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Abstract

The nanometer-scaled pore systems of gas shale reservoirs have a prominent contribution for gas storage. To obtain information about the characteristics of the nanopore structure within lacustrine organic-rich shales during their thermal evolution, artificial shale samples with different thermal maturities were obtained from a hydrous pyrolysis experiment. Nitrogen adsorption, field emission scanning electron microscopy, and porosity tests were used to investigate the characteristic pore structures of lacustrine shales with different thermal maturities from the Minhe Basin. The results show that the total organic carbon content decreased from 41.89% (unheated) to 27.7% (370℃) and that organic pores, intragranular pores of pyrite, and intergranular pores of clay minerals began to form with an increase in the simulated temperature and pressure. The porosity increased from 3.57% (unheated) to 26.09% (350℃) and then decreased to 20% (370℃) on the whole. The pore sizes were distributed from 1.7 to 500 nm, and the average pore diameter first showed a decreasing trend and then an increasing trend. The cumulative pore volume and cumulative specific surface area both presented a slowly increasing trend from an unheated status to 325℃, exhibited a rapid increase at 350℃, and then showed a slow increase at 370℃. This study could provide a reference for the exploration of shale gas in lacustrine shales with different thermal maturities.

Keywords

Hydrous pyrolysis thermal evolution nanopore structure lacustrine shale Minhe Basin

Introduction

Continental sedimentary basins containing thick, black shale strata are widely distributed throughout China, which makes it possible to form shale gases with immense reservoir potential. In recent years, China has devoted greater efforts toward exploring for these shale gases due to the shale gas revolution in the United States and has made significant breakthroughs in unconventional exploration and development. Large-scale commercial exploitations of shale gases have been achieved in Fuling Prefecture in the Sichuan Basin. The shale pore structure, which is a dominant factor influencing the capacity of an unconventional reservoir (Gregg and Sing, 1982), has become a hot topic in the energy field (Nie et al., 2011; Zou et al., 2012). As ultradense unconventional reservoirs with great complexity and anisotropy, shales have much lower porosities than carbonate reservoirs. Shales are heterogeneous rocks with variations in their structure and composition that exist on many levels from the nanoscale to the macroscale (Curtis et al., 2012). The main channels of a petroleum reservoir and interstitial flow within a shale play are nanometer pores (Yang et al., 2013). Scholars have carried out many related studies on the static characterization of nanoscale porosity in shale reservoirs and have yielded substantial results regarding their pore type, size, shape, spatial distribution, and connectivity (Chalmers et al., 2012; Clarkson et al., 2013; Liang et al., 2014; Loucks et al., 2009; Sun et al., 2015, 2016; Yang et al., 2015). However, studies on the dynamic evolution of nanoscale porosity are relatively lacking. Based on the limited literature, those studies mainly focused on the pore evolution of shale reservoirs in large-scale deposit basins, such as the Sichuan Basin and Ordos Basin, and ignored the evolution of shale reservoirs in small- to moderate-size basins in the northwestern region of China (Chen and Xiao, 2014; Cui et al., 2013; Tang et al., 2015; Wu et al., 2015; Xue et al., 2015). The Minhe Basin is located in northwestern China and has the character of being small but fat oil reservoir. It has an average black shale thickness ranging from 160 to 4000 m and is a shallow shale-favorable area with geological resources and recoverable resources of 2091–8894 × 10⁸ and 210–890 × 10⁸ m³, respectively (Su et al., 2011). However, the degree of shale gas exploration is lower in the Minhe Basin, and a related presentation of the evolution of black shale porosity in the basin is missing from the literature.

In this paper, given the abovementioned facts, we chose the immature oil shales of the Yaojie Fm. in the Minhe Basin as an objective to investigate the evolution of pores with respect to the thermal maturation. Samples with different maturities were obtained through a hydrous pyrolysis experiment. Then, the evolution of the nanopore structure was analyzed using organic geochemistry and petrology with low temperature N₂ adsorption, field emission scanning electron microscopy (FE-SEM), and porosity experiments.

Geological setting

The Minhe Basin lies between the northern Qilian Mountains and Laji Mountains, and it belongs to the eastern Qilian fold belt with an area of 1.13 × 10⁴ km². The Minhe Basin is an inland intermountain basin that developed during the Mesozoic–Cenozoic and is composed of 10 secondary units of five sags and five highs. The primary subsidence zone is comprised of the Yongdeng and Bazhou Sags, both of which are the main sources of hydrocarbons and are the target areas of oil and gas exploration (Figure 1) (Han et al., 2014).

Figure 1.

Map showing the partition of structural elements in the Minhe Basin and the sampling points.

The strata from the bottom to the top are of the Jurassic system (Xiangtang Fm., Yaojie Fm., and Tandonggou Fm.), Cretaceous system (Minhe Fm., Hekou Fm., and Datonghe Fm.), Tertiary system, and Quaternary system. The Jurassic Yaojie Fm., which is a shale reservoir of coal and oil in the Minhe Basin, was deposited at the peak period of rifting of the lacustrine basin. The thickness of the Yaojie Fm. is 110–360 m, the source rock of which is 50–150 m thick and includes black shale, oil shale, carbonaceous mudstone, and coal (Song, 2006). The thickness of the black shale in Tanshanling reaches 50–70 m with a stable distribution. The thickness of the source rock in the main subsidence center of the Minhe Basin reaches 150 m, and the thicknesses of oil shale, coal, and carbonaceous mudstone within the basin reach 30–60, 15–30 m, and less than 10 m, respectively (Figure 2) (Zhang et al., 2015). There are a total of five oil reservoir members of Middle Jurassic age in the Minhe Basin. Comparing the petroleum geochemical parameters (e.g. organic matter abundance, maturity of organic matter, and kerogen type) and the desorption data of the shale gases of the Minhe Basin with those of other oil- and gas-bearing basins in China and elsewhere, the Yaojie Fm. of the Minhe Basin demonstrates great potential for shale gas exploration (Han et al., 2014; Zhang et al., 2015).

Figure 2.

Simplified stratigraphic column for the Yaojie Formation, Minhe Basin.

Materials and methods

Samples

In this study, a block of oil shale sample were collected from the Middle Jurassic 4th Member of the Yaojie Fm. from Tanshanling, Minhe Basin, Gansu Province, Northwest China (Figures 1 and 2). The bulk block samples were collected from an outcrop in an oil shale mine. Prior to hydrous pyrolysis, six identical cylindrical samples with diameters of 25 mm were drilled along same oil-shale layer from the block of outcrop sample to guarantee homogeneous samples, and were labeled TSL-0, TSL-1, TSL-2, TSL-4, TSL-5, and TSL-6, corresponding to different temperature points (unheated, 250, 300, 325, 350, and 370℃, respectively). The original shale was organic rich with a total organic carbon (TOC) of 41.89%. Rock-Eval pyrolysis presented a hydrocarbon index (I_H) of 728 mg/g, an oxygen index (I_O) of 3 mg/g and a T-max of 440℃. The values of the S₁ (dissolved hydrocarbon) and S₂ (pyrolyzed hydrocarbons) peaks were 3.34 and 304.78 mg/g, respectively. The kerogen type for the experiment samples was type I. The vitrinite reflectance (R_O) was approximately 0.53%, and the productivity index equaled 0.01, all of which indicated that the oil shale was immature. The bulk mineral and clay composition of the sample was quartz (36%), feldspar and pyrite (16%), and clay minerals (48%), within which the relative quantities of clay minerals were kaolinite (64%), chlorite (19%), illite (12%), and illite–smectite mixed layers (5%).

Pyrolysis

The pyrolysis experiments were conducted at the Lanzhou Institute of Geology, Chinese Academy of Sciences (LIGCAS) by utilizing a WYMN-3 HTHP simulation instrument, which includes a high temperature–pressure chamber, bilateral hydraulic servo control, automatic hydrocarbon expulsion system, automatic control system, and data collection system (Figure 3), as used by Sun et al. (2015) and Wu et al. (2016). The equipment can simulate confining pressure and fluid pressure through a hydraulic control system and deionized water, respectively, and it can also maintain the isothermal heating of samples with automatic pressure compensation. Once the constant temperature time is complete, the yields of the expelled oil, water, and gaseous hydrocarbons can be collected.

Figure 3.

Schematic diagram of the pyrolysis experimental system.

An open system can be used to quickly determine the hydrocarbon-generating potential of source rocks while only reflecting the primary reaction, which lacks the experimental conditions of pressure and water (Behar et al., 1997; Schenk and Horsfield, 1993). For a closed system, the primary and secondary reactions would be mixed within the system (Dieckmann et al., 2000; Johannes et al., 2009; Sun and Wang, 2000).

A semiopen system can avoid the problems both existing in an open system and a closed system. Therefore, a semiopen system was used to make the experimental conditions more similar to a real, natural system in this paper. The yields of the expelled oil, water, and gaseous hydrocarbons can be ejected to avoid secondary reactions when the cell pressure reaches a set value within a semiopen system. The simulated temperature, time, confining pressure, fluid pressure, and hydrocarbon pressure expulsion threshold were set using a computer. To retain the original pore size, the samples were drilled into core columns with diameters of 25 mm and heights of 5–6 cm, which is a suitable size for a sample cell. The detailed information for the simulated experimental setting is presented in Table 1.

Table 1.

Hydrous pyrolysis simulation experimental conditions and set parameters.

Sample	Temperature (℃)	Simulated depth (m)	Pressure (MPa)		Constant temperature time (h)	Experimental system
Sample	Temperature (℃)	Simulated depth (m)	Fluid pressure	Confining pressure	Constant temperature time (h)	Experimental system
TSL-0	Unheated	1000	–	–	–	–
TSL-1	250	1300	16.9	29.3	72	Semiopen
TSL-2	300	1700	22.1	38.3	72	Semiopen
TSL-4	325	2100	27.3	47.3	72	Semiopen
TSL-5	350	2500	32.5	56.4	72	Semiopen
TSL-6	370	2900	37.7	65.4	72	Semiopen

Analysis of pore structure

Nitrogen adsorption measurements were conducted with an ASAP 2020 HD88 surface area analyzer at the LIGCAS. The lowest detection limits for the specific surface area and pore volume were 0.0005 m²/g and 0.0001 cm³/g, respectively. Before the experiment, the samples were crushed into a 40–60 mesh and extracted with chloroform. The experimental conditions were as follows. Each sample was degassed at 150℃ for 6 h in a vacuum chamber to remove gaseous impurities. Then, a high-purity nitrogen gas was injected into the vacuum sample tube. Isothermal physical absorption–desorption measurements were collected under a low-temperature experimental condition of −197℃ with a relative pressure (P/P₀) range of 0.01–0.998.

The micro-, meso-, and macropore volumes and the pore size distributions were calculated from the nitrogen adsorption isotherms using the Barrett–Joyner–Halenda theory (Clarkson et al., 2012). The evolution of the specific surface areas of the samples from the nitrogen sorption isotherms was determined by a multipoint Brunauer–Emmett–Teller (BET) analysis regression model (equation (1)) (Brunauer et al., 1938) $\frac{P}{V (P_{0} - P)} = \frac{1}{V_{m} C} + \frac{(C - 1) P}{V_{m} {CP}_{0}}$ (1) where V is the volume of the adsorbed gas at equilibrium pressure (cm³/g), P is the balance pressure (Pa), P₀ is the saturation pressure (Pa), V_m is the volume of the monolayer, and C is the BET constant.

Porosity measurements

The porosities of the shale samples were calculated from the bulk density and particle density using equation (2). The measurements of the bulk density (apparent density) and particle density (real density) were performed with an MDMDY-350 automatic density meter at the Sinopec Experimental Research Center-East using the national standards GB/T 23561.2-2009 “Methods for determining the true density of coal and rock” and GB/T23561.3-2009 “Methods for determining the bulk density of coal and rock.” The apparatus is designed using the physicochemical theories of the ideal gas law, gas molecular dynamics, and adsorption and desorption in solid–gas systems. The experimental conditions were set as follows: high purity nitrogen (99.99%) as the load gas, and a pressure of ± 1.3 MPa $φ = (1 - \frac{ρ_{b}}{ρ_{s}}) \times 100 %$ (2) where φ is the porosity, $ρ_{b}$ is the apparent density, and $ρ_{s}$ is the real density.

FE-SEM imaging

The original and simulated samples were analyzed using a FE-SEM made by ZEISS SIGMA. The instrument is a three-in-one system consisting of secondary electron imaging, EBSD, and an X-ray energy spectrum. Argon ion beam milling was employed to produce a much flatter surface, which contributed to observing the pore size, pore shape, pore distribution and pore type, and the mechanism of pore formation.

Results and discussion

Nitrogen adsorption isotherms

Figure 4 shows the nitrogen adsorption–desorption isotherms for the shale samples at different simulation temperatures. We can see that the adsorption curves of the samples with different maturities present slightly differently. The adsorption curves for samples TSL-0, TSL-1, TSL-2, and TSL-4 are not closed, the main reason for this may be the swelling phenomenon (Gregg and Sing, 1982).

Figure 4.

Nitrogen adsorption–desorption isotherms for samples with different simulation temperatures.

According to the classification of gas adsorption isotherms defined by the International Union of Pure and Applied Chemistry (IUPAC) (Figure 5(a)) (Brunauer et al., 1940), the samples with unheated temperatures of 250, 300, and 325℃ are type II, indicating that the samples developed a certain amount of mesopores. Meanwhile, the samples with 350 and 370℃ temperatures are similar to type III, indicating that their pore size distributions were similar to those of macropores due to the volume filling of macropores caused by capillary condensation (Chen et al., 2012). As the simulation temperature increased, the adsorbed nitrogen quantities increased compared to that of the unheated sample up to 370℃ at a relative P/P₀ of 0.9962 MPa, except for at a temperature of 250℃, with adsorbed quantities of 2.02, 2.47, 2.10, 2.27, 44.88, and 58.12 cm³/g.

Figure 5.

Six types of isotherms (a) and four types of hysteresis loops (b).

Because capillary condensation and capillary evaporation often do not occur at the same pressure, there is a detached portion between the corresponding adsorbed and desorbed isotherm branches. The detached parts form hysteresis loops (Gregg and Sing, 1982; Kruk and Jaroniec, 2001; Liu et al., 2005; Yang et al., 2013). Based on the classification (i.e. into five types) of hysteresis loops defined by Boer et al. (1972), the IUPAC recommends the classification of hysteresis loops into four types (Figure 5(b)) (Sing, 2009). Among them, type H3 hysteresis loops are characterized by a small hysteresis loop, which represents isotherm curves that increase slowly at low relative pressures and then increase dramatically at high relative pressures P/P₀ (P represents the balance pressure and P₀ is the saturation pressure). In this paper, the hysteresis loops for the samples are type H3, indicating that the pores developed are irregular and open with good connectivity between intragranular pores with shapes of parallel, slit-like, and open-ended tubes, which is conducive for gas transport and providing space for shale gases.

Response of pore structure parameters to temperature

The detailed pore structure parameters at the different final simulation temperatures are shown in Table 2. The cumulative specific surface area ranged from 1.0503 to 13.9618 m²/g with an average of 5.6134 m²/g. Sun et al. (2015) held that the pore volume and surface area have a positive relationship with temperature with correlation coefficients of 0.91 and 0.83, respectively. The relationship of the specific surface area with the average diameter and cumulative specific surface area is plotted in Figure 6. We can roughly divide the temperatures into three stages. From the unheated sample to 325℃, the cumulative specific surface area increased gradually with peak values that were generally concentrated into a range from 1 to 10 nm (Figure 6(a)), which changed from 0.5 to 2 nm (unheated) to 2 to 10 nm (325℃). From 325 to 350℃, the specific surface area increased rapidly with a peak of 1–2 nm (Figure 6(b)). From 350 to 370℃, the specific surface area increased gradually. The main contributors to the specific surface area are micropores and fine mesopores.

Table 2.

Pore parameters of the shale samples from nitrogen adsorption.

Sample	Specific surface area (m²/g)	Average diameter (nm)	Pore volume (cm³/g)	Pore volume (cm³/g)
Sample	Specific surface area (m²/g)	Average diameter (nm)	Pore volume (cm³/g)	Micropore (2 nm)	Mesopore (2–50 nm)	Macropore (>50 nm)
TSL-0	1.0503	17.4446	0.002948	0.000133	0.001247	0.001568
TSL-1	1.5881	13.8423	0.003509	0.0000792	0.0019069	0.0015229
TSL-2	1.9128	7.997	0.002978	0.000251	0.001104	0.001623
TSL-4	2.7448	6.5601	0.003328	0.000159	0.001567	0.001602
TSL-5	12.4228	23.5063	0.068315	0.000553	0.022493	0.045269
TSL-6	13.9618	23.7172	0.073699	0.001921	0.030627	0.041151

Figure 6.

Differential pore specific surface area versus pore width (a) and the cumulative specific surface areas of the oil shale samples with different maturities (b).

The distributions of the pore volumes and cumulative pore volumes are shown in Figure 7. The cumulative pore volume ranged from 0.0029 to 0.0737 cm³/g with an average of 0.0258 cm³/g. In these samples, the pore size distributions ranged from 1.7 to 500 nm with an average of 15.51 nm. Generally, the pore volumes of the micropores, mesopores, and macropores increased with an increase in the simulated temperature and pressure (Table 2). According to the IUPAC classifications (Gregg and Sing, 1982; Sing, 2009), pores are subdivided into three parts: micropores (pore diameter < 2 nm), mesopores (2 nm < pore diameter < 50 nm), and macropores (pore diameter > 50 nm). From the unheated to the 325℃ samples, the volumes of micropores and fine mesopores (2 nm < pore diameter < 10 nm) showed a slow rise as a whole, while they underwent almost no change for macropores, which indicates that hydrocarbon generation was beginning and produced small amounts of micropores with diameters of 2–10 nm (Figure 7(a)). At 350℃, the volumes of micropores, mesopores, and macropores increased steeply, especially for the macropores, the cumulative volume of which was much higher than those of the previous samples. The pore size distributions for the volume peak were 1–2 and 50–200 nm. The main reason for this may be that the organic pores were connected in the hydrocarbon-generating process, and an induced increase in the pore diameter may influence micropores to become mesopores or macropores, which indicates that the hydrocarbon generation was enhanced. At 370℃, even with further increases of the simulated temperature and pressure, the cumulative pore volume increased gradually, indicating that the sample reached the oil generation peak (Sun et al., 2015). The total cumulative pore volumes and specific areas increased with the temperature (Figure 7(b)), similar to the results obtained by Sun et al. (2015).

Figure 7.

Differential pore volume versus pore width (a) and the cumulative pore volume of the oil shale samples with different maturities (b).

Evolution of porosity with increasing maturity

The results for the measured porosities are shown in Table 3. The results show that the porosity first increased from 3.75% (unheated) to 26.09% (at 350℃) and then decreased to 20.00% (at 370℃) with an increase in the simulated conditions as a whole.

Table 3.

Porosity evolution of the oil shales from Tanshanling.

Samples	TOC (%)	Bulk density (g/cm³)	Particle density (g/cm³)	Porosity (%)
TSL-0	41.89	1.54	1.6	3.75
TSL-1	41.3	1.51	1.59	5.03
TSL-2	39.6	1.57	1.62	3.09
TSL-4	40.9	1.54	1.69	8.88
TSL-5	31.5	1.53	2.07	26.09
TSL-6	27.7	1.76	2.2	20.00

TOC: total organic carbon.

There are three mechanisms that control the pore structure of an organic-rich shale during diagenetic processes: hydrocarbon generation, mechanical compaction, and chemical compaction. The organic pores were formed in the process of hydrocarbon generation (Xue et al., 2015). The intragranular pores and intergranular pores developed due to mechanical compaction. The transformation of the illite–montmorillonite mixed layer into illite and the thermal decomposition of pyrite were controlled by chemical compaction (Cui et al., 2013).

Hydrocarbon-generating evolution of organic matter

The TOC content of the original collected sample reached 41.89% and decreased from 41.89 to 31.5%, which could have been the main contributor for the increased porosity. The hydrocarbon generation of organic matter is one of the factors that influence the increase in the porosity. Jarvie et al. (2007) claimed that the porosity would increase by 4.9% per consumption of 35% of the TOC for a shale with a TOC content of 7.0% and argued that organic carbon decomposition can induce pore development. Loucks et al. (2009) suggested that the pores in the Barnett Shale are mainly on the nanoscale, whose development was controlled by organic matter. Ceng et al. (2014) held that the TOC content is the main factor that controls the development of nanoscale pores because the TOC content has a positive relationship with the BET specific surface area and cumulative volume. The organic pores were poorly developed in the original sample and at 300℃ (Figure 8(a) and (b)). Organic pores began to develop at 325℃ (Figure 8(c)) and were well developed at 370℃ (Figure 8(d)). The main reason for the rapid increase in the porosity was the intense hydrocarbon generation causing organic pore development at 350℃, after which the porosity decreased gradually and the transformed organic matter began to stabilize, resulting in a reduction of the rate of pore development at 370℃.

Figure 8.

Microscopic pore structure characteristics of samples with different simulated conditions. (a) Unheated sample; organic pores were not developed. (b) At 300℃, organic pores were not developed. (c) At 325℃, localized organic pores were developed. (d) At 370℃, organic pores were greatly developed. (e) Unheated sample; intragranular pores of pyrite were not developed. (f) At 370℃, intragranular pores of pyrite were greatly developed. (g) At 325℃, micro-fractures began to develop around the particle edges with shapes of strip-like pores. (h) At 370℃, intergranular pores of clay were developed, and the micro-fractures around the particle edges were enlarged.

Behar and Vandenbroucke (1987) found that the amount of pores with diameters of 5–50 nm hinges on the kerogen type. Jiang et al. (2014) argued that the pore development of a shale reservoir is controlled by the TOC content, type, and maturity. This paper only analyzed the type I kerogen of the Minhe Basin, while the effects of other kerogen types on a shale reservoir were not analyzed.

Chemical compaction

Cui et al. (2013) held that the content of pyrite decreased from 10 to 0.6% with an increase in the simulated temperature and pressure, that the smectite mixed layer would disappear, and that the amount of illite would increase after 350℃. The results showed that the interlayer pores of clay minerals were not developed until 370℃ was reached. The intragranular pores of pyrite were not developed in the unheated sample (Figure 8(e)) and were well developed at 370℃ (Figure 8(f)), which could indicate that the content of pyrite would decrease further with an increase in the simulated temperature and pressure.

Mechanical compaction

The evolution of the pore structure was a consequence of the geostress, fluid, temperature, and geological time (Hu, 2013). Shale porosity is an inverse function of the pressure. Under an increasing pressure, the intergranular pores of clay particles will decrease and plate-like clay minerals can form preferred orientations; consequently, the porosity will decrease (Xue et al., 2015).

The preceding analysis showed that the total porosity increased first and then decreased (Table 3). From the unheated to the 350℃ samples, the dominating controlling factors might have been hydrocarbon generation and micro-fracture development around the particle edges (Figure 8(g)). From 350 to 370℃, the porosity decreased with an increase in the temperature and pressure in spite of the development of intragranular pores of pyrite and intergranular pores of clay, the main reason for which might have been that an increase in mechanical compaction dominated the evolution of porosity by reducing the quantity of macropores.

To summarize, the pore structure, pore type, and porosity changed with the simulated temperature and pressure. The burial depth was widely 2000–4000 m for the oil shales of the Yaojie Fm. in the central depression of the Minhe Basin. The favorable exploration area for depths from 4000 m to shallow shale layers reached 1400 km²; therefore, this study on the evolution of pore structure could provide valuable references for shale gas exploration at different depths in the Minhe Basin.

Conclusions

Lacustrine artificially matured shale samples were treated using hydrous pyrolysis. Low-temperature nitrogen adsorption, porosity measurement, and FE-SEM experiments were used to investigate the nanopore structures of artificially matured shale samples. The following conclusions were obtained.

The samples presented type II and type III nitrogen adsorption isotherms corresponding to temperature ranges from unheated to 325 and 350–370℃, respectively. The hysteresis loops were type H3, indicating that the pores developed were irregular and open with good connectivity between intragranular pores with shapes of parallel, slit-like, and open-ended tubes.

The pore sizes were distributed from 1.7 to 500 nm. From the unheated to the 325℃ samples, the micropores and fine mesopores (<10 nm) increased gradually; at 350 and 370℃, the micropores, mesopores, and macropores increased steeply.

The cumulative specific surface area and cumulative pore volume presented the same trend on the whole. From the unheated to the 325℃ samples, they increased gradually, while they increased rapidly at 350℃ and returned to a slower increase at 370℃.

In these artificially matured shale samples, the porosity first increased from 3.75% (unheated) to 26.09% (at 350℃) and then decreased to 26.09% (at 370℃).

Organic pores were not developed until 325℃. Intergranular pores of clay and intragranular pores of pyrite were well developed at 370℃.

Highlights

We present a first effort to investigate the pore evolution of lacustrine shale in Minhe Basin, Northwest China;

Thermal maturation affected the evolution of pore size distribution in shale.

The porosity first increases and then decreases with the increase of temperature and pressure.

Both cumulative specific surface area and cumulative volume presented an increasing trend with the increases of simulation conditions.

Footnotes

Acknowledgments

We appreciate the valuable comments and advices from editor and two anonymous reviewers.

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research,authorship,and/or publication of this article.

Funding

The author(s) disclosed receipt of the following financial support for the research,authorship,and/or publication of this article: This work was supported by the Strategic Priority Research Program of Chinese Academy of Sciences (Class B) (Grant No. XDB10010300),National Natural Science Foundation of China (Grant No. 41272144,Grant No. 41402130),and West Light Foundation of the Chinese Academy of Sciences (Class B).

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Evolution of nanopore structure in lacustrine organic-rich shales during thermal maturation from hydrous pyrolysis,Minhe Basin,Northwest China

Abstract

Keywords

Introduction

Geological setting

Materials and methods

Samples

Pyrolysis

Analysis of pore structure

Porosity measurements

FE-SEM imaging

Results and discussion

Nitrogen adsorption isotherms

Response of pore structure parameters to temperature

Evolution of porosity with increasing maturity

Hydrocarbon-generating evolution of organic matter

Chemical compaction

Mechanical compaction

Conclusions

Highlights

Footnotes

Acknowledgments

Declaration of conflicting interests

Funding

References