Controls on Gas Content and Carbon Isotopic Abundance of Methane

Article pubs.acs.org/EF

Controls on Gas Content and Carbon Isotopic Abundance of Methane in Qinnan-East Coal Bed Methane Block, Qinshui Basin, China Zhaoping Meng,*,†,§ Jiwei Yan,†,§ and Guoqing Li§,‡ †

College of Geosciences and Surveying Engineering, China University of Mining and Technology (Beijing), Beijing 100083, P. R. China ‡ Faculty of Earth Resources, China University of Geosciences, Wuhan, Hubei 430074, P. R. China § State Key Laboratory of Coal and CBM Co-mining, Shanxi Jincheng Anthracite Mining Group Company, Ltd., Jincheng, Shanxi 048000, P. R. China ABSTRACT: Qinnan-East Block is one newly planned coal bed methane (CBM) exploration area in the Qinshui Basin, China, and research on the accumulation of gas in this block is quite limited. In this study, on the basis of a series of laboratory experiments and the latest exploration data, the gas content and carbon isotopic ratio of methane [δ13C(CH4)] in the No. 3 coal seam of Permian Shanxi Formation in Qinnan-East Block were investigated, and then the correlations between δ13C(CH4) and vitrinite reflectance, burial depth, gas content, reservoir pressure, and gas adsorption saturation were analyzed; then, the mechanism controlling the gas bearing properties and the distribution of δ13C(CH4) in the study area were addressed. It turns out that the gas content in the study area ranges from 2.87 to 24.63 m3/t with an average of 13.78 m3/t, the CBM reservoir pressure ranges from 0.86 to 5.96 MPa with an average of 3.09 MPa, the reservoir pressure gradient ranges from 0.11 to 1.06 MPa/100 m with an average of 0.49 MPa/100 m, and the gas saturation ranges from 12.34 to 117.76% with an average of 67.58%; the gas content, CBM reservoir pressure, and gas saturation increase with an increase in burial depth. δ13C(CH4) of naturally desorbed methane from the No. 3 coal seam varies from −28.89 to −53.27‰ with an average of −36.48‰ and increases with an increase in vitrinite reflectance and burial depth. The carbon isotopic abundance of CBM is mainly controlled by the thermodynamic equilibrium fractionation in the formation of CBM and the kinetic disequilibrium fractionation in the transport of CBM. δ13C(CH4) rises in a nearly logarithmic form with the increase in CBM content, reservoir pressure, and gas saturation. The geological controls on gas bearing properties of the coal seam are vitrinite reflectance and effective burial depth, which are similar to those of the carbon isotopic abundance of methane. The outcomes may benefit the exploration of CBM in the study area.

1. INTRODUCTION The gas content in a coal seam is one of the key factors that influence the coal bed methane (CBM) resources and production potential. The formation, transport, and storage significantly influence the gas content, reservoir pressure, and gas saturation.1−3 The carbon isotopic abundance of methane is a widely used and effective index for distinguishing the origin of gas and hydrocarbon source rocks.4−10 δ13C(CH4) gradually rises with an increase in the degree of metamorphism of organic matter in the coal. The carbon isotopic ratio δ13C(CH4) is considered to be below −60‰ (‰ is per mille) on the PDB (Pee Dee Belemnite) scale for secondary biogenic methane and above −60‰ for thermogenic methane.11 Scott et al.12 suggested that secondary biogenic gas accounts for 15−30% of the total gas in place in Fruitland coal in the northern San Juan basin. Thielemann et al.13 found that δ13C(CH4) ranges from −40.0 to −57.3‰ in the Ruhr Basin, and the methane is a mixture of thermogenic and microbial gas. δ13C(CH4) in the Qinshui Basin ranges from −29.63 to −35.39‰, which indicates a typical thermogenic origin.14 Kedzior et al.15 found a secondary methane accumulation zone with a δ13C(CH4) value that ranges from −71 to −65‰, and this zone has a burial depth of 55‰, while for Received: November 29, 2016 Revised: January 12, 2017 Published: January 12, 2017 1502

DOI: 10.1021/acs.energyfuels.6b03172 Energy Fuels 2017, 31, 1502−1511

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Energy & Fuels

Figure 1. Stratigraphic column of the Permo-Carboniferous coal-bearing strata and contour of the No. 3 coal seam floor in the study area.

thermogenic gas, δD(CH4) is above −250‰ and Δ13C(CO2/ CH4) is below 40‰.20 Numerous researchers have investigated the distribution characteristics of δ13C(CH4) and found that it is affected by a few factors, including the carbon isotope exchange between methane and carbon dioxide, the differentiation effect during the desorption−diffusion−seepage process, the thermal evolution differentiation effect, secondary biogenic gas and groundwater runoff, etc.21−28 On the basis of the statistics of the available carbon isotope data for CBM reservoirs all over the world, Law19 and Rice20 found that δ13C(CH4) varies in a relatively wide range between −80 and −16.8‰. Qin et al.21,22 analyzed the distribution and formation of stable carbon isotopes in CBM reservoirs in China and found that δ13C(CH4) is overall low, ranges from −78 to −13‰, and varies with district, geological age, and coal rank. In regional terms, δ13C(CH4) ranges from −78 to −28‰ in northern China, from −68 to −25‰ in southern China, and from −68 to −49‰ in northeastern China. Zhang et al.23 found that δ13C(CH4) in the Qinshui Basin increases with an increase in burial depth. Qin et al.26,27 found that both δ13C(CH4) and gas content are low in the regions with strong hydrodynamic conditions and confirmed the hydrodynamic fractionation effect of gas in water with dissolving experiments. Li et al.28 tested the δ13C(CH4) values of 72 CBM samples with different coal ranks in five typical coal basins in China and analyzed the fractionation effect of isotope from four perspectives, including the thermal evolution process, biological degradation, the desorption/adsorption process, and the dissolution of gas in water.

Qinnan-East Block is one newly planned CBM exploration area in the Qinshui Basin, China. Knowledge of the origin of the gas and its accumulation in this block will benefit future CBM exploration and exploitation, but our current understanding of it is very limited. In this paper, following a brief introduction of the geology in the study area, on the basis of a series of laboratory experiments and the latest exploration data, the gas content and carbon isotopic ratio of methane [δ13C(CH4)] in the No. 3 coal seam of Permian Shanxi Formation in Qinnan-East Block were elucidated and then the correlations between δ13C(CH4) and vitrinite reflectance, burial depth, gas content, reservoir pressure, and gas adsorption saturation were analyzed; finally, the mechanism controlling the gas bearing properties and the distribution of δ13C(CH4) in the study area were addressed. The outcomes may benefit CBM exploration and development in this area.

2. MATERIALS AND METHODS 2.1. Geological Setting. Qinnan-East Block, located in the mideast region of Qinshui Basin, China, has an area of 1614 km2 (Figure 1). It has a complex terrain with many hills and mountains. The strata from top to bottom comprise Cenozoic Quaternary (Q), Neocene (N), Mesozoic Triassic System (T), Upper Paleozoic Permian Shiqianfeng Formation (P2sh), Upper Shihezi Formation (P2s), Lower Shihezi Formation (P1x), Shanxi Formation (P1s), Carboniferous Taiyuan Formation (C3t), Benxi Formation (C2b), and Paleozoic Ordovician Fengfeng Formation (O2f) in the block. The main minable coal seams are the No. 3 coal seam in Permian Shanxi Formation and the No. 15 coal seam in Carboniferous Taiyuan Formation. The No. 3 coal seam, located in the lower part of Shanxi 1503


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Energy & Fuels Formation (Figure 1), is our main target of CBM exploration, and its net thickness is approximately 5.00−6.50 m with an average of 5.40 m. The macrolithotype is mainly semibright coal and locally semidull coal. The coal structures of the No. 3 coal seam include primarily intact and cataclastic structures, and there is a layer of dirt band in this coal seam. There is overall a monocline structure in the study area. The strata strike in the north-northeast direction and dip in the southwest direction with a dip angle of 5−10°. There are also some secondary folds and some NE-trending normal faults. The burial depth of the No. 3 coal seam increases from east to west. 2.2. Experiments and Methodology. Seventy-two samples were collected from the No. 3 coal seam in Qinnan-East Block in Qinshui Basin using a rope coring method during the drilling of CBM wells (Figure 2). First, the gassy coal core samples were desorbed on site for

Oxygen Isotope in Organic Matter and Carbonate (SY/T5238-2008)”. The accuracy of the analysis is ±0.2‰, Pee Dee Belemnite (PDB). Vitrinite reflectance and macerals were measured using an AX10 Imager M1m-type Micro Photometer produced in Germany in terms of China national standard “Method of Determining Microscopically the Reflectance of Vitrinite in Coal (GB-T6948-2008)”.

3. RESULTS 3.1. Adsorption Capacity of Coal. The maximal reflectance of vitrinite (R°max) of the No. 3 coal seam ranges from 1.97 to 2.71% with an average of 2.36%, and the types of coal are primarily bituminous coal and anthracite. The vitrinite content ranges from 60.00 to 90.80% with an average of 73.66%; the inertinite content ranges from 7.20 to 40.00% with an average of 26.34%. The ash yield (as received) ranges from 7.94 to 37.04% with an average of 14.16%, and therefore, it is a medium−low-ash coal. The moisture content ranges from 0.58 to 1.53% with an average of 1.14%, and the volatile content ranges from 6.53 to 15.45% with an average of 9.77%. The results of isothermal adsorption experiments show that the Langmuir volume (air-dried basis) ranges from 18.15 to 34.75 m3/t with an average of 29.36 m3/t and the Langmuir pressure ranges from 1.47 to 2.71 MPa with an average of 2.03 MPa (Figures 2 and 3). The spatial distribution laws can be described as follows. (1) The Langmuir volume is relatively small in the west and southeast portions of the study area (Figure 2). (2) The Langmuir pressure generally increases from east to west and from shallow to deep in the study area (Figure 3). (3) There is a positive correlation between the Langmuir

Figure 2. Langmuir volume distribution of the No. 3 coal seam in the study area. 8 h, and then desorption experiments were conducted in the laboratory. The temperature in the sample tank was kept constant close to the reservoir temperature using a water bath. A series of isothermal adsorption experiments were performed in the laboratory using an ISO-300 isothermal adsorption and desorption instrument made by TerraTek. The testing procedure followed China national standard “Experimental Method of High-Pressure Adsorption Isothermal to Coal-Capacity Method (GB/T19560-2008)”. For isothermal adsorption experiments, a 100−120 g sample of coal with a size of 0.2−0.25 mm (60−80 mesh) was selected. Before the isothermal adsorption experiment, proximate analysis was conducted to determine the moisture, ash, volatile matter, and fixed carbon content of the coal samples in terms of China national standard “Proximate Analysis of Coal (GB/T212-2008)”. The carbon isotopes of 72 methane samples were measured with a MAT253 stable isotope ratio mass spectrometer produced by Thermo Fisher Scientific Co. according to China petroleum and natural gas industry standard “Analysis Method for Carbon, Hydrogen and

Figure 3. Langmuir pressure distribution of the No. 3 coal seam in the study area. 1504


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13.78 m3/t and increases with an increase in burial depth (Figure 6). The gas content is lower in this block than in the other blocks in the southern Qinshui Basin.

volume and the Langmuir pressure of the No. 3 coal seam in the study area (Figure 4).

Figure 4. Relationship between the Langmuir volume and Langmuir pressure for dry ash free coal.

3.2. Reservoir Pressure. The CBM reservoir pressure ranges from 0.86 to 5.96 MPa with an average of 3.09 MPa, and the pressure gradient ranges from 0.11 to 1.06 MPa/100 m with an average of 0.49 MPa/100 m above 886.30 m in the No. 3 coal seam of the Lower Permian Shanxi Formation in the study area (Figure 5). The pressure gradient is obviously lower

Figure 6. Gas content distribution of the No. 3 coal seam in the study area.

The coal seam gas extracted from the No. 3 coal seam consists of 55.82−99.30% methane (an average of 94.88%, by volume), 0.48−42.97% N2 (an average of 4.73%), and 0.10− 1.22% CO2 (an average of 0.37%). In addition, No. 3 coal seam gas in this block contains a small fraction of heavy hydrocarbons, ranging from 0 to 0.31% with an average of 0.03%. Gas adsorption saturation is the ratio of measured gas content in place to the gas adsorption capacity at the original reservoir pressure, and it is an important parameter for the evaluation of the potential of CBM extraction. Gas saturation in a conventional gas/oil reservoir is the volume percentage of gas/oil in the rock pore space, and therefore, the concept of gas saturation of a CBM reservoir is quite different from that of a conventional gas/oil reservoir. Gas saturation of a CBM reservoir actually refers to gas adsorption saturation of a coal seam because the methane is stored in a coal seam largely in an adsorbed state. Gas saturation in a coal seam can be calculated by the following equation:

Figure 5. Burial depth of the No. 3 coal seam.

in this region than in the other CBM blocks in the southern Qinshui Basin. The CBM reservoir pressure increases with an increase in burial depth, which can be described as follows: P0 = 0.0096D − 2.6333

(1)

where P0 is CBM reservoir pressure (megapascals) and D is the burial depth of coal (meters). 3.3. Gas Content, Composition, and Gas Saturation. The measured gas content of the No. 3 coal seam of Shanxi Formation ranges from 2.87 to 24.63 m3/t with an average of

S=

Va PL + Pr × VL Pr

(2)

where Pr is the CBM reservoir pressure (megapascals), Va is the actual gas content (cubic meters per ton), VL is the Langmuir 1505


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Energy & Fuels volume (cubic meters per ton), PL is the Langmuir pressure (megapascals), and S is the gas saturation (percent). The gas saturation of the No. 3 coal seam ranges from 12.34 to 100.00% with an average of 67.58% in the study area. This block is fully gas-saturated in local areas and is overall undergas-saturated, and gas saturation increases with an increase in the burial depth of the coal seam (Figure 7).

Figure 8. δ13C(CH4) of the No. 3 coal seam in the study area.

Table 1. Carbon Isotopes of Methane in Different Areas region China

eastern edge of Ordos Basin29 Qinnan-East of Qinshui Basin Sydney and Bowen basins30 San Juan Basin12

Figure 7. Gas saturation distribution of the No. 3 coal seam in the study area.

3.4. Distribution of the Carbon Isotopes of Methane. The experimental results (Figure 8) show that this block has the following characteristics in terms of gas composition and carbon isotope abundance of methane. (1) δ13C(CH4) in the No. 3 coal seam ranges from −28.89 to −53.27‰ with an average of −36.48‰ and is lower in this block than in Fanzhuang Block (from −30.30 to −48.20‰ with an average of −35.37‰) in the southern Qinshui Basin. δ13C(CH4) of the No. 15 coal seam in this block ranges from −27.62 to −34.03‰ with an average of −30.94‰. In the Heshun CBM Block, δ13C(CH4) ranges from −35.5 to −48.6‰ with an average of −42.05‰ for the No. 3 coal seam and from −32.76 to −39.00‰ with an average of −36.05‰ for the No. 15 coal seam. (2) δ13C(CH4) is generally greater in the block than in other CBM blocks in China with the same coal rank (Table 1). δ13C(CH4) in China ranges from −78 to −13‰.19,20 (3) δ13C(CH4) varies spatially in the study area (Figure 8). 13 δ C(CH4) increases gradually from east to west or from southeast to northwest. δ13C(CH4) is relatively low in southeast area with a value of generally below −40.00‰.

δ13C(CH4) (‰) −78 to −13

24

gas origin

−53.27 to −28.89

thermogenic and biogenic thermogenic and biogenic thermogenic

−70 to −50 −47.89 to −42.43

mainly biogenic thermogenic

−70.5 to −36.19

δ13C(CH4) is generally above −40.00‰ in the southwest and northwest portions of the study area, ranging from −35.00 to −40.00‰, as shown in Table 1.

4. DISCUSSION 4.1. Relationships between δ13C(CH4) and Gas Bearing Parameters of the No. 3 Coal Seam. Statistics show that δ13C(CH4) of the No. 3 coal seam increases with an increase in gas content, coal reservoir pressure, and gas saturation by a logarithmic function (Figure 9), which can be described as follows: δ13C(CH4) = 6.7121 ln(Q ) − 53.284

(3)

δ13C(CH4) = 4.9751Ln(P) − 44.012

(4)

13

δ C(CH4) = 8.1572 ln(S) − 69.975

(5)

where δ C(CH4) is the carbon isotopic ratio (‰) of methane, Q is the gas content (cubic meters per ton), P is the CBM 13

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Figure 11. Relationship between δ13C(CH4) and R°max.

verify them; however, we consider that the overall trends are rather clear. 4.2. Influence of Tectonic Movement on Gas Bearing Properties. CBM gas bearing properties are mainly controlled by the thermal evolution and tectonic differentiation of coals. The gas origin type relies on the metamorphic degree of the coal seam, and the cumulative gas generation volume increases with an increase in metamorphic degree.1 After the formation of coal seams in the study area, the fluid pressure of the coal seam decreased with the uplift and erosion of the coal seam due to tectonic movement, leading to the desorption and loss of gas in the coal seam, and thereby, the gas content decreased. From Late Permian to Late Triassic, with the rapid subsidence of the local crust and the increase in the temperature of the strata in the study area, CBM was formed. From the end of the Late Triassic to the Early Cretaceous, Yanshanian Orogeny led to an uplift of the local strata and the coal seams were degassed gradually with the uplift of Carboniferous-Permian strata, resulting in a decrease in gas content. Despite the uplift of the local strata, caused by the thermal effect of Yanshan tectonic movement, the temperature of the Carboniferous-Permian coal seam was higher than its historical peak temperature. As a result, coalification continued, the generation of hydrocarbon reached its peak, and the gas adsorption capacity of coal increased. After that, the coal seam experienced a large scale bathygenic movement in the Cenozoic period. However, this bathygenic movement did not increase the degree of metamorphosis of coal, and thereby, there was no regeneration or re-adsorption of gas in the coal seam (Figure 10). Cenozoic sedimentation can increase the coal seam pressure. Assuming a hydrostatic pressure gradient, when the thickness of Cenozoic strata increases by 100 m, the CBM reservoir pressure will increase by

Figure 9. Relationships between δ13C(CH4) and gas bearing properties of the CBM reservoir.

reservoir pressure (megapascals), and S is the gas saturation of CBM reservoir (percent). The correlation coefficients (R2) of eqs 3−5 for 72 samples [72 data points (N)] are 0.4072, 0.3324, and 0.4024, respectively. From the analysis described above, we can see that for the coal seams with similar coal ranks, the lower the CBM reservoir pressure and the lower the gas content and gas saturation, the smaller the δ13C(CH4). There is good correlation between δ13C(CH4) and these three gas bearing parameters. Mathematically, they are rough correlations, and more data are needed to

Figure 10. Burial depth and thermal history of Carboniferous-Permian coal-bearing strata.31 1507


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Energy & Fuels Table 2. Regression Coefficients between δ13C(CH4) and R°max no.

ref

year

regression coefficient a

regression coefficient b

remarks

1 2 3 4 5 6 7

4 5 6 7 32 33 10

1975 1980 1985 1985 1993 1991 1999

28 authors of this article

2010 2014

−28.0 −35.0 −32.8 −34.39 −34.48 −34.0 −34.1 −34.8 −45.80 −60.56

coal-type gas, north Germany (R°max > 0.5%) coal-type gas, North America coal-type gas, Dongpu Depression (R°max > 0.6%) China (R°max > 0.5%) Liaohe Basin (R°max = 0.3−1.3%) China (R°max = 0.3−2.0%) materials of the main coal-type gas basin in China

8 9

8.6 15.0 8.64 14.12 49.56 40.49 48.77 22.42 7.69 29.41

typical coal−gas-type basin in China Qinnan-East Block of Qinshui Basin

δ13C(CH4) values of a humic type of conventional natural gas in different stages are −78 to −55‰ (biogenic gas), −55 to −35‰ (thermal gas), and above −35‰ (pyrolysis gas) (Table 1). The Carboniferous-Permian coal seams consist mainly of bituminous coal and anthracite. The measured maximal vitrinite reflectance (R°max) of the No. 3 coal seam is 1.97−2.71% with an average of 2.36%. Then theoretically, CBM in this area is mainly thermogenic gas. The following logarithmic relationship between δ13C(CH4) and R°max of the No. 3 coal seam in this area (Figure 11) exists:

Figure 12. Relationship between δ13C(CH4) and burial depth.

δ13C(CH4) = 29.406 ln(R °max ) − 60.559

(6)

where δ C(CH4) is the carbon isotopic ratio of methane from the No. 3 coal seam (‰), R°max is the maximal reflectance of vitrinite (percent), correlation coefficient R2 = 0.4033, and the statistic points N = 72. The typical δ13C(CH4) values of CBM in China are −62, −43, and −36‰ when the vitrinite maximal reflectance values are equal to 0.5, 2.0, and 4.0%, respectively. Numerous researchers in China have obtained a logarithmic function relationship between δ13C(CH4) of coal-type gas and R°max. Then the relationship between δ13C1 of CBM and R°max can be generalized as follows: 13

Figure 13. Relationship between δ13C(CH4) and effective burial depth.

δ13C(CH4) = a ln(R °max ) + b

(7)

where a and b are the regression coefficients (Table 2). The δ13C(CH4) of the No. 3 coal seam is similar to that of thermal gas in a humic type of convention gas. The carbon isotopic ratio is mainly controlled by the thermodynamics of the equilibrium mechanism during the formation of CBM.19,20 There may be some other factors that can explain the scattered data in Figure 11, for instance, the CBM desorption− diffusion−seepage effect, the groundwater dynamics effect, etc. 4.3.2. Kinetic Disequilibrium Fractionation of the Carbon Isotope in the Transport of CBM. Methane is mainly adsorbed in the micropores of the coal matrix by van der Waals forces. The molecular weight of 13CH4 is larger than that of 12CH4, and coal has a higher adsorption capacity for 13CH4 than for 12 CH4. Therefore, carbon of different molecular weights would show a differentiation phenomenon when the methane desorbs from the coal matrix. 12CH4 desorbs from the coal matrix prior to 13CH4, and 13CH4 will mainly stay in the coal seam. In the diffusion−seepage process, 12CH4 becomes relatively enriched in the desorbed CBM, leading to a zoning distribution of isotope from deep to shallow.19,20 The adsorption and desorption of CBM in the coal seam are reversible with respect to each other. Because the van der Waals force between the 13CH4 and coal matrix is relatively large in the adsorption process, 13CH4 will be preferentially adsorbed in

nearly 1 MPa. Even if the original coal seam is in a gas-saturated state, when the reservoir pressure increases while the gas content does not increase correspondingly, the coal seam will be in a gas-unsaturated state. In addition, CBM was being emitted through the faults and karst collapse columns during the geological history, and thereby, the gas content and gas saturation decreased. 4.3. Mechanism of Fractionation of the Carbon Isotope of Methane and the Control of Gas Bearing Properties. 4.3.1. Thermodynamic Equilibrium Fractionation of the Carbon Isotope in the Formation of CBM. Carbon isotope differentiation relies on the fact that the energy required for bond breaking follows a descending order: 13C−13C > 12 C−13C > 12C−12C. At a relatively low temperature, the probability of the bond breaking and generation of methane is higher for the 12C−12C bond than for the 13C−13C bond. When the temperature increases, the probability of bond breaking of the 12C−13C and 13C−13C bonds will increase.21 δ13C(CH4), as well as gas bearing properties, varies with coal rank. The spatial variation of δ13C(CH4) in this study area is controlled by the thermal maturity of the coal and affected by the CBM desorption−diffusion−seepage effect and groundwater dynamics effect. 1508


Article strong runoff−weak runoff area

weak runoff-confined area

−65 to −50

−50 to −30

>−30

>80

≥90

Controls on Gas Content and Carbon Isotopic Abundance of Methane

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