallest in T-4, N2 adsorbedT-8, andexperiments T-10 volume, is almost for with the 12 0 the cm shale 3reverse/g, samples. indicating being thatthe case there in are sample no 0.8–1.1 T-1. nmThe pores N2 isotherms in these shaleof the samples. 12 shale samples are characterized by H3 and H4 types based on the shape of the hysteresis loops [52]. The adsorption3.2. Results ofisotherms the Low-Temperature and desorption Nitrogen isotherms Adsorption of Experimentall shale samples become very steep under saturated vapor pressure. For samples T-5, T-7, T-11, and T-12, their nitrogen adsorption capacities are relatively small, indicating that the four shale samples’ pore volumes are small and their hysteresis loops are narrow. In particular, the adsorption isotherms and desorption isotherms of samples T-11 and T-12 are basically coincident. This phenomenon may be due to the lowest clay content of the sample T-5 (Table 1). For the samples T-7, T-11, and T-12, with relatively high TOC contents (Table 1), it may be caused by their clay nanostructure being filled with organic matter [53]. Therefore, as mentioned above, sample T-1 has the largest N2 adsorption capacity probably because it has the highest clay content and relatively low TOC content (Table 1). In comparison, the hysteresis loops of other samples are much larger, and their desorption isotherms decrease significantly at a relative pressure of 0.5.

Energies 2020, 13, 1690 6 of 23

3.2. Results of the Low-Temperature Nitrogen Adsorption Experiment

As shown in Figure3a,b, when the relative pressure ( P/P0) is too high, the N2 adsorbed volumes of 3 3 these 12 shale samples range from 2 cm /g to 13 cm /g (STP). Sample T-11 has the smallest N2 adsorbed volume, with the reverse being the case in sample T-1. The N2 isotherms of the 12 shale samples are characterized by H3 and H4 types based on the shape of the hysteresis loops [52]. The adsorption isotherms and desorption isotherms of all shale samples become very steep under saturated vapor pressure. For samples T-5, T-7, T-11, and T-12, their nitrogen adsorption capacities are relatively small, indicating that the four shale samples’ pore volumes are small and their hysteresis loops are narrow. In particular, the adsorption isotherms and desorption isotherms of samples T-11 and T-12 are basically coincident. This phenomenon may be due to the lowest clay content of the sample T-5 (Table1). For the samples T-7, T-11, and T-12, with relatively high TOC contents (Table1), it may be caused by their clay nanostructure being filled with organic matter [53]. Therefore, as mentioned above, sample T-1 has the largest N2 adsorption capacity probably because it has the highest clay content and relatively low TOC content (Table1). In comparison, the hysteresis loops of other samples are much larger, and their desorptionEnergies isotherms 2020, 13, x FOR decrease PEER REVIEW significantly at a relative pressure of 0.5. 3 of 20

14 T-1 a

) 12 T-2 T-3 10 T-4 /g STP 3 T-5 cm ( 8 T-6

6

4

Adsorbed volume 2

0 0.0 0.2 0.4 0.6 0.8 1.0 Relative pressure (P/P ) 0 14 T-7 b

) 12 T-8 T-9 10 T-10 /g STP 3 T-11 cm ( 8 T-12

6

4

Adsorbed volume 2

0 0.0 0.2 0.4 0.6 0.8 1.0 Relative pressure (P/P ) 0 Figure 3. Nitrogen adsorption/desorption isotherms at 196 C for the 12 shale samples: (a) The first Figure 3. Nitrogen adsorption/desorption isotherms at −−196 °C◦ for the 12 shale samples: (a) The first six shalesix samples,shale samples, (b) The(b) The last last six six shale shale samples. samples.

The low-temperature nitrogen adsorption experiment provides information on pores with scales of 2–200 nm in the shale samples (Figure 4a,b). From the results of Figure 4a,b, it can be found that with increasing pore diameter, on the whole, the incremental pore volume increases for all 12 shale samples. It is clear that the pore size distribution curves of the 12 shale samples have two distinct peaks located at approximately 9 nm and 45 nm, as shown in Figure 4. Furthermore, when the pore diameter is 9 nm, sample T-11 has the smallest incremental pore volume, and sample T-1 has the largest incremental pore volume. Similarly, sample T-11 also has the smallest incremental pore volume when the pore diameter is 45 nm. However, the sample T-8 has the largest incremental pore volume at 45 nm.

Energies 2020, 13, 1690 7 of 23

The low-temperature nitrogen adsorption experiment provides information on pores with scales of 2–200 nm in the shale samples (Figure4a,b). From the results of Figure4a,b, it can be found that with increasing pore diameter, on the whole, the incremental pore volume increases for all 12 shale samples. It is clear that the pore size distribution curves of the 12 shale samples have two distinct peaks located at approximately 9 nm and 45 nm, as shown in Figure4. Furthermore, when the pore diameter is 9 nm, sample T-11 has the smallest incremental pore volume, and sample T-1 has the largest incremental Energies 2020, 13, x FOR PEER REVIEW 4 of 20 pore volume. Similarly, sample T-11 also has the smallest incremental pore volume when the pore diameter is 45 nm. However, the sample T-8 has the largest incremental pore volume at 45 nm.

0.0030 T-1 a

) 0.0025 T-2 /g 3 T-3 cm ( T-4 0.0020 T-5 T-6 0.0015

0.0010

Incremental pore volume 0.0005

0.0000 1 10 100 Diameter (nm)

0.0035 T-7 b ) 0.0030 /g T-8 3 T-9 cm ( 0.0025 T-10 T-11 0.0020 T-12

0.0015

0.0010

0.0005 Incrementalvolume pore

0.0000 1 10 100 Diameter (nm)

Figure 4. PoreFigure size 4. distribution Pore size distribution obtained obtained from the from low-temperature the low-temperature nitrogen nitrogen adsorption adsorption experiment for the 12 shalefor samples: the 12 shale (a) Thesamples: first (a) six The shale first samples,six shale samples, (b) The (b) last The sixlast shale six shale samples. samples.

3.3. Results of3.3. the Results High-Pressure of the High-Pressure Mercury Mercury Injection Injection Experiment Experiment As shown in Figure5a–c, the cumulative mercury injection volumes of these 12 shale samples range from 0.0013 cm3/g to 0.0076 cm3/g. The sample T-8 has the smallest cumulative mercury injection volume, and the sample T-12 has the largest cumulative mercury injection volume. It is obvious that the mercury injection curves of all the samples are similar. At the high-pressure stage (>50 MPa), the mercury injection volume increases rapidly with increasing pressure, mainly because there are large amounts of small pores in all the shale samples. Comparably, the mercury extrusion curves

Energies 2020, 13, 1690 8 of 23 of different shale samples are different. Based on the shapes of the mercury injection and extrusion curves, these 12 shale samples can be divided into three groups (Figure5a–c). The hysteresis loops of the shale samples in Figure5a are quite large, especially in the high-pressure stage, which means that the injected mercury is not released when the pressure decreases in the mercury extrusion cycle. Figure5a shows that almost no mercury is released when the extrusion pressure ranges from 200 MPa to 10 MPa (corresponding pore size: 3–75 nm). This result is mainly because the nanopores with scales of 3–75 nm in these shale samples are mainly ink-bottle shaped, and the mercury is not easily released from these pores [54]. The hysteresis loops of the shale samples in Figure5b are smaller than those in Figure5a, which increase gradually with decreasing pressure when the pressure is 10–200 MPa in the mercury extrusion cycle. This result means that the injected mercury is not easily released when the pressure decreases in the mercury extrusion cycle. This result is mainly because some nanopores analyzed at 10–200 MPa (3–75 nm) in these shales are also ink-bottle shaped [54]. The hysteresis loops of the shale samples in Figure5c are the smallest, especially the mercury injection curves, and the mercury extrusion curves are basically coincident when the pressure is 10–200 MPa. This result is mainly becauseEnergies 2020 the, 13 nanopores, x FOR PEER REVIEW analyzed at 10–200 MPa (3–75 nm) in these shales are mainly5 of 20 open pores, and the mercury is easily released from these pores.

0.0030 T-1 a

/g) T-7

3 0.0025 T-8

0.0020

0.0015

0.0010

0.0005 Mercury injection volume (cm

0.0000 0.01 0.1 1 10 100 1000 Pressure (MPa)

0.008 T-4 b 0.007 /g) T-5 3 T-10 0.006 T-11 0.005

0.004

0.003

0.002

0.001 Mercury injection volume (cm Mercury

0.000 0.01 0.1 1 10 100 1000 Pressure (MPa)

Figure 5. Cont.

Energies 2020, 13, x FOR PEER REVIEW 6 of 20 Energies 2020, 13, 1690 9 of 23

T-2 c ) 0.008

/g T-3 3 T-6 cm ( T-9 0.006 T-12

0.004

0.002 Mercury injection volume injection Mercury

0.000 0.01 0.1 1 10 100 1000 Pressure (MPa)

Figure 5. Intrusive mercury curve for the 12 shale samples: (a) The shale samples with quite large hysteresisFigure loops, 5. (b Intrusive) The shale mercury samples curve with for the medium 12 shale hysteresis samples: (a) loops, The shale (c) The samples shale with samples quite withlarge quite small hysteresishysteresis loops. loops, (b) The shale samples with medium hysteresis loops, (c) The shale samples with quite small hysteresis loops. In the high-pressure mercury injection experiment, the pore size distribution of mesopores and In the high-pressure mercury injection experiment, the pore size distribution of mesopores and macroporesmacropores is described is described by the by incremental the incremental pore pore volume volume (Figure (Figure6 6).). It is is obvious obvious that that the themesopores mesopores (2–50 nm)(2–50 contribute nm) contribute the majority the ofmajority the total of porethe total volume pore obtainedvolume obtained by the mercuryby the mercury injection injection experiment for the 12experiment shale samples. for the 12 The shale shale samples. sample The shale T-5 hassamp somele T-5 has macropores some macropores with a with scale a scale of 50–500 of 50– nm, and other500 shale nm, samplesand other haveshale samples fewer of have these fewer pores. of these This pores. finding This finding may be may because be because the T-5the T-5 shale shale sample sample has the highest brittle mineral content (quartz and plagioclase) and the lowest clay content Energieshas the 2020 highest, 13, x FOR brittle PEER mineral REVIEW content (quartz and plagioclase) and the lowest clay content (Table10 of 124). (Table 1). When the pore diameter is 8 or 15 nm, the volume of these pores in all 12 samples is clearly When the pore diameter is 8 or 15 nm, the volume of these pores in all 12 samples is clearly at the at the peak stage. Overall, the pore volumes of the 12 shale samples gradually decrease with at the peak stage. Overall, the pore volumes of the 12 shale samples gradually decrease with peak stage.increasing Overall, pore the diameter. pore volumes In addition, of the the 12 other shale samples, samples including gradually the samples decrease T-1, with T-2, increasingT-3, T-4, T- pore increasingdiameter.5, Inpore T-6, addition, anddiameter. T-9, have the In other some addition, macropores samples, the other including with diameterssamples, the sampleslargerincluding than T-1, 2000 the T-2, samplesnm. T-3,This T-4,phenomenon T-1, T-5, T-2, T-6, T-3, may and T-4, T-9, T- 5,have T-6, some andbe T-9, macroporescaused have by somemicrocracks with macropores diameters that were with largerproduced diameters than during 2000 largersample nm. thanpreparation. This 2000 phenomenon nm. This phenomenon may be caused may by bemicrocracks caused by thatmicrocracks were produced that were during produced sample during preparation. sample preparation.

0.0007 Mesopores T-1 Macropores a ) 0.0006 /g T-2 3 T-3 cm ( 0.0005 T-4 T-5 0.0004 T-6

0.0003

0.0002

0.0001 Incremental pore volume pore volume Incremental

0.0000 1 10 1001000 10,000 100,000 Pore diameter (nm)

Figure 6. Cont.

0.0012 Mesopores T-7 Macropores b )

/g 0.0010 T-8 3 T-9 cm ( T-10 0.0008 T-11 T-12 0.0006

0.0004

0.0002 Incremental pore volume volume pore Incremental

0.0000 1 10 1001000 10,000 100,000 Pore diameter (nm)

Figure 6. Pore size distribution by the high-pressure mercury injection experiment for the 12 shale samples: (a) The first six shale samples, (b) The last six shale samples.

3.4. Methane Adsorption Experimental Data Figure 7 shows the excess methane adsorption data of these shale samples and fitting curves using Equation (1). Moreover, Figure 8 illustrates the absolute methane adsorption data under each pressure of these shale samples. In addition, all the adsorption data in Figure 8 are fitted by the Langmuir equation. The Langmuir volume, indicating the maximum methane adsorption capacity, of all the shale samples ranges from 0.78 cm3/g to 9.26 cm3/g, and the Langmuir pressure ranges from 2.86 MPa to 9.43 MPa. When the pressure is 27 MPa, the excess adsorption volumes of methane in the 12 shale samples are in the range of 0.2–7 cm3/g (Figure 7), and the absolute adsorption volumes of methane range from 0.5 cm3/g to 8.5 cm3/g (Figure 8). The T-5 shale sample always has the smallest excess and absolute adsorption volumes, and T-11 has the largest excess and absolute adsorption volumes. This result may be because the T-5 shale sample has the lowest TOC content and T-11 has the highest TOC content (Table 1).

Energies 2020, 13, x FOR PEER REVIEW 10 of 24 at the peak stage. Overall, the pore volumes of the 12 shale samples gradually decrease with increasing pore diameter. In addition, the other samples, including the samples T-1, T-2, T-3, T-4, T- 5, T-6, and T-9, have some macropores with diameters larger than 2000 nm. This phenomenon may be caused by microcracks that were produced during sample preparation.

0.0007 Mesopores T-1 Macropores a ) 0.0006 /g T-2 3 T-3 cm ( 0.0005 T-4 T-5 0.0004 T-6

0.0003

0.0002

0.0001 Incremental pore volume pore volume Incremental

0.0000 1 10 1001000 10,000 100,000 Pore diameter (nm) Energies 2020, 13, 1690 10 of 23

0.0012 Mesopores T-7 Macropores b )

/g 0.0010 T-8 3 T-9 cm ( T-10 0.0008 T-11 T-12 0.0006

0.0004

0.0002 Incremental pore volume volume pore Incremental

0.0000 1 10 1001000 10,000 100,000 Pore diameter (nm)

Figure 6. Pore size distribution by the high-pressure mercury injection experiment for the 12 shale Figuresamples: 6. (Porea) The size first distribution six shale samples, by the high-pressure (b) The last six mercury shale samples. injection experiment for the 12 shale 3.4. Methanesamples: Adsorption(a) The first Experimentalsix shale samples, Data (b) The last six shale samples.

3.4. MethaneFigure7 Adsorptionshows the excessExperimental methane Data adsorption data of these shale samples and fitting curves using Equation (1). Moreover, Figure8 illustrates the absolute methane adsorption data under each pressure Figure 7 shows the excess methane adsorption data of these shale samples and fitting curves of these shale samples. In addition, all the adsorption data in Figure8 are fitted by the Langmuir using Equation (1). Moreover, Figure 8 illustrates the absolute methane adsorption data under each equation. The Langmuir volume, indicating the maximum methane adsorption capacity, of all the pressure of these shale samples. In addition, all the adsorption data in Figure 8 are fitted by the shale samples ranges from 0.78 cm3/g to 9.26 cm3/g, and the Langmuir pressure ranges from 2.86 MPa Langmuir equation. The Langmuir volume, indicating the maximum methane adsorption capacity, to 9.43 MPa. When the pressure is 27 MPa, the excess adsorption volumes of methane in the 12 shale of all the shale samples ranges from 0.78 cm3/g to 9.26 cm3/g, and the Langmuir pressure ranges from samples are in the range of 0.2–7 cm3/g (Figure7), and the absolute adsorption volumes of methane 2.86 MPa to 9.43 MPa. When the pressure is 27 MPa, the excess adsorption volumes of methane in range from 0.5 cm3/g to 8.5 cm3/g (Figure8). The T-5 shale sample always has the smallest excess the 12 shale samples are in the range of 0.2–7 cm3/g (Figure 7), and the absolute adsorption volumes and absolute adsorption volumes, and T-11 has the largest excess and absolute adsorption volumes. of methane range from 0.5 cm3/g to 8.5 cm3/g (Figure 8). The T-5 shale sample always has the smallest This result may be because the T-5 shale sample has the lowest TOC content and T-11 has the highest excess and absolute adsorption volumes, and T-11 has the largest excess and absolute adsorption TOC content (Table1). volumes.Energies 2020 This, 13, xresult FOR PEER may REVIEW be because the T-5 shale sample has the lowest TOC content and T-118 ofhas 20 the highest TOC content (Table 1). T-1 8 T-2

) T-3 /g 7 3 T-4 cm ( 6 T-5 T-6 5 T-7 T-8 4 T-9 T-10 3 T-11 T-12 2

1 Methane adsorption amount adsorption Methane

0 0 5 10 15 20 25 30 Pressure (MPa)

Figure 7. Excess adsorption of methane at 55 °C◦C in the 12 shale samples, fitted fitted using Equation (1).

T-1 10 T-2 ) T-3 /g 3 T-4 cm

( 8 T-5 T-6 T-7 6 T-8 T-9 T-10 4 T-11 T-12 2 Methane adsorption amount 0 0 5 10 15 20 25 30 Pressure (MPa)

Figure 8. Langmuir isotherms for absolute adsorption of methane at 55 °C in the 12 shale samples.

4. Discussion

4.1. Composition of the Shale Samples with Type III Kerogen Formed in the Marine-Terrigenous Environment

Energies 2020, 13, x FOR PEER REVIEW 8 of 20

T-1 8 T-2

) T-3

/g 7 3 T-4 cm ( 6 T-5 T-6 5 T-7 T-8 4 T-9 T-10 3 T-11 T-12 2

1 Methane adsorption amount adsorption Methane

0 0 5 10 15 20 25 30 Pressure (MPa)

Energies 2020, 13, 1690 11 of 23 Figure 7. Excess adsorption of methane at 55 °C in the 12 shale samples, fitted using Equation (1).

T-1 10 T-2 ) T-3 /g 3 T-4 cm

( 8 T-5 T-6 T-7 6 T-8 T-9 T-10 4 T-11 T-12 2 Methane adsorption amount 0 0 5 10 15 20 25 30 Pressure (MPa)

FigureFigure 8.8. Langmuir isotherms forfor absoluteabsolute adsorptionadsorption ofof methanemethane atat 5555 ◦°CC inin thethe 1212 shaleshale samples.samples. As shown in Figure7, with increasing pressure, the excess adsorption amount of all shale samples 4. Discussion first increases and then decreases, reaching the maximum excess adsorption amount at approximately 144.1. MPa. Composition The absolute of the Shale adsorption Samples isothermals with Type III of Kerogen all shale Formed samples in the increase Marine-Terrigenous with increasing pressure (FigureEnvironment8). 4. Discussion

4.1. Composition of the Shale Samples with Type III Kerogen Formed in the Marine-Terrigenous Environment The depositional environment has significant effects on the composition of shale with different types of kerogen [45,46,55–57]. In addition, for shales with different kerogen types, they have their own relationships between different compositions [34,58–60]. For example, for the Longmaxi shale with type I kerogen in southwest China, some quartz is of biological origin, and shale samples with high TOC contents tend to have larger quartz contents [34]. Figure9a,b show the relationship between the main inorganic mineral constituents (quartz and total clay) and the TOC content, respectively. Due to the wide range of TOC contents in these 12 samples, the relationship between quartz content/total clay content and TOC content is complicated. It is apparent that quartz decreases with increasing TOC content when the TOC is less than 10% (Figure9a). For samples T-11 and T-12, which have high TOC contents, their quartz contents are much lower than those in other samples (Figure9a). Similar conclusions have been made in previous studies; that is, quartz content decreases with increasing TOC content [58]. However, some scholars support different conclusions that quartz content increases with increasing TOC content in marine shales [20,59–61]. This finding may be due to the different origins of quartz in different types of shales. When quartz in shales is biogenic, the TOC content and quartz content tend to be positively correlated, while other shales have an opposite correlation. As for the shales with type III kerogen, many studies have shown that the quartz of them is mainly formed by plants, and there is almost no biological quartz [46,62]. In addition, from Figure9b it is clear that clay minerals have a positive correlation with the TOC content, and the shale samples with relatively high TOC contents (T-11 and T-12) have relatively large clay contents, which are larger than 70%. Based on the study by Ma et al., the clay minerals have a large adsorption capacity [63], and these clay minerals adsorb some organic matter during the deposition process [64,65]. Thus, clay minerals and organic matter are often deposited together. Energies 2020, 13, 1690 12 of 23

Energies 2020, 13, x FOR PEER REVIEW 9 of 20

45 a

40

35

30 Quartz (%) High TOC content 25

20

0 5 10 15 20 25 30 35 40 TOC (%) 75 b

70

65 High TOC content

60

55 Total clay (%)

50

45

0 5 10 15 20 25 30 35 40 TOC (%) FigureFigure 9. ( 9.a) ( Relationshipa) Relationship between between quartz quartz content content and and TOC TOC content; content; and and (b) ( relationshipb) relationship between between total total clayclay content content and and TOC TOC content. content.

4.1.1.4.1.1. Compositional Compositional Influence Influence on theon the Micropores Micropores (0.4–1.1 (0.4–1.1 nm) nm) Obtained Obtained by the by Low-Temperaturethe Low-Temperature CO2 Adsorption Experiment CO2 Adsorption Experiment The relationship between the pore volume of pores with scales of 0.4–1.1 nm, which is characterized by the low-temperature CO2 adsorption experiment, and the TOC content is shown in Figure 10a. It can be seen that there is a significant positive correlation between the pores (0.4–1.1 nm) and the TOC content. This finding means that organic matter provides most of the pores with scales of 0.4–1.1 nm in the shale with type III kerogen. Similar results have also been found in shales with type I kerogen based on previous studies [13,20,34]. For all types of shales, organic matter is the major contributor to the pores with scales of 0.4–1.1 nm. As Figure 10b shows, when the quartz content is low (approximately 20%), the volume of pores (0.4–1.1 nm) is large. In contrast, the pore volume is small when the quartz content is higher than 25%, and there is no apparent trend between the pore volume and the quartz content. Figure 10c shows the relationship between the volume of the pores (0.4–1.1 nm) and the total clay content. For samples T-11 and T-12, which have high TOC contents and high total clay contents

Energies 2020, 13, 1690 13 of 23

(Table1), their volumes of pores (0.4–1.1 nm) are larger than 0.005 cm 3/g. However, the pore volumes of other samples are smaller than 0.003 cm3/g, and there is no obvious trend between the pore volumes and the total clay contents. This finding means that quartz and clay minerals have no significant effect on the development of pores (0.4–1.1 nm) in shale with type III kerogen. For the samples T-11 and T-12,

Energiesthe high 2020 pore, 13, x volumes FOR PEER are REVIEW provided mostly by organic matter. 10 of 20

0.010 a ) /g 3

cm 0.008 (

0.006 y = 0.000212 x + 0.000916 R2=0.9735

0.004

0.002 Volumepores of (0.4-1.1 nm) 0.000 0 5 10 15 20 25 30 35 40 TOC (%) 0.010

) b /g 3

cm 0.008 (

Low quartz content 0.006

0.004

0.002 Volume of pores (0.4-1.1 nm) 0.000 20 25 30 35 40 45 Quartz content (%) 0.010 Figure 10. Cont. c ) /g 3

cm 0.008 ( High TOC content and high total clay content 0.006

0.004

0.002 Volume of pores (0.4-1.1 nm) (0.4-1.1 pores of Volume 0.000 45 50 55 60 65 70 75 Total clay (%)

Energies 2020, 13, x FOR PEER REVIEW 10 of 20

0.010 a ) /g 3

cm 0.008 (

0.006 y = 0.000212 x + 0.000916 R2=0.9735

0.004

0.002 Volumepores of (0.4-1.1 nm) 0.000 0 5 10 15 20 25 30 35 40 TOC (%) 0.010

) b /g 3

cm 0.008 (

Low quartz content 0.006

0.004

0.002 Volume of pores (0.4-1.1 nm) 0.000 Energies 2020, 13, 1690 20 25 30 35 40 45 14 of 23 Quartz content (%) 0.010 c ) /g 3

cm 0.008 ( High TOC content and high total clay content 0.006

0.004

0.002 Volume of pores (0.4-1.1 nm) (0.4-1.1 pores of Volume 0.000 45 50 55 60 65 70 75 Total clay (%)

Figure 10. (a) Relationship between volume of pores (0.4–1.1 nm) by the low-temperature CO2 adsorption experiment and TOC content; (b) relationship between volume of pores (0.4–1.1 nm) by the

low-temperature CO2 adsorption experiment and quartz content; and (c) relationship between volume of pores (0.4–1.1 nm) by the low-temperature CO2 adsorption experiment and total clay content.

4.1.2. Compositional Influence on the Mesopores (2–50 nm) and Macropores (50–200 nm) Obtained by the Low-Temperature N2 Adsorption Experiment As Figure 11a shows, the specific surface area of pores (2–200 nm), which is characterized by the low-temperature N2 adsorption experiment, decreases with increasing TOC content when the TOC content is less than 10%, while the samples (T-11 and T-12) that have high TOC contents (>10%) have smaller specific surface areas. Figure 11b shows the relationship between the specific surface area of pores (2–200 nm) and the quartz content. It is clear that the specific surface area is small for samples with low quartz contents (approximately 20%), while the specific surface area is large when the quartz content is higher than 25%, and it decreases with increasing quartz content. The relationship between the specific surface area of pores (2–200 nm) and the clay content is shown in Figure 11c. The specific surface area is small for samples with high TOC contents and high total clay contents. However, the specific surface area is large for other samples, and it increases with increasing total clay content. It is apparent that clay matter provides most of the pores with scales of 2–200 nm, while organic matter and quartz may inhibit the development of pores (2–200 nm) in shale with type III kerogen.

4.1.3. Compositional Influence on the Mesopores (5–50 nm) and Macropores (50–100,000 nm) Obtained by the HPMI Experiment The relationship between the pore volume of pores with a scale of 5–100,000 nm, which is characterized by the HPMI experiment, and the TOC content is shown in Figure 12. The pore volume (5–100,000 nm) decreases with increasing TOC content when the TOC is less than 10%. However, the samples T-11 and T-12 with high TOC contents have relatively larger pore volumes (5–100,000 nm), which are larger than the pore volumes of the other samples. This result means that organic matter inhibits the development of pores (5–100,000 nm) in shale with type III kerogen. Energies 2020, 13, 1690 15 of 23

Energies 2020, 13, x FOR PEER REVIEW 12 of 20 ) /g 2

m 0.020 ( a 0.018

0.016 Specific surface area decreases with 0.014 increasing TOC content when the TOC is less than 10% 0.012

0.010

0.008 High TOC content 0.006

0.004

0.002

Specific surface area of pores (2-200 nm) 0 5 10 15 20 25 30 35 40 TOC (%) ) /g 2

m 0.020 ( b 0.018

0.016

0.014

0.012

0.010

0.008

0.006 Low quartz content 0.004

0.002

Specific surface area of pores (2-200 nm) surfacearea of pores (2-200 Specific 20 25 30 35 40 45 Energies 2020, 13, x FOR PEER REVIEW Quartz content (%) 13 of 20 ) /g 2 m ( 0.020 c

0.018

0.016

0.014

0.012

of pores (2-200 nm) nm) (2-200 of pores 0.010

0.008 High TOC content and high total clay content 0.006

0.004

0.002 45 50 55 60 65 70 75 Specific surface area Total clay (%) Figure 11.Figure(a) Relationship 11. (a) Relationship between between specific specific surface surface area area of ofpores pores (2–200 (2–200 nm) by nm) the low-temperature by the low-temperature N2 adsorption experiment and TOC content; (b) relationship between specific surface area of pores N adsorption experiment and TOC content; (b) relationship between specific surface area of pores 2 (2–200 nm) by the low-temperature N2 adsorption experiment and quartz content; and (c) relationship (2–200 nm)between by the specific low-temperature surface area of Npore2 adsorptions (2–200 nm) by experiment the low-temperature and quartz N2 adsorption content; experiment and (c) relationship between specificand total surfaceclay content. area of pores (2–200 nm) by the low-temperature N2 adsorption experiment and total clay content. 4.1.3. Compositional Influence on the Mesopores (5–50 nm) and Macropores (50–100,000 nm) Obtained by the HPMI Experiment

0.008 ) /g 3 0.007 cm ( 0.006 High TOC content 0.005

0.004

0.003 Pore volume decreases with increasing TOC content when the TOC is less 0.002 than 10%

0.001

Volume of pores (5-100000 nm) 0.000 0 5 10 15 20 25 30 35 40 TOC (%)

Figure 12. Relationship between volume of pores (5–100,000 nm) by the high-pressure Hg injection experiment and TOC content.

4.2. Compositional Effects on Methane Adsorption Capacity in Shale with Type III Kerogen

Energies 2020, 13, x FOR PEER REVIEW 16 of 24 ) /g 2 m ( 0.020 c

0.018

0.016

0.014

0.012

0.010

0.008 High TOC content and high total clay content 0.006

0.004

0.002 45 50 55 60 65 70 75 Specific surface area of pores (2-200 nm) Specific surface Total clay (%) Figure 11. (a) Relationship between specific surface area of pores (2–200 nm) by the low-temperature

N2 adsorption experiment and TOC content; (b) relationship between specific surface area of pores (2–200 nm) by the low-temperature N2 adsorption experiment and quartz content; and (c) relationship

between specific surface area of pores (2–200 nm) by the low-temperature N2 adsorption experiment and total clay content.

4.1.3. Compositional Influence on the Mesopores (5–50 nm) and Macropores (50–100,000 nm) Obtained by the HPMI Experiment The relationship between the pore volume of pores with a scale of 5–100,000 nm, which is characterized by the HPMI experiment, and the TOC content is shown in Figure 12. The pore volume (5–100,000 nm) decreases with increasing TOC content when the TOC is less than 10%. However, the samples T-11 and T-12 with high TOC contents have relatively larger pore volumes (5–100,000 nm), whichEnergies are2020 larger, 13, 1690 than the pore volumes of the other samples. This result means that organic matter16 of 23 inhibits the development of pores (5–100,000 nm) in shale with type III kerogen.

0.008 ) /g 3 0.007 cm ( 0.006 High TOC content 0.005

0.004

0.003 Pore volume decreases with increasing TOC content when the TOC is less 0.002 than 10%

0.001

Volume of pores (5-100,000 nm) 0.000 0 5 10 15 20 25 30 35 40 TOC (%)

FigureFigure 12. 12. RelationshipRelationship between between volume volume of of pores pores (5–100, (5–100,000000 nm) nm) by by the the high-pressure high-pressure Hg Hg injection injection experimentexperiment and and TOC TOC content. content. 4.2. Compositional Effects on Methane Adsorption Capacity in Shale with Type III Kerogen

From the results presented in Figure 13a, the relationship between methane adsorption capacity and TOC content for the 12 shale samples can be divided into three stages. The Langmuir volume increases extremely quickly with increasing TOC content when the TOC content is less than 1.4%. Then, the Langmuir volume increases very slowly with increasing TOC content when the TOC content is 1.4–4.5%. Finally, the Langmuir volume increases with increasing TOC content when the TOC is more than 4.5%, but the speed of the increase is not as fast as that in the first stage. Overall, the Langmuir volume increases with increasing TOC content. This similar phenomenon has also been reported in other studies [18,21,26–28,30], which suggests that there is a very strong correlation between Langmuir methane adsorption capacity and TOC content. Therefore, an increase in TOC content helps to improve the methane adsorption capacity. Since an increasing TOC content has no significant effect on the methane adsorption capacity when the TOC content is 1.4–4.5%, several shale samples corresponding to this stage are analyzed separately. These samples have low quartz contents and high clay mineral contents. The relationship between methane adsorption capacity and quartz content or total clay content for these shale samples is shown in Figure 13b,c. The quartz content is negatively correlated with the Langmuir volume (Figure 13b), while the total clay mineral content is positively correlated with the Langmuir volume (Figure 13c). Some scholars support similar conclusions and also agree that methane adsorption capacity increases with decreasing quartz content or increasing total clay content [25,31,32]. The results as proposed above, indicate that the TOC content contributes less to the methane adsorption capacity when the TOC content is 1.4–4.5%. At the same time, the methane adsorption capacity is affected by the quartz content and the clay mineral content. However, the inhibition of methane adsorption capacity by quartz and the promotion of methane adsorption capacity by clay minerals cancel each other out. As a result, the methane adsorption capacity does not change significantly. Studies have shown that organic matter and clay minerals are tightly integrated at nanometer scales [64,65] and organic matter is adsorbed on the internal surface of clay minerals to form organoclay aggregates [66]. This phenomenon may be due to organic matter and clay minerals being deposited together to form the organoclay aggregates, which reduce the adsorption capacity of organic matter to methane when the TOC content is 1.4–4.5%. Energies 2020, 13, 1690 17 of 23 Energies 2020, 13, x FOR PEER REVIEW 14 of 20

10 a

) 8

/g 1 23 3 cm ( 6

4

Langmuir volume 2

0 0 5 10 15 20 25 30 35 40 TOC (%)

2.50 2.50

) b ) c /g /g

3 2.45 3 2.45 cm cm ( 2.40 ( 2.40

2.35 2.35

2.30 2.30

2.25 2.25 Langmuir volume Langmuir volume 2.20 2.20 24 28 32 36 40 44 50 55 60 65 70 75 Quartz content (%) Total clay (%)

Figure 13. (a) Relationship between methane methane adsorption adsorption capacity capacity and and TOC TOC content for the 12 shale samples; ((bb)) relationship relationship between between methane methane adsorption adsorption capacity capacity and quartzand quartz content content for the shalefor the samples shale sampleswhose TOC whose content TOC iscontent 1.4–4.5%; is 1.4%–4.5%; and (c) relationship and (c) relationship between methane between adsorptionmethane adsorption capacity andcapacity total andclay total content clay for content the shale for samplesthe shale whosesamples TOC whose content TOC is content 1.4–4.5%. is 1.4–4.5%. 4.3. Nanopore Effect on Methane Adsorption Capacity in Shale with Type III Kerogen 4.3. Nanopore Effect on Methane Adsorption Capacity in Shale with Type III Kerogen The relationship between methane adsorption capacity and nanopores is shown in Figures 14–16. The relationship between methane adsorption capacity and nanopores is shown in Figures 14– As Figure 14 shows, there is an excellent correlation between the Langmuir volume and the volume 16. As Figure 14 shows, there is an excellent correlation between the Langmuir volume and the of pores (0.4–1.1 nm) by the low-temperature carbon dioxide adsorption experiment (R2 = 0.9876). volume of pores (0.4–1.1 nm) by the low-temperature carbon dioxide adsorption experiment (R2 = The Langmuir volume is relatively discrete when the pore volume is less than 0.0025 cm3/g (R2 = 0.8038). 0.9876). The Langmuir volume is relatively discrete when the pore volume is less than 0.0025 cm3/g The relationship between methane adsorption capacity and specific surface area of pores (2–200 nm) (R2 = 0.8038). The relationship between methane adsorption capacity and specific surface area of pores for the 12 shale samples by the low-temperature nitrogen adsorption experiment is shown in Figure 15 (2–200 nm) for the 12 shale samples by the low-temperature nitrogen adsorption experiment is shown and can be divided into two stages. The Langmuir volume decreases rapidly as the specific surface area in Figure 15 and can be divided into two stages. The Langmuir volume decreases rapidly as the increases when the specific surface area is less than 0.0012 m2/g. Then, the Langmuir volume begins specific surface area increases when the specific surface area is less than 0.0012 m2/g. Then, the to decrease slowly when the specific surface area is greater than 0.0012 m2/g. The Langmuir volume Langmuir volume begins to decrease slowly when the specific surface area is greater than 0.0012 decreases with increasing pore volume (5–100,000 nm), which is analyzed by the HPMI experiment m2/g. The Langmuir volume decreases with increasing pore volume (5–100,000 nm), which is analyzed by the HPMI experiment for the shale samples with low TOC contents. For the samples T- 11 and T-12, which have high TOC contents, their pore volume and Langmuir volume are large at the same time (Figure 16).

EnergiesEnergies 20202020,, 13,, x 1690 FOR PEER REVIEW 1518 of of 20 23

Therefore, the development of micropore (0.4–1.1 nm) volume could increase the methane for the shale samples with low TOC contents. For the samples T-11 and T-12, which have high TOC adsorptionEnergies 2020, 13capacity., x FOR PEER Some REVIEW scholars have drawn similar conclusions that micropore volume15 ofand 20 contents, their pore volume and Langmuir volume are large at the same time (Figure 16). micropore surface area are the main influencing factors of methane adsorption capacity[13]. Therefore, the development of micropore (0.4–1.1 nm) volume could increase the methane Therefore, the development of micropore (0.4–1.1 nm) volume could increase the methane adsorption capacity.10 Some scholars have drawn similar conclusions that micropore volume and adsorption capacity. Some scholars have drawn similar conclusions that micropore volume and micropore surface area are the main influencing factors of methane adsorption capacity [13]. micropore surface area are the main influencing factors of methane adsorption capacity[13].

10 8 )

/g y=961.94717x+0.70285 3

cm 8 ( 6 R2=0.9876

) 3

/g y=961.94717x+0.70285 3 cm ( 6 2 4 R =0.9876 23 Langmuir volume 2 4 R =0.8038 2 12 y=1085.314x+0.53565 Langmuir volume 0.000 0.001R2=0.8038 0.002 2 0 1 y=1085.314x+0.53565 0.000 0.002 0.004 0.006 0.008 0.010 Volume of pores (0.4-1.10.000 nm) (cm3 0.001/g) 0.002 0 0.000 0.002 0.004 0.006 0.008 0.010 Figure 14. Relationship between methane adsorption capacity and pore volume (0.1–1.1 nm) for the Volume of pores (0.4-1.1 nm) (cm3/g) 12 shale samples by the low-temperature carbon dioxide adsorption experiment. Figure 14. Relationship between methane adsorption capacity and pore volume (0.1–1.1 nm) for the Figure12 shale 14. samples Relationship by the between low-temperature methane carbonadsorption dioxide capa adsorptioncity and pore experiment. volume (0.1–1.1 nm) for the 12 shale samples by the low-temperature carbon dioxide adsorption experiment. 10

108 ) /g 3 cm ( 68 ) /g 3 cm ( 46 Langmuir volume 24

Langmuir volume 02 0.004 0.008 0.012 0.016 0.020 Specific surface area of pores (2-200 nm) (m2/g) 0 Figure 15. Relationship between0.004 methane 0.008 adsorption 0.012 capacity 0.016 and specific 0.020 surface area of pores Figure(2–200 15. nm) Relationship for the 12 shale between samples methane by the adsorption low-temperature capacity nitrogen and specific adsorption surface experiment. area of pores (2– Specific surface area of pores (2-200 nm) (m2/g) 200 nm) for the 12 shale samples by the low-temperature nitrogen adsorption experiment.

Figure 15. Relationship between methane adsorption capacity and specific surface area of pores (2– 200 nm) for the 12 shale samples by the low-temperature nitrogen adsorption experiment.

EnergiesEnergies 20202020,, 13,, x 1690 FOR PEER REVIEW 2019 of of 24 23

10

) 8 /g 3 cm ( High TOC content 6

4

Langmuir volume volume Langmuir 2

0 0.001 0.002 0.003 0.004 0.005 0.006 0.007 0.008 Volume of pore (5-100,000 nm) (cm3/g)

Figure 16. Relationship between methane adsorption capacity and volume of pores (5–100,000 nm) for Figure 16. Relationship between methane adsorption capacity and volume of pores (5–100,000 nm) the 12 shale samples by the high-pressure mercury injection experiment. for the 12 shale samples by the high-pressure mercury injection experiment. 5. Conclusions 5. Conclusions The effect of nanostructure on methane adsorption of shale with type III kerogen was analyzed usingThe high-pressure effect of nanostructure mercury injection, on methane low-temperature adsorption nitrogenof shale with adsorption, type III low-temperature kerogen was analyzed carbon usingdioxide high-pressure adsorption, and mercury methane injection, adsorption. low-temp This studyerature draws nitrogen the following adsorption, conclusions: low-temperature carbon(1) dioxide The content adsorption, of clay and minerals methane in adsorption shale samples. This study with typedraws III the kerogen following is relativelyconclusions: high. Organic(1) The matter content and of clay clay minerals mineralsare in shale deposited samples simultaneously with type III kerogen in these is shale relatively samples. high. When Organic the matterTOC content and clay>10%, minerals the clay are deposited minerals contribute simultaneous morely thanin these 70% shale of the samples. total inorganic When the matter. TOC content >10%,(2) the Micropores clay minerals are mainlycontribute formed more in than organic 70% matter. of the total With inorganic increasing matter. TOC content, the micropore volume(2) Micropores increases linearly. are mainly Clay mineralsformed in and organic other matte inorganicr. With matter increasing have weak TOC influences content, the on microporesmicropore volumein shale withincreases type IIIlinearly. kerogen. Clay minerals and other inorganic matter have weak influences on micropores(3) The in N shale2 adsorption with type experimental III kerogen. results show that pores with scales of 2–200 nm are mainly affected(3) The byclay N2 adsorption minerals. With experimental increasing results clay mineral show that content, pores their with surface scales of area 2–200 tends nm to are increase. mainly affected(4) Itby was clay found minerals. that With the methane increasing adsorption clay mineral capacity content, of shaletheir surface samples area with tends type to III increase. kerogen is mainly(4) It was controlled found bythat organic the methane matter. adsorption In addition, capa claycity minerals of shale havesamples some with influence type III on kerogen methane is mainlyadsorption controlled capacity. by organic When TOCmatter. content In addition, is <1.4% clay or minerals>4.5%, thehave methane some influence adsorption on methane capacity adsorptionincreases linearly capacity. with When increasing TOC cont TOCent content.is <1.4% or However, >4.5%, the when methane the TOC adsorption content capacity is in the increases range of linearly1.4–4.5%, with clay increasing minerals haveTOC ancontent. obvious However, influence when on the the methane TOC content adsorption is in the capacity. range Atof this1.4–4.5%, stage, claywith minerals increasing have clay an mineral obvious content, influence the methaneon the methane adsorption adsorption capacity increases,capacity. andAt this with stage, increasing with increasingquartz content, clay themineral methane content, adsorption the methane capacity adso decreases.rption capacity increases, and with increasing quartz content, the methane adsorption capacity decreases. Author Contributions: Conceptualization, Y.H., Y.Z., Y.L. and Y.W.; Data curation, Y.H. and Y.L.; Formal analysis, AuthorY.H.; Funding Contributions: acquisition, Conceptualization, Y.Z.; Investigation, Y.H., Y.H., Y.L.,Y.Z., H.Z.Y.L. andand W.Y.; Y.W.; Supervision, Data curation, Y.Z. andY.H. Y.W.; and Validation, Y.L.; Formal Y.H. analysis,and Y.L.; Writing—originalY.H.; Funding acquisition, draft, Y.H. Y.Z.; All authors Investigation, have read Y.H., and Y.L., agreed H.Z. to and the publishedW.Y.; Supervision, version of Y.Z. the manuscript. and Y.W.; Validation,Funding: This Y.H. work and wasY.L.; supported Writing—original by the ’Fundamental draft, Y.H. Research Funds for the Central Universities’ programme Funding:(No. 2017CXNL03). This work was supported by the 'Fundamental Research Funds for the Central Universities' programmeAcknowledgments: (No. 2017CXNL03).The authors are sincerely thankful for the financial support. And the authors wish to thank Xiaowei Hou fou helping with the improving the grammar and readability of this paper. Acknowledgments: The authors are sincerely thankful for the financial support. And the authors wish to thank Conflicts of Interest: The authors declare no conflict of interest. Dr. Xiaowei Hou fou helping with the improving the grammar and readability of this paper.

Conflicts of Interest: The authors declare no conflict of interest.

Energies 2020, 13, 1690 20 of 23

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