Effect of Organic Matter and Maturity on Pore Size Distribution and

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Effect of Organic Matter and Maturity on Pore Size Distribution and Gas Storage Capacity in High-Mature to Post-Mature Shales Xianglu Tang,†,‡,§ Zhenxue Jiang,*,†,‡ Shu Jiang,*,§ Pengfei Wang,†,‡ and Caifu Xiang† †

State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China Unconventional Natural Gas Research Institute, China University of Petroleum, Beijing 102249, China § Energy and Geoscience Institute, University of Utah, Salt Lake City, Utah 84108, United States ‡

ABSTRACT: Pore structure is the key to understanding the shale gas accumulation mechanism. The effects of organic matter and maturity on pore size distribution and gas storage capacity in high-mature to post-mature shales are analyzed using gas adsorption (CO2, N2, and CH4), mercury intrusion porosimetry (MIP), and helium ion microscopy (HIM) for the Silurian Longmaxi and Cambrian Niutitang marine shales in southern China. The results show that the pores of high-mature Longmaxi shales with 2.32−2.42% Ro (vitrinite reflectance equivalent) are primarily composed of mesopores and macropores, whereas the pores of post-mature Niutitang shales with 3.49−3.66% Ro are primarily composed of mesopores and micropores. Organic matter clearly has a positive contribution to the micropore and mesopore development. In addition, increasing maturity appears to lower total porosity for post-mature shales, which has a lower total pore volume than that of high-mature shales. The free gas storage capacity of high-mature shales is controlled by the mesopores and macropores, whereas the free gas storage capacity of post-mature shales is controlled by the mesopores and micropores. The adsorbed gas storage capacity for both high-mature and post-mature shales is primarily controlled by the micropores.

1. INTRODUCTION Pore structure characteristics, including pore size, volume, surface area, shape, connectivity, and spatial distribution, significantly influence shale gas enrichment and migration.1 Shale gas, in its three primary forms of free gas, adsorbed gas, and dissolved gas, is stored in and produced from shale reservoirs.2 The pore volume of shale directly influences the free gas storage capacity and the surface area of shale directly influences the adsorbed gas storage capacity.3 Understanding the pore volume and surface area is critical to the study of shale gas storage capacity and gas enrichment mechanisms.4 In recent years, many qualitative and quantitative techniques have been used to study the pore structures of shales.5,6 The qualitative methods primarily include polarizing microscopy, field emission scanning electron microscopy, and atomic force microscopy.7,8 The quantitative methods primarily include low temperature gas adsorption (N2 and CO2), mercury intrusion porosimetry (MIP), small-angle and ultrasmall-angle neutron scattering (SANS and USANS), and nano-CT.9,10 Because shales have a wide range of pore sizes, a variety of technical methods are needed to comprehensively understand shale pore size distributions.11 The content and storage capacity of adsorbed gas are primarily obtained by CH4 adsorption experiments.12 The content and storage capacity of free gas are primarily obtained by pore volume calculation.13 The International Union of Pure and Applied Chemistry (IUPAC) has divided pores into micropores (50.0 nm).14 Many quantitative studies of shale pores have been conducted.15−17 No single method can obtain the full range pore size distribution at present. The only way is to use segmented tests and then combine them together to characterize the full range pore size distribution. © XXXX American Chemical Society

Many of the North American gas shales are low-mature to mature shales, e.g., Antrim shale, Barnett shale, and New Albany shale, and local areas for Marcellus shale and Haynesville shale may have reached high-mature to post-mature window.18 The organic-rich marine shales in southern China are generally characterized as high-mature to post-mature, with a thermal maturity of greater than 2% Ro (vitrinite reflectance equivalent).19 The organic matter content, kerogen types, mineral composition, and maturity all may affect the pore size distribution.20 As the pores formed during the generation of hydrocarbon, the thermal maturity of shale would affect the pores directly.21 The nanoporosity may increase as the thermal maturity increase.22 With the increasing maturity, the relative proportion of micopores, mesopores, and macropores would change accompaniedly.23 The organic-matter porosity has a clear positive trend with maturity.24 But the pores do not uniformly distribute in the organic matter within less than 1 μm.25 Therefore, the function of each factor cannot explain everything as each factor influences all others. How the pores distribute from micropores to macropores? How the organic matters control the pore size distribution without the effect of mineral composition? How the maturities contribute to the total porosity besides increasing the organic-pores? How the organic matter and maturity effect on the gas storage potential, especially for the free gas and adsorbed gas? These questions still need to be known to understand the shale gas accumulation mechanism. To determine the effects of organic matter and maturity on the pore size distribution and gas storage capacity in high-mature to post-mature shales, marine shale samples with similar mineral Received: June 19, 2016 Revised: August 27, 2016

A

DOI: 10.1021/acs.energyfuels.6b01499 Energy Fuels XXXX, XXX, XXX−XXX

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Figure 1. Map of Sichuan Basin, showing the primary shale gas blocks and well locations. Samples were taken from the Yuye-1, Pengye-1, Jiaoye-1, Chengqian-1, Chengtan-1, and Jinshi-1 wells shown on the map.

Table 1. Maturity, Organic Matter Content, Kerogen Type, Mineral Composition, Rock Density, and CH4 Adsorption Capacity of High-Mature and Post-Mature Shale Samples (LM = Longmaxi, NT = Niutitang)a

a

See Figure 1 for the wells location.

Formation shale with >2.5% Ro was used.27 In this study, a CO2 adsorption experiment was conducted to obtain the micropore distribution characteristics, a N2 adsorption experiment was employed to obtain the mesopore distribution characteristics, and MIP was performed to obtain the macropore distribution. Then, the micropore, mesopore, and macropore

compositions and kerogen types were selected from the Silurian Longmaxi Formation and the Cambrian Niutitang Formation in the Sichuan Basin, China. To distinguish the thermal maturity level of the two formations, the term “high-mature” for the Silurian Longmaxi Fomation shale with 2.0−2.5% Ro was used.26 And the term “post-mature” for the Cambrian Niutitang B


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Figure 2. MIP curves of the high-mature and post-mature shale samples. The pressure ranges from 0 to 413 MPa. (a) The MIP result of high-mature Longmaxi shales and (b) the MIP result of post-mature Niutitang shales. Under a specific relative pressure, the capillary condensation phenomenon would occur in a pore with a specific diameter corresponding to the specific relative pressure.35 The volume of pores with different pore diameters can be obtained by calculating the amount of liquid nitrogen occupying the pores at different relative pressures according to the Barrette−Joynere−Halenda (BJH) method. The shale samples were then used for CO2 adsorption after the N2 adsorption. Before the test, the samples were put into a vacuum drying oven for 2 h to vacuumize. Because the gas desorption tests have no effect on the samples, the pore structure would not be destroyed during the tests. The theory of CO2 adsorption is similar to that of N2 adsorption, but the experimental conditions and interpretation model of the pore volume are different between these two experiments.36 The CO2 adsorption analysis was primarily used to obtain the distribution characteristics of the micropores, whose diameter range is less than 2 nm. Because CO2 can enter a pore whose diameter is 0.35 nm, the distribution of micropores with diameters between 0.35 and 2 nm can be obtained using a pore size analyzer (USA, NOVA4200e) based on the nonlocal density functional theory (NLDFT).37 The sizes of the samples used in the test are about 2 mm. When getting the samples from the core, it should be very careful to avoid microfracture occur. 2.3. Mercury Intrusion Porosimetry (MIP). The samples were further used for MIP test after the N2 adsorption and CO2 adsorption tests since the MIP test is destructive for samples. Before the test, the samples were dried for 2 h at 110 °C to remove any adsorbed water and free water from the sample. An Auto Pore 9500 automatic pressure mercury analyzer was used, with a maximum working pressure of 413 MPa, a pore throat size measurement range of 0.003 to 200,000 nm, and a mercury intrusion measurement accuracy of 0.1 mL. The basic principle of MIP is that when the mercury is injected into the shale, it needs to overcome the capillary resistance, thus the pressure of mercury intrusion corresponds to a certain capillary resistance.38 The pore radius corresponding to a given mercury intrusion pressure can be obtained using the Washburn equation, and then the amount of mercury intrusion in the pore volume corresponding to the pore radius is obtained.39 Therefore, the distribution of the pore volume can be obtained by increasing the pressure and through statistical analysis of the amount of mercury intrusion. The micropores and mesopores of shale are well developed and have strong heterogeneity, but mercury has difficulty entering the micropores and mesopores and the higher pressure may cause induced fractures, sample deformation, and compression of shale pores, which will affect the results. Thus, MIP is primarily used to analyze macropores. Due to the pore throat size is similar to the pore size in the shale, pore size is used in this study for convenience comparing to and combining with the gas adsorption data. 2.4. Full Pore Size Distribution. Based on the CO2 adsorption, N2 adsorption, and MIP experiments, the pore size distribution can be quantified from the nanometer-scale to the micrometer-scale. The pore size range from CO2 adsorption data is about 0.35−1.5 nm and the pore size range from N2 adsorption data is about 0.4−200.0 nm, while the pore size range from MIP data is about 3.0−120 000.0 nm. Thus, the

sections were combined to obtain the full range pore size distribution. A CH4 adsorption experiment was adopted to measure the shale gas adsorption ability, and data were subsequently analyzed to investigate the effect of the pore size distribution on the gas storage capacity.

2. MATERIALS AND METHODS 2.1. Sample Collection. Marine shale samples from the Silurian Longmaxi Formation and the Cambrian Niutitang Formation were collected from shale gas wells in the Sichuan Basin, China (Figure 1). These two Formations are currently the strata with the highest potential for shale gas exploration in China, and their kerogens are both primarily type I.28,29 To study the function of organic matter and maturity without the influence of minerals, more than 400 samples with mineral composition and TOC content data were screened. The samples and data were obtained from the Chongqing Institute of Geology and Mineral Resources and the Sinopec. Then, 10 samples with similar mineral compositions and different TOC contents were selected for this study (Table 1). These shale samples have similar texture as they are all siliceous shale from deep shelf sedimentary environment. Both the Longmaxi Formation shale samples and Niutitang Formation shale samples have similar diagenesis respectively to avoid its effect on the pores. Finally, the maturity, TOC content, kerogens, mineral composition, rock density, and CH4 adsorption quantity tests were conducted (Table 1). The maturity was determined by testing the pyrobitumen reflectance (Rb) using a fluorescence microscope, LABORLUX 12 POL, and a MPV-3 microphotometer, according to the Chinese Oil and Gas Industry Standard SY/T 5125−1996. Since there is no vitrinite for Cambrian and Silurian rocks, we calculated the Ro based on the Rb according to Jacob’s formula.30 The TOC content was measured using a Leco analyzer, according to the Chinese National Standard GB/ T19145−2003. The quantitative mineral composition was analyzed using shale powders through a Bruker D8-Advance X-ray diffractometer.22 The kerogen type was measured using a Leica DM 4500P polarizing microscope.31 The rock density was measured using an Auto Pore 9500 automatic pressure mercury analyzer.23 The CH4 adsorption capacity was measured using a magnetic suspension balance (MSB) instrument according to the Chinese National Standard GB/T 195602004.32 The samples were crushed to less than 0.25 mm. The test temperature was 30 °C and the highest test pressure was 35 MPa. Furthermore, the helium ion microscopy (HIM) images33 were obtained using a Carl Zeiss Orion Plus at Carl Zeiss NTS to investigate the heterogeneous pore size distribution. The pixel resolution of HIM is 0.5 nm. The acceleration voltage is 10−40 kV. The beam is 0.1−100 pA. 2.2. Gas Adsorption. The N2 adsorption analysis was primarily employed to obtain the distribution characteristics of the shale mesopores. An automated pore size analyzer (USA, Quadrasorb-SI) was used to analyze the distribution of mesopores. The shale pore volume is obtained by calculating the amount of liquid nitrogen occupying the pores based on the capillary condensation mechanism.34 C


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Figure 3. Incremental pore volume of high-mature and post-mature shale samples determined by MIP. (a) The incremental pore volume of high-mature Longmaxi shales and (b) the incremental pore volume of post-mature Niutitang shales.

Figure 4. Pore size distribution of high-mature and post-mature shale samples determined by MIP. (a) The macropore volume of high-mature Longmaxi shales and (b) the macropore volume of post-mature Niutitang shales. pore sizes of the three methods have some overlapping intervals. Due to the N2 adsorption, data are not precise for the micropores and macropores, and the CO2 adsorption data can be used to obtain the pore size from 0.35 to 1.5 nm. Thus, for the pores smaller than 1.5 nm, the CO2 adsorption data was used. For the pores larger than 1.5 nm, the N2 adsorption data were used. Due to the MIP, data are not precise for the mesopores, the low pressure part of MIP data, which corresponding pore size is from 50 to 120 000 nm, was used. Through these data integration and analysis, the full pore size distribution range can be obtained.

are higher than those of samples NT2, NT4, and NT5 at the lowpressure range of 0−0.1 MPa. However, the intrusion volume of sample NT4 is higher than the other samples at the high-pressure conditions, whereas the NT1 and NT2 samples have the lowest intrusion volume. The pore size distributions determined by MIP are shown in Figure 3. The pore sizes are mainly larger than 10 000 nm or smaller than 50 nm. Due to the pores smaller than 50 nm may not be the true pore structure as the high pressure MIP could destroy the pores, the pores larger than 50 nm are recommended to analysis. As shown in Figure 4, the macropore volumes of the various samples are distinctly different. For the high-mature Longmaxi shale, the macropore volumes are primarily contributed by the pores with pore sizes in the ranges of 10 000− 120 000 nm (Figure 4a). The pores with pore diameters greater than 10 000 nm are more developed in samples LM2 and LM3. For the post-mature Niutitang shale, the pore volumes are also primarily contributed by the pores with pore sizes in the ranges of 10 000−120 000 nm (Figure 4b), which is similar to those of the high-mature Longmaxi shale. The macropores are very developed in sample NT1, followed by sample NT3. The pore volumes are similar for samples NT2, NT4, and NT5. 3.2. Mesopore Characterization from N2 Adsorption Data. Pore shape can be reflected by the N2 adsorption/ desorption curve. Based on the classification of De Bore in 1964, the IUPAC summarized four pore types (Type H1, H2, H3, and H4) according to the curve: Type H1 represents regular tubular pores with two open ends; Type H2 represents ink-bottle-shaped pores; Type H3 represents plate-like pores; and Type H4 represents narrow slit-like pores.14 As shown in Figure 5, the

3. RESULTS 3.1. Macropore Characterization from MIP Data. Pore characteristics can be inferred from the MIP curve. As shown in Figure 2, for the high-mature Longmaxi shale (Figure 2a), the injection curves of samples LM1, LM2, LM3, and LM4 were similar. There are two sections: 0−0.1 MPa and 100−410 MPa. The samples receive a majority of the intrusion volume in 0−0.1 MPa pressure increase section, whereas the intrusion volume is small from 0.1 to 100 MPa. This implies that two primary pore sizes in these samples can be separated from the MIP curves. The intrusion volume of sample LM5 was very small under low pressure (0−0.1 MPa), whereas the intrusion volume increased rapidly in the high-pressure range, and the amount increased is far greater than that of the other four samples. This suggests that the pores in sample LM5 are primarily pores into which mercury could be injected at a pressure greater than 100 MPa. For the post-mature Niutitang shale, the injection curves were similar to the curves of the high-mature shale (Figure 2b), for which the injection occurs primarily at 0−0.1 MPa and 100−410 MPa intervals. The intrusion volumes of samples NT1 and NT3 D


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Figure 5. N2 adsorption/desorption isotherms at a low temperature (77 K) for the high-mature and post-mature shale samples. The relative pressure ranges from 0.000003 to 0.994926. (a) The isotherms of high-mature Longmaxi shales and (b) the isotherms of post-mature Niutitang shales.

Figure 6. Pore size distribution of high-mature and post-mature shale samples determined by N2 adsorption. (a) The mesopore volume of high-mature Longmaxi shales and (b) the mesopore volume of post-mature Niutitang shales.

Figure 7. Surface area distribution of high-mature and post-mature shale samples determined by N2 adsorption. (a) The surface area of high-mature Longmaxi shales and (b) the surface area of post-mature Niutitang shales.

high-mature Longmaxi shales and post-mature Niutitang shales are similar. As the relative pressure (P/P0, where P is the equilibrium pressure of the gas in MPa, and P0 is the gas saturation pressure in MPa) increases from 0 to 0.03, the adsorption amounts of all of the samples increase rapidly at first and then increase slowly when the relative pressure is greater than 0.01. CO2 is first adsorbed in small pores and then in larger pores as the relative pressure increases.40 As shown in Figure 9, the micropore distribution curves of high-mature shales are similar to the curves of post-mature shales; they are primarily pores with diameters smaller than 0.7 nm. The pore volume increased rapidly as the diameter increased in the range of 0.3 to 0.7 nm, and the rate of pore volume change

pores in the high-mature to post-mature shales are primarily the aggregates of Type H2 and Type H3, which suggests that the pores are primarily ink-bottle-shaped pores and plate-like pores. The BJH pore size distribution was analyzed based on the adsorption curve. As shown in Figure 6, for the mesopore ranges, the high-mature and post-mature shales primarily have pores with pore diameters smaller than 20 nm. As the pore diameter decreases, the rate of change in the pore volume dramatically increases and the proportion of the pore volume becomes higher. The surface area of the pores is primarily provided by pores with diameters smaller than 10 nm (Figure 7). 3.3. Micropore Characterization from CO2 Adsorption Data. As shown in Figure 8, the CO2 adsorption curves of the E


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Figure 8. CO2 adsorption isotherms for the high-mature and post-mature shale samples. The relative pressure ranges from 0.000147 to 0.028994. (a) The isotherms of high-mature Longmaxi shales and (b) the isotherms of post-mature Niutitang shales.

Figure 9. Pore size distribution of high-mature and post-mature shale samples determined by CO2 adsorption. (a) The micropore volume of highmature Longmaxi shales and (b) the micropore volume of post-mature Niutitang shales.

Figure 10. Surface area distribution of high-mature and post-mature shale samples determined by CO2 adsorption. (a) The surface area of high-mature Longmaxi shales and (b) the surface area of post-mature Niutitang shales.

3.4. Full Range Pore Size Distribution. Figure 11 illustrates the full spectrum of pore size distribution merged from the CO2 adsorption data for micropores, the N2 adsorption data for mesopores, and the MIP data for macropores, which shows that the micropores, mesopores, and macropores are well developed in all shale samples and that the ranges of pore size distribution are wide. The common characteristics of all samples are that they all have three relatively stable peaks, which are 0.3− 0.7 nm, 1.5−10.0 nm, and 10 000−100 000 nm. However, the pore volume of each peak is different. The total pore volume is between 0.0078 and 0.0145 mL/g for high-mature shale samples (Table 2). The micropore volume (with an average of 0.0028 mL/g) accounts for approximately

slows when the diameter is larger than 0.7 nm. This suggests that the pores greater than 0.7 nm in diameter contribute less to the total porosity of the micropores. Thus, the micropore volume is primarily composed of pores with diameters that are less than 0.7 nm. The micropore volume increased appreciably as the TOC content increased. For example, the micropore volume of sample LM5 was approximately 4 times that of the micropore volume of sample LM1. Similarly, the micropore volume of sample NT5 was approximately 3 times that of the micropore volume of sample NT1. The surface area shows a similar trend for the micropore volume (Figure 10). As the TOC increases, the surface area increases for both high-mature shales and postmature shales. F


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Figure 11. Pore size distribution of high-mature and post-mature shale samples. The micropores are determined from CO2 adsorption data, the mesopores from N2 adsorption data, and the macropores from MIP data.

Table 2. Pore Volume, Surface Area, and Porosity of the High-Mature and Post-Mature Shale Samples surface area (m2/g)

pore volume (mL/g)

shale type high-mature shale from Longmaxi Formation

postmature shale from Niutitang Formation

sample ID

TOC (%)

micropore volume

mesopore volume

macropore volume

total pore volume

micropore surface area

mesopore surface area

macropore surface area

total pore surface area

porosity (%)

LM1 LM2 LM3 LM4 LM5 mean NT1 NT2 NT3 NT4 NT5 mean

1.0 2.3 3.2 4.2 5.1 3.2 1.2 2.0 3.4 4.1 5.3 3.2

0.0012 0.0018 0.0026 0.0040 0.0044 0.0028 0.0018 0.0026 0.0035 0.0037 0.0051 0.0033

0.0038 0.0040 0.0049 0.0068 0.0074 0.0053 0.0025 0.0049 0.0050 0.0060 0.0062 0.0049

0.0029 0.0060 0.0039 0.0038 0.0019 0.0037 0.0031 0.0021 0.0028 0.0023 0.0020 0.0025

0.0078 0.0118 0.0113 0.0145 0.0137 0.0118 0.0074 0.0095 0.0113 0.0121 0.0133 0.0107

4.109 6.487 8.213 11.505 14.853 9.033 6.385 8.522 10.433 13.742 15.986 11.013

2.153 2.403 2.915 3.522 3.359 2.870 1.856 2.386 2.428 2.582 3.479 2.546

0.010 0.009 0.007 0.007 0.005 0.008 0.003 0.005 0.005 0.013 0.009 0.007

6.272 8.899 11.135 15.034 18.217 11.911 8.244 10.913 12.866 16.337 19.474 13.566

2.1 3.0 3.1 3.7 3.5 3.1 1.9 2.5 2.8 3.1 3.3 2.7

of 0.0037 mL/g) accounts for approximately 32% (Figure 12a and b; Table 2). Therefore, the mesopores account for the largest contribution to the total pore volume of the high-mature shales,

23% of the total pore volume, the mesopore volume (with an average of 0.0053 mL/g) accounts for the largest proportion of approximately 45%, and the macropore volume (with an average G


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Figure 12. Pore volume and surface area of high-mature and post-mature shale samples. The TOC increases respectively for Silurian Longmaxi shale from LM1 to LM5 and Cambrian Niutitang shale from NT1 to NT5.

Figure 13. Correlation between micropores, mesopores, macropores, and the total pore volumes and TOC content for high-mature and post-mature shale samples.

followed by macropores, and micropores that contribute the least to the total pore volume. The total pore volume is between 0.0074 and 0.0133 mL/g for the post-mature shale samples (Table 2). The micropore volume

(with an average of 0.0033 mL/g) accounts for approximately 30% of the total pore volume, the mesopore volume accounts for the largest proportion of approximately 45% (with an average of 0.0049 mL/g), and the macropore volume (with a relatively H


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Figure 14. HIM images of high-mature and post-mature shale samples. (a) The organic matter is distributed between pyrites of the high-mature Longmaxi shale in sample LM-5. (b) An enlarged image of (a) showing the well-developed organic pores. (c) Many micropores and mesopores combined with macropores in the organic matter, which discernibly enlarged the surface area. (d) The organic matter in the entire morphology of the post-mature Niutitang shale in sample NT-3. (e) Enlarged image of (d). (f) The morphology of micropores and mesopores, enlarged from (d).

mesopores is primarily a factor of the organic matter: as the TOC content increases, the volumes of micropores and mesopores increase. The correlation between macropores and the TOC content is not readily discernible, indicating that the development of macropores is not simply controlled by organic matter. Maybe the mineral composition and rock fabrics have stronger effect on the macropores devolvement than the organic matter.25 It can also be observed from the HIM images that the micropores and mesopores are primarily organic pores (Figure 14). The organic pores are well developed in the organic matters due to the high maturity of the shales.24 However, few inorganic pores are developed and they are generally macropores. Thus, the observed results agree with the measured results of the pore size distribution. Maturity is another important factor affecting the pore size distribution for high-mature to post-mature shales. Compared to the high-mature shale, the ratio of macropores in the post-mature shale is reduced and the ratio of micropores is increased, showing that the pores in those samples were becoming smaller (Table 2). When the TOC content of samples is similar, the total pore volume of post-mature shale is smaller than that of the total pore volume of high-mature shale (Figure 13d). This is maybe due to the post-mature shale having a stronger compaction to weak metamorphism than the high-mature shale,45 leading to a reduction in porosity, especially for the macropores and mesopores.46 4.2. Effects of Pore Size Distribution on Gas Storage Potential. Pores provide a location for shale gas storage, and different pores have different effects on shale gas storage. The shale gas is mainly composed of adsorbed gas and free gas.25 Adsorbed gas is primarily adsorbed on the surface of organic

small volume of 0.0025 mL/g) accounts for approximately 25% (Figure 12a and b; Table 2). Therefore, the mesopores account for the largest contribution to the total pore volume of the postmature shale, followed by micropores, and macropores that contribute the least to the total pore volume. The surface area is primarily contributed by micropores for both high-mature shales and post-mature shales. Mesopores only account for a small portion, and the surface area provided by macropores is negligible (Figure 12c and d; Table 2). Shale porosity is calculated according to the density and total pore volume. The calculated porosity increases as the TOC content increases, and the calculated porosities of high-mature shales are larger than those of post-mature shales (Table 2).

4. DISCUSSION 4.1. Effects of Organic Matter and Maturity on Pore Size Distribution. The organic pores play an important role in the shale pore structure. For the low-mature New Albany shale in US, micropores mainly develop in the organic matter.41 In addition, for the low-mature Yanchang Formation lacustrine shale in China, the organic pores are two times higher than the inorganic pores.42 While for the high-mature Longmaxi Formation shale, organic matter contributes about 29.88% organic pores.26,43 Furthermore, for the post-mature Niutitang Formation shale, organic matter contributes about 35% total pores.44 Therefore, the pore size distribution is primarily caused by the different organic matter contents in the high-post mature shale. As shown in Figure 13, the volumes of micropores and mesopores both have good correlations with the TOC content, demonstrating that the development of micropores and I


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Figure 15. Correlation between adsorbed methane and micropore, mesopore, macropore, and total pore surface area for high-mature and post-mature shale samples.

matter, clays and pores, and free gas is primarily stored in the spaces of shale pores.47 Free gas storage potential is primarily determined by pore volume. The greater the pore volume, the larger the storage capacity for free gas. As shown in Table 2, for the high-mature shale samples, the mesopores provide approximately 45% of the total pore volume, resulting in the largest contribution to the total pore volume. This is followed by macropores, which provide approximately 32% of the total pore volume. The micropores, which contribute little to the total pore volume, provide only approximately 23% of the total pore volume. Therefore, mesopores and micropores are the primary locations for free gas storage in the high-mature shale samples and, therefore, control the storage capability for free gas. For the postmature shale samples, the mesopores provide approximately 45% of the total pore volume, resulting in the largest contribution to the total pore volume. This is followed by micropores, which provide approximately 30% of the total pore volume. The macropores, which contribute little to the total pore volume, providing only approximately 25% of the total pore volume (Table 2). Therefore, the mesopores and micropores are the primary locations for free gas storage in the post-mature shale samples, controlling the storage capability for free gas. Adsorbed gas storage potential is primarily decided by pore surface area of organic matter and clay minerals. The greater the surface area, the larger the storage capacity for adsorbed gas in the high-mature shale.3,48,49 But for the low-mature shale, the pore surface area is not the sole controlling factor of the gas adsorption capacity. Furthermore, the shale with greater micropore volume has greater gas adsorption capacity.49 In addition, the TOC content is the primary controlling factor for the gas adsorption capacity when the Ro is lower than 2.5%.50

As shown in Figure 15, for the high-mature to post-mature shales, the micropore surface area has a good positive correlation with adsorbed methane, and the adsorbed methane amount will gradually increase as the micropore volume increases. The mesopore surface area has a weak correlation with adsorbed methane, and the macropore volume has no obvious correlation with adsorbed methane given the very low surface area value. Furthermore, the correlation between the total pore surface area and adsorbed methane is good. This indicates that micropores and mesopores are the primary storage spaces for adsorbed gas.

5. CONCLUSIONS • For the high-mature to post-mature shales, the micropores, mesopores, and macropores are well developed. The pores of the high-mature shale are primarily mesopores and macropores, and the pores of the postmature shale are primarily mesopores and micropores. • Organic matter has a significant influence on pore development, especially for micropores and mesopores. As the TOC content increases, the micropores and mesopores increase dramatically. Compared to the highmature shale, the post-mature shale has a lower porosity, and the quantity of macropores is low while the quantity of micropores is high. • The mesopores and macropores control the free gas storage capacity of high-mature shales. The micropores and mesopores control the free gas storage capacity of post-mature shales. The micropore surface area controls the adsorbed gas storage capacity for both high-mature shales and post-mature shales, whereas the mesopore surface area has a relatively weak control function. J


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AUTHOR INFORMATION

Corresponding Authors

*E-mail: [email protected]. *E-mail: [email protected]; Tel.: +86(10)89733328. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This research was supported by the National Science and Technology Major Project (No. 2016ZX05034-001) and the National Natural Science Foundation of China (No. 41502123). The authors wish to acknowledge the Chongqing Institute of Geology and Mineral Resources and the Sinopec Group for providing the drill cores used in this study. Thanks to Professor Jijin Yang for the analysis of the HIM.

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