Geological controls on gas saturation in the Yanchuannan Coalbed Methane Field, Southeastern Ordos Basin, China

Marine and Petroleum Geology 78 (2016) 254e270

Contents lists available at ScienceDirect

Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo

Research paper

Geological controls on gas saturation in the Yanchuannan Coalbed Methane Field, Southeastern Ordos Basin, China Shihui Hou a, Xiaoming Wang a, *, Xingjin Wang a, Yudong Yuan b, Xinguo Zhuang a, Xiaomei Wang a a b

Key Laboratory of Tectonics and Petroleum Resources, China University of Geosciences, Wuhan 430074, China School of Petroleum Engineering, University of New South Wales, Sydney, NSW 2052, Australia

a r t i c l e i n f o

a b s t r a c t

Article history: Received 30 June 2016 Received in revised form 24 September 2016 Accepted 26 September 2016 Available online 28 September 2016

The paper investigates lateral variation of gas saturation and its geological controls of the No.2 coal seam in the Permian Shanxi Formation based on coal samples from 21 exploration wells in the Yanchuannan Coalbed Methane (CBM) Field, Southeastern Ordos Basin, China. The data set reveals that gas saturation of the No.2 coal seam shows a high lateral variation from 32.44% to 89.69%, and that there is an overall trend in gas saturation with depth overprinted by four other factors: 1) influence of faults, 2) secondary biogenic gas generation, 3) local top seal conditions and 4) variations in coal properties. The reverse faults F1 and F2 are effective barriers horizontally for the hydraulic communication and divide our study area into relatively closed and recharge zones. Gas saturation of the relatively closed zone is generally higher than that in the recharge zone. In the recharge, gas saturation increases generally along the flow pathway of groundwater with the exceptions of the areas affected by secondary biogenic gas. The stable isotope compositions suggest that late-stage biogenic methane was generated via CO2 reduction associated with meteoric water recharge, which significantly contributes to higher gas saturation than expected. Meanwhile, the biogenic gas generation was/is restricted to shallow depths. The apparent variations in local areas of lithology of the overlying stratum next to the coal seam suggest that the top seal conditions are deteriorative, which can cause gas dissipation and reduce gas saturation remarkably. Integrally, for the variations in coal properties, gas saturation has a general positive relationship with coalification, and weak negative correlations with moisture content and ash yield but the relationships lacks statistical significances. Gas saturation is not associated with coal maceral in the study area. © 2016 Elsevier Ltd. All rights reserved.

Keywords: Coalbed methane Gas saturation Yanchuannan Coalbed Methane Field Ordos Basin

1. Introduction Gas saturation is an important index to evaluate production performance of coalbed methane (CBM) wells, including gas rate, dewatering process, pressure decline and ultimate gas recoverability (Bustin and Bustin, 2008; Moore, 2012; Pashin, 2010). Large quantities of gas can be generated during the coal formation process, especially in later stages of coalification (Gan et al., 1972; Karweil, 1955), and can markedly exceed gas adsorption capacity of the coal reservoir itself (Bustin and Clarkson, 1998; Zhang et al., 2008). In the actual CBM gas production operations, however, coal reservoirs in most cases remain undersaturated rather than oversaturated with respect to methane at present-day burial depths and

* Corresponding author. E-mail address: [email protected] (X. Wang). http://dx.doi.org/10.1016/j.marpetgeo.2016.09.029 0264-8172/© 2016 Elsevier Ltd. All rights reserved.

temperatures (Bustin and Bustin, 2008; Scott, 2002). This can be attributed to basin uplift and cooling, which leads to an increase in gas adsorption capacity without augmentation by hydrocarbon migration or late-stage bacterial methanogenesis (Ayers Jr., 2002; Moore, 2012; Yang and Saunders, 1985) and/or the possible degassing of CBM to the surface (Scott, 2002; Yao et al., 2013). Gas saturation shows significant variations both vertically and laterally within a single coal seam (Stra˛ poc et al., 2008), which cannot be solely explained by basin uplift and cooling (Pashin, 2010; Scott, 2002). Therefore, more in-depth analysis is required to understand the controlling factors on gas saturation variation within a single coal seam and to establish a composite model on gas saturation variation. The present study examines the gas saturation heterogeneity and its controlling factors in the No.2 coal seam exclusively, though there are 10 coal seams ranging in age from Carboniferous to

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

Permian in the Yanchuannan CBM Field, Southeastern Ordos Basin, China. The coal seam is mined at shallower depths and is being developed as CBM resources in other areas of the studied area. This study will focus on the CBM areas. This paper begins with describing the lateral distribution of gas saturation, and then examines controlling factors, including depth, faults, secondary biogenic gas generation, sealing conditions and coal properties (coalification, coal quality and coal maceral). The paper concludes with proposing a model of lateral variation of gas saturation, which may serve as a theoretical basis for the next stage of CBM exploitation.

255

2. Geological setting The Yanchuannan CBM Field is located in the southeastern Ordos Basin (Fig. 1) which is a stable polycyclic sedimentary basin formed on the North China Craton (Yang et al., 2008; Zhu et al., 2008). The field with a total area of 701.4 km2 presents an irregular rectangle, which length and width are approximate 33.18 km and width 22.38 km, respectively. Four major faults are developed in the research area: Baihe reverse fault (F1) and Zhongduo reverse fault (F2) strike NE with the length of 20 km, and dip SE with the angle of 60
and the fault throw of 25e60 m. Jundiling normal fault

Fig. 1. The location of the Yanchuannan CBM Field as well as synoptic geological map of the study area showing the major tectonic blocks/units and the structural elevation on base of the No.2 coal seam.

256

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

(F3) strikes NE with a length of 15.6 km, and dips SE with an angle of 60
and a fault throw of 25e100 m. Zhangma normal fault (F4) strikes NE with a length of 29.8 km, and dips NW with an angle of 40
and a fault throw of 20e45 m. The current study mainly focuses on the northwest part of the fault F4, because the southeast part of the fault F4 is a coal mining area where no CBM wells have been drilled. The target area can be divided into three secondary tectonic blocks by the three major faults F1, F2, and F4 (Fig. 1), Wanbaoshan tectonic block (B1) (the area to the northwest of the fault F1), Central fault tectonic block (B2) (the area between the faults F1 and F2), and Tanping tectonic block (B3) (the area between the faults F2 and F4), among which Tanping tectonic block (B3) is subdivided into three tectonic units including Tanping gentle slope (B31), Bai'e fault-nose (B32) and Xibaigou gentle slope (B33). The tectonic units of B31 and B32 are the area between the faults F2 and F3, while the tectonic unit B33, presenting a graben, is the area between the faults F3 and F4. CBM wells are entirely in the tectonic blocks B1 and B3. The strata preserved in the Yanchuannan CBM Field include the Ordovician Majiagou Formation, Carboniferous Benxi and Taiyuan formations, Permian Shanxi, Shihezi and Shiqianfeng formations, Triassic Liujiagou, Heshanggou and Ermaying formations and unconsolidated Quaternary strata at the top (Fig. 2). The Triassic formations suffered from erosion in partial regions of the study area

during basin uplift. The main coal-bearing strata are the Carboniferous Taiyuan Formation deposited in an extensive tidal flat and shallow marine sedimentary environment (Ding et al., 2013; Watson et al., 1987), and the Permian Shanxi Formation deposited in a deltaic and lacustrine environment (Yang et al., 2005; Yao et al., 2013). The No.2 coal seam located within the Shanxi Formation is economically minable, with the burial depth ranging from 600 m to 1700 m. The structural contour of the bottom of the No.2 coal seam shows a homocline (Fig. 1), with NE strike and NW trend. The stratigraphic dip ranges from 2.2
to 5.3
. Simultaneously, the No.2 coal seam can be considered as an independent aquifer because of the hydrodynamic connection via coal fractures (Cai et al., 2014). 3. Experiments and methods Total gas content of all the 97 coal samples of the No.2 coal seam collected from 22 CBM exploration wells in the Yanchuannan CBM Field were determined by gas desorption canisters. Meanwhile, carbon (methane and carbon dioxide) and hydrogen (methane) stable isotopic compositions of desorbed gases were analyzed by using isotope mass spectrometer MAT253. After measurement of total gas content, coal samples were collected from coal canisters to perform methane adsorption isotherm experiments with an

Fig. 2. Stratigraphic column of the Yanchuannan CBM Field.

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

257

2009; 2013; 2014). Gas saturation of a coal refers to a ratio of measured total gas content to gas adsorption capacity at a given reservoir pressure and temperature (Moore, 2012; Pashin, 2010). According to Yao et al. (2013), gas saturation is defined as:

S ¼ GI =GE ¼ GI ðPR þ PL Þ=ðPR  VL Þ

Fig. 3. Absolute adsorption isotherm showing relationship among parameters of calculated gas saturation. Modified from Pashin (2010).

Isotherm Adsorption/Desorption System ISO-200. Mean maximum vitrinite reflectance (Ro, max), coal maceral and proximate analysis were obtained based on analysis of coal samples from canisters. Ro, max measurement and coal maceral analysis were performed on the same polished section of coal samples, with application of MPV-3 microphotometer. Meanwhile, two samples obtained from the Y8 and Y17 wells were conducted for BET specific surface area using a Micromeritics ASAP 2020 with nitrogen as an adsorbent. Water samples produced from the No.2 coal seam were collected following the guidelines of Rice (2003) during the dewatering processes to measure the groundwater geochemistry parameters. At the time of sampling, the CBM wells had been produced for over 5 months to remove disturbances of drilling and hydraulic fracturing fluids on the groundwater samples. Cation and anion concentrations of chloride and sulfate were determined using ion chromatograph ICS-1500, while bicarbonate and carbonate were detected with titration. The analysis standards for the above experiments are comprehensively discussed in Yao et al. (2008;

(1)

where, S is gas saturation, GI is total gas content, GE is theoretical maximum gas adsorption capacity for initial reservoir pressure (PR), and VL and PL are Langmuir volume (air dry basis) and Langmuir pressure, respectively. The correlation of parameters is shown in Fig. 3. The initial reservoir pressure was directly represented by the borehole pressure on the first day of pumping water from the No.2 coal seam. In general, well test interpretation is the best method to obtain the initial reservoir pressure. The injection falloff tests were performed in 10 exploration wells of the research area, but the tests fail to present representative values of initial reservoir pressure because of no occurrence of radial flow on log-log derivative plot. 4. Results and discussion 4.1. Distribution of gas saturation Table 1 summarizes the results of total gas content, gas adsorption capacity and gas saturation. Although all the 97 coal samples collected from 22 CBM exploration wells were tested for total gas content, some samples without isothermal adsorption data could not be used in the calculation of gas saturation. A total of 48 coal samples collected from 21 exploration wells were included to investigate the regional variation of gas saturation of the No.2 coal seam in the Yanchuannan CBM Field. Four subregions of the gas content, gas adsorption capacity and gas saturation across our study area were determined based on a reference of these parameters researched in Yao et al. (2013). The spatial distribution of gas content of the No.2 coal seam is

Table 1 Averaged results per well of total gas content, gas adsorption capacity, gas saturation, proximate analysis, coal maceral and Ro, max of the No.2 coal seam in the Yanchuannan CBM Field (number of coal samples ¼ 48; number of exploration wells ¼ 21). Well No. Sample depth

Y1 Y1P4 Y2 Y3 Y4 Y6 Y7 Y8 Y10 Y11P2 Y11P3 Y13 Y14 Y15 Y16 Y17 Y19 Y20 Y21 Y23 Y24

m

m

936.45 657.94 899.18 1169.48 900.20 1254.55 983.90 1245.08 899.60 979.40 659.10 932.88 920.22 898.14 1068.80 1500.70 1173.26 1130.15 1350.86 1432.38 1313.32

940.40 658.34 904.51 1171.98 900.50 1258.55 990.38 1246.59 900.90 980.50 659.40 933.28 920.66 898.54 1069.10 1501.10 1178.21 1132.65 1351.26 1433.75 1316.45

Sample count

a

GC m3/t

6 1 4 4 1 6 2 2 5 2 1 1 1 1 1 1 2 2 1 2 2

9.91 10.02 7.57 21.60 11.42 14.77 5.54 11.03 11.19 12.33 11.10 8.87 11.18 10.29 17.95 14.29 16.31 15.61 13.17 17.65 14.32

a

VL m3/t

32.30 29.07 31.80 31.55 30.64 23.11 20.85 33.78 20.92 19.37 24.33 32.26 34.60 33.25 38.31 37.31 22.13 28.59 24.63 22.19 26.36

a

PL MPa

2.20 1.39 2.55 3.04 2.59 2.40 2.53 3.69 2.06 2.06 3.58 4.80 4.03 5.18 4.15 4.42 1.29 3.72 1.92 1.05 1.59

T
C RP MPa

a

35 30 34 41 32 38 35 45 32 31 32 34 34 33 39 41 39 42 45 49 43

5.93 6.46 7.19 9.81 7.67 11.66 5.14 9.83 7.76 8.59 4.99 6.76 8.97 8.96 9.30 14.99 11.00 11.29 13.07 14.12 13.17

a

GAC m3/t

23.55 23.92 23.48 24.08 22.91 19.13 14.08 24.56 16.53 15.62 14.17 18.86 23.87 21.07 26.49 28.81 19.81 21.51 21.48 20.64 23.51

a

GS %

42.12 41.89 32.44 89.69 49.86 77.46 39.13 44.89 67.71 78.90 78.35 47.02 46.83 48.84 67.76 49.59 82.17 72.53 61.33 85.69 60.93

a

Mad %

1.51 1.89 0.73 0.87 0.94 0.67 0.64 0.49 0.70 0.61 0.46 0.96 1.00 0.75 1.38 0.94 0.98 0.95 0.56 0.92 0.82

a

Ad %

11.49 9.53 16.85 12.36 8.34 9.92 12.94 5.78 14.35 6.17 3.53 5.80 5.65 9.19 3.75 4.62 7.54 17.54 3.94 10.21 13.87

a

Vdaf %

12.77 15.28 14.16 10.75 14.60 9.41 11.81 9.14 13.07 12.54 12.92 11.22 10.38 9.49 7.94 8.01 9.30 10.56 8.28 10.47 10.24

a

Vmmf %

60.88 77.15 59.22 59.19 52.76 35.87 55.77 50.92 59.58 81.25 78.14 66.36 63.99 65.88 68.23 85.38 77.25 80.51 65.59 65.25 67.76

a

Immf %

39.12 22.85 40.78 40.81 47.24 64.13 44.23 49.08 40.42 18.75 21.86 33.64 36.01 34.12 31.77 14.62 22.75 19.49 34.41 34.75 32.24

a

Ro,

max

%

2.33 2.50 2.30 2.52 1.99 2.53 2.06 2.02 2.24 2.30 2.05 2.35 2.46 2.24 2.74 3.08 2.57 2.65 2.94 3.22 2.92

a Data were calculated by averaging samples selected from the No.2 coal seam in each well. GC, total gas content (ad); VL, Langmuir volume (ad); PL, Langmuir pressure; T, experimental temperature for methane isothermal adsorption measurement; RP, reservoir pressure directly represented by the borehole pressure on the first day of pumping water; GAC, gas adsorption capacity at reservoir pressure; GS, gas saturation; Mad, moisture content; Ad, ash yield; Vdaf, volatile matter yield; Vmmf, vitirnite content; Immf, inertinite content; Ro,max, mean maximum vitrinite reflectance; ad, air dry basis; d, dry basis; daf, dry and ash-free basis; mmf, mineral matter free basis.

258

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

Fig. 4. Distribution of gas content of the No.2 coal seam in the Yanchuannan CBM Field.

heterogeneous over the study area, as illustrated in Fig. 4. Total gas content varies from 5.54 m3/t to 21.60 m3/t, with an average of 12.67 m3/t. Gas content larger than 13 m3/t is mostly situated in the tectonic block B1 and in the southwest part of the tectonic block B3, while that of 10e13 m3/t is mostly gathered in the tectonic block B3 and in the northeast part of the tectonic block B1. Gas content lower than 10 m3/t is mainly seen in the northeastern part of the tectonic block B3 and in central tectonic units of B31 of the tectonic block B3. The spatial distribution of gas adsorption capacity of the No.2 coal seam is shown in Fig. 5. The initial reservoir pressure obtained from 21 exploration wells are in the range of 4.99e14.99 MPa, averaging at 9.36 MPa respectively (Table 1). Combined with isothermal adsorption VL (19.37e38.31 m3/t, 28.45 m3/t on average) and PL (1.05e5.18 MPa, 2.87 MPa on average), calculated gas adsorption capacity ranges from 14.08 m3/t to 28.81 m3/t (21.34 m3/ t on average), presenting high spatial variability in the study area. Gas adsorption capacity of 20e24 m3/t is concentrated in the tectonic block B1 and central tectonic block B3. Gas adsorption capacity of less than 20 m3/t is mainly seen in the northeast and southwest parts of the tectonic block B3. The higher gas adsorption capacity (greater than 24 m3/t) is located in the tectonic block B1. Fig. 6 shows the highly variable spatial distribution of gas saturation of the No.2 coal seam across the study area. Gas saturation calculated from equation (1) varies from 32.44% to 89.69%, with an average of 60.24%, which suggests that all samples are

undersaturated with respect to methane. Gas saturation greater than 55% is mainly distributed in the tectonic block B1, and southwestern part of the tectonic block B3 as well as central tectonic unit B33 of the tectonic block B3. Gas saturation of 40%e55% is mostly gathered in central tectonic block B3 and in the northeast part of the tectonic block B1. Gas saturation less than 40% is located in the northeastern part of the tectonic block B3. 4.2. Controlling factors of gas saturation 4.2.1. Depth As shown in Fig. 7, the monoclinal structure plays an important role in lateral distribution of gas saturation in the Yanchuannan CBM Field. Except for the high gas saturation of the Y11P3 well (controlled by secondary biogenic gas and discussed in detail in Section 4.2.3) in the tectonic unit B33, gas saturation generally increases with the depth of the No.2 coal seam as a whole. Furthermore, after being removed the abnormal values, including the Y17 well (controlled by an adjacent reverse fault and discussed in detail in Section 4.2.2), Y8 well (controlled by local lack of a top seal and discussed in detail in Section 4.2.4), and Y11P2 and Y11P3 wells (controlled by secondary biogenic gas and discussed in detail in Section 4.2.3), the scatter plot (Fig. 8a) shows there is general increase in gas saturation with depth with a better correlation coefficient of r ¼ 0.71. Many geological surveys indicate that depth is an

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

259

Fig. 5. Distribution of gas adsorption capacity of the No.2 coal seam in the Yanchuannan CBM Field.

important factor affecting CBM potential (Liu et al., 2012; Su et al., 2005), which means gas content difference is attributable to spatial difference of depth (Wei et al., 2007). An increase in hydrostatic pressure with depth (Ke˛ dzior et al., 2013) is favorable for greater gas content (Hamilton et al., 2012; Moore et al., 2014; Pashin, 2010; Yao et al., 2009) and gas adsorption storage capacity (Meissner, 1987). This, coupled with the presents of an effective top seal results in the deeper zone more effectively retaining methane than shallower coal (Wei et al., 2010), contributing to higher gas content. Meanwhile, the variation in gas content (r ¼ 0.66) with depth is higher than that of gas adsorption capacity (r ¼ 0.01) in the study area (Fig. 9a). The extremely weak negative correlation between depth and gas adsorption capacity suggests that parameters other than depth overpower the depth influence. 4.2.2. Faults Faults perform different roles in the process of CBM retention due to their variable properties (Lv et al., 2012). They can act as barriers for groundwater flowing, and to prevent CBM from escaping, which are favorable for CBM retainment and lead to higher gas saturation (Johnson and Flores, 1998; Kinnon et al., 2010). On the other hand, faults may also serve as conduits that can allow CBM to escape, resulting in lower gas saturation (Ke˛ dzior et al., 2013; Liu et al., 2009; Yao et al., 2009). Gas saturation shows significant variations overprinting this general trend of increasing with depth (Fig. 7): 1) gas saturation at the Y17 well in the tectonic block B1 is relatively low; 2) gas saturation in the tectonic units of

B31 and B32 of the tectonic block B3 are lower than that in the tectonic block B1. For the former variation, gas saturation at the Y17 well is lower than that of adjacent wells, mainly because the adjacent reverse fault of the Y17 well produces microstructurally altered coal with high specific surface area and gas adsorption capacity, which results in low gas saturation for the same gas content. Additionally, the results of low pressure nitrogen adsorption analysis show that the Y17 well has a considerable larger BET specific surface area than the Y8 well (0.83 m2/g compared to 0.04 m2/g), which verify the speculation. For the later variation, in combination with the locations of the inverse faults F1 and F2, it can be inferred that hydrogeological characteristics may play a role in this situation which we now explore further. The geochemical characteristics of produced groundwater from the No.2 coal seam are listed in Table 2. The water samples analysis were identified and culled with the aid of the methodology reported by Hitchon and Brulotte (1994). The analysis that report pH less than 5.0 (indicative of acid wash contamination), including the Y3 and Y6 wells, are removed. The analysis with pH less than 10.0 but appreciable CO2 are commonly indicative of mud filtrate 3 contamination. However, according to the research of Yao et al. (2014), the water samples produced from certain CBM wells in the Weibei field, which is adjacent to our study area, were reported with CO2 and not eliminated in their subsequent analysis. 3 Consequently, some water samples containing appreciable CO2 3 in areas located in the southeastern Ordos Basin are regarded as normal, and not removed from our analysis, either. The separated

260

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

Fig. 6. Distribution of gas saturation of the No.2 coal seam in the Yanchuannan CBM Field.

Fig. 7. Connecting-well section showing structural characteristics control on gas saturation of the No.2 coal seam in the Yanchuannan CBM Field. Line of cross-section AA' is shown in Fig. 1.

values of Kþ and Naþ of water samples are unavailable for all CBM wells with an exception of the Y8 well, because the lumped values of the two parameters were given out in the test report of water quality analysis. The ratio of Kþ (30.37 mg/L) to Naþ (5049.17 mg/L) of the water sample from the Y8 well is 0.006, which is much less than the threshold value (0.05), suggesting no KCl mud

contamination. Based on the fact, the assumption that water samples with lumped values of Kþ and Naþ from other CBM wells are not contaminated by KCl mud is suggested. The major cations primarily include KþþNaþ 5569.55 (537.00e42528.79) mg/L, Ca2þ 1595.66 (4.16e20624.24) mg/L and Mg2þ 165.20 (1.01e2364.57) mg/L and major anions are Cl 10606.74 (115.71e92453.60) mg/L,

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

261

Fig. 8. Scatter plots of depth (a), Ro, max (b), moisture content (c), ash yield (d) and vitrinite content (e) versus gas saturation of the No.2 coal seam in the Yanchuannan CBM Field.

 SO2 4 223.22 (0.00e765.28) mg/L, HCO3 1496.75 (154.08e2958.25) 2 mg/L and CO3 108.13 (0.00e424.26) mg/L. The total dissolved solids (TDS) of groundwater samples, presenting the remarkable difference, varies from 2170.33 mg/L to 147558.70 mg/L with an average value of 19765.27 mg/L. A relatively open hydrodynamic environment (recharge) and a relatively close hydrodynamic environment can be inferred by groundwater quality parameters such as TDS and water type where recharge is characterized by lower TDS (Pashin, 2007, 2010; Rice, 2003) and NaHCO3 type (Cheung et al., 2009; Pashin, 2007), while older groundwater in a relatively close hydrodynamic environment has higher TDS (Pashin, 2007; Rice, 2003) and NaCl type (Pashin, 2007; Yao et al., 2014). According to the distribution of TDS and types of groundwater (NaCl or NaHCO3) in the field (Fig. 10), the groundwater in the tectonic block B1, except for the Y18 well, are dominated by NaCl type with high TDS (14388.24 mg/L to 147558.70 mg/L). The groundwater in the tectonic block B3, with exceptions of the Y2 and Y15 wells, are characterized by NaHCO3 type with low TDS (2170.33 mg/L to 6576.76 mg/L), considerably less than TDS of water samples in the tectonic block B1. The freshwater plumes (TDS < 10,000 mg/L) and basinal brine (TDS > 30,000 mg/L) (Pashin et al., 2014) are determined by the mapping TDS (Fig. 10). The groundwater is typically fresh water (TDS < 10,000 mg/L) within the tectonic block B3, indicating meteoric recharge (Pashin, 2007), and by contrast, is predominated by saline to hypersaline water (TDS > 10,000 mg/L) in the tectonic block B1, indicating a relatively long residence time of this water (Bachu and Michael, 2003). Using water type and TDS as

differentiators, the tectonic blocks B1 and B3 are characterized by a relatively close hydrodynamic environment and recharge, respectively, which suggest that the thrust faults F1 and F2 are barriers horizontally for the hydraulic communication between the two blocks. However, the TDS of the Y18 well in the tectonic block B1 controlled by saline to hypersaline NaCl water implies that the pocket of fresh water possibly is caused by vertically local percolation along the fault and fracture zones (Pashin et al., 2014). Simultaneously, the vertically local percolation may have no influence on other wells in the tectonic block B1 based on the TDS and types of groundwater. In the tectonic block B3 characterized by fresher NaHCO3 water there are local areas of higher salinity formation water of NaCl type (the Y2 and Y15 wells). The smalldisplacement inverse faults may shelter the Y2 well from the regional recharge system, whereas the reason caused the NaCl type of the Y15 well deserves further study. The tectonic block B1 of a relatively close hydrodynamic environment where there are hydraulic barriers to recharge can impede leakage of the gas from the coal zone, conducive to retention of the gas in the coal and corresponding to higher gas content (Johnson and Flores, 1998; Kinnon et al., 2010). In the tectonic block B3 of active recharge with the higher permeability pathway where there is no mechanism for entrapment, gas content is generally low due to hydrodynamic flushing and diffusion (Cui et al., 2004; Lamarre, 2003; Pashin, 2010; Scott, 2002; Yao et al., 2014). Therefore, gas saturation in the tectonic block B1 is generally greater than that in the tectonic block B3 as a whole (Fig. 6). The flow direction of groundwater, which is controlled by

262

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

Fig. 9. Scatter plots of depth (a), Ro, max (b), moisture content (c), ash yield (d) and vitrinite content (e) versus gas content and gas adsorption capacity of the No.2 coal seam in the Yanchuannan CBM Field.

tectonics, topography, and precipitation (Cai et al., 2014; Su et al., 2005), can be indicated by the hydraulic head and TDS (Bachu and Michael, 2003). The TDS data are used to infer the flow of groundwater because hydraulic head data are absent in our study area. Van Voast (2003) suggested that TDS values demonstrate an increase trend along the downgradient flow path in basins. Furthermore, the groundwater in the tectonic block B3 has lower TDS in the northeast increasing in the value towards the southwest. Considering the geometry of the basin in conjunction with the variation in TDS, the flow direction of groundwater in the No.2 coal seam is highly speculated in the orientation of southwestward in the tectonic block B3 (Fig. 10). There is no discussion on the flow direction of groundwater in the tectonic block B1 (a relatively close hydrodynamic environment), which is sheltered from the recharge by the thrust faults F1 and F2. Gas saturation is controlled significantly by hydrogeology, and increases generally along the flow pathway of groundwater with the exceptions of the Y11P2 and Y11P3 wells in the tectonic block B3 (Fig. 6). The flowing groundwater from the northeast of the tectonic block B3 can break the dynamic balance between the adsorbed gas and the dissolved gas of the CBM reservoir by taking away the dissolved gas and accelerating the absorbed gas diffusion (Kaiser et al., 1994; Scott, 2002; Scott et al., 1994). Consequently, although the amount of the dissolved gas is relatively low, a large amount of gas was moved over geologic time by migrating groundwater (Scott, 2002). CBM went away with long-term flux of groundwater resulting in a decrease in

gas content and gas saturation in northeastern part of the tectonic block B3. At the same time, with the extension of lateral distance, the groundwater flux gradually becomes less towards the southwestern part of the tectonic block B3, forming a relatively weak hydrodynamic condition that is favorable for retention of the gas (Yao et al., 2013). Moreover, the permeability of the coal seam is less and thus less gas has been lost in the southwestern part of the tectonic block B3, which results in an increase in gas content and gas saturation. 4.2.3. Secondary biogenic gas The variation range of d13CCH4 and dDCH4 of the No.2 coal in the study area is 54.1‰ ~ 29.6‰ and 230‰ ~ 158‰, respectively (Table 3). The carbon and hydrogen isotope of methane is an effective and widely used index to identify the genetic type of CBM (Gentzis, 2013; Pitman et al., 2003; Schoell, 1980; Whiticar and Faber, 1986). Typical diagnostic values for thermogenic versus microbial gas for d13CCH4 and dDCH4 are 55‰ (Rice and Claypool, 1981; Schoell, 1980; Whiticar et al., 1986) and 250‰ (Gentzis et al., 2008). However, the d13CCH4 value between 50‰ and 60‰ is difficult to distinguish thermogenic from biogenic type of CBM using carbon isotope data individually (Rowe and Muehlenbachs, 1999; Whiticar, 1999). Thermogenic and biogenic origin are characterized by enrichment and depletion in both d13CCH4 and dDCH4, respectively. A cross-plot of d13C versus dD of methane (Fig. 11) suggests that there are significantly different

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

263

Table 2 Major ionic concentration and total dissolved solids (TDS) of produced groundwater samples from the No.2 coal seam in the Yanchuannan CBM Field. Well No.

pH

TDS mg/L

KþþNaþ mg/L

Ca2þ mg/L

Mg2þ mg/L

Cl mg/L

SO2 4 mg/L

HCO 3 mg/L

CO2 3 mg/L

Water type

Y1 Y2 Y3 Y4 Y5 Y6 Y7 Y8 Y10 Y11 Y12 Y13 Y14 Y15 Y16 Y17 Y18 Y19 Y20 Y21 Y22 Y23 Y24 Y1P4 Y1P5 Y1P6 Y11P1 Y11P2 Y11P3 Y11P4 Y11P5

8.28 6.90 3.98 7.46 8.18 4.96 8.53 7.77 7.74 7.56 nd 7.50 7.68 7.40 5.97 6.26 7.94 7.38 6.62 5.36 5.96 6.08 5.56 7.60 7.45 7.36 7.46 7.70 7.36 7.61 7.50

5671.34 7589.49 114431.79 6576.76 3639.78 80469.00 2875.03 14388.24 6327.75 2970.20 2448.83 3559.58 3310.14 7618.41 33015.63 40121.94 2947.43 5937.31 40696.07 147558.70 27573.30 38485.46 143773.59 2229.30 3450.87 2945.79 4986.65 4135.06 3282.80 2170.33 2906.95

3320.73 2441.06 24421.22 2008.72 1101.18 4678.88 537.00 5079.54 2066.01 902.04 680.57 1167.32 1056.46 2694.99 9042.78 12230.39 910.11 1820.79 12748.75 31903.73 7106.02 12480.24 42528.79 684.62 1065.35 934.28 1418.50 1190.94 936.43 616.14 843.61

4.16 162.33 16836.54 37.46 12.49 20582.61 257.93 54.08 8.32 12.49 8.32 12.49 12.49 16.65 3163.35 3100.92 8.32 24.97 2726.31 20624.24 3059.30 1737.76 11134.17 12.49 12.49 8.32 16.65 12.49 16.65 8.32 8.32

3.53 74.19 1456.09 1.01 1.01 2919.75 13.62 30.27 3.53 1.01 3.78 1.01 1.01 1.01 257.40 68.14 1.01 3.53 118.61 2364.57 219.55 434.05 1178.50 1.01 1.01 1.01 1.01 3.53 1.01 1.01 1.01

260.14 2950.22 71651.54 381.78 337.90 51774.02 293.76 6272.56 1155.87 158.49 115.71 410.77 530.59 2599.87 19930.86 24269.07 294.90 1061.02 24415.39 92453.60 16641.65 23113.40 88293.19 135.93 252.35 262.76 225.48 306.97 164.95 117.77 188.48

151.60 669.50 35.58 765.28 33.20 482.92 0.00 60.91 479.84 296.85 4.90 218.17 18.34 308.52 4.94 83.62 411.58 38.96 101.52 58.48 331.07 350.23 361.60 42.96 244.03 18.88 397.58 248.37 345.67 132.86 293.96

1856.12 1170.97 30.82 2958.25 1972.17 30.82 1772.72 2890.88 2311.13 1417.49 1635.55 1355.86 1479.12 1664.02 616.3 369.8 1230.6 2927.43 585.49 154.08 215.71 369.78 277.34 1140.16 1633.20 1417.49 2927.43 2372.76 1818.09 1294.23 1571.57

75.06 121.22 0 424.26 181.83 0 0 0 303.05 181.83 0 393.96 212.13 333.35 0 0 90.91 60.61 0 0 0 0 0 212.13 242.44 303.05 0 0 0 0 0

NaHCO3 NaCl NaCl NaHCO3 NaHCO3 CaCl2 NaHCO3 NaCl NaHCO3 NaHCO3 NaHCO3 NaHCO3 NaHCO3 NaCl NaCl NaCl NaHCO3 NaHCO3 NaCl NaCl NaCl NaCl NaCl NaHCO3 NaHCO3 NaHCO3 NaHCO3 NaHCO3 NaHCO3 NaHCO3 NaHCO3

nd, not detected.

sources of CBM in the Yanchuannan CBM Field. Stable isotope analysis shows that two samples from the Y11P3 well located in the tectonic unit B33 are characterized CBM by a mixture of thermogenic origin and biogenic origin. A cross plot of d13C (CH4) and d13C (CO2) is an additional tool to interpret the origin of CBM (Warwick et al., 2008). It seems like, given by the samples of CBM wells, that gas compositions have a mainly thermogenic origin except for the samples from the Y4, Y11P2, and Y11P3 wells located in the tectonic unit B33 (Fig. 12). A sample from the Y4 well plots in the thermogenic field, and another sample from the Y4 well and the sample obtained from the Y11P2 well fall in the mixed origin field, together with the two samples of the Y11P3 well which fall in the CO2 reduction field. The data other than the Y11P2 and Y11P3 wells suggest a dominant thermogenic maturation trend in the study area which we now explore. Isotopic fractionation between CO2 and CH4, D13CCO2eCH4, is frequently used as diagnostic parameter to describe CBM origin (Smith and Pallasser, 1996; Stra˛ poc et al., 2007). CBM generated by CO2 reduction has more D13CCO2eCH4 than that formed by thermogenic or acetate fermentation generally (Warwick et al., 2008). The diagnostic value of D13CCO2eCH4 for thermogenic vs. biogenic CBM is <40‰ vs. > 55‰ (Stra˛ po c et al., 2008). Additionally, D13CCO2eCH4 is expected to keep consistent throughout a whole field in a closed environment (Kinnon et al., 2010). The D13CCO2eCH4 and isotope fractionation factor (aCO2eCH4) in this research vary from 9.1‰ to 56.3‰ and 1.009 to 1.060 (Table 3), respectively, which provide the further evidence of a mixture of thermogenic origin and biogenic origin. And the large variation of D13CCO2eCH4 indicates that the study area is an open system. Based on the hydrogeology characteristics and stable isotopic compositions, we believe that CBM in tectonic unit B33 is affected by late-stage biogenic methane generated via CO2 reduction. The relatively fresh recharge water made coals habitable for a variety of

microbes, and served as transport media for the microbes (Martini et al., 1996; Scott et al., 1994; Stra˛ poc et al., 2008). Methanegenerating bacteria responsible for secondary biogenesis of methane was apparently introduced into coals together with groundwater in some meteoric water recharge areas (Johnson and Flores, 1998; Kinnon et al., 2010; Pashin, 2007; Scott, 2002; Zhou et al., 2005). Thus late-stage biogenic methane has a significant contribution to the increase in gas content in the tectonic unit B33, which can explain effectively higher gas saturation than other parts of the tectonic block B3. The present geological conditions and the nature of the structure have a significant influence on the inoculation of methanogenic bacteria and the formation of biogenic gases (Scott, 2002; Stra˛ po c et al., 2007). The microbial CH4 generation was/is restricted to shallow depths at relatively low temperatures (Kotarba, 1990; Scott, 2002; Scott et al., 1994). The greater burial depth provides a relatively high reservoir temperature which is less hospitable for methanogenic communities. Thus the biogenic gas only occurs in the tectonic unit T33 rather than elsewhere in the tectonic block B3. 4.2.4. Sealing conditions The effect of the seal capacity and thickness of strata surrounding the No.2 coal seam on the gas saturation is examined. Surrounding coal zone seals with different seal capacities can be classified as high seal capacity such as mudstone, moderate seal capacity such as mudstone and siltstone interbeds, low seal capacity such as fine sandstone and ineffective such as limestone (Tang et al., 2007). In our study area, the lithology and thickness of the directly overlying stratum and underlying stratum of the No.2 coal seam were acquired from core data and listed in Table 4. All the lithology of directly underlying stratum is mudstone with high seal capacity, which prevents CBM dissipation through the base of the coal seam and benefits the retention of CBM. Different from the

264

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

Fig. 10. Map of TDS and types of groundwater from the No.2 coal seam showing saline to hypersaline water in the tectonic B1, fresh water and the flow direction of groundwater in the tectonic block B3 of the Yanchuannan CBM Field.

Table 3 Carbon and hydrogen isotopic compositions of desorbed gas from coal samples of the No.2 coal seam in the Yanchuannan CBM Field. Well No.

Sample depth m

m

Y1

937.05

937.45

Y2

899.18

899.68

Y3

1169.48 1172.88 896.96 900.20 1256.55 1258.05 987.65 1245.08 899.80 979.40 656.20 659.10 930.78 933.58 919.76 924.22 898.14 1067.50 1499.70

1169.78 1173.08 897.26 900.50 1257.05 1258.55 987.95 1245.66 900.10 979.70 656.50 659.40 931.48 933.98 920.22 924.60 898.54 1067.85 1500.10

Y4 Y6 Y7 Y8 Y10 Y11P2 Y11P3 Y13 Y14 Y15 Y16 Y17 nd, not detected.

d13C(CH4) ‰

dD(CH4) ‰

d13C(CO2) ‰

D13C(CO2eCH4) ‰

a(CO2eCH4)

36.9 34.7 37.8 37.0 29.6 30.7 44.0 45.8 32.0 32.9 36.5 29.6 37.4 50.6 54.1 53.8 33.7 33.6 38.1 36.9 37.9 31.9 32.2

185 186 189 180 164 167 209 217 166 169 205 161 206 215 224 230 169 196 194 193 187 158 163

18.2 19.7 nd nd 20.5 18.9 18.3 14.5 20.6 19.2 nd nd nd 0.8 2.2 1.5 20.1 12.8 18.4 20.4 nd nd nd

18.7 15.0 nd nd 9.1 11.8 25.7 31.3 11.4 13.7 nd nd nd 51.4 56.3 55.3 13.6 20.8 19.7 16.5 nd nd nd

1.019 1.016 nd nd 1.009 1.012 1.027 1.033 1.012 1.014 nd nd nd 1.054 1.060 1.058 1.014 1.022 1.020 1.017 nd nd nd

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

265

respectively; 2) siltstone belonging to the poorly effective seal capacity of the Y21 well and corresponding with intermediate gas saturation of 61.33%; and 3) mudstone and fine sandstone interbeds associated with poorly effective seal capacity of the Y8 well with gas saturation of 44.89%. It can be concluded that gas saturation is closely related to the lithology of the overlying stratum next to the coal seam. Generally, mudstone with highly effective seal capacity is more favorable for the retention of CBM (Xu et al., 2012), causing higher gas content and gas saturation of the Y6 and Y20 wells, while sandstone is conducive to gas dissipation which makes lower gas saturation of the Y8 and Y21 wells. Moreover, it is noted that gas saturation is mainly controlled by the directly overlying stratum lithology rather than thickness due to the fact of thin roof (only 0.05 m) with high gas saturation (72.53%) of the Y20 well. The nearly uniform lithology of the coal zone top seal across our study area affects gas saturation only in specific local areas but it is not a dominant factor controlling gas saturation in the entire region.

Fig. 11. Cross-plot of d13CCH4 and dDCH4 isotopes of CBM desorbed from the No.2 coal samples in the Yanchuannan CBM Field. Compositional fields based on Whiticar (1999).

uniformity of the lithology of underlying stratum, the lithology of directly overlying stratum of the No.2 coal seam is characterized by mudstone with the exceptions of the Y8 well (mudstone and fine sandstone interbeds), Y12 well (mudstone and siltstone interbeds) and Y21 well (siltstone). The lithology of overlying stratum has an important influence on CBM preservation (Cai et al., 2014; Drobniak et al., 2004). Three different types of directly overlying stratum lithology (Fig. 13) in the tectonic block B1 were selected to characterize their control on gas saturation. They are, 1) thin carbonaceous mudstone falling into the highly effective seal capacity of the Y6 and Y20 wells, which correspond with high gas saturation of 77.46% and 72.53%,

4.2.5. Coalification Figs. 8 and 9 can effectively explain gas saturation variation when compared with various coal properties. The correlation (r ¼ 0.57) between Ro, max and gas saturation (Fig. 8b) suggests that there is a general relationship. Coalification can influence pore size, pore volume and pore distribution of coal (Mastalerz et al., 2008; Unsworth et al., 1989), and the volume of macropores decreases and that of micropores increases with an increase in coalification (Mastalerz et al., 2008), which has been considered as one of the important parameters controlling on gas content and methane adsorption capacity (Chalmers and Bustin, 2007; Pashin, 2010; Scott, 2002). Coals evolved to a certain rank beyond the peak maximum of thermogenic gas generation could theoretically contain higher gas content (Gentzis et al., 2006). Additionally, considerable geological surveys and experiments reveal that gas content and methane adsorption capacity of coal generally increase with an increase in coalification (Bustin and Clarkson, 1998; Kim, 1977; Moore et al., 2014). Moreover, in our study area, there is also a general positive correlation (r ¼ 0.58) between gas content and Ro, max (Fig. 9b), which might drive the positive relationship

Fig. 12. Cross plot of d13C(CH4) versus d13C(CO2) of CBM desorbed from the No.2 coal samples in the Yanchuannan CBM Field. Compositional fields are from Stra˛poc et al. (2006), Warwick et al. (2008) and Whiticar (1999).

266

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

Table 4 Lithology and thickness of directly overlying and underlying strata of the No.2 coal seam in the Yanchuannan CBM Field. Well No.

Overlying stratum lithology

Thichness, m

Underlying stratum lithology

Thichness, m

Y1 Y1P4 Y2 Y3 Y4 Y6 Y7 Y8 Y10 Y11 Y11P2 Y11P3 Y12 Y13 Y14 Y15 Y16 Y17 Y18 Y19 Y20 Y21 Y22 Y23 Y24

black mudstone grayish black mudstone grayish black mudstone black mudstone grayish black mudstone black carbonaceous mudstone mudstone interbeds of grayish black mudstone and gray fine sandstone grayish black mudstone grayish black mudstone black mudstone grayish black mudstone interbeds of grayish black mudstone and gray siltstone grayish black mudstone black mudstone mudstone grayish black mudstone black carbonaceous mudstone mudstone grayish black mudstone black carbonaceous mudstone gray siltstone grayish black mudstone black mudstone grayish black mudstone

6.50 1.60 2.60 1.03 1.90 0.52 2.20 2.25 2.02 2.37 1.61 2.00 1.34 2.35 4.15 4.90 4.57 0.06 1.70 1.11 0.05 1.50 6.10 0.94 2.74

black mudstone grayish black mudstone grayish black mudstone black mudstone grayish black mudstone grayish black mudstone mudstone grayish black mudstone grayish black mudstone grayish black mudstone black mudstone grayish black mudstone grayish black sandy mudstone grayish black mudstone black mudstone mudstone grayish black mudstone black mudstone grayish black mudstone grayish black mudstone black carbonaceous mudstone grayish black mudstone black carbonaceous mudstone black mudstone black mudstone

1.30 1.77 2.00 0.42 3.70 1.91 4.20 1.56 2.00 0.66 1.22 1.07 1.72 2.20 1.92 4.30 2.00 0.28 2.10 2.00 1.55 2.00 2.17 2.15 2.00

Fig. 13. Connecting-well section showing lithology of overlying and underlying strata next to the coal seam controls on gas saturation of the No.2 coal seam in the Yanchuannan CBM Field. Line of cross-section BB' is shown in Fig. 1.

between coalification and gas saturation. Note that Ro, max ranging from 2.5% to 3% is highly negatively correlated with gas content or gas saturation. However, higher gas content values are commonly associated with higher rank coals until Ro, max evolves to the value of 3.5% (Qin et al., 1999; Scott, 2002). The phenomenon in our data is most likely associated with differences in gas content control from other parameters such as depth.

4.2.6. Coal quality Moisture content is not associated with gas saturation in the

study area. The scatter plot (Fig. 8c) shows that gas saturation has an insignificant negative correlation with moisture content (r ¼ 0.20). Because moisture can compete with methane in occupying space (Clarkson and Bustin, 2000; Warwick et al., 2008) and be absorbed preferentially on coal pore surface due to the polarity of water molecule (Clarkson and Bustin, 2000), moisture content shows a negative correlation with gas content and methane sorption capacity by inhibiting methane adsorption and storage (Bustin and Clarkson, 1998; Joubert et al., 1973, 1974). There is almost no correlation between gas content and moisture content

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

(r ¼ 0.08) and a weak positive correlation between gas adsorption capacity and moisture content (r ¼ 0.52) (Fig. 9c), which might facilitate the negative relationship between moisture content and gas saturation. The gas adsorption capacity, which was expected to decrease with an increase in moisture content (Crosdale et al., 2008; Hildenbrand et al., 2006), shows an increasing trend. This anomaly implies that the control of moisture content on gas adsorption capacity may be masked by other controlling factors. Ash yield is not associated with gas saturation integrally either. There is some indication of weak negative association but the relationship lacks statistical significance (r ¼ 0.03) (Fig. 8d). On the one hand, nearly all of CBM is adsorbed on the coal surface rather than ash layers or dispersed among the mineral matters (Chalmers and Bustin, 2007; Yee et al., 1993); on the other hand, mineral matter acts as a diluent (Laxminarayana and Crosdale, 2002; Yee et al., 1993), and mineral particles can fill in pores (Liu et al., 2014). Ash yield can reduce both gas content (Hemza et al., 2009; Liu et al., 2012) and gas adsorption capacity (Bustin and Clarkson, 1998; Liu et al., 2012; Moore et al., 2014), and the proportion of gas content (r ¼ 0.19) decline is greater than that of gas adsorption capacity (r ¼ 0.08) (Fig. 9d). 4.2.7. Coal maceral As a whole, there is no appreciable correlation between gas saturation and vitrinite content in the studied area (Fig. 8e), with a weak correlation coefficient (r ¼ 0.03). Evidence on the role of maceral composition in determining gas content and gas adsorption capacity of coal remains conflicting in the literature (Chalmers and Bustin, 2007; Levine, 1993). Some studies concluded that gas content increases with an increase in vitrinite in general (Lamberson and Bustin, 1993; Laxminarayana and Crosdale, 2002), while Stra˛ po c et al. (2008) indicated that maceral composition appears to have inconspicuous influence on the gas content. Some researchers reported that inertinite has a greater adsorption capacity than vitrinite (e.g., Berbesi et al., 2009) because of a decrease in coal surface area with an increase in vitrinite content generally (Lamberson and Bustin, 1993). Whereas, vitrinite-rich coal has a greater methane adsorption capacity than inertinite-rich coal (Clarkson and Bustin, 1999; Moore, 2012), which is attributed to higher micropore volume and surface area in vitrinite than intertinite (Chalmers and Bustin, 2007; Lamberson and Bustin, 1993; Unsworth et al., 1989). Faiz et al. (2007) indicated that methane sorption capacity does not show any systematic relationship or consistent trends with maceral composition. The data in our study suggest that there is no correlation between coal maceral and gas content (r < 0.01, Fig. 9e), which is in support of the finding of

267

Stra˛ poc et al. (2008). However, the weak positive correlation (r ¼ 0.21, Fig. 9e) occurring in coal maceral and gas adsorption capacity is in support of the findings of Clarkson and Bustin (1999) and Moore (2012).

4.3. Gas saturation variation model Based on the comprehensive analysis of the geological controlling factors on gas saturation of the No.2 coal seam in the Yanchuannan CBM Field, we propose a distribution model for gas saturation (Fig. 14). There is a background primary control of depth on gas saturation, which is overprinted by a number of secondary factors, including faults, secondary biogenic gas generation, local lack of a top seal and variations in coal characteristics. The study area is divided into the relatively closed and the recharge zones by the inverse fault which is barrier horizontally for the hydraulic communication between the two zones (Fig. 14③ ③). The relatively closed zone where there are hydraulic barriers to recharge can prevent CBM from escaping, resulting in higher gas saturation. In contrast, the recharge zone where there is no mechanism for entrapment corresponds to the lower gas saturation because of the hydrodynamic flushing and diffusion. For example, the Y24 well located in the relatively closed zone and the Y7 well located in the recharge zone are characterized by higher gas saturation (60.93%) and lower gas saturation (39.13%), respectively. Conversely, the normal fault may serve as a conduit that can allow CBM to escape, resulting in lower gas saturation (Fig. 14⑥ ⑥). Secondary biogenic gas generation associated with fresh water recharge has an important contribution to gas saturation levels of the coal reservoir (Fig. 14⑦ ⑦), such as the Y11P2 and Y11P3 wells with higher gas saturation (78.90% and 78.35%, respectively). However, the microbial CH4 generation was/is restricted to the shallow depth, since the greater depth provides a relatively high reservoir temperature which is less hospitable for methanogenic communities. The apparent variations of lithology of the overlying stratum next to the coal seam in local areas suggest that the top seal has an important influence on CBM preservation (Fig. 14① ①). Generally, mudstone with highly effective seal capacity is more favorable for the retention of CBM, while sandstone is conducive to gas dissipation. The lithology of the directly underlying stratum of the Y8 well is distinguished by mudstone and fine sandstone interbeds, which has poorly effective seal capacity and leads to lower gas saturation (44.89%). Coal properties, covering coal quality, coal maceral and coalification, play a limited role in gas saturation variation (Fig. 14② ②④⑤).

Fig. 14. The variation model of gas saturation of the No. 2 coal seam in the Yanchuannan CBM Field.

268

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

There is a positive general relationship between Ro, max and gas saturation. Meanwhile, gas saturation has an insignificant negative correlation with moisture content and ash yield. For example, when we consider two wells with very similar depth (936.45 m compared to 920.22 m) in the recharge zone, the Y1 and Y14 wells, but different coal characteristics, the Y14 well having the higher coal coalification, lower moisture content and lower ash yield has higher gas saturation than the Y1 well (46.83% compared to 42.12%). As a whole, there is no appreciable correlation between gas saturation and vitrinite content.

5. Conclusion Based on diverse geologic data and experimental results, this paper investigates the lateral variation of gas saturation and its geological controls of the No.2 coal seam in the Yanchuannan CBM Filed, and reaches the following conclusions: 1) The total gas content and gas adsorption capacity vary from 5.54 m3/t to 21.60 m3/t and from 14.08 m3/t to 28.81 m3/t, respectively, while gas saturation ranges from 32.44% to 89.69%. There is a background trend increasing gas saturation with depth but that this is overprinted by secondary processes. These are influence of faults, secondary biogenic gas generation, local top seal conditions and variations in coal properties. 2) The inverse faults F1 and F2 are effective barriers horizontally for the hydraulic communication and divide our study area into the relatively closed zone (the tectonic block B1) and the recharge zone (the tectonic block B3). The tectonic block B1 where there are barriers to prevent the gas escape has generally higher gas saturation than the tectonic block B3 where there is no mechanism for the gas entrapment. In the recharge, gas saturation increases generally along the flow pathway of groundwater with the exceptions of the areas affected by secondary biogenic gas. 3) The carbon and hydrogen stable isotope analysis of desorbed gas from coal samples reveals that CBM is a mixture origin of thermogenic gas (primary component) and secondary biogenic gas (secondary component). Higher gas saturation in the tectonic unit B33 of the tectonic block B3 is controlled directly by the amount of secondary biogenic gas generated from CO2 reduction. 4) Top seal conditions are responsible for gas saturation in specific local areas because the nearly uniform lithology of the coal zone top seal across our study area. Since gas saturation is mainly controlled by the directly overlying stratum lithology rather than the thickness, lower gas saturation is expected in areas adjacent to sandstone because of its low effective seal capacity. 5) It is reasonable to suggest that coal properties are not major determinants of gas saturation across the study area. Gas saturation has a positive general relationship with coalification, and weak negative correlations with moisture content and ash yield with lacking of statistical significances. Coal maceral is not associated with gas saturation in the study area.

Acknowledgments The research was supported by the National Natural Science Foundation of China (Nos. 41101098 and 41572143). Enormous thanks to East China Branch Company of SINOPEC for assistance with sampling and sample analysis. The authors thank Jim Underschultz and another anonymous reviewer for their constructive comments to improve the manuscript.

References Ayers Jr., W.B., 2002. Coalbed gas systems, resources, and production and a review of contrasting cases from the San Juan and Powder River Basins. AAPG Bull. 86, 1853e1890. http://dx.doi.org/10.1306/61eeddaa-173e-11d78645000102c1865d. Bachu, S., Michael, K., 2003. Possible controls of hydrogeological and stress regimes on the producibility of coalbed methane in Upper CretaceouseTertiary strata of the Alberta basin, Canada. AAPG Bull. 87, 1729e1754. http://dx.doi.org/10.1306/ 06030302015. Berbesi, L.A., M arquez, G., Martínez, M., Requena, A., 2009. Evaluating the gas content of coals and isolated maceral concentrates from the Paleocene Guasare Coalfield, Venezuela. Appl. Geochem. 24, 1817e1824. http://dx.doi.org/10.1016/ j.apgeochem.2009.06.003. Bustin, A.M.M., Bustin, R.M., 2008. Coal reservoir saturation: impact of temperature and pressure. AAPG Bull. 92, 77e86. http://dx.doi.org/10.1306/08270706133. Bustin, R.M., Clarkson, C.R., 1998. Geological controls on coalbed methane reservoir capacity and gas content. Int. J. Coal Geol. 38, 3e26. http://dx.doi.org/10.1016/ S0166-5162(98)00030-5. Cai, Y.D., Liu, D.M., Zhang, K.M., Elsworth, D., Yao, Y.B., Tang, D.Z., 2014. Preliminary evaluation of gas content of the No.2 coal seam in the Yanchuannan area, southeast Ordos basin, China. J. Petroleum Sci. Eng. 122, 675e689. http:// dx.doi.org/10.1016/j.petrol.2014.09.010. Chalmers, G.R.L., Bustin, R.M., 2007. On the effects of petrographic composition on coalbed methane sorption. Int. J. Coal Geol. 69, 288e304. http://dx.doi.org/ 10.1016/j.coal.2006.06.002. Cheung, K., Sanei, H., Klassen, P., Mayer, B., Goodarzi, F., 2009. Produced fluids and shallow groundwater in coalbed methane (CBM) producing regions of Alberta, Canada: trace element and rare earth element geochemistry. Int. J. Coal Geol. 77, 338e349. http://dx.doi.org/10.1016/j.coal.2008.07.012. Clarkson, C.R., Bustin, R.M., 1999. The effect of pore structure and gas pressure upon the transport properties of coal: a laboratory and modeling study. 1 Isotherms and pore volume distributions. Fuel 78, 1333e1344. http://dx.doi.org/10.1016/ S0016-2361(99)00055-1. Clarkson, C.R., Bustin, R.M., 2000. Binary gas adsorption/desorption isotherms: effect of moisture and coal composition upon carbon dioxide selectivity over methane. Int. J. Coal Geol. 42, 241e271. http://dx.doi.org/10.1016/S01665162(99)00032-4. Crosdale, P.J., Moore, T.A., Mares, T.E., 2008. Influence of moisture content and temperature on methane adsorption isotherm analysis for coals from a lowrank, biogenically-sourced gas reservoir. Int. J. Coal Geol. 76, 166e174. http:// dx.doi.org/10.1016/j.coal.2008.04.004. Cui, X.J., Bustin, R.M., Dipple, G., 2004. Differential transport of CO2 and CH4 in coalbed aquifers: implications for coalbed gas distribution and composition. AAPG Bull. 88, 1149e1161. http://dx.doi.org/10.1306/02230403047. Ding, W.L., Zhu, D.W., Cai, J.J., Gong, M.L., Chen, F.Y., 2013. Analysis of the developmental characteristics and major regulating factors of fractures in marinecontinental transitional shale-gas reservoirs: a case study of the Carboniferous-Permian strata in the southeastern Ordos Basin, central China. Mar. Petroleum Geol. 45, 121e133. http://dx.doi.org/10.1016/ j.marpetgeo.2013.04.022. Drobniak, A., Mastalerz, M., Rupp, J., Eaton, N., 2004. Evaluation of coalbed gas potential of the Seelyville coal member, Indiana, USA. Int. J. Coal Geol. 57, 265e282. http://dx.doi.org/10.1016/j.coal.2003.12.007. Faiz, M., Saghafi, A., Sherwood, N., Wang, I., 2007. The influence of petrological properties and burial history on coal seam methane reservoir characterisation, Sydney Basin, Australia. Int. J. Coal Geol. 70, 193e208. http://dx.doi.org/10.1016/ j.coal.2006.02.012. Gan, H., Nandi, S.P., Walker Jr., P.L., 1972. Nature of the porosity in American coals. Fuel 51, 272e277. http://dx.doi.org/10.1016/0016-2361(72)90003-8. Gentzis, T., 2013. Coalbed methane potential of the Paleocene Fort Union coals in south-central Wyoming, USA. Int. J. Coal Geol. 108, 27e34. http://dx.doi.org/ 10.1016/j.coal.2012.06.003. farge, F., 2008. Coalbed methane Gentzis, T., Goodarzi, F., Cheung, F.K., Laggoun-De producibility from the Mannville coals in Alberta, Canada: a comparison of two areas. Int. J. Coal Geol. 74, 237e249. http://dx.doi.org/10.1016/ j.coal.2008.01.004. Gentzis, T., Schoderbek, D., Pollock, S., 2006. Evaluating the coalbed methane potential of the Gething coals in NE British Columbia, Canada: an example from the Highhat area, Peace River coalfield. Int. J. Coal Geol. 68, 135e150. http:// dx.doi.org/10.1016/j.coal.2006.02.001. Hamilton, S.K., Esterle, J.S., Golding, S.D., 2012. Geological interpretation of gas content trends, Walloon Subgroup, eastern Surat Basin, Queensland, Australia. Int. J. Coal Geol. 101, 21e35. http://dx.doi.org/10.1016/j.coal.2012.07.001. Hemza, P., Sivek, M., Jir asek, J., 2009. Factors influencing the methane content of coal beds of the Czech part of the Upper Silesian Coal Basin, Czech Republic. Int. J. Coal Geol. 79, 29e39. http://dx.doi.org/10.1016/j.coal.2009.04.003. Hildenbrand, A., Krooss, B.M., Busch, A., Gaschnitz, R., 2006. Evolution of methane sorption capacity of coal seams as a function of burial historyda case study from the Campine Basin, NE Belgium. Int. J. Coal Geol. 66, 179e203. http:// dx.doi.org/10.1016/j.coal.2005.07.006. Hitchon, B., Brulotte, M., 1994. Culling criteria for ‘‘standard’’ formation water analyses. Appl. Geochem. 9, 637e645. http://dx.doi.org/10.1016/0883-2927(94) 90024-8.

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270 Johnson, R.C., Flores, R.M., 1998. Developmental geology of coalbed methane from shallow to deep in Rocky Mountain basins and in Cook InleteMatanuska basin, Alaska, U.S.A. and Canada. Int. J. Coal Geol. 35, 241e282. http://dx.doi.org/ 10.1016/S0166-5162(97)00016-5. Joubert, J.I., Grein, C.T., Bienstock, D., 1973. Sorption of methane in moist coal. Fuel 52, 181e185. http://dx.doi.org/10.1016/0016-2361(73)90076-8. Joubert, J.I., Grein, C.T., Bienstock, D., 1974. Effect of moisture on the methane capacity of American coals. Fuel 53, 186e191. http://dx.doi.org/10.1016/00162361(74)90009-X. Kaiser, W.R., Hamilton, D.S., Scott, A.R., Tyler, R., Finley, R.J., 1994. Geological and hydrological controls on the producibility of coalbed methane. J. Geol. Soc. Lond. 151, 417e420. http://dx.doi.org/10.1144/gsjgs.151.3.0417. Karweil, J., 1955. Die Metamorphose der Kohlen vom Standpunkt der physikalischen Chemie. Z. Dtsch. Geol. Ges. Band 107, 132e139. Ke˛ dzior, S., Kotarba, M.J., Pe˛ kała, Z., 2013. Geology, spatial distribution of methane content and origin of coalbed gases in Upper Carboniferous (Upper Mississippian and Pennsylvanian) strata in the south-eastern part of the Upper Silesian Coal Basin, Poland. Int. J. Coal Geol. 105, 24e35. http://dx.doi.org/10.1016/ j.coal.2012.11.007. Kim, A.G., 1977. Estimating Methane Content of Bituminous Coalbeds from Adsorption Data. U.S. Bureau of Mines Report of Investigations 8245, pp. 1e22. Kinnon, E.C.P., Golding, S.D., Boreham, C.J., Baublys, K.A., Esterle, J.S., 2010. Stable isotope and water quality analysis of coal bed methane production waters and gases from the Bowen Basin, Australia. Int. J. Coal Geol. 82, 219e231. http:// dx.doi.org/10.1016/j.coal.2009.10.014. Kotarba, M.J., 1990. Isotopic geochemistry and habitat of the natural gases from the  r coal-bearing formation in the Nowa Ruda coal Upper Carboniferous Zacle district (Lower Silesia, Poland). Org. Geochem. 16, 549e560. http://dx.doi.org/ 10.1016/0146-6380(90)90069-C. Lamarre, R.A., 2003. Hydrodynamic and stratigraphic controls for a large coalbed methane accumulation in Ferron coals of east-central Utah. Int. J. Coal Geol. 56, 97e110. http://dx.doi.org/10.1016/S0166-5162(03)00078-8. Lamberson, M.N., Bustin, R.M., 1993. Coalbed methane characteristics of Gates Formation coals, northeastern British Columbia: effect of maceral composition. AAPG Bull. 77, 2062e2076. http://dx.doi.org/10.1306/bdff8fd8-1718-11d78645000102c1865d. Laxminarayana, C., Crosdale, P.J., 2002. Controls on methane sorption capacity of Indian coals. AAPG Bull. 86, 201e212. http://dx.doi.org/10.1306/61eeda8a-173e11d7-8645000102c1865d. Levine, J.R., 1993. Coalification: the evolution of coal as source rock and reservoir rock for oil and gas. In: Law, B.E., Rice, D.D. (Eds.), Hydrocarbons from Coal, AAPG Studies in Geology, pp. 39e77. Liu, D.M., Yao, Y.B., Tang, D.Z., Tang, S.H., Che, Y., Huang, W.H., 2009. Coal reservoir characteristics and coalbed methane resource assessment in Huainan and Huaibei coalfields, Southern North China. Int. J. Coal Geol. 79, 97e112. http:// dx.doi.org/10.1016/j.coal.2009.05.001. Liu, H.H., Sang, S., Wang, G.G.X., Li, M.X., Xu, H.J., Liu, S.Q., Li, J.J., Ren, B., Zhao, Z.G., Xie, Y., 2014. Block scale investigation on gas content of coalbed methane reservoirs in southern Qinshui basin with statistical model and visual map. J. Petroleum Sci. Eng. 114, 1e14. http://dx.doi.org/10.1016/j.petrol.2013.08.039. Liu, H.H., Sang, S., Wang, G.G.X., Li, Y.M., Li, M.X., Liu, S.Q., 2012. Evaluation of the synergetic gas-enrichment and higher-permeability regions for coalbed methane recovery with a fuzzy model. Energy 39, 426e439. http://dx.doi.org/ 10.1016/j.energy.2011.12.027. Lv, Y.M., Tang, D.Z., Xu, H., Luo, H.H., 2012. Production characteristics and the key factors in high-rank coalbed methane fields: a case study on the Fanzhuang Block, Southern Qinshui Basin, China. Int. J. Coal Geol. 96e97, 93e108. http:// dx.doi.org/10.1016/j.coal.2012.03.009. Martini, A.M., Budai, J.M., Walter, L.M., Schoell, M., 1996. Microbial generation of economic accumulations of methane within a shallow organic-rich shale. Nature 383, 155e158. http://dx.doi.org/10.1038/383155a0. Mastalerz, M., Drobniak, A., Stra˛ po c, D., Acosta, W.S., Rupp, J., 2008. Variations in pore characteristics in high volatile bituminous coals: implications for coal bed gas content. Int. J. Coal Geol. 76, 205e216. http://dx.doi.org/10.1016/ j.coal.2008.07.006. Meissner, F.F., 1987. Mechanisms and patterns of gas generation and expulsiondmigration and accumulation associated with coal measures, Green River and San Juan Basins, Rocky Mountain region, USA. In: Doligez, B. (Ed.), Migration of Hydrocarbons in Sedimentary Basins. Editions Technip, Paris, pp. 79e112. Moore, T.A., 2012. Coalbed methane: a review. Int. J. Coal Geol. 101, 36e81. http:// dx.doi.org/10.1016/j.coal.2012.05.011. Moore, T.A., Bowe, M., Nas, C., 2014. High heat flow effects on a coalbed methane reservoir, East Kalimantan (Borneo), Indonesia. Int. J. Coal Geol. 131, 7e31. http://dx.doi.org/10.1016/j.coal.2014.05.012. Pashin, J.C., 2007. Hydrodynamics of coalbed methane reservoirs in the Black Warrior Basin: key to understanding reservoir performance and environmental issues. Appl. Geochem. 22, 2257e2272. http://dx.doi.org/10.1016/ j.apgeochem.2007.04.009. Pashin, J.C., 2010. Variable gas saturation in coalbed methane reservoirs of the Black Warrior Basin: implications for exploration and production. Int. J. Coal Geol. 82, 135e146. http://dx.doi.org/10.1016/j.coal.2009.10.017. Pashin, J.C., McIntyre-Redden, M.R., Mann, S.D., Kopaska-Merkel, D.C., Varonka, M., Orem, W., 2014. Relationships between water and gas chemistry in mature coalbed methane reservoirs of the Black Warrior Basin. Int. J. Coal Geol. 126,

269

92e105. http://dx.doi.org/10.1016/j.coal.2013.10.002. Pitman, J.K., Pashin, J.C., Hatch, J.R., Goldhaber, M.B., 2003. Origin of minerals in joint and cleat systems of the Pottsville Formation, Black Warrior basin, Alabama: implications for coalbed methane generation and production. AAPG Bull. 87, 713e731. http://dx.doi.org/10.1306/01140301055. Qin, Y., Fu, X.H., Ye, J.P., Lin, D.Y., Tang, S.H., Li, G.Z., 1999. Geological controls and their mechanisms of coal reservoir petrography and physics of coalbed methane occurrence in China. J. China Univ. Min. Technol. 28, 14e18. http:// dx.doi.org/10.3321/j.issn:1000-1964.1999.01.004 (in Chinese with English abstract). Rice, C.A., 2003. Production waters associated with the Ferron coalbedmethane fields, central Utah: chemical and isotopic composition and volumes. Int. J. Coal Geol. 56, 141e169. http://dx.doi.org/10.1016/S0166-5162(03)00086-7. Rice, D.D., Claypool, G.E., 1981. Generation, accumulation and resource potential of biogenic gas. AAPG Bull. 65, 5e25. http://dx.doi.org/10.1306/2f919765-16ce11d7-8645000102c1865d. Rowe, D., Muehlenbachs, K., 1999. Isotopic fingerprints of shallow gases in the Western Canadian sedimentary basin: tools for remediation of leaking heavy oil wells. Org. Geochem. 30, 861e871. http://dx.doi.org/10.1016/S0146-6380(99) 00068-6. Schoell, M., 1980. The hydrogen and carbon isotopic composition of methane from natural gases of various origins. Geochimica Cosmochimica Acta 44, 649e661. http://dx.doi.org/10.1016/0016-7037(80)90155-6. Scott, A.R., 2002. Hydrogeologic factors affecting gas content distribution in coal beds. Int. J. Coal Geol. 50, 363e387. http://dx.doi.org/10.1016/S0166-5162(02) 00135-0. Scott, A.R., Kaiser, W.R., Ayers Jr., W.B., 1994. Thermogenic and secondary biogenic gases, San Juan Basin, Colorado and New Mexicoeimplications for coalbed gas producibility. AAPG Bull. 78, 1186e1209. http://dx.doi.org/10.1306/a25feaa9171b-11d7-8645000102c1865d. Smith, J.W., Pallasser, R.J., 1996. Microbial origin of Australian coalbed methane. AAPG Bull. 80, 891e897. http://dx.doi.org/10.1306/64ed88fe-1724-11d78645000102c1865d. Stra˛ po c, D., Mastalerz, M., Eble, C., Schimmelmann, A., 2007. Characterization of the origin of coalbed gases in southeastern Illinois Basin by compound-specific carbon and hydrogen stable isotope ratios. Org. Geochem. 38, 267e287. http://dx.doi.org/10.1016/j.orggeochem.2006.09.005. Stra˛ po c, D., Mastalerz, M., Schimmelmann, A., Drobniak, A., Hedges, S., 2008. Variability of geochemical properties in a microbially dominated coalbed gas system from the eastern margin of the Illinois Basin, USA. Int. J. Coal Geol. 76, 98e110. http://dx.doi.org/10.1016/j.coal.2008.02.002. Stra˛ po c, D., Schimmelmann, A., Mastalerz, M., 2006. Carbon isotopic fractionation of CH4 and CO2 during canister desorption of coal. Org. Geochem. 37, 152e164. http://dx.doi.org/10.1016/j.orggeochem.2005.10.002. Su, X.B., Lin, X.Y., Liu, S.B., Zhao, M.J., Song, Y., 2005. Geology of coalbed methane reservoirs in the southeast Qinshuim basin of China. Int. J. Coal Geol. 62, 197e210. http://dx.doi.org/10.1016/j.coal.2005.01.002. Tang, S.H., Wang, Y.B., Zhang, D.S., 2007. A comprehensive appraisal on the characteristics of coal-bed methane reservoir in Turpan-Hami basin. J. China Univ. Min. Technol. 17 (521e525), 545. http://dx.doi.org/10.1016/S1006-1266(07) 60138-2. Unsworth, J.F., Fowler, C.S., Jones, L.F., 1989. Moisture in coal: 2. Maceral effects on pore structure. Fuel 68, 18e26. http://dx.doi.org/10.1016/0016-2361(89)900057. Van Voast, W.A., 2003. Geochemical signature of formation waters associated with coalbed methane. AAPG Bull. 87, 667e676. http://dx.doi.org/10.1306/ 10300201079. Warwick, P.D., Breland Jr., F.C., Hackley, P.C., 2008. Biogenic origin of coalbed gas in the northern Gulf of Mexico Coastal Plain, U.S.A. Int. J. Coal Geol. 76, 119e137. http://dx.doi.org/10.1016/j.coal.2008.05.009. Watson, M.P., Hayward, A.B., Parkinson, D.N., Zhang, Z.M., 1987. Plate tectonic history, basin development and petroleum source rock deposition onshore China. Mar. Petroleum Geol. 4, 205e225. http://dx.doi.org/10.1016/0264-8172(87) 90045-6. Wei, C.T., Qin, Y., Wang, G.G.X., Fu, X.H., Jiang, B., Zhang, Z.Q., 2007. Simulation study on evolution of coalbed methane reservoir in Qinshui basin, China. Int. J. Coal Geol. 72, 53e69. http://dx.doi.org/10.1016/j.coal.2006.12.001. Wei, C.T., Qin, Y., Wang, G.G.X., Fu, X.H., Zhang, Z.Q., 2010. Numerical simulation of coalbed methane generation, dissipation and retention in SE edge of Ordos Basin, China. Int. J. Coal Geol. 82, 147e159. http://dx.doi.org/10.1016/ j.coal.2009.12.005. Whiticar, M.J., 1999. Carbon and hydrogen isotope systematics of bacterial formation and oxidation of methane. Chem. Geol. 161, 291e314. http://dx.doi.org/ 10.1016/S0009-2541(99)00092-3. Whiticar, M.J., Faber, E., 1986. Methane oxidation in sediment and water column environmentsdIsotope evidence. Org. Geochem. 10, 759e768. http:// dx.doi.org/10.1016/S0146-6380(86)80013-4. Whiticar, M.J., Faber, E., Schoell, M., 1986. Biogenic methane formation in marine and freshwater environments: CO2 reduction vs. acetate fermentationdIsotope evidence. Geochimica Cosmochimica Acta 50, 693e709. http://dx.doi.org/ 10.1016/0016-7037(86)90346-7. Xu, H., Tang, D.Z., Liu, D.M., Tang, S.H., Yang, F., Chen, X.Z., He, W., Deng, C.M., 2012. Study on coalbed methane accumulation characteristics and favorable areas in the Binchang area, southwestern Ordos Basin, China. Int. J. Coal Geol. 95, 1e11. http://dx.doi.org/10.1016/j.coal.2012.02.001.

270

S. Hou et al. / Marine and Petroleum Geology 78 (2016) 254e270

Yang, R.T., Saunders, J.T., 1985. Adsorption of gases on coals and heat-treated coals at elevated temperature and pressure: 1. Adsorption from hydrogen and methane as single gases. Fuel 64, 616e620. http://dx.doi.org/10.1016/00162361(85)90043-2. Yang, H., Fu, J.H., Wei, X.S., Liu, X.S., 2008. Sulige field in the Ordos Basin: geological setting, field discovery and tight gas reservoirs. Mar. Petroleum Geol. 25, 387e400. http://dx.doi.org/10.1016/j.marpetgeo.2008.01.007. Yang, Y.T., Li, W., Ma, L., 2005. Tectonic and stratigraphic controls of hydrocarbon systems in the Ordos Basin: amulticycle cratonic basin in central China. AAPG Bull. 89, 255e269. http://dx.doi.org/10.1306/10070404027. Yao, Y.B., Liu, D.M., Qiu, Y.K., 2013. Variable gas content, saturation, and accumulation characteristics of Weibei coalbed methane pilot-production field in the southeastern Ordos Basin, China. AAPG Bull. 97, 1371e1393. http://dx.doi.org/ 10.1306/02131312123. Yao, Y.B., Liu, D.M., Tang, D.Z., Tang, S.H., Che, Y., Huang, W.H., 2009. Preliminary evaluation of the coalbed methane production potential and its geological controls in the Weibei Coalfield, Southeastern Ordos Basin, China. Int. J. Coal Geol. 78, 1e15. http://dx.doi.org/10.1016/j.coal.2008.09.011. Yao, Y.B., Liu, D.M., Tang, D.Z., Tang, S.H., Huang, W.H., 2008. Fractal characterization of adsorption-pores of coals from North China: an investigation on CH4

adsorption capacity of coals. Int. J. Coal Geol. 73, 27e42. http://dx.doi.org/ 10.1016/j.coal.2007.07.003. Yao, Y.B., Liu, D.M., Yan, T.T., 2014. Geological and hydrogeological controls on the accumulation of coalbed methane in the Weibei field, southeastern Ordos Basin. Int. J. Coal Geol. 121, 148e159. http://dx.doi.org/10.1016/j.coal.2013.11.006. Yee, D., Seidle, J.P., Hanson, W.B., 1993. Gas sorption on coal and measurement of gas content. In: Law, B.E., Rice, D.D. (Eds.), Hydrocarbons from Coal, AAPG Studies in Geology, pp. 203e218. Zhang, E., Hill, R.J., Katz, B.J., Tang, Y.C., 2008. Modeling of gas generation from the Cameo coal zone in the Piceance Basin, Colorado. AAPG Bull. 92, 1077e1106. http://dx.doi.org/10.1306/04020806015. Zhou, Z., Ballentine, C.J., Kipfer, R., Schoell, M., Thibodeaux, S., 2005. Noble gas tracing of groundwater/coalbed methane interaction in the San Juan Basin, USA. Geochimica Cosmochimica Acta 69, 5413e5428. http://dx.doi.org/10.1016/ j.gca.2005.06.027. Zhu, H.T., Chen, K.Y., Liu, K.Y., He, S., 2008. A sequence stratigraphic model for reservoir sand-body distribution in the Lower Permian Shanxi formation in the Ordos Basin, northern China. Mar. Petroleum Geol. 25, 731e743. http:// dx.doi.org/10.1016/j.marpetgeo.2008.03.007.