Front. Earth Sci. Frontiers in Earth Science Front. Earth Sci. 2296-6463 Frontiers Media S.A. 751543 10.3389/feart.2021.751543 Earth Science Original Research Characteristics of Shale Pores and Surfaces and Their Potential Effects on the Fluid Flow From Shale Formation to Fractures Li et al. Fluid Flow in Shale Pores Li Xu 1 2 Cai Jingong 2 * Gao Bo 1 Long Shengxiang 1 Feng Dongjun 1 Peng Zeyang 1 Guo Benqiang 2 State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, SINOPEC, Beijing, China State Key Laboratory of Marine Geology, Tongji University, Shanghai, China

Edited by: Min Wang, China University of Petroleum (Huadong), China

Reviewed by: Rui Yang, China University of Geosciences Wuhan, China

Enze Wang, Peking University, China

Shansi Tian, Northeast Petroleum University, China

 *Correspondence: Jingong Cai, jgcai@tongji.edu.cn

This article was submitted to Economic Geology, a section of the journal Frontiers in Earth Science

 22 10 2021 2021 9 751543 01 08 2021 20 09 2021 Copyright © 2021 Li, Cai, Gao, Long, Feng, Peng and Guo. 2021 Li, Cai, Gao, Long, Feng, Peng and Guo

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Fluid flow is critical for the efficient exploitation of shale resources and can be split into two stages: the flow in the artificial fractures and, more importantly, the flow from shale formations to the artificial fractures. In this study, X-ray diffraction, N2 adsorption, mercury intrusion, and ethylene glycol monoethyl ether adsorption were conducted on the shales collected from Es3 middle, Es3 lower, and Es4 upper sub-members in the Dongying Sag to reveal the potential effects of the characteristics and properties of pores and surfaces on the fluid flow in shale formations. The results are indicated as follows: 1) The shales from Es3 middle and Es3 lower contain more I/S and detrital minerals but less illite and carbonate minerals than those of Es4 upper. 2) The shales from Es3 middle and Es3 lower are mainly composed of smaller pores present in larger surface areas and lead to the steeper slope between the BrunauerEmmettTeller specific surface area (BET-SSA) and pore volumes. 3) Clay minerals mainly contribute to pore development, and carbonate minerals inhibit pore development. All kinds of surface areas (especially the inner surface area) are sourced by clay minerals, while I/S and illite present opposite effects. 4) Pore size and surface properties affect significantly the fluid flow in shale formations. The shales from Es4 upper are the favorable interval for shale oil accumulation and flow, especially for the shales with depth ranges of 3360∼3410 m, which possess high carbonates, illite and total organic carbon content, low clay mineral content, large pore volume, high large pore content, and small surface areas. Additionally, fluid composition needs to be paid more concern in the future.

 pore characteristics surface characteristics mineral composition interfacial interaction fluid flow 41972126 Foundation for Innovative Research Groups of the National Natural Science Foundation of China10.13039/501100012659 National Major Science and Technology Projects of China10.13039/501100013076 China Petrochemical Corporation10.13039/501100010824 Introduction

Hydraulic fracturing is one of the most important technologies for the successful exploitation of unconventional oil and gas resources with ultra-low porosity and permeability, especially for shale resources (Osiptsov, 2017; Wang and Sheng, 2017; Lu et al., 2018; Aadnøy and Looyeh, 2019; Yang and Guo, 2019; Lu et al., 2020; Shi et al., 2020; Xie et al., 2020; Wang et al., 2022). One of the key concerns of the exploitation of shale resources is the evaluation of the production performance after fracturing (Jarvie et al., 2007; Wang and Gale, 2009; Jin et al., 2014; Tang et al., 2019; Wei et al., 2020). Previous studies have observed that the fracturing fluids interact significantly with minerals and change their properties such as wettability, morphology, composition, water-bearing properties, and cation exchange capacity (CEC) (Chen et al., 2016; Chen et al., 2018a; Chen et al., 2018b; Lu et al., 2018; Sari et al., 2019; Zeng et al., 2019), leading to problems such as low flowback recovery of fracturing fluids, environment hazard, hydration, expansion, and rheology of clay minerals (O'Brien and Chenevert, 1973; Makhanov et al., 2014; Al-Ameri et al., 2018; Sui et al., 2018; Aadnøy and Looyeh, 2019; Zeng et al., 2019) and will impact seriously on the production progress. Therefore, to better understand the mechanisms of these problems and their potential effect on production performance, a detailed analysis of the characteristics of shale pores and surface structures and their potential interactions with the fracturing fluids and the confined fluids in shale formations is of great significance.

The fluid flow after hydraulic fracturing in the shales can be divided into two stages: the flow from shale formations to the fractures and the flow in the fractures. Because the ultimate and the most important purpose of hydraulic fracturing is to release oil and gas occluded in pores or adsorbed on surfaces as much as possible, the former stage is more important and is affected more significantly by pore and surface attributes. The international union of pure and applied chemistry (IUPAC) classified the pores into micropore (<2 nm), mesopore (2∼50 nm), and macropore (>50 nm) according to the pore size, adsorption properties, and capillary condensation (Sing, 1985). Shale presents pores with a wide diameter range, and the capillary pressure that relates closely to fluid flow differs according to the pore size if the properties of pore walls are the same. More importantly, the fluid flow in nanopores and the space close to surfaces do not follow Darcy’s law because of the strong interactions between fluids and pore walls (Zeng et al., 2011; Wang et al., 2015; Wang Z. et al., 2016; Wang and Sheng, 2017; Yu et al., 2017; Song et al., 2018; Cheng et al., 2019). Pore walls are constructed by minerals or organic matter (OM) that presents significant divergences in their physical and chemical properties. Differences in the origin of the pores result in the differences in the morphology, size, and attributes of pore walls (surfaces). For example, the pores formed by plate-like clay minerals tend to be slit-like (Curtis et al., 2012; Kuila and Prasad, 2013; Mathia et al., 2016); micropores and small mesopores are mainly related to clay minerals and organic matter (Chalmers and Bustin, 2008; Klaver et al., 2012; Zhang et al., 2012; Kuila and Prasad, 2013; Kuila et al., 2014). Therefore, the distribution of confined fluids differs greatly according to the shale pore structure and surface properties, which are closely related to the shale mineral composition and burial evolution. For example, nanopores with higher elastic buckling pressure increase with increasing depth (Curtis et al., 2012; Kuila and Prasad, 2013); mineral composition changes significantly due to diagenesis including illitization, dolomitization, recrystallization (Li W. et al., 2016; Wilson et al., 2016a; Mathia et al., 2016; Bai et al., 2018; Cai et al., 2018; Liang et al., 2018; Du et al., 2019; Wang and Guo, 2019), leading to the changes of pore and surface properties (Klaver et al., 2012; Li W. et al., 2016; Wilson et al., 2016b; Wang and Guo, 2019). In summary, shale pores and surfaces are complex, and their characteristics and properties change significantly according to the mineral composition and burial evolution. These complexities control the interactions between pore walls and confined fluids, and they must affect the shale oil mobility and production performance.

To further illustrate the potential impacts of the complexity of the characteristics and properties of pores and surfaces on the fluid flow from shale formation to fractures, the interactions between fluids and pores or surfaces in different fracturing stages were summarized. During the pumping stage, fracturing fluids are pumped into shale formation and forming fractures. Then, fracturing fluids gradually intrude into shale rocks under high fluid pressure. After pumping, the well will be shut. Shut-in is commonly used and is important for the formation of stable fractures and provides time for the water blockage removal (Al-Ameri et al., 2018; Wijaya and Sheng, 2019). During this stage, fracturing fluids imbibe into the formation spontaneously. It is important to note that spontaneous imbibition also happens during the fluid pumping, the flowback, and the long-term production stage (Al-Ameri et al., 2018; Zeng et al., 2019). The strength of the imbibition is greatly affected by the wettability, the pore structure, and the pore connectivity of the rock (Dehghanpour et al., 2012; Xu and Dehghanpour, 2014; Wilson et al., 2016b; Zolfaghari et al., 2016; Sun et al., 2017; Yu et al., 2017; Yang et al., 2018). In addition, the wettability of some surfaces can be changed from oil wetting to water wetting due to imbibition (Chen et al., 2016; Roshan et al., 2016; Chen et al., 2018a; Chen et al., 2018b; Zeng et al., 2019), and the pore structure can also be changed by fracturing fluids and surfactant (Xu and Dehghanpour, 2014; Lu et al., 2019), which will further change the flow characteristics conversely. During the flowback stage, part of the fracturing fluids is adsorbed by the minerals (especially the clay minerals) or trapped into the pores with narrow throat, leading to low flowback recovery of the fracturing fluids (Xu and Dehghanpour, 2014; Al-Ameri et al., 2018; Wijaya and Sheng, 2019). Meanwhile, the chemical properties of the flowback fluids change obviously due to the mass exchange between the fracturing fluids and the pore fluids or the mineral components (Haluszczak et al., 2013; Engle and Rowan, 2014; Zolfaghari et al., 2016). Additionally, the strength of the impacts differs according to mineral types because of the divergences in their physical and chemical properties (Zolfaghari et al., 2016). For example, smectite and I/S impact more on the flowback water chemical properties than illite (Zolfaghari et al., 2016). In summary, characteristics and properties of pores and surfaces will impact the absolute permeability of shale and, more importantly, the relative permeability of oil. Thus, the analysis of the characteristics and properties of shale pores and surfaces is important for the evaluation of shale oil potential, but they are seldomly considered previously.

In this study, shale samples with different mineral compositions and degrees of evolution were collected from different shale formations in the Dongying Sag, Jiyang Depression. The complete shale pore’s size distribution and surfaces with different properties were analyzed by N2 adsorption, mercury intrusion porosimetry, and EGME adsorption methods. Then, the mineral composition, pore, and surface characteristics and properties were compared among the shales at different intervals. Based on all these detections and comparisons, the fluids flow from shale formation to the hydraulic fractures was evaluated, and the favorable interval for shale oil storage and flow was obtained on the profile from the perspective of potential fluid flow properties. This study can benefit the selection of fracturing fluids, the implementation of fracturing, and the accurate evaluation of shale oil production performance.

 Materials and Methods Materials

The Dongying Sag locates in the southeastern of Bohai Bay Basin, northern China. Previous exploration has confirmed the great shale oil potential in the third and fourth members of Shahejie Formation (Li Z. et al., 2016; Li et al., 2020). In order to characterize the influence of pore structure on the fracturing of the shales with different compositions, thirty-four argillaceous source rocks were selected for detection, which were taken from well NY1, N38, and N872 at depths of 3000∼3500 m in the middle and lower section of the third member (Es3 middle and Es3 lower) and upper section of the fourth member (Es4 upper) of Shahejie Formation (Figure 1; Table 1) in the Dongying Sag. All the bulk samples were detected by X-ray diffraction (XRD), Rock-Eval VI pyrolysis, N2 adsorption, mercury injection porosimetry (MIP), and ethylene glycol monoethyl ether (EGME) adsorption methods. The clay fraction of each sample was detected by XRD to obtain the clay mineral composition. For the separation of the clay-sized fractions, the bulk rocks were ground to less than 1 mm and were then soaked in deionized water within a 2000-ml beaker at room temperature via natural sedimentation.

Structural map and sampling well locations of the Dongying Sag (modified from Li et al., 2020).

Sample information and mineral composition.

Sample no. Well Depth Member Bulk mineral composition/% Clay mineral composition/%
M Clay Detrital Carbonate I/S Illite Kaolinite Chlorite
1 NY1 3334.36 Es4 upper 37 21 39 61 36 2 1
2 NY1 3355.61 Es4 upper 22 26 49 67 33 0 0
3 NY1 3372.01 Es4 upper 8 24 66 0 100 0 0
4 NY1 3378.36 Es4 upper 9 25 64 30 70 0 0
5 NY1 3380.21 Es4 upper 15 21 62 28 72 0 0
6 NY1 3382.16 Es4 upper 48 33 16 35 65 0 0
7 NY1 3385.76 Es4 upper 22 19 56 12 88 0 0
8 NY1 3390.45 Es4 upper 13 24 62 0 100 0 0
9 NY1 3398.90 Es4 upper 6 19 74 0 100 0 0
10 NY1 3408.00 Es4 upper 24 21 53 0 100 0 0
11 NY1 3468.63 Es4 upper 44 39 14 50 50 0 0
12 NY1 3479.73 Es4 upper 5 12 83 0 100 0 0
13 NY1 3494.45 Es4 upper 9 10 38 0 100 0 0
14 NY1 3497.90 Es4 upper 15 15 31 3 97 0 0
15 N38 3022.00 Es3 middle 42 50 4 74 14 7 5
16 N38 3025.00 Es3 middle 31 46 20 76 13 6 5
17 N38 3034.81 Es3 middle 27 38 32 69 15 9 7
18 N38 3089.52 Es3 middle 47 42 11 68 22 6 4
19 N38 3137.61 Es3 middle 42 35 21 81 15 2 2
20 N38 3140.91 Es3 middle 45 39 14 74 19 4 3
21 N38 3143.41 Es3 middle 45 50 5 68 20 7 5
22 N38 3147.41 Es3 middle 51 41 6 73 20 4 3
23 N38 3336.60 Es3 lower 43 44 13 65 30 3 2
24 N38 3342.60 Es3 lower 41 34 22 59 41 0 0
25 N872 3050.80 Es3 middle 30 33 31 72 20 4 4
26 N872 3049.70 Es3 middle 34 28 32 71 17 7 5
27 N872 3053.50 Es3 middle 37 40 21 71 25 2 2
28 N872 3072.30 Es3 middle 32 50 16 73 22 3 2
29 N872 3074.30 Es3 middle 26 53 20 73 22 3 2
30 N872 3201.00 Es3 lower 25 35 35 52 40 4 4
31 N872 3203.00 Es3 lower 29 27 39 69 27 2 2
32 N872 3208.70 Es3 lower 18 29 49 57 36 4 3
33 N872 3327.30 Es4 upper 19 36 43 5 95 0 0
34 N872 3329.40 Es4 upper 38 35 24 49 51 0 0
Methods X-Ray Diffraction (XRD)

An X’pert-MPD diffraction instrument (Philips Corp) was employed for XRD measurements. The samples were crushed to a particle size of 320 mesh. The test conditions include a copper butt, pipe pressure of 30 kV, conduit flow of 40 mA, and scanning speed of 2° (2θ)/min. The bulk mineral composition was detected by a natural thin section of bulk rock. The clay mineral composition detection was conducted on natural ethylene glycol saturated and 550 C heated orientation sheet of clay fractions. The ethylene glycol-saturated orientation sheet was made by exposing the naturally oriented sheet in ethylene glycol vapor at 60°C for 8 h, and 550°C heated orientation sheet was made by heating at 550°C for 2 h.

 Pore Characteristics Determination N<sub>2</sub> Adsorption

Pore size distribution (PSD) of pores with diameters ranging from approximately 1–50 nm was conducted with the low-temperature (77 K) N2 adsorption methods on the JW-BK adsorption instrument (Beijing JWGB SCI & Tech Corp). Approximately 2∼4 g of sample was crushed to a particle size smaller than 3 mm and degassed by heating at 80°C for more than 6 h under vacuum (10 μm Hg) to remove adsorbed moisture and volatile matter prior to the analysis. Measurements in adsorption mode were performed over the relative pressure (P/P0) range of 0.1 ∼ 0.95 to obtain the adsorption isotherm. The PSD was obtained by inverting the adsorption branch of the isotherm using BarrettJoynerHalenda (BJH) method (Barrett et al., 1951).

 Mercury Intrusion Porosimetry

The PSD of pores with diameters ranging from approximately 3.2 nm–40 μm was determined using the mercury intrusion method on a Micromeritics Autopore IV 9500 series apparatus. Samples (2∼4 g) were crushed to a particle size smaller than 3 mm and were oven-dried (80°C) and evacuated under vacuum (30 μm Hg) for 30 min prior to mercury intrusion. The measured pressure ranged from 0.5 to 60,000 psia, and the PSD was calculated by the Washburn equation (Schmitt et al., 2013). In our calculations, the interfacial tension of Hg was 485 mN/m, the wetting angle was 140°, and the density of Hg was 13.5335 g/ml.

 Combination of N<sub>2</sub> Adsorption and MIP and Calculation of Pore Characteristics Parameters

Previous researchers have established several methods to combine N2 adsorption method and MIP for obtaining the complete PSD of shales (Spitzer et al., 1976; Echeverria et al., 1999; Schmitt et al., 2013; Kenvin et al., 2015). In this study, we obtained the complete PSD referring to the method proposed by Schmitt et al. (2013) and Li et al. (2020). The junction point of each sample is listed in Table 2. After achieving the complete PSD, the total pore volume (Vt) was calculated.

Junction points, pore volumes and contents, surface areas.

Sample no Junction point Vt V1 V2 V3 V1% V2% V3% TSA ISA BET-SSA
nm cm3/g cm3/g cm3/g cm3/g % % % m2/g m2/g m2/g
1 10.72 0.007799 0.003210 0.001605 0.002984 41.16 20.58 38.26 122.69 120.87 1.82
2 18.32 0.003750 0.000341 0.001806 0.001604 9.08 48.16 42.76 78.91 78.76 0.15
3 14.08 0.011062 0.000187 0.001401 0.009474 1.69 12.67 85.64 34.14 33.85 0.29
4 13.52 0.007807 0.000553 0.003219 0.004035 7.09 41.23 51.69 34.92 34.07 0.85
5 6.75 0.003593 0.003106 0.000163 0.000324 86.44 4.53 9.03 70.74 67.70 3.05
6 36.79 0.088121 0.000608 0.007541 0.079972 0.69 8.56 90.75 129.65 128.31 1.34
7 17.66 0.027352 0.009051 0.006746 0.011555 33.09 24.66 42.24 65.80 60.06 5.74
8 26.33 0.005770 0.000029 0.001438 0.004303 0.50 24.92 74.58 32.00 30.07 1.93
9 18.73 0.004906 0.000048 0.000763 0.004095 0.98 15.56 83.46 22.16 21.51 0.65
10 25.52 0.021793 0.003493 0.007661 0.010639 16.03 35.15 48.82 51.58 49.04 2.54
11 13.74 0.087995 0.036221 0.036579 0.015195 41.16 41.57 17.27 128.88 98.35 30.53
12 25.33 0.005556 0.000308 0.002110 0.003138 5.55 37.97 56.48 20.91 19.74 1.17
13 31.85 0.006996 0.001080 0.005282 0.000634 15.43 75.50 9.06 23.20 22.37 0.83
14 15.92 0.014206 0.002730 0.010687 0.000789 19.22 75.23 5.56 40.15 38.43 1.72
15 12.67 0.009972 0.005662 0.003765 0.000545 56.78 37.75 5.47 107.98 102.15 5.83
16 15.42 0.013532 0.005506 0.006636 0.001391 40.69 49.03 10.28 117.03 109.31 7.72
17 13.31 0.005320 0.002438 0.002114 0.000768 45.83 39.73 14.44 109.86 107.72 2.14
18 17.47 0.027000 0.016127 0.010290 0.000583 59.73 38.11 2.16 160.87 131.25 29.62
19 14.26 0.027401 0.012389 0.012697 0.002316 45.21 46.34 8.45 151.98 131.77 20.21
20 14.75 0.020501 0.011490 0.007354 0.001657 56.05 35.87 8.08 155.70 140.25 15.45
21 23.39 0.028910 0.013045 0.012291 0.003575 45.12 42.51 12.37 115.33 91.45 23.88
22 19.71 0.030813 0.016797 0.012868 0.001148 54.51 41.76 3.73 162.53 132.96 29.57
23 17.56 0.026642 0.014331 0.011117 0.001195 53.79 41.73 4.48 122.70 104.95 17.74
24 21.06 0.018754 0.004835 0.005779 0.008139 25.78 30.82 43.40 147.47 144.01 3.46
25 24.95 0.006979 0.000583 0.003136 0.003260 8.35 44.94 46.71 125.03 123.97 1.05
26 13.47 0.006426 0.002081 0.003374 0.000971 32.39 52.51 15.11 134.92 132.97 1.95
27 12.13 0.015185 0.009051 0.004849 0.001286 59.60 31.93 8.47 151.86 141.16 10.70
28 14.69 0.020578 0.012020 0.006391 0.002167 58.41 31.06 10.53 138.95 124.26 14.69
29 18.94 0.018109 0.008317 0.009056 0.000736 45.93 50.01 4.06 116.64 106.58 10.06
30 14.26 0.007901 0.000140 0.004101 0.003660 1.77 51.90 46.33 113.77 113.16 0.61
31 27.63 0.004121 0.000020 0.002119 0.001982 0.49 51.42 48.09 153.49 151.88 1.61
32 27.63 0.005280 0.000067 0.002008 0.003205 1.27 38.03 60.71 93.85 91.93 1.92
33 15.70 0.009027 0.001751 0.003340 0.003936 19.40 37.00 43.61 62.81 60.96 1.85
34 24.59 0.088952 0.006882 0.024590 0.057480 7.74 27.64 64.62 124.09 119.36 4.73
Surface Areas Measurement N<sub>2</sub> Adsorption

The determination procedure is the same as the Surface Areas Measurement section. After obtaining the adsorption isotherms, the outer surface area (BET-SSA) for each sample was determined by inversion of the adsorption branch of the isotherm using the BrunauerEmmettTeller (BET) analysis procedure (Brunauer et al., 1938), with a relative pressure range of 0.05 ∼ 0.3. The molecular sectional area of N2 was 0.162 nm2.

 EGME Adsorption

For the EGME procedure, a vacuum pump (with a vacuum pressure of 609 mmHg) and an electronic analytical balance (with an accuracy of 0.0001 g) were employed. Approximately 1 g of sample was weighed and put in the oven at 80°C for more than 6 h. Then, the sample was taken out and put in the aluminum tare (with a diameter of 5 cm and a height of 8 mm), and 3 ml EGME solution (analytical grade) was quickly added to the sample with a pipette and swirled gently until the sample was soaked. Afterward, the aluminum tares with mixture were placed in a sealed desiccator with EGME solution, calcium chloride (CaCl2), and phosphorus pentoxide (P2O5). The desiccator was evacuated for approximately 1 hour to remove water vapor. More than 8 h later, the tares were weighed after the desiccator was evacuated again. The process of evacuation was repeated, and they were weighed until a constant weight was attained (the mass difference between the two measurements was less than 0.001 g). Finally, the total surface area (TSA) of the sample was calculated based on the absorbed quantity of EGME molecules (the conversion factor is 2.86 × 10–4 g/m2), and the inner surface area (ISA) was the differences between TSA and BET-SSA.

 Results Mineral Composition Bulk Mineral Composition

It is found from the XRD curves of typical bulk rocks (Figure 2A) that although clay, quartz, calcite are the main mineral types of all the shales, the relative contents of different types of minerals vary greatly among the shales from different sections. For example, the shales from Es4 upper contain more dolomite, especially for the deeper burial samples. Comparison of bulk mineral composition of the shales from different sections (Figure 2B) shows that the shales from Es3 middle contain the most amount of clay (37.62%) and detrital (41.92%) minerals and the least amount of carbonate (17.92%) minerals; the shales from Es4 upper are composed of much more calcite (31.94%) and dolomite (15.31%) than those of Es3 middle and Es3 lower; the shales from Es3 lower contain moderate content of almost all types of minerals.

Mineral compositions of the shales from different sections. (A) XRD curves of typical samples from Es3 middle (28, 18), Es3 lower (23, 31), and Es4 upper (24, 6, 10, 14). The burial depths of the samples from each member increase from top to bottom. (B) Bulk mineral composition. (C) Clay mineral composition.

 Clay Mineral Composition

From the analysis of the composition of clay minerals (Table 1; Figure 2C), the average contents of mixed-layer illite/smectite (I/S) (46.62%) and illite (49.26%) of all the shales were found to be high, while there are also great differences among the shales from different sections. The shales from Es3 middle contain the most amount of I/S (72.54%) and the least amount of illite (18.77%); the shales from Es4 upper are composed of much more illite (78.56%) than those of Es3 middle and Es3 lower; the shales from Es3 lower contain moderate content of I/S (60.40%) and illite (34.80%).

 Pore and Surface Characteristics Surface Characteristics

From the results of the N2 adsorption measurement (Tables 2; Figure 3A), the shales from Es3 middle have the largest average BET-SSA (13.30 m2/g), which ranges from 1.05 to 29.62 m2/g; the BET-SSA of the shales from Es3 lower ranges from 0.61 to 17.74 m2/g with an average of 5.07 m2/g; the shales from Es4 upper possess BET-SSA ranges from 0.15 to 30.53 m2/g, with 3.70 m2/g on average. According to the EGME measurement (Table 2; Figure 3C), the shales from Es3 middle possess the largest average TSA (134.51 m2/g), which ranges from 107.98 to 162.53 m2/g; the TSA of the shales from Es3 lower ranges from 93.85 to 153.49 m2/g with an average of 126.26 m2/g; the shales from Es4 upper present minimal TSA ranges from 20.91 to 129.65 m2/g, with 65.17 m2/g on average. Based on N2 adsorption and EGME measurements (Table 2; Figure 3B), the ISA can be calculated. The results show that the shales from Es3 middle and Es3 lower also present larger ISA (with 121.21 m2/g and 121.19 m2/g on average, respectively), while the shales from Es4 upper have much smaller ISA (61.47 m2/g).

Box plot of the outer surface area [BET-SSA, (A)], inner surface area [ISA, (B)], total surface area [TSA, (C)], total pore volume [Vt, (D)], and calculated average pore diameter [Rt = 4 × Vt/(BET-SSA), (E)] of the shales from different sections.

 Pore Characteristics

According to the complete pore size distribution (PSD) curves of the shales from different sections (Figure 4), most of the shales are mainly composed of the large mesopore (10∼50 nm) and small macropore (50∼100 nm), while most of the shales from Es4 upper contain a significant amount of pores with diameter >100 nm (Figures 4A–D). In addition, the PSD of the shales from different sections shows great differences. Qualitatively, the shales from Es4 upper contain more pores with larger diameter than the shales from Es3 middle and Es3 lower, while the shales from Es3 middle present a very low amount of larger pores. Considering the characteristics of the PSD curves, the volumes of the pores with diameter <10 nm (V1), 10∼100 nm (V2), and >100 nm (V3) were further calculated by interpolation (Table 2).

Pore size distribution of all the shale samples. (A–D) shales from Es4 upper; (E, F) shales from Es3 lower; (G–I) shales from Es3 middle.

Based on these findings, Vt, V1, V2, and V3 and their relative contents of the shales from different sections were further calculated and compared (Table 2; Figures 3D,E, 5). The Vt of the shales from Es3 middle ranges from 0.005320 to 0.030813 cm3/g, with 0.017748 cm3/g on average; the Vt of the shales from Es3 lower ranges from 0.004121 to 0.026642 cm3/g, with 0.012539 cm3/g on average; the Vt of the shales from Es4 upper ranges from 0.003593 to 0.088952 cm3/g, with an average of 0.024668 cm3/g (Table 2; Figure 3D). Further comparing the pore volumes of the pores with different diameter ranges (Figures 5A–C), it can be found that the shales from Es3 middle have the largest V1 (0.008885 cm3/g) and V2 (0.007294 cm3/g) and minimal V3 (0.001569 cm3/g); the shales from Es3 lower possess minimal V1 (0.003879 cm3/g) and V2 (0.005025 cm3/g) and moderate V3 (0.003636 cm3/g), while the shales from Es4 upper have maximal V3 (0.013135 cm3/g) and moderate V1 (0.004350 cm3/g) and V2 (0.007183 cm3/g). Viewing from the contents of V1, V2, and V3 (Figures 5D–F), the shales from Es3 middle contain the most amount of V1 (46.81%) and the least amount of V3 (11.53%), the shales from Es3 lower possess minimal V1 (16.62%) and maximal V2 (42.78%), the shales from Es4 upper present maximal V3 (47.74%) and minimal V2 (33.18%).

Box plot of the pore volumes and contents of the pores with diameter <10 nm (A, D), between 10–100 nm (B, E) and >100 nm (C, F) of the shales from different sections, respectively.

 Discussions Relationships Between Pores and Surfaces

Pores and outer surfaces are the places where shale oil occurs. Their relationships depend on the relative contribution of free oil and adsorbed oil. Therefore, the relationships between pore volumes and the BET-SSA were analyzed firstly. It can be found that Vt of the shales from Es3 middle and Es3 lower presents a better relationship with BET-SSA (especially for Es3 middle) than that of Es4 upper (Figure 6A). Viewing from the pores with different diameter ranges (Figures 6B,C), the correlation coefficients of the relationships between V1 of the shales from each section with BET-SSA are high (>0.95), while the correlation coefficients of the relationships between V2 of the shales from each section are smaller, especially for the shales from Es4 upper; there are no relationships between V3 and BET-SSA (the data were not shown in Figure 6). These observations coincide well with previous researches; that is, the pores with small size contribute primarily to the outer surface area, while the pores with larger size mainly contribute to the pore volume (Beliveau, 1993; Chalmers et al., 2012; Curtis et al., 2012; Wang and Guo, 2019). Further comparison of the shales from different sections suggests that (Figure 6) the slopes of the shales from Es3 middle and Es3 lower are steeper than those of Es4 upper, especially for V2 and Vt, indicating the differences in their pore size and in the ratio between pore volume and outer surface area. It has been confirmed previously that pores with different sizes have different ratios between pore volume and outer surface area, leading to the difference in the proportion of oil with different occurrence states (Chalmers et al., 2012; Curtis et al., 2012; Wang and Guo, 2019). MDSs and spontaneous imbibition experiments also showed that the intensity of the interfacial interaction of the pores with different pore volume/surface area ratios (or pore diameter) differs significantly (Xu and Dehghanpour, 2014; Yu et al., 2017). The pores with smaller pore volume and larger surface area possess stronger interfacial interaction intensity and larger capillary force, leading to larger adsorption potential to wetting phase fluids and stronger inhibition to non-wetting phase fluids (Wang et al., 2015; Wang S. et al., 2016; Yu et al., 2017; Zeng et al., 2019). Therefore, the shales from Es4 upper which present larger pore volume and smaller surface area are more conducive to fluid flow without considering the properties of the pore walls. However, shales are composed of varieties of minerals which present divergence attributes. Thus, to analyze the properties of pore walls and their influence on fluid mobility of the shales from different sections, the relationships between minerals and pores/surfaces were further analyzed.

(A) relationships between BET-SSA and Vt; (B) relationships between BET-SSA and V1; (C) relationships between BET-SSA and V2.

 Contributions of Mineral Components to Pores and Surfaces Pores

Clay minerals (I/S, illite), detrital minerals (quartz, feldspar), and carbonate minerals (calcite, dolomite) are the main bulk mineral components in shale rocks (Table 1; Figure 2). According to the relationships between bulk mineral compositions with Vt (Figure 7), it is found that Vt positively correlates with clay and detrital mineral content but negatively correlates with carbonate mineral content for the shales from all sections and generally presents a high correlation coefficient. These correlations indicate that inorganic pores are the main pore type of the studied area, while clay and detrital minerals contribute to the shale pores and carbonate minerals generally inhibit the development of pores. These findings are similar to previous studies on the shales from similar locations (Zhang et al., 2016; Zhu et al., 2019; Zhang et al., 2019; Liu et al., 2019). Previous studies have confirmed the chemical instability of carbonate minerals, and they probably destroy or block the pores by digenesis such as dissolution, precipitation, and recrystallization (Chalmers et al., 2012; Gaines et al., 2012; Loucks et al., 2012; Liu et al., 2019). In addition, the correlations between Vt and clay and carbonate mineral are usually better than those of detrital minerals, indicating the stronger control of clay and carbonate minerals in shale pores.

(A) relationships between Vt and clay mineral content; (B) relationships between Vt and detrital mineral content; (C) relationships between Vt and carbonate mineral content.

Comparison of the correlations of the shales from different sections shows that the slopes of the shales from Es4 upper are much larger than those of the other two sections (Figure 7), suggesting the greater role of mineral components in the development of pores, especially for the relatively larger pores. The conclusion can be certificated by the previous studies indicating that clay minerals mainly relate to micropores and small mesopores while carbonate minerals generally correlate well with pores with larger diameter (Chalmers et al., 2012; Klaver et al., 2012; Kuila and Prasad, 2013; Mathia et al., 2016; Liu et al., 2019; Zhang et al., 2020) and the relatively high carbonate mineral content of the shales from Es4 upper. Moreover, based on the relationships between clay mineral content and pore volumes of pores with different diameter range (Figure 8), it can be found that V3 of the shales from Es4 upper correlates well with clay mineral content while present no obvious relationships for the shales from Es3 middle and Es3 lower. On the contrary, the correlation coefficients between V1 and clay mineral contents for the shales from Es3 middle and Es3 lower are much higher than that of Es4 upper (Figure 8). The results indicate that although clay minerals mainly benefit the development of pores, the relative contributions of clay minerals to pores with different diameters for the shales from different sections differ significantly. Previous studies indicated that illitization, dolomitization, and dissolution benefit the shale reservoir properties and create more macropores for oil accumulation and flow (Chalmers et al., 2012; Li W. et al., 2016; Mathia et al., 2016; Bai et al., 2018; Liang et al., 2018; Wang and Guo, 2019). Thus, considering differences in mineral composition of different sections (Figure 2), we attribute these divergences to the clay mineral composition of the shales from different sections. In summary, the shales from Es4 upper contain more carbonate minerals and undergone a higher degree of illitization and dolomitization than those of Es3 middle and Es3 lower, thus leading to more pores with larger diameter (Table 2; Figures 3–5). Therefore, the shales from Es4 upper present a higher potential for oil accumulation and flow from shale formations to fractures.

(A) relationships between V1 and clay mineral content; (B) relationships between V2 and detrital mineral content; (C) relationships between V3 and carbonate mineral content.

 Surfaces

Clay minerals correlate with smaller pores with large correlation coefficients (Figure 8) (Kuila and Prasad, 2013) and possess larger outer surface area than detrital and carbonate minerals (Beliveau, 1993; Chalmers and Bustin, 2008; Chalmers et al., 2012; Kuila and Prasad, 2013; Zhu et al., 2015; Saidian et al., 2016). Additionally, clay minerals such as smectite and I/S have inner surface areas between clay sheets, and ISA is usually one or two orders of magnitude larger than the outer surface area (Macht et al., 2011; Zhu et al., 2015). Thus, we only analyze the contributions of clay minerals to surface areas. Comparison of the clay mineral composition of the shales from different sections (Table 1) indicates that I/S and illite contents of the shales from Es3 middle and Es3 lower only distribute in a narrow range (≈20∼30%), which is much smaller than that of Es4 upper. Therefore, it is more appropriate to put all the shales from different sections together when analyzing the relationships between clay mineral composition and surface areas. The results show that all kinds of surface areas correlate with clay mineral content, in which BET-SSA mainly trend correlates with clay mineral contents, while ISA and TSA present excellent correlations with clay mineral contents (Figures 9A–C). Further comparison of the relationships between surfaces areas and specific clay mineral types indicates that all types of surface areas positively correlate with I/S content while negatively correlate with illite content (Figures 9D–I). Also, BET-SSA only shows trend relations with I/S and illite contents, while ISA and TSA present an excellent correlation with I/S and illite contents. These findings indicate that surfaces are mainly constructed by clay minerals, especially for ISA, while I/S and illite present the opposite effect. Therefore, the lower clay mineral content and higher illite content of the shales from Es4 upper lead to its smaller surface areas (Figures 2, 3).

Relationships between surface areas and clay mineral contents (A–C), I/S contents (D–F) and illite (G–I) contents of the shales from different sections.

According to Figure 9, the correlation coefficients for BET-SSA are much worse than those of ISA. To understand these differences, it must be noted that the measured surface areas are the surface areas after the release of hydrocarbon or other confined fluid during coring and subsequent sample preservation (Jiang et al., 2016; Li et al., 2020; Wang et al., 2022). It has been demonstrated that free and physically adsorbed hydrocarbons or OM is mainly occurred on the outer surface, and they vaporize much easier and faster than chemically adsorbed hydrocarbons or OM which mainly occur on the inner surface (Jiang et al., 2016; Zhu et al., 2016). Therefore, the outer surface area is affected by hydrocarbons or OM that is confined in the shale pores more remarkably, and leading to relatively poor relationships between BET-SSA and mineral compositions.

To summarize, pores and surfaces are all greatly affected by mineral components, especially clay minerals. Previous studies have indicated that the physical and chemical properties differ significantly according to mineral types and clay minerals are more active. For example, clay minerals mainly correlate with smaller pores; smectite and I/S are easier to hydrate and swell than illite and kaolinite (Zolfaghari et al., 2016; Al-Ameri et al., 2018; Sui et al., 2018), and their higher CEC will lead to stronger impacts on the chemical properties of flowback water (Greenland, 1971; Han et al., 2016; Saidian et al., 2016; Zolfaghari et al., 2016); along with burial evolution, smectite with large ISA will transfer to illite with no ISA by illitization, leading to the decreasing of ISA (Zhu et al., 2015; Wilson et al., 2016b; Singh et al., 2016) and the change of pore structure and BET-SSA (Wu et al., 2015; Wang and Guo, 2019). These differences will result in divergences in the interactions between pore walls and fluids and then affect the fluid flow significantly.

 Effects of Pore and Surface Characteristics and Properties on Fluid Flow

Based on the discussions above, a hypothesis model was established to illustrate the effects of the characteristics and properties of pores and surfaces on the fluid flow from shale formation to hydraulic fractures (Figure 10). It has been confirmed that the affinity to fluids of different minerals follows the order: I/S > illite > carbonate minerals ≈ detrital minerals (Zhang et al., 2012; Singh et al., 2016; Zolfaghari et al., 2016; Al-Ameri et al., 2018; Saikia et al., 2018). Therefore, if the pore size and fluid condition are assumed to be the same: for the pores constructed by I/S, more fluids will be adsorbed onto the pore walls, and the mobility pore diameter is much smaller than the real pore diameter (Figure 10A); for the pores related to illite, the thickness and distribution range of residual fluids are smaller than those of the I/S (Figure 10B); for the pores related to carbonate and detrital minerals, the thickness of the residual fluids reduces further and the distribution is localized (Figure 10C).

Hypothetical model to explain the effects of characteristics and properties of pores and surfaces on the fluid flow from shale formation to fractures. (A–C) Distribution of mobile and residual fluids in the pores with different surface properties. (D) Distribution of fluids after flow from shale formation to fractures for the shales from Es3 middle and Es3 lower. (E) Distribution of fluids after flow from shale formation to fractures for the shales from Es4 upper.

Combined with the features and the differences in the mineral composition and pore and surface characteristics of the shales from different sections (Figures 2–9), the fluid distribution and flow pattern were established to illustrate the differences in the production potential of the shales from different sections (Figures 10D,E). Comparison of the fluid flow characteristics between the same mineral types of the shales from different sections indicates that because the interfacial interaction strength of pores with a smaller diameter is much larger than that of larger pores (Wang S. et al., 2016; Yu et al., 2017), more oil is retained in shale formation (Figures 10D,E) for the shales from Es3 middle and Es3 lower than that of Es4 upper (Figures 4, 5). In addition, fracturing fluids that intruded into the shales may also be trapped more seriously in the shales with smaller pores and leading to more oil blocked in shale formation if the trapped fracturing fluids block the pores or pore throat (Figures 10D,E). Further comparison of the fluid flow characteristics between different mineral types shows that (Figures 10D,E) more oil and intruded fracturing fluids are trapped in shale formations due to the generally smaller pore size of the pores correlate to clay minerals than those of carbonate and detrital minerals (Klaver et al., 2012; Kuila and Prasad, 2013; Malik and Lu, 2015; Li W. et al., 2016; Mathia et al., 2016) and the larger affinity to fluids of clay minerals, especially for I/S (Zhang et al., 2012; Singh et al., 2016; Zolfaghari et al., 2016; Al-Ameri et al., 2018; Saikia et al., 2018). In summary, the fluid flow in shale formation is controlled both by the pore size and by the properties of pore walls (surfaces). Due to the larger Vt, V2, V3, and smaller surface areas, as well as the high carbonate and illite content, the shales from Es4 upper possess better production potential (Figures 10D,E).

 Significances and Prospects

The breakability of shale is one of the key characteristics that depend on the fracturing and extraction of oil and gas occluded within shale play (Aadnøy and Looyeh, 2019). Brittle mineral content is the main concern when evaluating breakability. Jarvie et al. (2007) viewed quartz as the main brittle mineral in the Barnett Shale and used its relative content for stimulation evaluation (Jarvie et al., 2007). In addition to quartz, Wang and Gale (2009) also regarded dolomite as a brittle mineral (Wang and Gale, 2009). Based on the study of the mechanical properties of minerals, Jin et al. (2014) further classified feldspar, calcite, and mica as brittle minerals (Jin et al., 2014). In summary, it is widely accepted that breakability relates closely to mineral composition. The rocks with relatively high detrital minerals and carbonate minerals and low amount of clay mineral content present better breakability (Aadnøy and Looyeh, 2019). However, to efficiently exploit shale resources, brittle mineral content is not the only concerning factor, characteristics and properties of pores and surfaces should also be paid attention to because of their significant effects on fluid flow in shale formation (Figure 10). On the one hand, pores with different diameters present divergence capillary force and specific surface area, leading to differences in the adsorption potential and flow profile. On the other hand, the physical and chemical properties of minerals and their relationships with pores and surfaces differ significantly according to mineral types, leading to divergences in the interfacial interactions between the pore walls and the confined fluids. These divergences will change the distribution, occlusion, and flow of fracturing fluid and oil. Furthermore, water is the main component in fracturing fluids, and it will interact with clay minerals (especially I/S) significantly during the pumping, flowback, and production stages (O'Brien and Chenevert, 1973; Makhanov et al., 2014; Xu and Dehghanpour, 2014; Sui et al., 2018; Shi et al., 2020) and might lead to the low flowback recovery, the changes of pore and surface properties, and the reduction of oil relative permeability. Therefore, characteristics and properties of pores and surfaces are the indispensable factors that need to be taken into the evaluation of shale oil potential. Take the research area as an instance, based on the burial evolution profile of TOC, pore volume, surface areas, mineral composition, and composition of pores, the deep burial shales from Es4 upper are the favorable interval for shale oil accumulation and flow, especially for the shales with depth ranges of 3360∼3410 m (Figure 11), which present high carbonate minerals, illite and TOC content, low clay mineral content, large total pore volume, more pores with a larger diameter and small surface areas.

Burial evolution of mineral composition, pores, and surfaces.

Remarkable changes of mineral composition and pore structure along with burial evolution are some of the most important characteristics of shale resources. For example, diagenesis such as compaction, recrystallization, and cementation increases the brittleness of rocks and result in the increase of breakability of rocks; diagenesis such as illitization, dissolution, and dolomitization improves reservoir properties by forming more large pores and reducing surface areas (Chalmers et al., 2012; Li W. et al., 2016; Mathia et al., 2016; Zhang et al., 2016; Bai et al., 2018; Liang et al., 2018; Wang and Guo, 2019); I/S that contains interlayer space decreases by illitization and forms illite that without interlayer space (Wilson et al., 2016a; Wilson et al., 2016b; Saidian et al., 2016), thus leading to the decreases in the clay mineral swelling, the retention of fracturing fluids, and the effects on flowback water chemical properties (Zolfaghari et al., 2016; Al-Ameri et al., 2018). Furthermore, the flow properties are greatly affected by the fluid composition due to the divergences in the physical and chemical properties of different components and the interfacial interactions of different components with pore walls (Xu and Dehghanpour, 2014; Wang S. et al., 2016; Chen et al., 2016). Additionally, the fluid composition also changes along with the maturation of OM and the generation of lighter hydrocarbons, leading to the increase of the mobility of shale oil (Wang et al., 2022). Ion is the other chemical additive that is important for the efficient production of shale resources. Previous studies have confirmed that the wettability of mineral surfaces or bulk rocks is significantly affected by brine (Chen et al., 2018a; Chen et al., 2018b; Zeng et al., 2019). In summary, evaluation of the hydraulic fracturing and production performance of shale resources need to consider not only the brittleness of minerals but also the characteristics and properties of pores and surfaces. In addition, diagenesis, shale oil composition, and chemical composition of fracturing and flooding fluids are also important factors that need to be paid more attention in the future.

 Conclusion

In this study, shales samples were collected from different sections and were detected by XRD, N2 adsorption, EGME adsorption, and mercury intrusion methods to analyze the characteristics of pores and surfaces and their potential effects on fluid flow from shale formation to hydraulic fractures. The main conclusions were listed as below:

1) The shales from Es3 middle and Es3 lower contain more clay minerals (especially I/S) and less carbonate minerals than those of Es4 upper. Clay minerals mainly contribute to pore development, and carbonate minerals inhibit pore development. More importantly, the contributions of clay minerals to pores with different diameter ranges differ according to sections, and we attribute these divergences to clay mineral composition. All kinds of surface areas are mainly sourced by clay minerals, while I/S correlates positively to surface areas and illite correlates negatively to surfaces areas, especially for ISA.

2) Pores with smaller diameters present larger outer surface area while large pores contribute minor to surface area. The shales from Es3 middle and Es3 lower are mainly composed of smaller pores, leading to the larger surface areas and steeper slope between pore volume and surface area.

3) Mineral composition, fluid composition, pore structure, and surface properties are the factors that need to be considered for the evaluation of fluid flow in shale formation. The shales with high carbonate and illite content, larger total pore volume, larger pores, and smaller surface areas present better shale oil accumulation and fluid flow conditions. To better evaluate shale oil flow and production potential, fluid compositions of both the fracturing fluids and shale oil need more concern in the future.

Data Availability Statement

The original contributions presented in the study are included in the article/Supplementary Material, and further inquiries can be directed to the corresponding author.

 Author Contributions

XL: conceptualization, methodology, investigation, data curation, formal analysis, writing—original draft preparation, writing—review and editing. JC: conceptualization, resources, supervision, project administration, methodology. BG: methodology, data curation, writing—review and editing. SL: resources, funding acquisition. DF: funding acquisition, project administration. ZP: resources. BG: data curation. All authors contributed to the article and approved the submitted version.

 Conflict of Interest

XL, BG, SL, DF, and ZP were employed by SINOPEC.

The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

 Publisher’s Note

All claims expressed in this article are solely those of the authors and do not necessarily represent those of their affiliated organizations, or those of the publisher, the editors, and the reviewers. Any product that may be evaluated in this article, or claim that may be made by its manufacturer, is not guaranteed or endorsed by the publisher.

We sincerely thank the Shengli Oil field, SINOPEC, for sampling. We also thank the experimental research center of Wuxi Research Institute of Petroleum Geology of SINOPEC for N2 adsorption and mercury intrusion detections.

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