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. 2024 Mar 12;9(12):13764–13781. doi: 10.1021/acsomega.3c08330

Chemical and Geological Properties of Shale Gas: In Situ Desorption of Lower Cambrian Niutitang Shale in the Micangshan Tectonic Zone of South Shaanxi, China

Xiaotao Zhang †, Bin Shen †,*, Tao Tian ‡,*, Shizhen Li §, Xuemin Xu †, Jiajia Yang †, Weilin Sun †, Jing Qin †
PMCID: PMC10976364  PMID: 38559952

Abstract

graphic file with name ao3c08330_0019.jpg

Shale gas was recently found in the Lower Cambrian Niutitang Formation (LCNF) of the Micangshan tectonic zone of south Shaanxi (MTZSS), but not in commercial quantities. To determine the laws governing the generation, enrichment, and desorption of shale gases in overmatured shale strata in the LCNF of MTZSS, we carried out in situ desorption experiments on nine shale core samples and got 168 desorbed gas samples at different phases of desorption. Also measured were the chemical and carbon isotopic compositions of these desorbed gas samples and the geochemical parameters of the shale core samples. CH4 was the predominant hydrocarbon shale gas identified in the 82.06–98.48% range, suggesting that the gases were mainly dry. The nonhydrocarbon gases found were CO2 and H2. The CH4 content of the desorbed gas samples dropped continuously during desorption, lowering the dryness index to 98.48 and 92.26% of the first and last desorbed shale gas, respectively. The change in the gas ratio during shale gas desorption proved that the adsorbability of the LCNF to the various gases follows the trend H2 > CO2 > C2H6 > CH4 > He. Further, δ13C2H6 and δ13CH4 become heavier during desorption, showing isotopic fractionation arising from the desorption-diffusion coeffect. As the desorption temperature increases, the value of δ13CH4 increases because 12CH4 is more sensitive to temperature than 13CH4, so it is with the ethane. Similar to the LCNF shale gas in other areas of China, the desorbed shale gases are characteristic of carbon isotope reversal (CIR) (δ13CH4 > δ13C2H6). The cracking of the residual soluble organic matter at the high overmaturity stage mixed with the cracking of kerogen at the early stage of maturation, causing CIR. Furthermore, the desorbed gas content was proportionally and inversely related to the CIR degree and final dryness index of the desorbed gas, respectively. Moreover, the carbon isotope fractionation degree of CH4 and δ13C1 of the last desorbed gas correlated positively with the desorbed gas content and the desorbed time of the gas. In conclusion, the four parameters are effective parameters for identifying shale gas sweet spots.

1. Introduction

Shale gas is a natural gas preserved at its site of origin.1 It has become an essential part of China’s energy resource since the commercial exploitation of shale gas at the Upper Odovician Wufeng and Lower Silurian Longmaxi Formations was successfully implemented in the Sichuan Basin.2−4 Examples of such gas fields are Fuling (the largest shale gas field in China) and Weiyuan-Changning shale gas fields. The Lower Cambrian Niutitang Formation (LCNF), also called the Qiongzhusi Formation or Shuijingtuo Formation, is currently the shale gas of interest in potential strata in China, aside from the Upper Ordovician Wufeng and Lower Silurian Longmaxi Formations. There were significant LCNF shale gas exploration breakthroughs in the Sichuan Basin and its periphery in the past years.3−10 However, the shale gas production of the Wufeng and Silurian Longmaxi Formation is much higher than that of the LCNF, having negligible commercial development.11 In recent years, the LCNF shale gas exploration in MTZSS suggests that the LCNF is ideal for exploration.10,12−14

Shale gas is composed of free, adsorbed, and dissolved gases.7,15 Several researchers have reported that shale gas exists predominantly in adsorbed and free states, with minimal dissolved forms.16 Generally, adsorbed gas accounts for 20–85% of total shale gas content.17 Consequently, it is vital to understand the adsorption–desorption phenomenon of shale gas toward production and commercialization.18 In situ desorption of core samples in well sites using a shale gas desorption apparatus is often adopted to study shale gas desorption behavior.5,8,19,20 Afterward, chemical and isotopic changes of the constituent gases inform on the shale gas-bearing properties,21 the proportion of free and adsorbed gas,6,22 production,9,23 and the genetic sources.9,19,20

Shale gas predominantly consists of methane (>94%), with fewer amounts of relatively high molecular weight hydrocarbon gases, such as (CH4, C2H6, and C3H6), and minimum quantities of nonhydrocarbon gases, e.g., CO2 and N2.24 However, many scholars have reported different gas components during production and desorption caused by the various adsorbability of the constituents.5,9,20,25 Because different gas components with different molecular sizes show varying adsorption affinities in the microporous shales,25 the ratios of different gas components indicate different variation trends with increasing desorbed time and temperature, for example, C2H6/CH4 and have a generally rising trend with increasing desorbed time and temperature, whereas the CO2/C2H6 ratio has a decreasing trend with increasing desorbed time and temperature, elucidating that the order of the shale’s absorption capacity for CH4, C2H6, and CO2, is determined as CO2> C2H6> CH4.5,9,20,25

The carbon isotopic values of the constituent gases are closely correlated with the evolutional thermal degree of the source rocks. The values are commonly utilized to distinguish coal-derived gas from shale-derived gas and thermogenic gas from biogenic gas.19,26−30 More so, the carbon isotope fractionation has a profound impact on the carbon isotopic values.5,8,20,25,31−34 The major factors affecting carbon isotope fractionation include the gas molecular weight,35,36 physical properties of shales,8,32,37 gas ratio,33 and adsorption–desorption properties.20,34,38

Several shale gas exploration and production events have discovered CIR widely,8,9,19,20,39−42 even in a shale gas reservoir in North America.39,41 It was concluded that carbon isotope influences high shale gas production.9 Although the genesis of CIR is controversial, it can be classified into four categories: (a) the secondary cracking of oils accompanied by kerogen cracking;9,20,40,42,43 (b) the reaction between the shale kerogen and inorganics;39,44 (c) the molecular diffusion of shale gas;36,45 and (d) the adsorption–desorption behavior of shale gas.20 The mixed gases derived from both the cracking of oils and kerogen are the most accepted opinion in interpreting the CIR. Moreover, gas wetness,39,40 the role of water in hydrocarbon cracking,39,44 and high maturity shale in a closed system39,42,46 are the other factors influencing CIR. These factors are linked to the secondary cracking of oils accompanied by kerogen cracking. Therefore, the CIR is influenced by multiple parameters.

Presently, studies on shale gas of LCNF in MTZSS focus mainly on the relationship between Paleo-oxygen facies and organic matter enrichment,14,47,48 hydrocarbon generation and accumulation of shale gas,13 organic geochemical characteristics and the concomitant evaluation of shale source rocks,10,49,50 reservoir characteristics of shale gas,49,51,52 gas-bearing properties (total shale gas content),49 and tectonic movement.53,54 So far, no studies have been carried out on the compositional and isotopic characteristics of shale gas of LCNF in the MTZSS.

In the current study, desorbed gas samples were obtained using in situ desorption in the drilling site for shale gas exploration of the LCNF in MTZSS. Then, the gas samples were tested for chemical and carbon isotopic compositional changes during desorption. We explored the laws governing the generation, enrichment, and desorption of shale gases in overmatured shale strata, Also, we determined the order of the LCNF shale’s absorption capacity for different gas components in MTZSS and proposed the CIR degree and final dryness index of the desorbed gas, the δ13C1 and gas dryness index of the last desorbed gas samples can be effective indicators for identifying shale gas sweet spots. Our findings provide significant geological indications for further exploration and development of the LCNF shale gas in MTZSS.

2. Sampling and Experiments

2.1. Sampling

For this study, nine shale core samples of the SZY1 Well were collected, and 168 desorbed gas samples of the corresponding shale core samples were obtained through in situ desorption experiments during shale gas exploration of LCNF in the MTZSS. The Micangshan tectonic zone, consisting of five Secondary tectonic units, lies in the northern part of the Yangtze Platform. It is regarded as a transitional belt between the Sichuan Basin and Qinling Orogenic Belts54 (Figure 1). By studying the Early Cambrian small skeletal fossils, previous studies have reported that the early Cambrian of the Micangshan tectonic zone is an independent terrane rather than a part of the Upper Yangtze region.22 The Niutitang Formation deposited black carbonaceous shale, with small amounts of gray-black shale and gray-black calcareous shale at the top and bottom, respectively. The LCNF shales of SZY1 Well, located in the east margin of Micangshan Uplift in MTZSS (Figure 1).

Figure 1.

Figure 1

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Locations of the Micangshan tectoni zone and the SZY1 well.

2.2. In Situ Shale Gas Desorption

A Petroleum and Natural Gas Industry Standard of the People’s Republic of China “SY/T 6940–2020 Measurement method of shale gas content” was adopted for carrying out the in situ shale gas desorption measurements and calculating the gas content of shale samples. The in situ shale gas desorption experiments were carried out immediately after the shale core samples exited the core barrel and were sealed in the desorption canisters. The instrument for in situ shale gas desorption consists of heating, automatic metering, and data collection and processing parts (Figure 2). The whole workflow and working principle for measuring desorbed gas content are as follows: the core sampled from the wellbore of the drilling site was quickly put into a canister filled with saturated saltwater. The canister was covered tightly and sealed. The sealing time was recorded. After that, the pipe of the automatic meter was quickly plugged into the connector of the desorption canister. Meanwhile, the temperature controller was set in place.

Figure 2.

Figure 2

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Schematic diagram of the instrument for shale gas desorption and in situ shale gas desorption experiments in the MTZSS (PLC = programmable logic controller).

The desorbed gas from the canister entered the glass tube filled with water through the inlet valve, resulting in a pressure difference between the water tube and the water container. The information was fed to the Programmable logic controller (PLC), which rapidly transmitted the processed signal to the servo motor. The motor then drove the ball screw to rotate, pushing the water container down and keeping the liquid level of the glass tube and the water container consistent. When the water container drops about 2/3 of the glass tube length, the inlet valve is closed. In contrast, the outlet valve is opened to discharge the desorbed gas collected in the gas bag if necessary. The liquid level of the glass tube and the water container rose and returned to the zero interface. Then, the desorbed gas was quantitated according to the PLC data using eq 1:

2.2.

where, Vd is the volume of desorbed gases, d is the diameter of the glass tube, and D is the descending distance of the water container. All real-time data from PLC were transmitted to the computer, and specialized software recorded, further processed, and visualized the data. Also, variation trends, such as the trend of desorbed gas content and desorption temperature with desorbed time, were observed.

According to the heating procedure, the shale gas desorption experiment was divided into three phases: In Phase I, the desorption temperature was maintained at mud temperature (30 °C) for 3 h; in Phase II, the desorption temperature was raised to strata temperature (60 °C) over 1 h and maintained for 10 h; In Phase III, the desorption temperature was further elevated to 80 °C over 1 h and then held until the desorption ended. At 80 °C, prompt shale gas desorption was ensured without delaying the drilling. Moreover, the lasting desorbed time differs among the shale core samples because of the differences in the drilling time.

2.3. Laboratory Experiments

Laboratory experiments were performed at the National Research Center for Geoanalysis (NRCGA) in Beijing, China. Rock-eval pyrolysis and TOC measurements were conducted using a Rock-Eval 6 instrument and LECO CS-230H carbon/sulfur analyzer, respectively.55 The shale samples were crushed to 1–2 mm particles, then coldly embedded with epoxy resin, and the surface of the thin section needed to be polished to no mechanical scratches by using an automatic polishing machine. After that, a Zeiss Axioimager II microscope system equipped with an ultraviolet light source and Diskus-Fossil system carried out the Rb measurements and maceral observation,56−58 and two Petroleum and Natural Gas Industry Standards of the People’s Republic of China-“SY/T 5124-2012 Method of determining microscopically the reflectance of vitrinite in sedimentary” and “SY/T 6414-2014 Maceral identification and statistical methods on polished surfaces of whole rocks” were adopted to determine the Rb and maceral observation of shale samples. Based on these two standards, the number of particles counted for Rb and maceral observation should not be less than 30 points and 800 points, respectively. In addition, the chemical composition of the desorbed shale gas was examined using an Agilent7890 B Gas Chromatography (GC) System equipped with two thermal conductivity detectors (TCD) and one flame ionization detector (FID).20

A coupled system consisting of an Agilent 7890B gas chromatograph, an Elementar Isoprime Precision isotope mass spectrometer, and an Elementar GC5 pyrolyzer determined the carbon isotope composition of the desorbed gases. Split injection mode was used in this system with a split ratio of 1:3 and an injection temperature of 300 °C. The gas components were separated by a PLOT-Q column (30 m × 0.32 mm × 20 μm) and carried by He gas at a 1.2 mL/min constant flow rate. The gases were converted to CO2 in a furnace set at 940 °C. The oven temperature was initially fixed at 40 °C for 6 min before it was elevated to 150 °C at a heating rate of 30 °C/min and held for 1 min. Vienna Pee Dee Belemnite (VPDB) standard calibrated the system. The measurement precision was ±0.5‰ for δ13C.

3. Results and Discussion

3.1. Geochemical Characteristics of Shale Samples

The LCNF shales of the the SZY1 well have an average total organic carbon (TOC) content of 4.31% (range = 2.78–8.35%). The average S1 + S2 ranged from 0.08 to 0.24 mg/g (Table 1) and was high over maturity with a vitrinite equivalent reflectance (Requiv) range of 2.44–2.78%. The Requiv is based on the bitumen reflectance (Rb) equation proposed by previous researchers55 (Table 1). The Requiv values agree with the Niutitang shales (1.51–3.19%) reported for the outcrop samples from the Micangshan Tectonic zone.50 Additionally, maceral analysis of shale core samples indicated the LCNF shale of the study area is classified as type I kerogen (Table 1), a good gas source because the oils cracked to wet gas when Ro is >1.4%. In comparison, all condensate-rich gases cracked to dry gas when Ro is >2.0%.56

Table 1. Basic Geochemical Data of the Shale Sample and Testing Results of Desorbed Shale Gasa.

sample ID depth (m) TOC/% S1 + S2/ (mg/g) Rb/% Requvi/% desorbed gas content (cm3/g) total gas content (cm3/g) kerogen type δ13C1F/‰ δ13C2F/‰ δ13C1L/‰ δ13C2L/‰ δ13C1L21/‰
SZY1–1 1950.74–1951.00 3.20 0.10 3.34 2.59 1.13 2.55 I –28.90 –37.29 –16.78 –33.87 –16.78
SZY1–2 1962.03–1962.31 2.78 0.12 3.42 2.64 0.95 1.34 I –30.19 –37.53 –21.63 –33.40 –24.15
SZY1–3 1970.38–1970.64 8.35 0.24 3.28 2.55 2.27 3.49 I –29.79 –37.78 –4.00 –32.17 –8.07
SZY1–4 1979.36–1979.61 6.81 0.18 3.18 2.48 2.50 3.81 I –33.41 –37.41 –1.45 –33.17 –5.62
SZY1–5 1990.22–1990.49 2.95 0.08 3.28 2.55 1.02 1.47 I –31.74 –38.51 –10.87 –32.01 –14.15
SZY1–6 2000.67–2000.87 4.17 0.11 3.41 2.64 1.50 2.48 I –25.73 –37.53 –1.82 –32.71 –5.61
SZY1–7 2009.91–2010.19 3.46 0.09 3.13 2.44 1.03 1.57 I –32.89 –38.19 –2.97 –32.31 –11.30
SZY1–8 2014.86–2015.14 2.97 0.09 3.53 2.72 1.19 1.77 I –31.93 –36.26 –5.27 –33.92 –12.98
SZY1–9 2023.61–2023.89 4.12 0.12 3.63 2.78 1.50 2.22 I –30.92 –38.44 –6.89 –33.82 –14.06
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a

δ13C1F = the value of δ13C1 of the first desorbed shale gas sample, δ13C2F = the value of δ13C2 of the first desorbed shale gas sample, δ13C1L = the value of δ13C1 of the last desorbed shale gas sample, δ13C2L = the value of δ13C2 of the last desorbed shale gas sample, δ13C1L21= = the value of δ13C1 of desorbed shale gas sample with desorbed time of about 21 h.

3.2. Gas-Bearing Properties of Shale

In situ gas desorption experiments examined the desorbed gas from nine shale core samples collected from the LCNF of the SZY1 Well. Based on the method established by USBM (1973), the scattered or disappeared gas constituents lost between core drilling and core canister sealing were as tagged as lost gas. Also, at the end of the desorption, the gas reserved in the disconnected pores could be released by desorption. Hence, it was termed residual gas; it is negligible. Consequently, the desorbed gas and lost gas were considered when the total gas content.

The mean (range) of the desorbed gas and total gas contents of the nine shale samples were 1.45 (0.95–2.50) and 2.30 (1.34–3.81) cm3/g, respectively (Table 1). According to the evaluation criteria for the gas content of LCNF shale suggested by a previous study,49 five shale samples belonged to the gas-rich shale category while the other four were high-gas shale, indicating LCNF in south Shanxi is the favorable stratum for exploration. Figure 3 shows a strong positive linear correlation between desorbed gas content and TOC (2.78–8.35%), a common phenomenon already reported.8,59

Figure 3.

Figure 3

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Crossplot of desorbed shale gas content versus TOC of shale core samples.

3.3. Adsorbability of the Shale Toward Various Gases

3.3.1. Constituents of the Desorbed Gases

The 169 gas samples obtained from the desorption phases were analyzed by GC. Air mixing with shale gas is unavoidable during the desorption experiment (Li et al., 2021). Figure 4 shows that the N2 content correlated positively with the O2 content, and N2/O2 (mean of 2.33) varies between 1.89 and 3.45, lower than the 3.72 found in the air. Based on N2/O2, N2 was completely removed, while some of the O2 content was retained. However, previous studies reported that no O2 exists in the LCNF shale gas.5,8,9,25 Therefore, N2 and O2 were removed in this study, normalizing the remaining gases to 100% (Table 2).

Figure 4.

Figure 4

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Crossplot of N2 and O2 contents of desorbed shale gas samples.

Table 2. Geochemical Characteristics of Shale Gases Derived from the In Situ Desorption Experiments of the Niutitang Formation Shale of the SZY1 Well.
core sample ID gas sample ID sampling time (h) main component (vol, %)
 C1/C1–5 C1/(C2 + C3) ln(C1/C2) ln(C2/C3) δ13C PDB (‰)
He H2 CH4 C2H6 CO2 C3H8 CH4 C2H6
SZY1–1 1 0.53   0.01 97.45 2.50 0.04   97.50 39.02 3.66   –28.90 –37.29
2 1.69   0.04 97.22 2.67 0.07   97.33 36.47 3.60   –26.77 –36.25
3 2.83   0.06 97.28 2.59 0.07   97.41 37.54 3.63   –25.78 –36.48
4 3.85   0.07 97.40 2.45 0.08   97.55 39.76 3.68   –23.55 –35.12
5 4.94   0.08 97.31 2.51 0.10   97.49 38.78 3.66   –24.58 –35.83
6 6.34   0.10 97.20 2.62 0.09   97.38 37.15 3.61   –24.08 –35.80
7 8.31   0.12 97.19 2.59 0.10   97.40 37.46 3.62   –22.57 –34.30
8 11.39   0.16 97.09 2.65 0.11   97.35 36.68 3.60   –21.12 –34.79
9 14.38   0.20 96.28 3.31 0.21   96.68 29.08 3.37   –18.64 –35.02
10 17.14   0.46 93.96 5.12 0.45   94.83 18.34 2.91   –17.70 –36.48
11 20.94   0.83 93.69 5.01 0.47   94.92 18.70 2.93   –16.78 –33.87
SZY1–2 1 0.48 0.03 0.03 98.47 1.44 0.03   98.56 68.33 4.22   –30.19 –37.53
2 1.60 0.03 0.02 98.55 1.36 0.03   98.64 72.36 4.28   –29.36 –36.09
3 2.87 0.02 0.02 98.59 1.33 0.03   98.67 74.22 4.31   –30.26  
4 3.93 0.02 0.02 98.10 1.84 0.03   98.16 53.42 3.98   –21.72  
5 4.81 0.01 0.03 97.61 2.30 0.03   97.69 42.37 3.75   –28.18 –36.50
6 5.89 0.01 0.05 97.69 2.20 0.04   97.80 44.36 3.79   –27.83 –34.92
7 7.11 0.01 0.07 97.70 2.19 0.04   97.81 44.67 3.80   –27.29 –34.83
8 8.43 0.01 0.08 97.97 1.89 0.05   98.10 51.76 3.95   –25.34 –33.77
9 10.22 0.01 0.09 97.75 2.11 0.04   97.89 46.28 3.83   –26.62 –35.71
10 12.46 0.01 0.12 97.70 2.15 0.03   97.84 45.40 3.82   –26.20 –36.60
11 14.48   0.17 96.72 3.07 0.04   96.93 31.55 3.45   –25.81 –35.12
12 16.52   0.34 96.05 3.54 0.07   96.45 27.14 3.30   –25.06 –35.13
13 19.47   0.47 96.32 3.13 0.08   96.85 30.78 3.43   –24.15 –33.96
14 22.25   0.54 96.59 2.78 0.09   97.20 34.76 3.55   –25.10 –33.94
15 26.92   0.60 96.09 3.20 0.10   96.77 30.00 3.40   –23.04 –33.58
16 36.03   0.67 96.60 2.62 0.12   97.36 36.91 3.61   –21.63 –33.40
SZY1–3 1 0.01   0.02 98.65 1.30 0.03   98.69 75.60 4.33   –29.79 –37.78
2 0.48   0.00 98.33 1.65 0.02   98.35 59.67 4.09   –30.46 –36.99
3 1.44   0.01 98.16 1.81 0.03   98.19 54.36 4.00   –28.70 –36.98
4 2.20   0.01 98.10 1.87 0.02   98.13 52.39 3.96   –26.42 –35.06
5 2.88   0.01 98.13 1.83 0.03   98.17 53.69 3.98   –24.00 –34.56
6 3.66   0.01 97.48 2.49 0.02   97.51 39.19 3.67   –25.94 –35.45
7 4.37   0.05 95.75 4.15 0.02 0.03 95.82 22.92 3.14 5.07 –23.80 –35.35
8 5.23   0.13 95.13 4.67 0.02 0.04 95.28 20.18 3.01 4.75    
9 5.54   0.13 95.13 4.67 0.02 0.04 95.28 20.18 3.01 4.75    
10 6.23   0.21 95.24 4.49 0.03 0.04 95.46 21.03 3.05 4.82 –19.94 –35.48
11 7.28   0.27 95.27 4.40 0.03 0.03 95.56 21.51 3.08 4.90 –18.26 –35.33
12 8.33   0.31 95.27 4.35 0.03 0.03 95.60 21.75 3.09 4.99 –16.73 –36.57
13 9.48   0.37 94.99 4.57 0.03 0.04 95.37 20.60 3.03 4.81 –17.52 –35.61
14 11.07   0.46 94.84 4.64 0.03 0.04 95.30 20.28 3.02 4.82 –16.34 –35.26
15 13.08   0.58 94.67 4.69 0.03 0.04 95.25 20.05 3.01 4.87 –14.23 –34.91
16 14.50   0.61 93.27 6.02 0.04 0.07 93.87 15.32 2.74 4.47 –14.23 –35.31
17 15.44   0.78 90.61 8.43 0.05 0.13 91.37 10.59 2.37 4.19 –13.01 –35.06
18 17.33   1.68 88.86 9.25 0.07 0.14 90.44 9.46 2.26 4.17 –10.85 –34.71
19 22.45   2.17 88.09 9.50 0.09 0.14 90.13 9.13 2.23 4.19 –8.07 –33.67
20 29.73   2.53 88.13 9.10 0.11 0.13 90.53 9.56 2.27 4.28 –6.22 –33.09
21 35.64   2.72 87.94 9.10 0.13 0.10 90.53 9.56 2.27 4.47 –4.00 –32.17
SZY1–4 1 0.13   0.00 98.36 1.61 0.02   98.39 60.94 4.11   –33.41 –37.41
2 0.52   0.00 98.17 1.79 0.03   98.21 54.73 4.00   –40.91  
3 1.05   0.01 97.99 1.98 0.02   98.02 49.48 3.90   –31.17 –38.14
4 1.60   0.01 98.00 1.97 0.02   98.03 49.76 3.91   –27.55 –37.11
5 2.10   0.01 98.12 1.85 0.03   98.15 53.10 3.97   –28.54 –36.89
6 2.65   0.01 98.04 1.92 0.03   98.08 50.99 3.93   –27.96 –37.84
7 3.31   0.01 98.23 1.72 0.04   98.28 57.20 4.05   –26.73 –37.73
8 3.98   0.03 96.64 3.30 0.03   96.70 29.32 3.38   –25.11 –36.57
9 4.70   0.11 95.20 4.64 0.04   95.35 20.50 3.02   –22.39 –36.51
10 5.67   0.22 95.10 4.63 0.05   95.36 20.54 3.02   –22.07 –38.34
11 6.70   0.27 95.08 4.56 0.05 0.05 95.38 20.64 3.04 4.61 –19.23 –37.17
12 7.75   0.33 95.25 4.36 0.05   95.62 21.86 3.08   –14.59 –35.54
13 8.91   0.38 95.01 4.56 0.05   95.42 20.84 3.04   –14.36 –35.31
14 10.22   0.45 94.87 4.59 0.05 0.04 95.35 20.49 3.03 4.71 –17.55  
15 12.09   0.55 94.79 4.56 0.06 0.04 95.37 20.62 3.03 4.77 –12.84 –35.81
16 13.95   0.66 93.85 5.43 0.06   94.53 17.27 2.85   –11.48 –35.76
17 15.36   0.84 90.93 8.12 0.12   91.80 11.20 2.42   –10.58 –35.01
18 17.43   1.57 88.25 10.02 0.16   89.81 8.81 2.18   –9.21 –35.34
19 22.34   2.22 88.02 9.58 0.18   90.18 9.19 2.22   –5.62 –35.42
20 32.45   2.42 89.19 8.21 0.19   91.58 10.87 2.39   –2.62 –33.39
21 34.95   2.64 86.44 10.59 0.33   89.08 8.16 2.10   –1.55 –32.66
22 41.90   3.07 84.38 12.10 0.46   87.46 6.98 1.94   –1.45 –33.17
SZY1–5 1 0.28   0.02 98.14 1.82 0.02   98.18 53.89 3.99   –31.74 –38.51
2 0.98   0.01 98.09 1.87 0.02   98.13 52.38 3.96   –30.26 –35.72
3 2.02   0.02 98.09 1.87 0.02   98.13 52.37 3.96   –28.40 –36.39
4 3.17   0.02 98.06 1.89 0.03   98.11 51.96 3.95   –27.68 –35.82
5 4.15   0.04 96.65 3.29 0.02   96.71 29.41 3.38   –27.39 –36.60
6 5.09   0.16 95.99 3.82 0.03   96.18 25.15 3.22   –25.02 –35.69
7 6.16   0.23 95.69 4.06 0.02   95.93 23.57 3.16   –24.06 –35.65
8 7.25   0.30 95.59 4.09 0.02   95.90 23.39 3.15   –22.89 –35.01
9 8.67   0.38 95.65 3.94 0.03   96.04 24.26 3.19   –21.82 –35.38
10 11.03   0.45 95.69 3.82 0.04   96.16 25.06 3.22   –19.65 –34.59
11 14.64   0.52 95.83 3.61 0.04   96.37 26.55 3.28   –18.36 –34.97
12 15.78   0.61 93.97 5.37 0.05   94.60 17.51 2.86   –17.08 –34.17
13 17.79   1.04 92.07 6.83 0.07   93.10 13.49 2.60   –15.97 –33.86
14 21.07   1.37 90.94 7.61 0.08   92.28 11.95 2.48   –14.15 –33.84
15 35.21   1.46 91.96 6.46 0.11   93.43 14.23 2.66   –10.87 –32.01
SZY1–6 1 0.22   0.00 98.73 1.24 0.02   98.76 79.51 4.38   –25.73 –37.53
2 0.68   0.01 98.51 1.45 0.02   98.55 67.73 4.22   –29.84 –36.98
3 1.32   0.00 98.37 1.61 0.02   98.39 61.28 4.12   –28.15 –34.90
4 2.05   0.01 98.41 1.56 0.03   98.44 63.11 4.14   –25.51 –36.95
5 2.73   0.01 98.48 1.47 0.04   98.53 67.05 4.21   –23.97 –36.55
6 3.45   0.01 97.90 2.06 0.03   97.94 47.47 3.86   –24.05 –35.61
7 4.51   0.11 95.67 4.18 0.04   95.81 22.87 3.13   –19.59 –34.80
8 5.85   0.19 95.45 4.32 0.03   95.67 22.09 3.10   –18.54 –34.87
9 7.92   0.30 95.46 4.20 0.04   95.79 22.74 3.12   –14.85 –34.56
10 12.10   0.45 95.61 3.89 0.06   96.09 24.59 3.20   –12.00 –34.27
11 14.41   0.62 94.99 4.32 0.07   95.65 22.00 3.09   –8.65 –33.67
12 15.78   0.75 91.71 7.47 0.07   92.47 12.28 2.51   –8.26 –33.51
13 19.20   1.36 90.08 8.47 0.10   91.41 10.64 2.36   –5.61 –33.19
14 33.80   2.30 88.65 8.93 0.12   90.85 9.93 2.30   –1.82 –32.71
SZY1–7 1 0.28   0.01 98.71 1.25 0.03   98.75 78.91 4.37   –32.89 –38.19
2 0.85   0.01 98.48 1.49 0.02   98.51 66.17 4.19   –30.84 –37.09
3 1.37   0.01 98.45 1.52 0.02   98.48 64.67 4.17   –28.58 –35.88
4 2.07   0.01 98.44 1.53 0.03   98.47 64.40 4.17   –28.50 –36.95
5 3.29   0.01 98.42 1.53 0.03   98.46 64.12 4.16   –26.37 –37.22
6 4.23   0.02 98.18 1.78 0.03   98.22 55.15 4.01   –26.38 –36.80
7 4.61   0.02 97.30 2.66 0.02   97.34 36.64 3.60   –25.67 –36.11
8 4.99   0.05 96.67 3.25 0.03   96.75 29.77 3.39   –25.77 –36.53
9 5.49   0.10 96.11 3.77 0.02   96.23 25.50 3.24   –24.57 –36.98
10 6.20   0.16 96.15 3.66 0.03   96.34 26.31 3.27   –22.86 –34.62
11 7.23   0.22 95.93 3.83 0.03   96.17 25.08 3.22   –21.25 –34.55
12 8.80   0.29 95.87 3.80 0.03   96.18 25.20 3.23   –19.39 –35.57
13 11.35   0.39 95.71 3.87 0.03   96.12 24.75 3.21   –17.05 –35.95
14 14.10   0.51 94.83 4.63 0.04   95.34 20.48 3.02   –15.61 –35.03
15 16.43   0.77 91.99 7.19 0.05   92.75 12.80 2.55   –14.55 –35.29
16 19.65   1.34 92.09 6.50 0.08   93.41 14.17 2.65   –11.30 –33.53
17 24.76   1.61 90.73 7.59 0.08   92.28 11.96 2.48   –9.58 –34.36
18 36.43   1.91 91.14 6.85 0.09   93.01 13.31 2.59   –5.61 –32.68
19 45.90   2.13 89.22 8.48 0.17   91.32 10.52 2.35   –2.97 –32.31
SZY1–8 1 0.11   0.04 98.75 1.18 0.03   98.82 83.75 4.43   –31.93  
2 0.36   0.01 98.89 1.09 0.02   98.91 91.11 4.51   –31.27  
3 0.56   0.01 98.82 1.15 0.02   98.85 85.82 4.45   –31.80  
4 0.83   0.00 98.73 1.24 0.02   98.76 79.37 4.37   –31.00  
5 1.21   0.00 98.68 1.29 0.02   98.71 76.32 4.33   –30.08  
6 1.78   0.00 98.69 1.28 0.03   98.72 77.00 4.34      
7 2.76   0.00 98.60 1.38 0.02   98.62 71.65 4.27   –27.58 –36.26
8 3.64   0.01 98.29 1.68 0.02   98.32 58.36 4.07   –25.93 –39.75
9 4.14   0.01 97.51 2.46 0.02   97.54 39.66 3.68   –26.88 –36.46
10 4.70   0.03 96.99 2.96 0.02   97.04 32.81 3.49   –26.30 –37.56
11 5.55   0.05 96.96 2.96 0.03   97.03 32.71 3.49      
12 6.59   0.06 96.98 2.93 0.03   97.07 33.14 3.50   –22.77 –36.40
13 7.89   0.09 96.82 3.07 0.03   96.93 31.57 3.45   –21.80 –36.85
14 9.67   0.11 97.12 2.74 0.04   97.26 35.46 3.57   –19.70 –36.40
15 11.29   0.13 97.36 2.47 0.05   97.53 39.49 3.68   –18.92 –35.48
16 12.56   0.15 97.00 2.81 0.05   97.19 34.56 3.54   –18.55 –36.59
17 14.26   0.18 96.94 2.83 0.05   97.17 34.31 3.54   –17.43 –36.04
18 14.79   0.20 96.19 3.56 0.05   96.43 27.03 3.30   –17.25 –35.75
19 15.54   0.23 94.99 4.73 0.05   95.26 20.10 3.00   –17.11 –35.40
20 16.71   0.37 94.51 5.05 0.07   94.93 18.71 2.93   –16.02 –35.01
21 18.56   0.59 93.59 5.75 0.07   94.21 16.28 2.79   –15.06 –35.27
22 21.39   0.82 93.63 5.47 0.08   94.48 17.13 2.84   –12.98 –35.42
23 27.42   1.01 92.88 6.02 0.09   93.91 15.42 2.74   –11.24 –35.19
24 34.96   1.25 93.02 5.63 0.10   94.30 16.53 2.81   –8.35 –34.57
25 41.76   1.42 91.25 7.16 0.17   92.73 12.75 2.55   –5.27 –33.92
SZY1–9 1 0.17   0.01 98.68 1.28 0.02   98.71 76.82 4.34   –30.92 –38.44
2 0.63   0.01 98.38 1.59 0.02   98.41 61.93 4.13   –29.37 –38.72
3 1.13   0.01 98.34 1.63 0.02   98.37 60.26 4.10   –28.32  
4 1.61   0.01 98.31 1.66 0.02   98.34 59.23 4.08   –29.14 –38.40
5 2.28   0.01 98.34 1.63 0.02   98.37 60.34 4.10   –28.18 –38.25
6 3.18   0.01 98.38 1.59 0.03   98.41 61.91 4.13   –26.77 –37.43
7 3.97   0.01 96.89 3.08 0.02   96.92 31.47 3.45   –26.05 –38.09
8 4.65   0.04 95.99 3.95 0.02   96.05 24.29 3.19   –26.14 –38.40
9 5.52   0.05 96.15 3.77 0.03   96.23 25.49 3.24   –24.85 –37.67
10 6.62   0.06 96.24 3.67 0.03   96.33 26.25 3.27   –19.72 –37.01
11 7.86   0.07 96.34 3.56 0.03   96.43 27.04 3.30   –22.77 –37.33
12 9.27   0.09 96.38 3.50 0.03   96.49 27.50 3.31   –21.13 –37.68
13 11.18   0.10 96.79 3.07 0.04   96.93 31.54 3.45   –19.23 –36.48
14 12.33   0.11 96.57 3.29 0.04   96.71 29.39 3.38   –20.12 –36.79
15 13.80   0.12 96.55 3.28 0.04   96.71 29.41 3.38   –19.12 –36.53
16 14.41   0.14 94.90 4.93 0.03   95.06 19.24 2.96   –17.97 –37.38
17 16.08   0.31 92.94 6.71 0.04   93.26 13.84 2.63   –16.60 –36.68
18 18.63   0.45 93.10 6.39 0.06   93.58 14.57 2.68   –15.40 –36.31
19 20.67   0.51 93.10 6.33 0.06   93.63 14.70 2.69   –14.06 –36.08
20 23.23   0.55 93.05 6.33 0.07   93.63 14.69 2.69   –13.12 –36.04
21 27.00   0.60 93.54 5.79 0.07   94.17 16.15 2.78   –17.52  
22 32.73   0.65 93.79 5.47 0.08   94.49 17.14 2.84   –10.64 –35.21
23 48.25   0.70 92.58 6.62 0.11   93.33 13.98 2.64   –8.23 –35.03
24 59.43   1.05 90.80 8.00 0.15   91.90 11.34 2.43   –6.89 –33.82
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The desorbed gas consisted of large and small amounts of hydrocarbon and nonhydrocarbon gases, respectively. Hydrocarbon gases consisted of CH4, C2H6 and very little C3H8 which only existed in SZY1–3 and SZY1–4 core samples (Table 2, Figure 5e), whereas nonhydrocarbon gases consisted of H2, CO2 and very little He which was only detected in the SZY1–2 core sample (Table 2, Figure 5f).

Figure 5.

Figure 5

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Changes of various gas components with variation of desorbed temperature and time.

CH4 was the predominant hydrocarbon gas. Herein, the average (range) CH4 content of the first and last desorbed gas from the shale core samples were 98.18% (97.33–98.48%) and 88.38% (82.06–94.59%), respectively (Table 2, Figure 5a). Compared with the CH4 content, the C2H6 content was relatively low. The average (range) C2H6 content of the first and last desorbed gas were 1.51% (1.17–2.49%) and 7.37% (2.56–11.76%), respectively (Table 2, Figure 5b). Thus, unlike C2H6, CH4 exhibited a lowering trend (Figure 5a-b), suggesting a different adsorbability of CH4 and C2H6 onto the shale core. Additionally, C3H8 was the other hydrocarbon identified.

The nonhydrocarbon gases were H2, CO2, and He. The mean (range) CO2 content of the first and last desorbed gases were 0.03% (0.02–0.04%) and 0.21% (0.11–0.47%), respectively (Table 2, Figure 5c). At phase I of desorption, H2 was present in trace amounts (0.004–0.04%), while H2 increased to 0.67–3.07% at phase III of desorption (Table 2, Figure 5d). In general, the quantity of these two gases increased as desorption proceeded, albeit at different growth rates. In addition, He existed negligibly in phase I of desorption of the SZY1–2 sample. Hence, He was undetected in the other gas samples (Table 2, Figure 5f). Nevertheless, the He content decreased as desorption progressed, indicating that the gas has an adsorption pattern different from that of H2 and CO2.

In addition, the methane content dropped continuously during desorption, lowering the mean (range) dryness index (C1/C1–5) from 98.48% (97.50–98.82%) from the first desorbed gas to 92.26% (87.46–97.36%) of the last desorbed gas samples. However, given the overall CH4 proportion in the desorbed gas, the shale gas produced from the LCNF in MTZSS is a typical dry gas (Table 2, Figure 6).

Figure 6.

Figure 6

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Changes of the dryness index with variation of desrobed temperature and time.

3.3.2. Gas Adsorbability Sequence of Shale

Figure 5a shows that CH4 content was relatively stable, albeit showing a steady fall in Phases I and II with a constant desorption temperature. In contrast, a dramatic decrease in Phase III occurred. Contrarily, C2H6, CO2, and H2 contents were relatively stable with a steady rise in Phases I and II, while Phase III exhibited a significantly rising profile (Figure 5b–d). C2H6, CO2, and H2 contents maintained a rising trend in Phase III of the desorption. Nevertheless, C2H6, CO2, and H2 accounted for a minute proportion of shale gases relative to CH4. Therefore, it is strongly suggested that the residue gas is predominantly CH4.

Furthermore, Figure 5d,f illustrate how fast He was quickly desorbed in phases I and II, while the respective H2 amounts desorbed were negligible and minute, such as in SZY1–1, SZY1–2, SZY1–8, and SZY1–9 core samples. It is opined that the deciphered shale has a weak capacity to adsorb He but a strong capacity toward H2. In addition, the C3H8 content did not change with increasing desorption temperature, probably owing to its minimal content (Table 2, Figure 5e).

Adsorption leads to increasing shale gas storage capacity by two or more times than without adsorption.60 van der Waals forces exist between shale (adsorbent) and shale gas (an adsorbate). Hence, the shale gas adsorption onto the shale is via reversible physisorption.61 Therefore, adsorption is an exothermic process,62 whereas desorption is endothermic. One of the fundamental properties of gas molecules is the existence of intermolecular forces among them, mainly derived from electrostatic forces. The intermolecular forces cause a multilayer gas accumulation,63 forming a high-density adsorbed phase different from the free counterpart.64 In addition, higher pressure made it easier to form a multilayer of gas accumulation.65 Overall, the shale gas accumulation depends on the temperature, pressure, and properties of the adsorbate (shale gas) and adsorbent (shale).

In Phase I of desorption, the gases with weak adsorbability were desorbed faster than the gases with strong adsorbability. Hence, the content of the former (such as CH4 and He) decreased gently with desorption while those of the latter (such as C2H6, CO2, and H2) increased gradually during desorption. Figure 7a–d illustrate a significant negative correlation between the CH4 content and those of C2H6, CO2, and H2. Also, the CH4 content correlates positively with the He content, indicating similar affinities of shale toward CH4 and He, but different for C2H6, CO2, and H2.

Figure 7.

Figure 7

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Crossplots of CH4 contents versus desorbed shale gas samples.

Based on the relationship between adsorbability and desorption rate and the variations in gas ratios with desorbed time and temperature, the sequence of adsorbability of the shale toward the gases was confirmed (Figures 8a–d). H2/CO2, C2H6/CH4, and CH4/He ratios had a generally rising trend with increasing desorbed time and temperature (Figures 8a–c), demonstrating that the adsorbability of the shale toward H2 is stronger than that for CO2 and O2. The shale’s adsorbability was C2H6 > CH4 > He. As for CO2/C2H6, this ratio remained relatively steady at phases I and II before it slowly increased at phase III (Figure 8d). Such a trend shows that the sequence of adsorbability for CO2 and C2H6 was similar in phases I and II, while the counterpart was CO2 > C2H6 in phase III.

Figure 8.

Figure 8

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Change of ratios for different gas components of desrobed shale gases with variation of the desorbed temperature and time.

Moreover, the C3H8 content was limited, and the variation trend of its ratios to those of the other gases was irregular. Therefore, the sequence of adsorbability of the shale to different gases was H2 > CO2 > C2H6 > CH4 > He, which was almost consistent with previous conclusions.20,25 The order of absorption capacity of the shale from the Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation in west Hubei for different gas components is determined to be CO2 > H2 > C3H8 > C2H6 > CH4 > He. Furthermore, CO2 and C2H6 have higher adsorption affinities to the organic shales from the Lower Silurian Longmaxi Formation and the Lower Cambrian Shuijingtuo Formation in the eastern part of Chongqing than CH4, causing early desorbed gases to be relatively enriched in CH4, whereas gases desorbed later are relatively enriched in CO2 and C2H6, indicating the gas adsorbability sequence of shale was dominated by the varying molecular sizes of gas, which led to the differences of intermolecular forces. Especially for hydrocarbon gases, the accumulation of gas with big molecular size resulting in formation of a high-density adsorbed phase64 owing to the higher intermolecular forces.

The TOC variation influenced the shale’s adsorbability to gaseous hydrocarbons (Figure 3). Therefore, more hydrocarbon gas was adsorbed with the increase in the shale’s TOC. In addition, the desorbed gas content was inversely proportional to the dryness index of the last desorbed gas of each core sample (Figure 9a). Hence, the desorbed gas content increases with the decrease in dryness index at the end of desorption.20,66,67 This phenomenon is thought to be a result of the different adsorbabilities of the shale to gaseous hydrocarbons. The fundamental cause is that the more the shale gas content, the better the reservoir physical properties of shale, with more micropores for enhanced adsorbability.68 Thus, shale with a higher TOC provides more adsorption space for C2H6 and C3H8 with relatively stronger adsorbability, leading to more C2H6 and C3H8 being preserved. As a result, C2H6 and C3H8 were desorbed in large quantities at the appropriate temperature. However, the desorbed gas content did not correlate with the dryness index of the first desorbed gas of each core sample (Figure 9b) due to the relatively stronger adsorbability. It caused minute amounts of C2H6 to be present and C3H8 was released at the beginning of desorption. Consequently, the dryness index of the last desorbed gas of the core sample is a useful indicator of sweet spots for shale gas exploration and production.

Figure 9.

Figure 9

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Crossplots of desorbed shale gas content vs dryness index of the last (a) and first desrobed shale gas samples (b).

3.4. Characteristics and Affecting Factors of Carbon Isotope Fractionation during Desorption

3.4.1. Characteristics of the Carbon Isotope of the Desorbed Gases

The average δ13C1 (−30.51‰) and δ13C2 (−37.66‰) values of the first desorbed sample were minimal, ranging between −33.41 and −25.73‰ (Table 1, Figure 10a) and between −38.50 and −36.26‰, (Table 1, Figure 10b), respectively. The δ13C1 of the desorbed samples gradually increased as the desorption was completed, which is ascribed to the enrichment of 13CH4 as desorption proceeded. Overall, the δ13C2 trend was similar to that of CH4, with some frequent fluctuations (Table 1, Figure 10a). The value of δ13C1 of the last desorbed sample varied between −21.63 and −1.45‰ (mean = −7.85‰), while that of δ13C2 varied narrowly between −33.92 and −32.01‰ (−32.93‰ on average) (Table 1, Figure 10b). The respective overall δ13C1 and δ13C2 fractionation of the gases from all core samples were in the range 8.56–31.97‰ and 2.34–6.50‰, with SZY1–4 and SZY1–5 samples exhibiting the highest fractionation degree, respectively (Table 1, Figures 10a, b).

Figure 10.

Figure 10

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Changes of δ13C1 and δ13C2 of desrobed shale gas with variation in desorbed temperature and time.

The gases with relatively lighter δ12C are preferentially released during desorption. Based on this conclusion, two inferences could be obtained: (i) the δ13C of the lost shale gas is lighter in comparison with desorbed shale gas; (ii) the shorter the exposure time of the core shale, the lighter the δ13C at the beginning of desorption (Figure 11). The δ13C1 of the first desorbed shale gas of each core sample was inversely proportional to the exposure time of the corresponding sample. Here, the exposure time refers to the time from core drilling to canister sealing. This observation verified the priority of desorption of the relatively lighter δ12C. Therefore, caution should be applied when using the values of δ13C of hydrocarbon gases, and the desorption phase of the gas sample should be first taken into consideration.

Figure 11.

Figure 11

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Changes of δ13C1 of the first desrobed shale gas samples with variation of exposure time referring to time from core drilling to canister sealing of each shale core sample.

3.4.2. Factors Affecting Carbon Isotope Fractionation

Generally, the gaseous carbon isotopic characteristics (δ13C) of hydrocarbon gases are associated with their genetic source and thermodynamic fractionation. Thus, it commonly serves as an indicator to identify gas sources26,28,29 and confirm thermal maturity.69 Thus, carbon isotope fractionation is a highly pervasive phenomenon.8,20,25,31−34

The factors influencing carbon isotope fractionation can be classified as internal and external factors. The internal factors (such as TOC and physical properties of shales) intrinsically influence the shale and its gas,31,32,37 while the external factors are foreign forces. The TOC and the physical properties of shales improve the micropores and nanopores, giving rise to a larger pore volume, and eventually improving the carbon isotope fractionation.8,33 Furthermore, the volume and proportion of the gases34,38,70,71 are other internal factors influencing the carbon isotope fractionation. Seepage,31,72 diffusion,20,35,72 dissolution,73 and adsorption/desorption20,34,38,74 are critical external factors controlling the carbon isotope fractionation. However, determining the most vital factor is still controversial.

Diffusion is a common factor influencing the carbon isotope fractionation of shale gas. It is easily accepted because diffusion usually accompanies desorption during transport or migration.20 Compared with conventional natural gas, shale gas is an unconventional natural gas characterized by shale as the source rock and reservoir simultaneously. Hence, the shale gas migration distance is much shorter than conventional natural gas, and the carbon isotopic fractionation and composition are not influenced by the effect of migration fractionation.75,76

Figure 10a,b shows that δ13C1 and δ13C2 gradually became heavier with an increased desorption time. This observation agrees with many research results from the theoretical analyses and simulation experiments.31,36,71 The value of δ13C2 decreased slightly in Phases II and III of desorption. In contrast, the value of δ13C1 was unchanged, growing until the end of desorption, suggesting that the adsorption/desorption was dominant in the carbon isotope fractionation. Diffusion was only significant in the carbon isotope fractionation of the heating phase. In other words, diffusion happened throughout the desorption phases. However, the desorption intensity was much higher than that of diffusion most of the time. Such occurrence was consistent with the above conclusion that the diffusion was limited because the migration distance of shale gas was much shorter than conventional natural gas.

An increase in temperature thermally induces intense diffusion, causing more 12C2 to diffuse rapidly through the micropores/nanopores of the shale. Accordingly, 12C2H6 diffusion was sensitive to the temperature increase. 12C2H6 diffusion was much faster than that of 13C2H6 in the heating phase, resulting in δ13C2 becoming lighter. Besides, the adsorbability of 13CH4 and 13C2H6 was stronger than those of 12CH4 and 12C2H6, respectively, leading to 13CH4 and 13C2H6 enrichment in Phases II and III.

Previous studies had reported that the shale gases from the Lower Paleozoic strata in West Hubei had a positive relationship with the carbon isotope fractionation degree of CH4.20 Also, the given shale intervals from LCNF of the middle Yangtze region were characteristic of high shale gas content, accompanied by isotopic fractionation of CH4 of the corresponding mud gases and cutting-released gases.9Figure 12a shows that the desorbed gas content correlated weakly with carbon isotope fractionation. This occurrence could be attributed to the difference in the desorption time of the last desorbed samples of each core sample, which varies inherently and considerably. Such as the SZY1–1 sample with the shortest desorbed time of the last desorbed samples of 20.94 h and the SZY1–9 sample with the longest desorbed time of the last desorbed samples of 59.43 h. Thus, the value of δ13C1 in the desorbed samples with 21 h desorption time (δ13C1L21) replaces those of the last desorbed samples in the cross plots (Figure 12b). The correlation between the desorbed gas content and the carbon isotope fractionation degree (Δδ13C1L21-F) of all nine core samples improved (Figure 12b).

Figure 12.

Figure 12

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Crossplots of carbon isotope fractionation of CH4 versus desorbed gas content and TOC (a–c), the value of δ13C1 of desorbed samples with desorption time of about 21 h (δ13C1L21) versus desorbed gas content. (Δδ13C1L-F = the difference between the value of δ13C1 of the last desorbed shale gas sample and that of the first desorbed shale gas sample, Δδ13C1L21-F = the difference between the value of δ13C1 of desorbed shale gas sample with desorbed time of about 21 h and that of the first desorbed shale gas sample).

Additionally, the TOC correlated positively with the carbon isotope fractionation degree (Δδ13C1L21-F) (Figure 12c). The higher the TOC of the shales, the more the micropores/nanopores, and the better the adsorption capability.33 Due to the stronger adsorption capability of 13CH4 relative to 12CH4, more substantial carbon isotope fractionation ensued.

Summarily, the carbon isotope fractionation of desorbed CH4 and C2H6 from the nine shale core samples (from the LCNF of the SZY1 well) occurred via adsorption/desorption and diffusion. 12C2H6 diffusion was temperature-sensitive, and its diffusion rate was much faster than that of 13C2H6 in the heating phase. Therefore, the temperature could be an external factor in reducing the carbon isotope fractionation of a specific gas at a particular desorption phase. In contrast, pressure is the other external factor facilitating carbon isotope fractionation.34 This condition was why CH4 was isotopically heavier during production, owing to a lowering of pressure after the hydraulic fracturing.

Furthermore, the degree of carbon isotope fractionation should be used, provided that the desorption time of the last desorbed samples is equal or similar for all shale core samples. The carbon isotope fractionation degree is a viable indicator of sweet spots for shale gas exploration and production. Figure 12d suggests that the desorbed gas contents of the shale core samples correlated positively with the δ13C1 of the last desorbed gas samples (δ13C1L21). Such a result indicates that Δδ13C1L21-F is a contemporary indicator for the desorbed gas contents.

3.5. Genetic Source of the Shale Gas

Geochemical characterization (such as chemical composition analysis and stable carbon isotopy) of gases is commonly used to identify the origins of natural gases,7−9,19,75,77 their evolution, migration, and accumulation.78 Shale gas preserves the original geochemical characteristics in a sealed system because of the gas’ self-generation and self-storage. Thus, the migration distance is much shorter than or even negligible. Therefore, the migration and geochemical characteristics can be ignored compared to generation, evolution, and accumulation occurring in the closed system of the shale itself before desorption. Nevertheless, the adsorbability of the shale to both hydrocarbon components and isotopologues differs significantly, causing the compositional and isotopic fractionation of shale gas. Therefore, the fractionation effects must be considered when using these parameters for the genetic source identification of shale gases.

According to the diagram of δ13C1 versus C1/(C2 + C3),79 the desorbed gases were distributed outside the region of thermogenic gases (Figure 13). However, with maturity, C1/(C2 + C3) and δ13C1 were thermally increased during the high maturation,8,20,80,81 while the desorption leads to the considerable carbon isotope fractionation.20,34,38,74 The Ro of the shale core samples of SZY1 Well informed us that these shales were within the high-over mature range (Table 1). Thus, all desorbed gases were thermogenic when high maturity and isotope fractionation effects were considered (Figure 13).

Figure 13.

Figure 13

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Diagram of δ13C1 versus C1/(C2 + C3) of desorbed shale gas samples to determine the genetic source of Lower Cambrian shale gas in MTZSS (Adapted with permission from Whiticar, 1999, Elsevier B.V.).

Because δ13C2 retains the original genetic information on gases, its value is one of the most frequently used indicators to determine the genetic source of gases.19,20,82,83 In general, the δ13C2 value of oil-type gas is ←29‰, whereas that of coal-formed gas is >−28‰.82 These gases, derived from various precursors, increased with maturity. The majority of the δ13C2 values of all desorbed samples were ←29‰ (Table 1, Figure 14), suggesting that the shale gases from LCNF in MTZSS belong to the oil-type gas.

Figure 14.

Figure 14

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Diagram of δ13C1 versus δ13C2 of the desorbed shale gas samples to determine the genetic source of Lower Cambrian shale gas in MTZSS (Adapted with permission from Dai et al., 2014, Elsevier B.V.). The lower Cambrian Niutitang shale gases in MTZSS belong to mixed gases with negative carbon isotopic series, and the desorption caused the distribution of outside Region III1 for most desorbed gas samples.

The oil-type gas originates from the thermal cracking of kerogen and oil, which are widely distributed in nature and difficult to differentiate. Hence, a genetic diagram of ln(C1/C2) versus ln(C2/C3) was employed to distinguish oil-cracking gas from kerogen-cracking gas.20,42,70,84,85 The principle is that the kerogen-cracking gas originates from the demethylation of kerogen. CH4 is the main component of demethylated products, substantially characterized by the rapid increase in the CH4 content versus the slow generation of C2H6 and C3H8. Thus, C1/C2 increases rapidly, whereas C2/C3 increases slowly or almost unchanged.

Oil-cracking gas refers to the secondary cracking of oil. It is derived from the carbon–carbon cleavage of long aliphatic oil chains, resulting in large quantities of C2H6 and C3H8. Accordingly, the C2/C3 ratio varies more comprehensively than the unchanged C1/C2 ratio. Figure 15 shows that all desorbed gas samples’ C1/C2 ratios had an overall downward trend, although the values were stable in each temperature phase. Furthermore, regarding the SZY1–3 sample, one of the two shale core samples contained propane. The C1/C2 ratios of the desorbed samples varied in a narrower range compared to C2/C3 ratios at the beginning of the desorption (Figure 15). These observations suggest that the shale gases from LCNF in MTZSS are predominantly oil-cracking gases, and the absence of propane is due to the highly/overmature shales. Such observation coincides with the view that the shale of type I kerogen is considered a good gas source because all oils cracked to wet gas when Ro is >1.4%. In comparison, all condensate-rich gases cracked to dry gas when Ro is >2.0%56 due to the primary type I organic matter of LCNF shales in MTZSS. Nevertheless, the gas generation from type I kerogen cracking at low and high maturity is inevitable.42 δ13C1 versus δ13C2 diagram proposed by Dai et al. (2014) pointed out that the Niutitang shale gas of the study area belongs to mixed gas (Figure 14). Consequently, the shale gases from LCNF in MTZSS are primarily composed of oil-cracking gases mixed with kerogen-cracking gases. This observation is consistent with those in the Lower Cambrian Qiongzhusi (Niutitang) shale in the Weiyuan Block of Sichuan Basin in the Upper Yangtze region and the LCNF shale in the Yichang Block of west Hubei in the Middle Yangtze region.85

Figure 15.

Figure 15

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Crossplots of ln(C1/C2) versus ln(C2/C3) (blue solid dot) and desorbed time (red hollow dot).

3.6. Feature and Origin of Carbon Isotope Reversal

Based on carbon isotope thermodynamic fractionation, the carbon isotopic differentiation of the natural gas components is a widespread phenomenon during gas exploration and production.8,9,19,20,39−41 Specifically, all the LCNF shale gases in highly over-mature shales in China are characteristic of CIR.5−9 Similarly, LCNF shale gas in the Yichang Block of west Hubei of Middle Yangtze region6,8,9 and Lower Cambrian Qiongzhusi (Niutitang) shale gas in the southeast and northeast Sichuan Basin of Upper Yangtze region5,7 exhibit similar property. This phenomenon is mainly caused by the secondary cracking of oils, which is accompanied by the cracking of kerogen. Previous researchers have observed a usual isotopic trend in the Lower Cambrian Qiongzhusi shale gas of Xiushan of southeast Chongqing.23 However, the gases used in this study were residual gas extracted by vacuum crushing from the outcrop shale samples of the Qiongzhusi Formation. In the early stages of diagenesis, the remaining gas is reserved in the pores generated by diagenesis. These pores are sealed in the later stage of diagenesis (and even Catagensis), resulting in disconnected pores. Thus, the gas could not be desorbed. Therefore, the remaining gases belong to Region III for the trend of maturity-dependent δ13C2 and δ13C1 variation.86

The carbon isotopic composition of CH4 and C2H6 of all desorbed shale gas samples of Lower Cambrian in south Shanxi is characterized by a reversed sequence of carbon isotope (δ13C1 > δ13C2) (Figures 16a,b). The degree of CIR of the last desorbed gas samples is much larger than that of the first desorbed gas samples (Figure 16a,b), caused by more significant carbon isotope fractionation of δ13C1 than of δ13C2. The higher the shale maturity, the higher the wetness and the lighter the δ13C of the secondary cracking gas, caused by conversion (between oil and condensate) and carbon–carbon cleavage. The proportion of the second cracking gas in the mixed gases gradually increases during maturation, whereas the percentage of C2+ is relatively high and thus gives rise to 12C2 enrichment. When a specific level of maturity is reached, and 12C2 carbon is enriched to a degree, CIR will occur.43 Based on this theory, a previous study proposed dividing the CIR into four regions.86 The gas samples in this study belonged to Region III of the diagram based on the maturity-dependent δ13C2 and δ13C1 trends during maturation (Figure 17).

Figure 16.

Figure 16

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Degree of carbon isotope reversal of the first desorbed gas samples (a) and the last desorbed gas samples (b).

Figure 17.

Figure 17

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A complete trend of maturity-dependent δ13C2 and δ13C1 variation.86 Regions: I—normal trend; II—δ13C2 reversal with respect to maturity trend; III—δ13C reversal against carbon number (δ13C1>δ13C2); IV—normal trend (Adapted with permission from Xia et al., 2013, Elsevier B.V.).

The CIR of CH4 and C2H6 of all desorbed shale gas samples of LCNF in MTZSS arose mainly from cracking residual soluble organic matter (oil, condensate, and asphaltene) at the high-overmature stage, coupled with the cracking of kerogen at the early maturation stage. Such an observation agrees with the explanation from the diagram of δ13C1 versus δ13C2 of the desorbed shale gas samples (Figure 14). In addition, even though the diffusion of shale gas is minimal because shale gas is an unconventional natural gas, the shale strata have been raised over a long geological period, causing CIR diffusion.20,87

According to the burial and thermal history of adjacent wells in south Shanxi, the lower Cambrian shales were raised significantly, owing to the two Yanshanian and Himalayan tectonic movements.13 Therefore, diffusion is an indispensable factor in the LCNF shale gas’s CIR in MTZSS since CIR is the cumulative result of many factors. Furthermore, Figure 18 shows that the degree of CIR of the last desorbed samples correlated positively with the desorbed gas content. As an inference, the degree of CIR could be a valuable indicator to determine sweet spots of shale gas in south Shanxi.

Figure 18.

Figure 18

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Crossplots of desorbed shale gas content versus the degree of carbon isotope reversal of the last desorbed gas samples (Δδ13C1L–C2L).

3.7. Indicators for Identifying Shale Gas Sweet Spots for the Exploration and Production

The desorbed gas content is inversely proportional to the dryness index of the last desorbed gas samples of each core sample (Figure 9a) while the desorbed gas content did not correlate with the dryness index of the first desorbed gas of each core sample (Figure 9b). Namely, the desorbed gas content increases with the decrease of dryness index at the end of desorption, which coincided well with many reports20,66,67 and is thought to be a result of various adsorbability of the shale to gaseous hydrocarbon. Consequently, the dryness index of the last desorbed gas of the core sample is a useful indicator of sweet spots for shale gas exploration and production.

The calculation of the carbon isotope fractionation degree should follow a rule that the desorbed time of the last desorbed samples must be the same or very close for all shale core samples. Based on this rule, the desorbed gas contents of shale core samples correlated positively with the carbon isotope fractionation degree (Δδ13C1L21-f) (Figures 12b), and the carbon isotope fractionation degree (Δδ13C1L21-f) is an effective indicator of sweet spots for shale gas exploration and production. Besides, Figure 12d suggests that the desorbed gas contents of shale core samples had a positive relation with the δ13C1 of the last desorbed gas samples (δ13C1L21), suggesting that it is also the same indicator of sweet spots for shale gas exploration and production as Δδ13C1L21-f

The carbon isotope reversal (CIR) (δ13CH4 > δ13C2H6) of the natural gas components is a common phenomenon during gas exploration and production.8,9,19,20,39−41 Specifically, all the LCNF shale gases in highly over-mature shales in China are characteristic of CIR,5−9 also which is caused by the cracking of the residual soluble organic matter at the high overmaturity stage mixed with the cracking of kerogen at the early stage of maturation as well as the diffusion of gas. Figure 18 exhibits that the degree of CIR of the last desorbed samples is positively related to the desorbed gas content, deciphering the degree of CIR (Δδ13C1L–C2L) could be a useful indicator to determine sweet spots of shale gas.

In a word, the last desorbed shale gas samples featured by a low value of the dryness index, high values of δ13C1, high carbon isotope fractionation, and a CIR degree indicate shale gas sweet spots for the exploration and production of LCNF in MTZSS, which probably can be applied to LCNF shale gas in the other exploration blocks of South China.

4. Conclusions

Based on scientific analyses, the LCNF shale in south Shanxi was more of a gas-rich and high gas interval, indicating the excellent shale gas resource potential of the LCNF of MTZSS.

The desorbed gases were composed of plenty of hydrocarbon gases (predominantly CH4) and a small amount of nonhydrocarbon gases. The former consisted of CH4, C2H6, and a minute amount of C3H8 found only in the SZY1–3 and SZY1–4 core samples. The nonhydrocarbon gases were H2, CO2, and a minute quantity of He found in the SZY1–2 core sample. Overall, the gas components increased during desorption, except for CH4 and He. Based on the ratio between the two gases, with an increase in desorption time and temperature, the sequence of adsorbability of the shale for different gases was H2 > CO2 > C2H6 > CH4 > He.

The value of δ13C1 of the desorbed samples gradually became heavier until the desorption experiments were over. The δ13C2 value had the same changing trend as CH4, but it frequently fluctuated due to the increasing temperature.

Also, the shorter the exposure time of core shale, the lighter the δ13C at the beginning of desorption, which is ascribed to the preferential release of δ13C during desorption. The carbon isotope fractionation of the desorbed CH4 and C2H6 of nine gas-bearing shale core samples from the LCNF of the SZY1 well was determined jointly by adsorption/desorption and diffusion.

Through the analytical diagrams of ln(C1/C2) versus ln(C2/C3), δ13C1 versus C1/(C2 + C3), and δ13C1 versus δ13C2, the shale gases from LCNF of south Shanxi primarily consist of oil-cracking gases mixed with kerogen-cracking gases, which is the dominant cause of CIR. Additionally, diffusion is an indispensable factor in CIR since the lower Cambrian shales in MTZSS experienced significant uplift due to the Yanshanian and Himalayan tectonic movements.

Furthermore, the desorbed gas content had positive and negative relationships with the corresponding isotopic reversal degree and gas dryness index of the last desorbed samples, respectively. The degree of CH4 carbon isotope fractionation and δ13C1 of the last desorbed gas samples correlated positively to the desorbed gas content. Thus, calculating carbon isotope fractionation degree could be used when the desorption time of the last desorbed samples is the same or similar for all shale core samples. Hence, the four parameters can be effective indicators for identifying shale gas sweet spots for the exploration and production of LCNF in MTZSS.

Acknowledgments

This study was supported by Key Parameter Testing for Shale Gas in Key Areas of Southern China (DD20230265) of China Geological Survey, Shaanxi Province 2023 Innovation Capability Support Plan (2023KJXX-122), National Natural Science Foundation of China (Grants No. 41702159), and Rock macerals in situ SEM analysis and three-dimensional interspace reconstruction technology (CSJ-2023-09). We appreciate Shaanxi Coal Geological Oil and gas Drilling Co., Ltd. for all the help in collecting gas and core samples. Besides, we are grateful to the editors and all reviewers for their valuable suggestions that we have used to improve the quality of our manuscript.

The authors declare no competing financial interest.

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