Predicting the proportion of free and adsorbed gas by isotopic geochemical data: A case study from lower Permian shale in the southern North China basin (SNCB)

International Journal of Coal Geology 156 (2016) 25–35

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International Journal of Coal Geology journal homepage: www.elsevier.com/locate/ijcoalgeo

Predicting the proportion of free and adsorbed gas by isotopic geochemical data: A case study from lower Permian shale in the southern North China basin (SNCB) Yang Liu a, Jinchuan Zhang a,b,⁎, Xuan Tang a a b

School of Energy Resources, China University of Geosciences, 29 Xueyuan Road, Beijing 100083, China Key Laboratory of Shale Gas Exploration and Evaluation, Ministry of Land and Resources, China University of Geosciences, 29 Xueyuan Road, Beijing 100083, China

a r t i c l e

i n f o

Article history: Received 2 November 2015 Received in revised form 22 January 2016 Accepted 24 January 2016 Available online 26 January 2016 Keywords: Shale gas Carbon isotope Hydrogen isotope Southern North China basin

a b s t r a c t The alternating marine-terrigenous shale facies of the Lower Permian Taiyuan (P1t) formation and the Lower Permian Shanxi (P1s) formation in the north margin of the southern North China basin (SNCB) are characterized by their high TOC values (1.76–5.09%), types II and III organic matter, and high Ro values (N3.0%). Geochemical parameters of 12 gas samples from the Lower Permian shale formations from well Weican-1 were analyzed in this study. The gases are dominated by methane, with small amounts of ethane, without propane and butane. Wetness of the gas is only 0.25–0.58% reflecting extremely high maturity of the source rock. The δ13C1 values range from − 31.6 ‰ to − 26.8 ‰ and the δ13C2 values range from − 35.9 ‰ to − 33.2 ‰, the δ2HCH4 values range from − 221.1 ‰ to − 187 ‰. Furthermore, carbon isotopic compositions of the alkane gases from the Lower Permian shale are characterized by δ13C1 N δ13C2, this indicates that the gases released from Permian shale are of thermogenic origin and mostly sourced from the continental shale and coal measures, with minor contribution from oil cracked gas from marine mudstones. Geochemical fractionation during the adsorption/ desorption process of the shale system may play a significant part in influencing δ13C1 values of shale gas. The results show that the δ13C1 becomes heavier with increasing degree of gas desorption. Based on isotope fractionation during desorption of gas in shales, an equation was established to estimate the proportion of free and adsorbed gas in shales using δ13C1 of shale gas. In comparison with other equations, this equation is based on the direct data of gas desorption experiment to avoid the adsorbed gas content often exhibit maxima from excess sorption isotherms experiment. This method provides efficient way to understand the gas storage behavior in shales and broaden the application of gas isotope. © 2016 Elsevier B.V. All rights reserved.

1. Introduction Shale gas is one of the most important unconventional hydrocarbon resources in which natural gas is found as absorbed gas within organic matter and on inorganic minerals, free gas within fractures and intergranular porosity, and as well as dissolved gas in kerogen, oil and water (Schettler and Parmely, 1990; Martini et al., 1998). Adsorbed gas may account for 20–85% of total gas in shale reservoirs (Hill and Nelson, 2000). Thus unlike conventional gas accumulations, in which gas is present mainly as free gas, or coalbed methane accumulations, where gas is considered to be mainly adsorbed, both of free gas and adsorbed gas may attribute to gas production from shales. To understand gas occurrence and storage mechanism in shales is a key question for shale gas reservoir engineering. One commonly used method is to use reservoir simulation for representation, however, this ⁎ Corresponding author at: School of Energy Resources, China University of Geosciences, 29 Xueyuan Road, Beijing 100083, China. E-mail address: [email protected] (J. Zhang).

http://dx.doi.org/10.1016/j.coal.2016.01.011 0166-5162/© 2016 Elsevier B.V. All rights reserved.

will require a reservoir simulator that faithfully represents the shale gas storage and flow behaviors. Moreover, because adsorbed gas may take a longer time to transport through the matrix than free gas (e.g. Yuan et al., 2014), the contribution of adsorbed and free gas may be even more complex. Different stages of basin evolution directly control the development and distribution of organic-rich shale (Li et al., 2009). According to the depositional environment, organic-rich shale can be divided into marine shale, marine-terrigenous coal bed carbonaceous shale and continental lacustrine derived shales (Zou et al., 2010). Coal bed shale (shale derived from mixed marine-terrigenous sources) was formed in marine-terrigenous transitional deltaic facies, such as the Carboniferous Benxi Formation and the Lower Permian Shanxi Formation–Taiyuan Formation in Ordos Basin, the Carboniferous–Permian in Junggar Basin, the Carboniferous–Permian in Tarim Basin, the Carboniferous–Permian in Northern China, and the Permian Longtan Formation in Southern China. It can also be a major source rock for large-scale oil/gas fields. For example, the Upper Paleozoic carbonaceous shale in Ordos Basin is the major gas source rock for Sulige and other large gas fields and its

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environment of deposition was deltaic facies. The Triassic–Jurassic and Tertiary developed several sets of carbonaceous shale, which were associated with coal measures of deltaic facies (Zou et al., 2010). Since the oil and gas exploration in the southern North China basin, previous studies confirmed that the coal bed shale from the Lower Permian which formed in alternating marine-terrigenous deltaic facies are widely distributed in this area. But shale gas exploration in this region has not achieved commercial progress due to complex geological conditions such as structural deformation in the southern North China basin. In 2014, the vertical drills (well Weican-1 and Mouye-1) in the Permian shale firstly found shale gas in this region, which marks a major breakthrough in the exploration of alternating marine-terrigenous deltaic facies shale gas in north China. Natural gas from marine shale (shale gas derived from marine organic matter) has recently gained significant success in the USA, and it triggered a worldwide fever for shale hydrocarbon resources (Curtis, 2002; Tang et al., 2014a, 2014b). In contrast, there has been little work done and less attention paid to alternating marine-terrigenous deltaic facies shale. In this paper, we present stable carbon and hydrogen isotopes of alkane gases as a means to understand the geochemical characteristics of gases from the lower Permian alternating marineterrigenous deltaic facies shale in the north margin of the southern North China basin. In addition, the generation of shale gas follows a mechanism that is similar to that of conventional gas, which means the origins of shale gas can also be biogenic, thermogenic or a mixture of the two. In conventional gas reservoirs, the variation of gas isotope composition is mainly determined by kerogen isotope composition, maturity and charging efficiency. For shale gas, residual oil in shale may convert to gas and water may involve in this conversion. Products from different chemical processes make the isotope composition deviate from conventional models. Therefore, the reasons for the geochemical particularities of shale gas may be mainly related to the storage stage. We have studied dynamic changes in the geochemical characteristics of shale gas (on the basis of the process of desorption) in order to improve our understanding on the isotope variability of shale gas. Moreover, a simple two-end member mass balance model was proposed to estimate the relative proportion of free gas and adsorbed gas in desorbed gas by using carbon isotope of methane in different stages of the desorption experiment. 2. Geological setting The southern North China basin (SNCB) is one of the Meso-Cenozoic superimposed basin which is located in the south of North China platform. It is on the western side of the Tan–Lu fault, the northern side of the Qinling–Dabie orogenic belt and the eastern side of the western Henan uplift zone (Lin et al., 2011). The tectonic evolution of this basin is controlled by the Qinling–Dabie orogenic belt and the Tan–Lu fault zone and thus showing the NW-WNW tectonic pattern. From the north to the south, the southern North China basin can be divided into five secondary tectonic units: the Kaifeng depression, Taikang uplift, Zhoukou depression, Changshan uplift and Xinyang–Hefei depression (Fig. 1). In addition, the secondary tectonic units in the basin can be divided into some episodes of subsidence and uplift, the total area of the basin is 150000 km2 (Diao et al., 2011; Lin et al., 2011). The SNCB is a part of the North China Craton Basin formed during the late Paleozoic. Affected by the sea level rise in Late Carboniferous, the study area began to accept marine derived sedimentation from a transgression, and the evolution process of the epicontinental sea to the continental basin was started (Diao et al., 2011). The depositional process was controlled by regional tectonic movement, and can be divided into three processes. First, the North China platform re-subsided upon entering the Late Carboniferous, and seawater intruded from the northeast to the southwest under the paleotopography background (i.e., high in the south and low in the north), forming the vast North China epicontinental sea basin. The Taiyuan formation, which consists of black shale,

coal, limestone and quartzose sandstone, was deposited in this environment during the early Permian, with a thickness ranging from 30 to 175 m. Second, the collision between the North China plate and the Siberia plate caused largescale tectonic movement and a marine regression from north to south. The river-dominated shallow water delta, which was transitioned from an epicontinental sea via marine regression, was a major depositional environment during the early Permian. The Shanxi formation, which consists of shale, coal, quartzose sandstone, was deposited in this environment with thicknesses ranging from 50 to 130 m. Finally, the North China plate was again uplifted by squeezing action during the late Permian, causing seawater to fully withdraw from the North China platform, forming terrestrial deposition environment (Diao et al., 2011; Duan et al., 2002; Liu et al., 1999; Yu et al., 2005; Zhou et al., 2010). The organic matter of the two set of source rocks are type II to type III kerogen and dominated by type III kerogen (Dai, 2000; Dang et al., 2016). The TOC of the black mudstones from P1t and P1s coal-bearing measures ranges from 0.92% to 4.24% and from 0.44% to 5.10%, respectively (Dang et al., 2016). The maturity of the source rocks in the east and south of the basin is relatively low, the vitrinite reflectance (Ro) values range from 0.5% to 1.0% and from 0.7% to 1.2%, respectively. However, the source rocks in the north of the basin are in the over mature stage with the vitrinite reflectance values over 3.0% (Sun et al., 2014). 3. Samples and methods In this study, four shale core samples from a depth of 2730–2762 m (WC-1, WC-2, WC-4, WC-6) investigated here were collected from shale gas well Weican-1 in the north margin of the SNCB. Among them, sample WC-1 (2730 m) and WC-2 (2731 m) were from Shanxi formation, and sample WC-4 (2758 m) and WC-6 (2762 m) from Taiyuan formation. The samples are of 10 cm diameter, 4.5 kg, 4.5 kg, 2.97 kg and 4.21 kg in weight respectively. The TOC values of the four shale core samples were 2.27%, 2.78%, 3.62%, 2.15% respectively, and the Ro were 3.2%, 3.2%, 3.5%, 3.7% respectively. The high vitrinite reflectance values (Ro) presented here are also supported by previous studies, which reported that abnormally high thermal maturities (N3.0%) occur in this area, mainly caused by thermal events (Cheng et al., 2011; Wu et al., 2015; Xu et al., 2005, 2011; Zhao et al., 2011). Twelve gas samples were collected from the desorption of the above four core samples, and we collected gas samples at 20 °C, 90 °C and 120 °C for the gas releasing process of each core sample. The molecular composition of gas was performed at the Key Laboratory of Marine Reservoir Evolution and Hydrocarbon Abundance Mechanism, China University of Geosciences, Beijing. The stable carbon and hydrogen isotopes analyses were performed at the Nuclear Industry Beijing Geological Research Analysis and Test Research Centre (http://www.briug.cn/). Desorbed gas content was quantified after the core sample recovered at the drilling site. It was placed as quickly as possible inside a hermetically sealed canister using quartz sand fill gaps and the volumes of gas released inside the canister were periodically measured using a graduated cylinder at atmospheric pressure (Mavor and Nelson, 1997; Ma et al., 2015). The gas releasing process can be divided into three stages (Fig. 2), the amounts of gas released at room temperature of 20 °C were small (stage 1). However, the amounts of gas released at reservoir temperature of 90 °C rapidly increased and the final stabilized (stage 2). A high temperature of 120 °C was used to expedite the adsorbed gas completely released (stage 3). Gas content of each stage determination finished when the released gas fell below 5 ml in 2 h. The molecular composition of the gas samples was determined by Agilent 6890 N gas chromatograph (GC) equipped with a flame ionization detector and a thermal conductivity detector. Individual hydrocarbon gas components (C1–C2) were separated using a capillary column (PLOT Al2O3 50 m × 0.53 mm). Nonhydrocarbon gases were separated using two capillary columns (PLOT Molsieve 5 Å 30 m × 0.53 mm, PLOT Q 30 m × 0.53 mm). The GC oven temperature was initially set

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Fig. 1. Map showing the geology of the study area and the well location.

Fig. 2. Desorbed gas curve versus time shows that desorption process is divided into three stages: gases released at room temperature (20 °C) mainly occur as free gas, gases released at reservoir temperature (90 °C) mainly mixed with free gas and adsorbed gas, gases released at high temperature (120 °C) mainly is adsorbed gas.

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Table 1 Geochemical characteristics of shale gases released in the desorption experiments from the Lower Permian shale in the well Weican-1. Sample

Formation

Depth(m)

Desorption stage

Temperature

WC-1

P1s

2730

1 2 3 1 2 3 1 2 3 1 2 3

20 °C 90 °C 120 °C 20 °C 90 °C 120 °C 20 °C 90 °C 120 °C 20 °C 90 °C 120 °C

WC-2

P1s

2731

WC-4

P1t

2758

WC-6

P1t

2762

Gas composition (%)

Wetness (%)

δ13C(‰)VPDB

δ2H(‰)VSMOW

CH4

C2H6

CO2

N2

CH4

C2H6

CH4

84.60 67.15 47.75 67.31 63.53 51.93 63.02 76.22 77.09 82.38 88.59 76.18

n.d. 0.39 0.28 n.d. n.d. 0.22 n.d. 0.27 0.34 0.21 0.26 0.29

15.40 8.93 34.24 32.69 12.50 33.63 11.87 9.18 17.40 6.28 7.63 20.57

n.d. 23.53 17.74 n.d. 23.96 14.22 25.10 14.33 5.16 11.13 3.52 2.96

−31 −30.2 −27.7 −31.6 −29.2 −26.8 −31.6 −30.5 −29.7 −29.9 −29.8 −29

n.d. −33.2 −33.2 n.d. n.d. n.d. n.d. −35.9 −34.8 −34.8 −34.1 −34.7

−211 −210 −207 −221 −203 −199 −196 −195 −187 −199 −195 −192

0.58 0.58

0.42 0.35 0.44 0.25 0.29 0.38

Notes 1. n.d. means not detected. 2. P1S = Shanxi formation (Fm); P1t = Taiyuan Fm 3. All the gas compositions (CH4, C2H6, N2, CO2) have made correction to eliminate the influence of the air.

at 30 °C for 10 min, and then increased to 180 °C at 10 °C/min and held at this temperature for 20–30 min. All the gas compositions have made oxygen-free correction and the corresponding correction for nitrogen (Ni et al., 2013). Nitrogen was corrected for the presence of traces of oxygen using the area ratio of nitrogen to oxygen peaks measured on air (Jenden et al., 2015). Stable carbon isotope values were determined on a Finnigan Mat Delta Plus mass spectrometer interfaced with a HP 5890II chromatograph. Individual hydrocarbon gas components (C1–C4) and CO2 were separated on a gas chromatograph using a fused silica capillary column (PLOT Q 30 m × 0.32 mm). The GC oven was ramped from 35 °C to 80 °C at 8 °C/min, then to 260 °C at 5 °C/min, and maintained at the final temperature for 10 min. Stable carbon isotopic values are reported in the δ-notation in permil (‰) relative to VPDB. The measurement precision was estimated to be ±0.5 ‰ for δ13C (Ni et al., 2013; Dai et al., 2014a, 2014b). Stable hydrogen isotopes were measured on a Finnigan GC/TC/IRMS mass spectrometer, which consists of Trace GC Ultra gas chromatograph (GC) interfaced with a micropyrolysis furnace (1450 °C) in line with a Finnigan MAT253 isotope ratio mass spectrometer. Gas components were separated on a HP-PLOT Q column (30 m × 0.32 mm × 20 μm) with a helium carrier gas at 1.5 ml/min. A split injection was used for methane with a split ratio of 1:7 at 40 °C. The sample introduction for ethane and propane used non-split injection mode. The GC oven temperature was initially set to 40 °C for 4 min, increases to 80 °C at 10 °C/min, then to 140 °C at 5 °C/min, and finally to 260 °C at 30 °C/min. The stable hydrogen isotopic values are reported in the δ-notation in permil (‰) relative to the international standard Vienna Standard Mean Ocean Water (VSMOW). Precision for individual components in the molecular δ2H analysis is ±3 ‰ (Ni et al., 2013; Dai et al., 2014a, 2014b). The methane adsorption isotherm was obtained at 30 °C and a humidity of 2.31% using the Schlumberger Terra Tek ISO-300 isothermal apparatus, with 99.99% methane as a carrier gas. The shale samples were crushed and sieved to less than 60 mesh particle size. The moisture-equilibrated condition was achieved in an evacuated desiccator under controlled relative humidity (RH) conditions using saturated salt solutions of K2SO4 (97% RH). The detailed methane adsorption experimental procedure was described in detail by Ji et al. (2014). 4. Results 4.1. Molecular composition of shale gas As shown in Table 1, all of the natural gases liberated in the desorption experiments are dominated by methane, and small amounts of

ethane without propane and butane were detected. The nonhydrocarbon gases are mainly carbon dioxide and nitrogen without hydrogen sulfide. For sample WC-1, the content of methane and ethane varies from 84.60% to 47.75% and from 0% to 0.39%, respectively. The contents of carbon dioxide and nitrogen are from 8.93% to 34.24% and from 0% to 23.53%, respectively. For sample WC-2, the contents of methane and ethane are from 51.93% to 67.31% and from 0% to 0.22%, respectively. The contents of carbon dioxide and nitrogen are from 12.50% to 33.63% and from 0% to 23.96%, respectively. For sample WC-4, the contents of methane and ethane are from 63.02% to 77.09% and from 0% to 0.34%, respectively. The contents of carbon dioxide and nitrogen are from 9.18% to 17.40% and from 5.16% to 25.10%, respectively. For sample WC-6, the contents of methane and ethane are from 76.18% to 88.59% and from 0.21% to 0.29%, respectively. The contents of carbon dioxide and nitrogen are from 6.28% to 20.57% and from 2.96% to 11.13%, respectively.

4.2. Stable carbon and hydrogen isotopes The stable carbon and hydrogen isotopic compositions of alkanes are also shown in Table 1. The δ13C1 values range from − 31.6 ‰ to − 26.8 ‰ (average − 29.8 ‰) while the δ13C2 values range from − 35.9 ‰ to − 33.2 ‰ (average − 34.4 ‰). The δ2HCH4 values range from −221.1 ‰ to −187 ‰ (average − 201.3 ‰). Because of the low concentration of ethane, the δ2HC2H6 values cannot be detected.

4.3. Methane adsorption isotherm The fitted Langmuir parameters for all 30 °C isotherms are listed in Table 2. VL ranges from 1.10 to 1.96 m3/t with an average of 1.50 m3/t and PL at that temperature ranges from 1.25 to 1.97 MPa with an average of 1.64 MPa.

Table 2 Measured methane adsorption capacity for shale samples at 30 °C. Sample

Formation

Depth(m)

VL(m3/t)

PL(MPa)

WC-1 WC-2 WC-4 WC-6

P1s P1s P1t P1t

2730 2731 2758 2762

1.42 1.52 1.96 1.10

1.25 1.71 1.97 1.64

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Fig. 3. Plots of various gas composition variation in the desorption experiments, all the gas compositions (CH4, C2H6, N2, CO2) have made correction to eliminate the influence of the air.

5. Discussion 5.1. Change of gas molecular composition in different stages Selective adsorption is affected by both adsorption affinity (energy) and kinetic diameter of gas molecules. Carbon dioxide has the largest adsorption energy among CO2, CH4, and N2 (Chareonsuppanimit et al., 2012). Therefore, the theoretical self-diffusivity of carbon dioxide is several times smaller than those of CH4 and N2 in open space. However, experimental derived diffusivities of CO2 in coals are much higher than those of CH4 and N2 (Cui et al., 2004). In addition, there is a strong preferential adsorption of wet hydrocarbon gases over methane. The adsorption selectivity among the C2–C6 hydrocarbon gases shows that there is stronger adsorption for the heavier gas molecules (Cheng and Huang, 2004). Shale gas may be stored as free gas in natural fractures and intergranular pores, as adsorbed gas in organic matter and on clay particle surfaces, or as dissolved gas in oil and water (Curtis, 2002). Gas molecular composition is changing at various stages of gas desorption due to the selective adsorption of different gas in shale. For

sample WC-1 and WC-2, the content of methane gradually decreases with the temperature increasing from desorption stage 1 to stage 3 as other gases are released in the last two stages. Because the adsorption affinity of ethane is stronger than methane, therefore, the methane released in stage 2 is considered to be adsorbed gas due to the occurrence of ethane in this stage (Fig. 3). Cui et al. (2004) indicated that the diffusion coefficients of the three gases in the coal matrix decrease in the order of CO2 N N2 N CH4, in contrast to their theoretical self-diffusion coefficients. Therefore, nitrogen should be released earlier than methane in coal or shale because of the larger diffusion coefficient of nitrogen, but the opposite sequence is presented in stage 1. It suggests that the methane released in this stage is dominated by free gas in natural fractures and intergranular pores. However, there were significant differences between sample WC-1, WC-2 and WC-4, WC-6. The major reason for this difference is that the samples WC-1 and WC-2 show very low permeability (0.0067 × 10− 3 μm2 and 0.0087 × 10− 3 μm2, respectively) and the samples WC-4 and WC-6 have relatively high permeability (0.6702 × 10− 3 μm2 and 1.2135 × 10−3 μm2, respectively) due to the presence of micro cracks in the shales.

Fig. 4. a, Natural gas interpretative “Bernard” diagram combining the molecular and isotopic compositional information indicating no microbial admixtures of gases from the Lower Permian shale in the north margin of the SNCB (After Bernard et al., 1978; Whiticar, 1999); 4b, plot of δ13C1 vs. C1/C2 + 3 showing the gases from the Lower Permian shale in the north margin of the SNCB are mixed with coal-derived and oil cracked gas (modified after Dai, 1992).

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Fig. 5. Plot of δ13CCH4 vs. δ2HCH4 of gases from the Lower Permian shale in the north margin of the SNCB, implying a thermogenic origin (After Schoell, 1980; Whiticar, 1999).

5.2. Origin of shale gas from the lower Permian in the southern North China basin The carbon and hydrogen isotopic compositions of methane and associated gases in combination with molecular composition are used to establish gas origin (e.g., Whiticar et al., 1986; Berner and Faber, 1988; Chung et al., 1988; Schoell, 1980; Whiticar, 1999; Strąpoć et al., 2007, 2008). In the Bernard diagram (modified after Bernard et al., 1978 and Whiticar, 1999), all data points fall in the area slightly outside the thermogenic gas outline, probably due to their relatively high gas dryness coefficient and heavy methane carbon isotopic values (Table 1, Fig. 4a). Schoell (1980) showed that the different types of methane have characteristic carbon and hydrogen isotopes compositions, which varied also with source rock type and maturity in the case of thermogenic methane. Whiticar et al. (1986) extended this work to include the effect of methane generation pathway on the molecular and isotopic compositions of microbial gases. δ2HCH4 versus δ13CCH4 diagram (Schoell, 1980) also show a thermogenic origin for these gases (Fig. 5). Thermogenic gas could be categorized into coal-derived gases sourced from terrestrial humic organic matter and oil-derived gases (including oil-associated and oil cracked gases) mainly sourced from

marine sapropelic organic matter. As shown in Fig. 4b, all data point to near the boundary of oil cracked gas and coal-derived gas. Considering the source rocks are both type III kerogen with a small amount of type II kerogen and the frequent interaction between mudstone and coal seam, the gases released from Permian shale are of thermogenic origin and mostly sourced from the continental shale and coal measures, with minor contribution from oil cracked gas from marine mudstones. Besides, the methane with heavy carbon isotopic and light hydrogen isotopic values maybe produced through formation water reacting with inorganic carbon (Burruss and Laughrey, 2010). The CO2 and N2 concentration of gases in the Well Weican-1 ranged from 6.28% to 34.24% and from 0% to 25.10%, respectively. The high CO2 contents of 0.58% to 15.4% were also detected in the P2I coal-derived gases in the Sichuan Basin. Hu et al. (2013) indicated that both the decomposition of carbonates and their dissolution by acidic fluids in the reservoirs are possible mechanisms. In addition, nitrogen is produced in great quantities during the thermogenic transformation of organic matter (Krooss et al., 1995). The process of molecular nitrogen production from organic matter was also documented by pyrolytic experiments (Gerling et al., 1997). Therefore, the high carbon dioxide and nitrogen content in Well Weican-1 may be due to the extremely high

Fig. 6. a, Plot of δ13C1–δ13C2 indicating the gases from the Lower Permian shale in the north margin of the SNCB are mixed gases with negative carbon isotopic series which suggested mixed with oil cracked and coal-derived gases from different sources (modified after Dai et al., 2014a); 6b, plot between the δ13C1 and δ13C2 values, the trend line “S″ is based on the data from typical marine shale gas in China, Canada and America (modified after Dai et al., 2014b).

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Fig. 7. Plots of various gas geochemical parameter changes in the desorption experiments. The carbon and hydrogen isotopic composition of methane become more negative as the desorption time increased.

maturity of shale. However, the specific reasons still need to be proved by other data. 5.3. Isotopic rollovers and reversals in shale gas Carbon isotope reversals were reported in some of Canada's most productive shale gas fields (Tilley et al., 2011; Tilley and Muehlenbachs, 2013) and in deep shale gas reservoirs of the northern Appalachian Basin (Burruss and Laughrey, 2010). Partial reversal in the carbon isotopes of n-alkanes could be due to the admixture of various gases (abiogenic and biogenic, oil-associated gas, oil cracked gas and coal-derived gases from different sources, gases from the same source but at different maturity) or microbial oxidation of one or more alkane components or thermochemical sulfate reduction (Dai et al., 2004). Burruss and Laughrey (2010) revealed that Rayleigh fractionation during redox reactions caused isotopic reversals which provide important implications for natural gas resources in deeply buried sedimentary basins. They proposed that these reactions involve redox reactions with transition metals and water at late stages of diagenesis at temperatures on the order of 250–300 °C, and the reversal in the 2H composition of methane can be explained by mixing with a late stage, super mature methane that has isotopically exchanged with formation water at these temperatures. The carbon isotopic compositions of all the alkane gases from the Lower Permain shale in the Well Weican-1 are characterized by δ13C1 N δ13C2 which has a close relationship with the high maturity of shale (Ro = 3.2–3.7%). The maximum burial depth reached about 7000 m of Permian strata in the study area. However, due to the influence from magmatic and hydrothermal activities, the Permian source rock have obtained a maximum temperature of 200–350 °C (Zhong and Ren, 1990; Zhong and Cao, 1994). Therefore, the reversed trend of gases can be caused by Rayleigh fractionation of ethane and propane involve redox reactions with transition metals and water at late stage of catagenesis at temperature of 250–300 °C. The phenomenon that δ13C1 N δ13C2 was also commonly observed in the Fayetteville shale of the Arkoma Basin (Ro = 2.5–3.0%), the Barnett shale of eastern Fort Worth Basin (Ro = 1.3–2.1%) and high maturity Horn River, Doig shales in western Canada and Longmaxi shale in southern Sichuan Basin (wetness b 1%) (Zumberge et al., 2012; Tilley and Muehlenbachs, 2013; Dai et al., 2014b). As shown in Fig. 6a, all data points fall in the zone of mixed gases with negative carbon isotopic series which suggested mixed origins with oil cracked and coal-derived gases from different sources (Fig. 4b). As shown in Fig. 6b, all data points fall on the trend line “S” in the zone of δ13C1 N δ13C2. The first turning point was considered to be the beginning of secondary cracking and mixing of primary and secondary cracking gas may cause an isotope reversal (Hao and Zou, 2013; Xia et al., 2013, Tilley et al., 2011; Tilley and Muehlenbachs, 2013). The second turning point may indicate a “postreversal” stage of extremely high maturity (Dai et al., 2014a, 2014b).

In summary, the isotopic reversal of alkane gases from the lower Permian in the north margin of the SNCB was probably due to (1) destructive redox reactions at maximum burial resulting in Rayleigh type fractionation and/or (2) being mixed by oil cracked gas and coalderived gases from different sources. The reversed trend in δ2H in methane appears to be caused by isotopic exchange with formation water at the same temperatures. 5.4. The calculation of free gas and adsorbed gas in shale Total gas content of shale gas requires measurement of three components: lost gas, measured gas, and remainder gas (Ma et al., 2015; Yang et al., 2016). The term “desorbed gas” is used for the measurement of the content of coalbed gas, instead of measured gas. However, for the determination of shale gas content, the gas released includes the adsorbed gas as well as free gas in the core Matrix. Therefore, the measured gas is used to avoid confusion (Ma et al., 2015). Lost gas is considered to be dominated by free gas and residual gas is considered to be dominated by adsorbed gas while the measured gas is a mixture of free gas and adsorbed gas. Therefore, the proportion of free gas in measured gas is the key to estimate the proportion of free gas in total gas. Both shale gas production and desorption experiments confirmed that the δ13C1 and δ2HCH4 values have a tendency to become heavier with increasing degree of gas desorption (Tang and Xia, 2011). As shown in Table 1 and Fig. 7, a relative change occurs in the δ13C1 values from − 31 ‰ to − 27.7 ‰ (WC-1), from − 31.6 ‰ to − 26.8 ‰ (WC-2), from − 31.6 ‰ to − 29.7 ‰ (WC-4) and from − 29.9 ‰ to − 29 ‰ (WC-6), respectively. A methane molecule with 12C atom has smaller adsorption energy and a higher diffusivity compared with a methane molecule with 13C atom (Tang and Xia, 2011). Therefore, the released gas enriches in 12C at the early stage (carbon isotope composition is more “light”), and the concentration of 13C increases during desorption

Fig. 8. Methane adsorption isotherms at 30 °C comparison for different samples.

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Y. Liu et al. / International Journal of Coal Geology 156 (2016) 25–35

Table 3 Gas composition and carbon isotope of methane for shale gases released in the desorption experiments from well Mouye-1. Sample

Formation

Depth(m)

Desorption stage

Temperature

MY-7

P1s

2887

MY-25

P1s

2891

MY-40

P1s

2894

MY-49

P1t

2901

MY-53

P1t

2904

1 2 3 1 2 3 1 2 3 1 2 3 1 2 3

20 °C 90 °C 120 °C 20 °C 90 °C 120 °C 20 °C 90 °C 120 °C 20 °C 90 °C 120 °C 20 °C 90 °C 120 °C

δ13C(‰)VPDB

Gas composition (%) CH4

C2H6

CO2

N2

CH4

96.40 88.12 82.53 88.13 82.32 76.22 89.1 78.23 72.56 91.73 84.24 77.84 88.43 80.21 76.54

n.d. n.d. 0.42 n.d. 0.21 0.38 n.d. 0.24 0.44 n.d. n.d. 0.32 n.d. 0.18 0.46

3.60 7.35 10.33 11.87 7.86 13.62 10.9 8.59 12.23 8.27 7.86 10.65 11.57 8.24 10.88

n.d. 4.53 6.72 n.d. 9.61 9.78 n.d. 12.94 14.77 n.d. 7.9 11.19 n.d. 11.37 12.12

−29.7 −29.1 −27.8 −31.5 −30.7 −29.3 −31.4 −30.8 −28.6 −30.4 −29.5 −28.2 −29.3 −28.4 −27.4

Notes 1. n.d. means not detected. 2. P1S = Shanxi formation (Fm); P1t = Taiyuan Fm 3. All the gas compositions (CH4, C2H6, N2, CO2) have made correction to eliminate the influence of the air.

(carbon isotope composition becomes more “heavy”) within individual heating stages. Assuming free gas and adsorbed gas binary mixing, the δ13C1 values can be used to estimate the proportion of free gas and adsorbed gas components in desorption process. The proportion of free gas in measured gas is calculated as: Free gasðmeasured

gasÞ

h i ð%Þ ¼ δ13 C1ðmixedÞ −δ13 C1ðadsorbedÞ h i  100= δ13 C1ðfreeÞ −δ13 C1ðadsorbedÞ :

Free gas (measured gas) (%) is the proportion of free gas in measured gas; δ13C1 (mixed) is the δ13C1 value of the gas released in the stage 2 (reservoir temperature) of desorption experiment; δ13C1 (free) is the δ13C1 value of the gas released in the stage 1 (room temperature) of desorption experiment; δ13C1 (adsorbed) is the δ13C1 value of the gas released in the stage 3 (high temperature) of desorption experiment. To use this expression, the composition of the two end-members must be defined and each sample has its own end member value. In this study, the carbon isotope values of methane released at room temperature is identified as the end member of free gas and the carbon isotope values of methane released at high temperature is identified as the end member of adsorbed gas. As shown in Table 1, the gas released in the stage 1 of sample WC-1 and WC-2 is considered mainly free gas (the δ13C1 values are − 31 ‰ and −31.6 ‰, respectively) while the gas released in high temperature stage (stage 3) is considered mainly adsorbed gas (the δ13C1 values are −27.7 ‰ and −26.8 ‰, respectively), the gas released in reservoir temperature is mixed by the two kinds of gases. Our calculations show that

the proportion of the free gas in desorbed gas from sample WC-1 and WC-2 is 75.8% and 50%, respectively. The desorption curve (Fig. 2) also shows that the accumulation of gas in the first two stages was significantly more than that of the final stage (WC-1). But for sample WC-2, the accumulation of gas in the first two stages is roughly equivalent to that of the final stage. Because physical adsorption contributes significantly to the gas storage capacity of shales, knowledge of gas sorption capacity is important for the accurate prediction of maximum gas in place quantities in shale gas reservoirs. Previous studies have shown that the sorption capacity of shales is influenced by total organic carbon (TOC) content, thermal maturity, organic matter type and pore structure (Chalmers and Bustin, 2007a, 2008; Gasparik et al., 2012, 2014; Rexer et al., 2014; Ross and Bustin, 2007, 2009; Wang et al., 2013; Zhang et al., 2012). The 30 °C methane excess adsorption isotherms of the shale samples measured up to a pressure of 20 MPa are shown in Fig. 8. The methane adsorption capacity varies significantly from sample to sample. Under the measured pressure range, the isotherms of the shale samples increase monotonously with pressure, and subsequently become stable. When the experimental pressure reaches 15 MPa, the amount of adsorbed gas reaches its maximum of 1.10–1.97 m3/t. The sequence of the decrease in methane adsorption capacity for different shale samples (WC-4 N WC-2 N WC-1 N WC-6) is closely related to the TOC content. We applied this method to the study of well Mouye-1 which is located in the northeast of the well Weican-1 with their linear distance of 7 km. Five core samples for desorption experiment are from the Lower Permian Shanxi and Taiyuan formation. The carbon isotope values of gas samples (Table 3) from different desorption stage were used to

Table 4 The gas content of well Mouye-1 estimated by the USBM and isotopic method compared with the results estimated by well logging data. Sample

MY-7 MY-25 MY-40 MY-49 MY-53

Formation

P1s P1s P1s P1t P1t

Depth(m)

2887 2891 2894 2901 2904

Estimated by the USBM and isotopic method

Estimated by the logging data

Total gas(m3/t)

Lost gas(m3/t)

Measured gas(m3/t)

Remainder gas(m3/t)

Free gas(m3/t)

Adsorbed gas(m3/t)

Total gas(m3/t)

Free gas(m3/t)

Adsorbed gas(m3/t)

1.71 1.03 1.70 0.97 1.61

0.87 0.49 0.73 0.42 0.74

0.50 0.29 0.64 0.26 0.45

0.34 0.25 0.34 0.29 0.42

1.22 0.68 1.23 0.57 0.98

0.49 0.35 0.48 0.40 0.63

1.97 1.12 1.98 1.08 1.87

1.24 0.68 1.34 0.54 0.97

0.73 0.44 0.64 0.54 0.90

Notes 1. Free gas estimated using the USBM method = (Proportion of free gas in measured gas × measured gas) + lost gas. 2. Adsorbed gas estimated using the USBM method = Total gas-free gas. 3. Estimated by the logging data from Henan institute of geological survey, unpublished.

Y. Liu et al. / International Journal of Coal Geology 156 (2016) 25–35

33

Fig. 9. Comparison of well logging interpretation and calculated free gas based on carbon isotope of methane from well Mouye-1 indicated that carbon isotope of methane can effectively estimate the proportion of free gas in shales refer to equation or method used in the text for this determination, special mineral = plagioclase + siderite + pyrite.

calculate the relative content of free gas in measured gas (70.3%, 64.5%, 78.6%, 58.4% and 52.5%, respectively). Therefore, the free and adsorbed gas content in total gas can be estimated as: Free gasðtotoal

 gasÞ

 m3 =t ¼ Free gasðmeasured gasÞ ð%Þ    Measured gas m3 =t  3  þ Lost gas m =t :

Lost gas, the gas released from the time the target shale was drilled to the time that the sample was sealed in the desorption canister, can be estimated using the United States Bureau of Mines (USBM) method (Kissell et al., 1973). Subsequently the “remainder gas” is determined by crushing the desorbed sample to a powder (~200 mesh) in a sealed mill (Yang et al., 2016). On the other hand, the gas content logging interpretation model based on the adsorption isotherm and volume model has been widely used in the prediction of gas content in shale gas (e.g. Passey et al., 1990; Zuber et al., 2002; Lewis et al., 2004; Tang et al., 2014b). Based on the data of gas content using direct USBM and isotopic

method, the free and adsorbed gas content can be estimated (Table 4). The results estimated by the USBM and isotopic method compared with the results estimated by well logging data (Henan institute of geological survey, unpublished) are shown in Fig. 10a, the total and adsorbed gas contents estimated by logging data are often greater than those estimated by the USBM and isotopic method. The proportion of free gas in total gas also shows that the results of these two methods are relatively close, but there are still some gaps (Figs. 9 and 10b). This is mainly related to the results estimated by well logging data, which usually overestimate the content of adsorbed gas. 6. Conclusions (1) The stable isotopic data of carbon and hydrogen of shale gas released from Permian shale in the north margin of the SNCB show that the gas are thermogenic origin and sourced from the continental shale and coal measures, with minor contribution from oil cracked gas from marine mudstones. Besides, the methane with heavy carbon isotopic and light hydrogen isotopic

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Y. Liu et al. / International Journal of Coal Geology 156 (2016) 25–35

Fig. 10. a, Comparison of the gas content (total, free and adsorbed gas) estimated by USBM and isotopic method and which estimated by logging data; 10b, the proportion of free gas in total gas estimated by these two method.

values maybe produced through formation water reacting with inorganic carbon. (2) The carbon isotopic compositions of all the alkane gases from the lower Permian in the north margin of the SNCB are characterized by δ13C1 N δ13C2 which was probably due to (1) destructive redox reactions at maximum burial resulting in Rayleigh type fractionation and/or (2) being mixed by oil cracked gas and coal-derived gases from different sources. The reversed trend in δ2H in methane appears to be caused by isotopic exchange with formation water at the same temperatures. (3) The gas desorption experimental results show that the δ13C1 values have a tendency to become heavier with increasing degree of gas desorption. The variation of stable carbon isotopes in different desorption stage was applied to establish an equation: Free gas (measured gas) (%) = [δ13C1 (mixed) − δ13C1 13 13 (adsorbed)] × 100 / [δ C1 (free) − δ C1 (adsorbed)] to estimate the ration of free gas and adsorbed gas in measured gas. (4) The total and adsorbed gas contents estimated by logging data are often greater than those estimated by the USBM and isotopic method. The proportion of free gas in total gas also shows that the results of these two methods are relatively close, but there are still some gaps mainly related to the results estimated by well logging data, which usually overestimate the amount of adsorbed gas.

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