Origin and distribution of hydrogen sulfide in the Yuanba gas field, Sichuan Basin, Southwest China

Marine and Petroleum Geology 75 (2016) 220e239

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Research paper

Origin and distribution of hydrogen sulfide in the Yuanba gas field, Sichuan Basin, Southwest China Pingping Li a, *, Fang Hao b, Xusheng Guo c, Huayao Zou a, Yangming Zhu d, Xinya Yu a, Guangwei Wang a a

State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing, Changping, Beijing 102249, China Key Laboratory of Tectonics and Petroleum Resources, Ministry of Education, China University of Geosciences, Wuhan, Hubei 430074, China SINOPEC Exploration Company, Chengdu, Sichuan 610041, China d Department of Earth Sciences, Zhejiang University, Hangzhou, Zhejiang 310027, China b c

a r t i c l e i n f o

a b s t r a c t

Article history: Received 20 November 2015 Received in revised form 21 April 2016 Accepted 22 April 2016 Available online 23 April 2016

The Yuanba gas field in the Permian Changxing Formation (P2c), which exhibits wide variations in its hydrogen sulfide (H2S) concentration (1.20e12.16%), is a typical sour gas field in the northern Sichuan Basin. The sulfur-rich reservoir's solid bitumen (atomic S/C ratios are 0.032e0.142), and late calcite cement d13C values, which are smaller than the d13C values of the host dolostone, indicate that the H2S originated from thermal sulfate reduction (TSR) and oil was involved in TSR. The gas souring index (GSI) of P2c's gases is generally lower than 0.1. The ethane d13C values increase as the GSI increases, although no obvious increase was observed in the methane d13C values. The calcite cements' d13C values (
15.36 to þ4.56‰) in dolostone are heavier than the typical reported values, which implies that only limited heavy hydrocarbon gases were involved in TSR. No anhydrites developed in P2c's reservoirs, and dis2
solved sulfate anions (SO2
4 ) were mainly enriched during dolomitization. Insufficient dissolved SO4 most likely caused the lower H2S concentrations in the Permian to Triassic reservoirs in the northeastern Sichuan Basin compared to the Permian Khuff Formation in Saudi Arabia and the Jurassic Smackover 2
Formation in Mississippi. Except for the SO2
4 in residual water in paleo-oil zones, SO4 from bottom water may also be involved in TSR; therefore, oil reservoirs with bottom water have more SO2
4 and can produce more H2S than pure oil reservoirs. This phenomenon may be the main cause of the great difference in the H2S concentrations between reservoirs, while gravitational differentiation during late uplift most likely creates differences in H2S concentrations in a single reservoir. Carbon dioxide (CO2), which has a relatively heavy d13C value (
3.9 to
0.3‰), may be the combined result of TSR, the balance between CO2 and inorganic fluid systems, and carbonate decomposition. © 2016 Elsevier Ltd. All rights reserved.

Keywords: Hydrogen sulfide Thermal sulfate reduction Carbon dioxide Stable carbon isotopes Yuanba gas field Sichuan Basin

1. Introduction H2S is toxic and corrosive and can increase the handling costs of natural gas. Thus, the origins and distribution predictions of H2S are crucial topics in the petroleum industry. Numerous laboratory studies (e.g., Kiyosu and Krouse, 1990, 1993; Cross et al., 2004; Yuan et al., 2013), geological case studies (e.g., Worden et al., 1995; Heydari, 1997; Cai et al., 2004; Hao et al., 2008), and comprehensive studies and reviews (e.g., Goldstein and Aizenshtat, 1994; Machel, 2001; Hao et al., 2015) have been conducted over the

* Corresponding author. E-mail address: [email protected] (P. Li). http://dx.doi.org/10.1016/j.marpetgeo.2016.04.021 0264-8172/© 2016 Elsevier Ltd. All rights reserved.

past 40 years. The main sources of H2S in hydrocarbon reservoirs are as follows: (1) the thermal decomposition of organic sulfur compounds in kerogen or oil (also termed thermal chemical alteration, TCA, e.g., Kelemen et al., 2008), (2) bacterial or microbial sulfate reduction (BSR), and (3) thermochemical sulfate reduction (TSR) (Orr, 1974; Machel, 1987, 2001). In most cases, TSR mainly contributes to the high concentrations of H2S (>10%) in deeply buried gas reservoirs (Orr, 1974, 1977; Worden and Smalley, 1996; Mougin et al., 2007). TSR is a reaction between hydrocarbons and dissolved sulfate (Machel et al., 1995; Worden et al., 1996; Bildstein et al., 2001). Dissolved SO2
4 is highly stable because of its symmetrical tetrahedral molecular structure (Ma et al., 2008). Therefore, energy absorption is essential to break its sulfureoxygen bonds. Most

P. Li et al. / Marine and Petroleum Geology 75 (2016) 220e239

experimental studies determined or estimated relatively high activation energies of 140e250 kJ/mol (Kiyosu, 1980; Cross et al., 2004; Ma et al., 2008; Zhang et al., 2012), which implies that TSR would occur at relatively high temperatures. The onset temperature to initiate TSR in the laboratory is generally above 200  C (Toland, 1960; Kiyosu and Krouse, 1993; Cross et al., 2004; Xia et al., 2014). Although still controversial, the commonly believed lowest temperature for TSR is 100e140  C based on laboratory experiments and case studies (Orr, 1974; Worden et al., 1995, 1998; Cai et al., 2004). The initiation mechanism, reaction process, and products of TSR have been studied intensively (Orr, 1974; Machel et al., 1995; Worden and Smalley, 1996; Zhang et al., 2007, 2008a; Amrani et al., 2008; Yuan et al., 2013). A three-stage TSR has been proposed by Hao et al. (2008): liquid-hydrocarbon-involved TSR (R1), heavy-hydrocarbon-gas-dominated TSR (R2), and methanedominated TSR (R3). If the respective metals are available, pyrite, saddle dolomite, ankerite, siderite, witherite, and strontianite can form during these reactions (Machel, 1987, 2001; Krouse et al., 1988; Heydari and Moore, 1989): Liquid hydrocarbons þ SO2
4 / NSOcompound þ bitumen þ H2S þ CO2

(R1)

nCaSO4 þ CnH2nþ2 / nCaCO3 þ H2S þ (n
1)S þ nH2O

(R2)

CH4 þ CaSO4 / CaCO3 þ H2S þ H2O

(R3)

The Sichuan Basin, which has relatively high H2S concentrations (generally >5.0%) in its marine Permian to Triassic reservoirs, is a typical sour gas province in southern China. Previous studies mainly focused on Permian to Triassic gas reservoirs in the eastern Sichuan Basin and proved that the H2S originated from TSR (Cai et al., 2003, 2010; Li et al., 2005; Zhu et al., 2005, 2007; Hao et al., 2008). However, whether intense methane-dominated TSR occurred remains controversial (Hao et al., 2015). The newly discovered Yuanba gas field in Permian Changxing Formation (P2c), which exhibits wide variations in its H2S concentration (1.20e12.16%), is located in the northern Sichuan Basin. Many isolated gas reservoirs with isolated gas-water contacts are present here, and the H2S concentration varies greatly between different reservoirs and even in a single reservoir. The hydrocarbon gases are mainly derived from secondary oil cracking (Li et al., 2015a). No anhydrite is present in P2c's gas reservoir in the Yuanba gas field, which is obviously different from commonly reported case studies (Worden and Smalley, 1996; Heydari, 1997; Jenden et al., 2015). Therefore, the Yuanba gas field is a suitable geological example to examine the essential conditions and stages of TSR. The purpose of this paper is to address the following questions: (1) What is the origin of the H2S and CO2 in the Yuanba gas field? (2) Was methane involved in TSR? (3) What is the source of the sulfates that are required for TSR? (4) What are the factors that control the distribution of H2S? (5) Why are the H2S concentrations relatively low in the Yuanba gas field and adjacent areas in the Sichuan Basin? 2. Geological setting The Sichuan Basin, which has an area of 180,000 km2, is a rhombic basin in southwestern China (Fig. 1). The general evolutionary history and stratigraphy of the basin have been reviewed by Ma et al. (2007), Hao et al. (2008), and Li et al. (2015a). The Sichuan Basin has experienced several tectonic cycles and movements (Zhai, 1989; Tong, 1992) (Fig. 2). Before the early Indosinian movement, the basin was mainly characterized by subsidence and

221

uplift, while large-scale lateral compression has been occurring since the late Indosinian movement, and strong lateral compression occurred during the Himalayan movement (Ma et al., 2007). The total thickness from the Sinian to the Quaternary in the Sichuan Basin is 6000e12,000 m (Fig. 2). The Lower Sinian consists of piedmont and fluvial deposits to the southwest; eruptive materials to the west; and fluvial, offshore, and shallow sea deposits to the southeast. The Upper Sinian-Lower Permian mainly consists of marine carbonate and shale. The Upper Permian Longtan Formation (P2l) developed in a continental to marine transitional environment in the southwestern part of the basin and consists of mudstone that is interbedded with coal; simultaneously, the Wujiaping Formation (P2w) developed in a restricted embayment in the northeastern basin and consists of marine mudstone and muddy limestone. The P2c layer to the Lower Triassic Feixianguan Formation (T1f) developed in an open and shallow platform and consists of limestone and dolostone. During the deposition of P2c, a northwest- to southeast-trending shelf developed in the northern and eastern Sichuan Basin, and platform edges developed in both the western and eastern regions of the shelf (Fig. 3A). During the deposition of the second member of the Feixianguan Formation (T1f2), the shelf closed in the northwestern part and the range of the shelf decreased (Fig. 3B). Near the end of T1f, the shelf completely disappeared and a completely restricted platform formed. The Lower Triassic Jialingjiang (T1j) and Middle Triassic Leikoupo (T2l) Formations developed in restricted and evaporite platforms and consist of limestone and widespread anhydrite. The Upper TriassicQuaternary Xujiahe Formation (T3x) developed in a fluviallacustrine environment and consists of coal, mudstone, sandstone, and local conglomerate. Five potential petroleum source rocks developed in the Sichuan Basin, including Lower Cambrian shale and mudstone; Lower Silurian shale; Upper Permian coal, mudstone, and muddy limestone; Upper Triassic mudstone and coal; and Lower-Middle Jurassic mudstone (Fig. 2). The Upper Permian source rocks have been confirmed to have contributed abundant natural gases from T1f and P2c in the northeastern Sichuan Basin (Li et al., 2005; Hao et al., 2008, 2009; Zou et al., 2008). The Yuanba gas field, which was discovered in 2007, is located in the northern Sichuan Basin (Fig. 1) and contains its main gas production interval in P2c's dolostone reservoir (Guo, 2011). Platform margin reefs and shoals traps developed in P2c, and open sea limestone in the first member of T1f is the direct cap rock. The hydrocarbon gases in P2c's reservoirs in the Yuanba gas field are mainly secondary cracking gases that were derived from P2w's sapropelic source rock (Guo, 2011; Duan et al., 2013; Li et al., 2015a). P2c's reservoirs reached maximum burial depths of approximately 8000 m and temperatures of approximately 240  C at 100 Ma during the Late Cretaceous before being uplifted to a present depth of 6500e7000 m. The reservoirs exhibit a present-day thermal maturity above 3.0% and have equivalent vitrinite reflectance (Ro) (Fig. 4, Li et al., 2015a). 3. Samples and methods The chemical composition of the natural gas and carbon isotope, reservoir porosity and water saturation data were collected from the SINOPEC Exploration Southern Company. All the gas samples were collected during drill stem testing by using standard techniques in the industry and were analyzed with standard techniques at the Key Laboratory of Gas Geochemistry, Lanzhou Institute of Geology, Chinese Academy of Sciences. The chemical composition of the natural gas samples was analyzed by using a Finnigan MAT271 mass spectrometer, and the stable carbon isotope compositions of methane, ethane, and CO2 were measured by using a Finnigan

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Fig. 1. Main structural units and marine Permian and Triassic gas fields of the Sichuan Basin in southwestern China (modified from Tong, 1992; Ma et al., 2010). I ¼ eastern complete fault-fold zone, II ¼ southern gentle fault-fold zone, III ¼ southwestern gentle fault-fold zone, IV ¼ central flat zone, V ¼ northern gentle fault-fold zone, VI ¼ western gentle faultfold zone. YB ¼ Yuanba, LG ¼ Longgang, PG ¼ Puguang, TSP ¼ Tieshanpo, LJZ ¼ Luojiazhai, JN ¼ Jiannan, WLH ¼ Wolonghe.

MAT-253 instrument. The details of these procedures were presented in Liu et al. (2013). Solid bitumens were obtained from cores of P2c marine carbonates and T3x continental sandstones reservoirs. The solid bitumens were cleaned and extracted before their elemental compositions were analyzed. The bitumen reflectance was measured by using conventional methods (Stach et al., 1982). For comparison, solid bitumen data from the Puguang gas field were also obtained from a published paper (Hao et al., 2008). Core samples from both the present gas zones and water zones were sealed with wax after coring, and then the porosity and water saturation were measured at the State Key Laboratory of Oil and Gas Reservoir Geology and Exploration (Chengdu University of Technology) based on the Archimedes principle and by using an absolute ethyl alcohol system. After removing the wax on the core sample, the primary weight (W0) was measured by an analytical balance. The sample was then sent into a drying oven, and the dry weight (W1) was measured by using an analytical balance. Then, the dry sample was immersed into absolute ethyl alcohol to obtain the sample weight (W2), and the sample weight (W3) after saturation with ethyl alcohol was measured by using an analytical balance. The porosity (P) was calculated by P ¼ 100  (W3
W1)/ (W1
W2). The water saturation (SW) was calculated by SW ¼ 100  r  (W0
W1)/(W3
W1), where r is the density of ethyl alcohol. The details of this measurement procedure followed the Chinese National Standards. Dolostone, limestone, and calcite cement samples (fully or partially filled in the limestone and dolostone vugs) were collected from the cores. These samples were broken into chips and powdered in an agate mortar. Then, the powder was reacted with 100% pure phosphoric acid, and the resultant CO2 gas was analyzed on a MAT253 mass spectrometer at the State Key Laboratory of Geological Processes and Mineral Resources at the China University of Geosciences (Wuhan). The isotopic data were reported in units per thousand relative to the Vienna Pee Dee Belemnite (VPDB) standard. Reservoir water samples were collected from T1f and P2c's water

zones in the Yuanba, Puguang, and Jiannan gas fields during the drilling test process. The water samples from the Yuanba and Puguang gas fields and those from the Jiannan gas field were analyzed at the Geological Central Lab of the Southwest Branch Company of SINOPEC and at the Petroleum Geologic Test Center of the Jianghan Oilfield Company of SINOPEC, respectively. All the water samples were filtered by using filter paper to remove suspended solids. Then, the Naþ þ Kþ, Ca2þ, Mg2þ, Cl
, and SO2
4 concentrations of the obtained water were measured by using ion
chromatography, and the CO2
3 , and HCO3 concentrations were measured by using an automatic potentiometric titrator. The total dissolved solids (TDS) were calculated by summing the cation and anion concentrations. The details of this measurement procedure followed the Oil and Gas Industry Standard of China. 4. Results 4.1. Elemental composition and reflectance of solid bitumen The elemental composition and reflectance of solid bitumen from P2c and T3x in the Yuanba gas field are shown in Table 1. Generally, the atomic H/C ratios, O/C ratios, and S/C ratios of marine P2c and T1f solid bitumen in the Yuanba and Puguang gas fields were above 0.03, below 0.40 and above 0.05, respectively, which are different from those of non-marine T3x solid bitumen (Fig. 5). The atomic N/C ratios of T3x and P2c solid bitumen fell within the same range in the Puguang gas field, whereas the atomic N/C ratios of P2c solid bitumen were remarkably higher than those of T3x solid bitumen in the Yuanba gas field. Compared to that from the Puguang gas field, P2c's solid bitumen from the Yuanba gas field had lower atomic S/C and O/C ratios, higher atomic H/C ratios, and similar atomic N/C ratios, whereas the T3x solid bitumen from the Yuanba gas field had higher atomic S/C and H/C ratios, similar atomic H/C ratios, and lower atomic N/C ratios (Fig. 5). The reflectance (Rb) of P2c and T3x's solid bitumen was 2.72e3.84% and 1.92e2.21%, respectively. The corresponding

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223

Fig. 2. Generalized stratigraphic column of the northern Sichuan Basin. Sym. ¼ symbol.

calculated Ro was 2.08e2.77% and 1.59e1.77%, respectively. A linear relationship (Ro ¼ 0.618Rb þ 0.40) applied when Rb was between 0.1% and approximately 3.0% (Jacob, 1989). However, two Rb values from the Y2 well measured 3.83% and 3.84%, respectively. Thus, the calculated Ro (2.77%) is for reference only. P2c's Ro should be mainly between 2.08% and 2.17% in the Yuanba gas field. P2c's solid bitumen in the Yuanba gas field was similar to the marine solid bitumen in the Puguang gas field. Both materials were insoluble in

organic solvent, and pyrobitumen formed at high thermal maturity (Ro was above 1.7%, Sassen, 1988).

4.2. Chemical and stable carbon isotopic compositions of natural gases The chemical and isotopic compositions of the gases in the Yuanba gas field are shown in Table 2. The hydrocarbon gases were

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Fig. 3. Sedimentary facies at the end of the deposition of the Changxing Formation (P2c) (A) and the second member of the Feixianguan Formation (T1f2) (B) in the Sichuan Basin (modified from Du et al., 2010; Shu, 2014).

dominated by methane, and the non-hydrocarbon gases included H2S, CO2, and nitrogen (N2). Except for the gas in the water zone from the Y123 well, the methane concentration ranged between 77.68% and 91.23%, the gas dryness ranged between 99.73% and 99.99%, the H2S concentration ranged between 1.20% and 12.16%, and the CO2 concentration ranged between 1.63% and 11.31%. The GSI (Worden et al., 1995) was 0.01e0.13 for P2c's gases in the Yuanba gas field. The methane d13C values for gases from P2c in the Yuanba gas field ranged from
31.0‰ to
27.9‰, the ethane d13C values ranged from
29.9‰ to
25.6‰, and the CO2 d13C values ranged from
3.9 to
0.7‰. The H2S concentration of gas in the water zone from the Y123 well reached 25.70% (6978e6986 m). However, the H2S concentration in the water zone cannot be used to assess the extent of TSR

because methane, CO2, and H2S have greatly different solubility in water (Cai et al., 2013). Thus, the gas chemistry from the water zones is not discussed in the following section. The gas in T1f2 from the Y204 well was also dominated by methane (96.18%), whereas the H2S concentration was extremely low (0.003%), and other non-hydrocarbon gases mainly included CO2 (2.54%) and N2 (0.64%). The d13C values of methane, ethane, and CO2 were
27.9‰,
30.4‰, and
0.6‰, respectively. 4.3. H2S concentration distribution The H2S concentration varied largely between reservoirs, and even within the same reservoirs, in the Yuanba gas field (Figs. 6 and 7). For example, the H2S concentration was 4.97% and 4.37% in the

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225

Fig. 4. Burial and thermal history of P2w's source rock and P2c's carbonate reservoir in the Y2 well (well location is shown in Fig. 6) in the Yuanba gas field. Ro ¼ vitrinite reflectance.

Table 1 Elemental compositions and reflectance values of solid bitumen from the Changxing Formation (P2c) and Xujiahe Formation (T3x) in the Yuanba gas field. Well

Strata

Depth (m)

C (%)

H (%)

O (%)

N (%)

S (%)

H/C

O/C

N/C

S/C

Rb (%)a

C. Ro (%)b

Y102 Y2 Y2 Y2 Y9 Y5 Y204 Y204 Y204 Y4 Y5 Y10 Y104 Y122 Y16 Y271 Y271 Y271

P2c P2c P2c P2c P2c T3x T3x T3x T3x T3x T3x T3x T3x T3x T3x T3x T3x T3x

6776.9 6554.5 6582.1 6588.4 6930.8 4776.0 4634.4 4819.8 4860.2 4776.5 4776.1 4924.8 4594.3 4175.5 4640.7 4280.8 4287.2 4280.3

47.52 76.94 77.86 74.77 76.42 65.94 84.75 78.07 62.16 81.16 74.75 63.66 76.59 76.24 81.43 76.22 61.90 87.65

2.00 2.42 3.06 2.42 1.64 2.91 3.64 3.46 2.19 3.82 3.87 3.31 3.61 3.80 4.23 3.78 3.75 3.72

6.61 5.56 6.80 7.12 3.51 3.95 3.03 5.40 3.58 2.90 3.07 2.95 3.44 2.48 2.64 2.61 2.50 2.23

0.93 1.51 1.62 1.15 1.09 1.11 0.61 0.61 0.32 0.44 0.80 0.50 0.58 0.54 0.62 0.77 0.55 0.60

17.99 11.37 6.64 11.34 14.48 7.48 1.46 4.30 4.56 1.42 3.46 5.48 4.14 2.40 1.95 2.37 2.78 2.32

0.505 0.377 0.472 0.388 0.258 0.530 0.515 0.532 0.423 0.565 0.621 0.624 0.566 0.598 0.623 0.595 0.727 0.509

0.104 0.054 0.066 0.071 0.034 0.045 0.027 0.052 0.043 0.027 0.031 0.035 0.034 0.024 0.024 0.026 0.030 0.019

0.017 0.017 0.018 0.013 0.012 0.014 0.006 0.007 0.004 0.005 0.009 0.007 0.006 0.006 0.007 0.009 0.008 0.006

0.142 0.055 0.032 0.057 0.071 0.043 0.006 0.021 0.028 0.007 0.017 0.032 0.020 0.012 0.009 0.012 0.017 0.010

2.86 3.83 2.72 3.84 ND 2.20 2.04 2.06 2.12 2.19 1.93 2.15 2.06 2.00 1.92 2.20 2.21 2.03

2.17 2.77 2.08 2.77 ND 1.76 1.66 1.67 1.71 1.75 1.59 1.73 1.67 1.64 1.59 1.76 1.77 1.65

a b

Rb ¼ bitumen reflectance; ND ¼ no data. C. Ro ¼ calculated Ro values from the equation Ro ¼ 0.618Rb þ 0.40 (Jacob, 1989).

Y205 and Y2 wells, respectively, in the same reservoir of the first member of P2c (P2c1), whereas the H2S concentration was only 1.20% in the Y29 well. The H2S concentration in the Y10c1 well was 7.25% in the reservoir of the second member of P2c (P2c2) compared to 3.30% in the Y107 well. The H2S concentration was higher in relatively lower reservoirs. For example, the H2S concentration was generally lower than 5.00% in the northwestern reservoirs in P2c1 but was commonly 5.49e12.16% in the middle and eastern reservoirs (Figs. 6 and 7). In particular, the concentrations were remarkably higher in reservoirs with bottom water. For example, the H2S concentration was 8.96% and 12.16% in the Y123 and Y16 wells in P2c2, respectively. In addition, the H2S concentration in relatively lower wells was higher even within the same reservoir. For example, the H2S concentration increased from 5.14% to 5.20% and 5.59% in the Y27, Y271, and Y273 wells in P2c2, respectively (the present-day burial depth increases sequentially). These values also increased from 4.36% to 7.15% and 7.04% in the Y102, Y104, and Y104 wells in P2c2, respectively. A

similar result was observed in the Puguang gas field. The H2S concentration in T1f increased from 11.04e14.05% to 14.80e16.89% and 14.43e17.41% in the PG6, the PG2, and PG4ePG10 wells, respectively (Fig. 8). The H2S concentration increased as the burial depth increased, even within the same well, increasing from 11.01% to 14.05% in the PG6 well in T1f and from 14.80% to 15.82e16.89% in the PG2 well in T1f (Fig. 8).

4.4. Stable carbon and oxygen isotopic compositions of dolostone, limestone, and calcite cements Calcite cements commonly developed in limestone and dolostone in P2c (Fig. 9). The calcite cements in tight limestone were mainly completely filled vugs (Fig. 9A, C), whereas coarse calcite cements could be observed in partly filled vugs (Fig. 9B). Clumpy calcite cements developed in porous dolostone (Fig. 9D, H), but partly filled coarse calcite cements in vugs were more common (Fig. 9E, F, H).

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dolostone were lighter than those of the calcite cements in the limestone. 4.5. Cations, anions, and salinity of the reservoir water The cations and anions of the reservoir water from the Puguang, Yuanba, and Jiannan gas fields are shown in Table 4. All the water was sampled from daily water production wells. The cation and anion concentrations varied widely across the three gas fields (Table 4). The SO2e 4 concentrations fell within the ranges of 0e1.474 g/L, 0e1.381 g/L, and 1.487e2.913 g/L in P2c and T1f's water from the Puguang, Yuanba, and Jiannan gas fields, respectively. The highest total dissolved solid (TDS) concentrations were found in the Jiannan gas field (101.255e148.414 g/L, average of 119.926 g/L), followed by P2c in the Puguang (50.982e83.224 g/L, average of 70.190 g/L) and Yuanba gas fields (46.901e67.842 g/L, average of 56.562 g/L) and T1f in the Puguang gas field (39.800e62.207 g/L, average of 53.428 g/L). These differences in the TDS between these gas fields may be related to the extent of the TSR (discussed in 5.2). 4.6. Reservoir porosity and water saturation The variations in the reservoir porosity and water saturation are shown in Fig. 11. The lowest porosity value of the effective reservoir was 2.0% in the Yuanba gas field (Feng et al., 2012). In general, the water saturation decreased as the reservoir porosity increased and was below 20% in the gas zone. The water saturation in the gas zone in the Yuanba gas field was 10e20%, which indicates residual water in the current gas zones, and the water saturation in the water zone was 20e80%, which indicates that natural gases were dissolved in the water. 5. Discussion 5.1. Origin of H2S

Fig. 5. Variation in the atomic H/C (A), atomic O/C (B), and atomic N/C ratios (C) with the atomic S/C ratio for solid bitumen from the Yuanba gas field (YB) and the Puguang gas field (PG). The data for solid bitumen from the Puguang gas field are from Hao et al. (2008). P2c, T1f and T3x represent the Changxing, Feixianguan and Xujiahe Formations, respectively.

The d13C and d18O values of the calcite cements and corresponding host rock are shown in Table 3 and Fig. 10. The d13C values of the dolostone (3.18e5.26‰, except for the Y28 well, which was 0.38‰) and limestone (2.79e4.15‰) fell within the same range, whereas the dolostone's d18O values (
6.34 to
3.71‰) were heavier than those of the limestone (
6.12 to
5.40‰). The d13C values (3.07e3.64‰) and d18O values (6.84 to
5.28‰) of the calcite cements in the limestone were similar to those of the limestone host rock, whereas the d13C values (
15.36 to 4.56‰) and d18O values (
7.73 to
5.61‰) of the calcite cements in the dolostone were lighter than those of the dolostone host rock. Furthermore, the d13C and d18O values of parts of the calcite cements in the

The H2S concentration from the thermal decomposition of organic sulfur compounds in kerogen or oil is generally lower than 5.0% because the amount of organic sulfur is limited in kerogen or oil (Orr, 1977). BSR can occur only at temperatures below 80  C (Orr, 1974, 1977; Machel et al., 1995; Machel, 2001), and the H2S concentration is generally lower than 5.0%. In most cases, TSR mainly contributes to the high concentrations of H2S (>10%) in deeply buried gas reservoirs (Orr, 1974; Worden and Smalley, 1996). The present-day temperature of P2c's gas reservoirs is 140e165  C at a burial depth of 6500e7000 m, and hydrocarbon gases mainly occur as in-situ oil secondary-cracking gases in the Yuanba gas field (Li et al., 2015a). The H2S concentration ranged between 1.20% and 12.16% in P2c in the Yuanba gas field (Table 2). Thus, the H2S in the Yuanba gas field most likely originated from TSR. GSI (Worden et al., 1995) was used to reflect the extent of TSR, and the positive correlations between H2S and CO2 and between GSI and CO2 have been accepted as the result of TSR (Krouse et al., 1988; Worden and Smalley, 1996). However, as shown in Fig. 12AeB, no obviously positive correlations exist between H2S and CO2 and between GSI and CO2 (only roughly positive correlations), which does not support the occurrence of TSR in the Yuanba gas field. This observation may be related to the multiple origins of CO2 (discussed in 5.5). Heavy (C2þ) hydrocarbon gases are preferentially exhausted during TSR; thus, the gas dryness increases as GSI increases (Worden and Smalley, 1996; Pan et al., 2006; Hao et al., 2008; Zhang et al., 2008b). However, the ln (C1/C2) values ranged from

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227

Table 2 Chemical and isotope compositions of natural gases from the Yuanba gas field in the Sichuan Basin. Well

Y1-c1 Y10-c1 Y101 Y102 Y103H Y104 Y107 Y11 Y12 Y123 Y123 Y124-c1 Y16 Y2 Y2 Y204 Y205 Y205 Y27 Y28 Y29 Y271 Y273 Y224 Y204 a b c

Strata

P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c1 P2c1 P2c1 P2c2 P2c1 P2c2 P2c1 P2c2 P2c2 P2c1 P2c2 P2c2 P2c2 P2c1 P2c2 P2c2 P2c2 T1f2

a

Depth (m)

7331e7368 7011e7180 6955e7022 6711e6791 7047e7696 6700e6726 6676e6694 6797e6917 6692e6780 6978e6986 6904e6918 6940e7483 6950e6974 6677e6700 6545e6593 6523e6590 6698e6711 6448e6480 6262e6319 6796e6817 6808e6820 6320e6370 6811e6880 6625e6636 6398e6436

Chemical composition (%)

C1/C1e3%

CH4

C2H6

C3H8

H2S

CO2

N2

86.72 86.16 81.51 84.33 85.18 87.09 90.83 82.16 77.68 46.89 78.04 80.64 84.58 83.21 85.56 91.23 89.56 89.14 89.03 88.12 88.76 90.39 89.92 84.76 96.18

0.04 0.04 0.08 0.05 0.04 0.04 0.05 0.06 0.04 0.01 0.04 0.04 0.23 0.06 0.13 0.04 0.04 0.05 0.09 0.01 0.06 0.04 0.04 0.06 0.08

0.00 0.00 0.009 0.03 0.00 0.00 0.00 0.00 0.002 0.00 0.00 0.00 0.003 0.00 0.005 0.005 0.00 0.00 0.002 0.00 0.00 0.00 0.00 0.00 0.00

6.61 7.25 7.15 4.36 7.11 7.04 3.30 6.18 9.84 25.70 8.96 9.90 12.16 4.37 3.81 2.36 4.97 5.33 4.08 5.49 1.20 5.20 5.59 10.61 0.003

6.25 6.24 1.63 9.72 6.06 5.23 5.38 11.31 3.68 15.65 11.02 7.26 2.56 10.95 8.78 4.32 4.79 5.03 5.06 5.44 7.03 3.28 3.86 4.08 2.54

0.28 0.28 4.51 1.45 0.24 0.52 0.37 0.25 2.72 7.74 1.90 0.01 0.46 1.36 1.40 1.54 0.59 0.00 1.22 0.85 4.02 1.01 0.53 0.34 0.64

99.95 99.95 99.89 99.91 99.95 99.95 99.94 99.93 99.95 99.98 99.95 99.95 99.73 99.93 99.84 99.95 99.96 99.94 99.90 99.99 99.93 99.96 99.96 99.93 99.92

GSIb

0.07 0.08 0.08 0.05 0.08 0.07 0.04 0.07 0.11 0.35 0.10 0.11 0.13 0.05 0.04 0.03 0.05 0.06 0.04 0.06 0.01 0.05 0.06 0.11 0.00

d13C (PDB, ‰)c

Gas occurrence

C1

C2

CO2

ND ND
31.0
29.4 ND
29.1 ND ND
30
29.8
29.3 ND
29.7 ND
30.5
29.4
27.9
29.5
28.9 ND
28.9 ND ND ND
27.9

ND ND ND ND ND
25.6 ND ND ND ND
29.9 ND ND ND ND
26.0 ND
27.5
26.6 ND
29.3 ND ND ND
30.4

ND ND
1.7 ND ND
0.77 ND ND
0.7
3.9
1.3 ND
1.3 ND
2.3
1.4
0.86
1.2
1.2 ND
3 ND ND ND
0.6

Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Water zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone Gas zone

P2c1 ¼ first member of the Changxing Formation (Fm), P2c2 ¼ second member of the Changxing Fm, T1f2 ¼ second member of the Feixianguan Fm. GSI ¼ gas souring index. PDB ¼ Pee Dee Belemnite standard, ND ¼ no data.

6 to 8, and these values remained stable as the GSI increased (Fig. 13). These values contradict chemical alteration by TSR. In fact, this observation may have resulted from the extremely high thermal maturity (>2.0%) because the gas dryness was generally above 99.9%. The chemical alteration of gas by TSR may be clear at relatively lower thermal maturity. However, the isotopic compositions of hydrocarbon gases are also altered by TSR. As shown in Fig. 14, the ethane d13C values increased as the GSI increased, but no obvious increase in the methane d13C values was observed (discussed in Section 5.2). During TSR, 12C preferentially reacts with sulfate; thus, residual hydrocarbon gases would be enriched in 13C (Krouse et al., 1988; Manzano et al., 1997; Zhu et al., 2005; Hao et al., 2008). The residual sulfur-rich solid bitumen in P2c's reservoirs also provides evidence for TSR. Compared to solid bitumen in the nonmarine T3x, the marine solid bitumen in P2c in the Yuanba and Puguang gas fields was hydrogen-poor, sulfur-rich, and oxygen-rich (Fig. 5). This hydrogen-poor characteristic is related to high thermal maturity (Ro > 2.0%), whereas the sulfur- and oxygen-rich characteristics may related to TSR processes because sulfur and oxygen can be incorporated into solid bitumen during reactions between liquid oil and sulfates (Orr, 1977; Kelemen et al., 2008, 2010; Zhang et al., 2008b; King et al., 2014). Kelemen et al. (2008, 2010) proposed that the atomic S/C ratio of TSR solid bitumen is above 0.03 and that the atomic N/C ratio is below 0.01, whereas the atomic S/C ratio of TCA solid bitumen is below 0.03 and the atomic N/C ratio is above 0.01. The atomic S/C ratios of the marine solid bitumen in the Yuanba and Puguang gas fields were both above 0.03, and the atomic N/C ratios were above 0.01. These results indicate that the marine solid bitumen was the co-result of TSR and TCA. However, the high reflectance (Rb > 2.5%) sulfur-rich solid bitumen showed that oil was involved in the TSR. Marine solid bitumen with higher atomic N/C ratios occurs because non-marine oils are expected to have lower nitrogen concentrations than marine oils (Tissot and Welte, 1984).

The carbon isotopic compositions of the calcite cements also show evidence for TSR. Calcite and dolomite grains are deposited in reservoirs during the reaction of heavy gas and methane with sulfates (R2 and R3) (Worden and Smalley, 1996; Heydari, 1997; Machel, 2001). Furthermore, organic carbon can be incorporated into calcite and/or dolomite cements, so the d13C values of these cements would be lighter (Heydari and Moore, 1989; Machel et al., 1995; Yang et al., 2001; Zhu et al., 2005). The d13C and d18O values of the calcite cements in the tight limestone were similar to those of the host limestone (Fig. 10), which implies that these calcite cements were not altered by TSR. Some of the calcite cements in the dolostone had d13C values that were similar to those of its host rock but also had lighter d18O values, which demonstrates that these calcite cements were deposited after dolomitization and probably before TSR. Other calcite cements in the dolostone had lower d13C (
15.36 to 3.5‰) and d18O (
8.33 to
5.83‰) values than their host rock (Fig. 10). These calcite cements, which had consistently lighter d13C values than the corresponding dolostone host rock, demonstrate that organic carbon was incorporated into the calcite cements during TSR and provide evidence of TSR. 5.2. Was methane involved in TSR? Whether methane can be a dominant organic reactant remains controversial because methane is the most stable hydrocarbon gas, although the reaction between methane and sulfates in the presence of sulfur and the production of H2S and CO2 can be observed at 250e340  C in the laboratory (Yuan et al., 2013). However, whether methane can be remarkably altered by TSR under geologic conditions remains unclear (Machel, 1998, 2001; Hao et al., 2008, 2015). Methane is stable under the investigated reaction conditions and is likely a product of TSR by other gaseous hydrocarbons rather than a significant reactant (Xia et al., 2014). Currently reported geological cases where methane-dominated TSR occurred include the Permian Khuff Formation in Abu Dhabi (Worden and Smalley, 1996;

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P. Li et al. / Marine and Petroleum Geology 75 (2016) 220e239

Fig. 6. Hydrogen sulfide (H2S) concentration (%) of natural gases in the gas pools of the first member (A) and second member (B) of the Changxing Formation (P2c) in the Yuanba gas field. GPW ¼ gas production well, NGPW ¼ non-gas production well, CLUPS ¼ contour line of the upper P2c surface (m).

Jenden et al., 2015) and T1f in China's Sichuan Basin (Cai et al., 2004). Hao et al. (2015) proposed that three conditions must be met for methane-dominated TSR to occur to a significant degree for in-situ thermal oil-cracking gas: (1) the reservoirs must have sufficiently high temperatures and sulfate concentrations to allow most C2þ hydrocarbons to be cracked or oxidized; (2) sufficient sulfates must still exist after most of the C2þ hydrocarbons are cracked or consumed; and (3) the reservoirs must remain at high temperatures for a long time after most of the C2þ hydrocarbons are

cracked or oxidized to allow methane-dominated TSR to occur to a significant degree. P2c's reservoirs in the Yuanba gas field meet the temperature requirement. According to the thermal history reconstruction for the Y2 well, P2c's reservoir temperature reached 140  C at 170 Ma during the Late Jurassic, increased to approximately 230  C at 100 Ma during the Late Cretaceous, and then decreased to the present 150e165  C range (Fig. 4). The lowest temperature for oil-involved TSR is 120e140  C, and gas-involved TSR occurs above 140  C

P. Li et al. / Marine and Petroleum Geology 75 (2016) 220e239

229

Fig. 7. Gas pool sections of the Changxing Formation (P2c) that show the gas composition, interpreted gas-water contact (GWC) and paleo-oil-water contact (POWC) in the Yuanba gas field. T1f ¼ Feixianguan Formation, P2c1 ¼ first member of P2c, P2c2 ¼ second member of P2c, HC ¼ hydrocarbons, Rd ¼ deep investigated double lateral resistivity log (ohm m), Den ¼ density (g/cm3). The well locations are shown in Fig. 6.

Fig. 8. Gas pool sections of the Changxing (P2c) and Feixianguan (T1f) Formations that show the gas compositions in the Puguang gas field. T1f1e3 ¼ first to third members of T1f, T1f4 ¼ fourth member of T1f, T1j ¼ Jialingjiang Formation, HC ¼ hydrocarbons.

(Heydari and Moore, 1989; Worden et al., 1995; Cai et al., 2004). Thus, we believe that this high temperature (>140  C) requirement was met to initiate TSR in the Yuanba gas field. In addition, the C2þ hydrocarbon concentrations of P2c's gases in the Yuanba gas field were generally below 0.23% (Table 1). However, judging whether

the relatively lower concentrations of C2þ hydrocarbons were the result of TSR or the thermal cracking of C2þ gas hydrocarbons is difficult. The temperature for oil cracking is approximately 150  C (Barker, 1990), which overlaps with the required temperature for TSR.

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P. Li et al. / Marine and Petroleum Geology 75 (2016) 220e239

Fig. 9. Photographs of typical calcite cements in vugs of limestone (AeC) and dolostone (DeH) in the Changxing formation (P2c) in the Yuanba gas field. (A) Y16 well, 6961.0 m; coarse calcite cements fully filled the vugs in the limestone. (B) Y122 well, 6800.4 m; coarse calcite cements partly filled the vugs in the limestone. (C) Y123 well, 6964.9 m; coarse calcite cements fully filled the vugs in the limestone. (D) Y11 well, 6912.1 m; coarse calcite cements in the dolostone. (EeG) Y224 well, 6636.6 m, 6636.1 m, and 6650.1 m, respectively; coarse calcite cements partly filled the vugs in the dolostone. (H) Y205 well, 6461.5 m; coarse calcite cements fully filled the vugs in the dolostone. L ¼ limestone, D ¼ dolostone, C ¼ calcite.

One sample (GSI of 0.1, d13C2 of
29.9‰) from the Y123 well obviously deviated from the increasing trend (Fig. 14). The sample (6904e6918 m) was close to an underlying gas-water layer (6925e6950 m). As mentioned earlier, the H2S and gas compositions of gases from gas-water layers cannot reflect the original composition. Thus, this sample cannot be adequately interpreted. Overall, the ethane d13C increased as the GSI increased (Fig. 14), so we consider that TSR contributed to the exhaustion of ethane. The key for methane-dominated TSR is whether the sulfate concentration is sufficient. The isotopic compositions of hydrocarbon gases can prove that methane-dominated TSR did not occur in the Yuanba gas field. No obvious increase in the methane d13C values was observed as the GSI increased (Fig. 14), which is different from the typical reported methane-dominated TSR in the Permian Khuff Formation in Abu Dhabi (Worden et al., 1996; Jenden et al., 2015). This observation indicates that ethane-dominated TSR occurred in the Yuanba gas field. However, the ethane d13C values increased as the GSI increased (Fig. 14), and the gas carbon isotope ratios between methane and ethane changed from reversed carbon isotope ratios to normal carbon isotope ratios as the GSI increased (Fig. 15), whereas T1f2's gas from the Y204 well, which had no H2S, exhibited a reversed carbon isotope ratio. In addition, the ethane d13C and d13C1
d13C2 values had a notable negative correlation (Fig. 16), which indicates that the ethane d13C value increased rapidly and the methane d13C value remained relatively stable. These features indicate that heavy hydrocarbon gases was involved in TSR and also validate the models by Hao et al. (2008) and Liu et al. (2013). According to the model (Liu et al., 2013) for the Sichuan Basin, the oil cracked to gas when the GSI was below 0.01 and d13C1 > d13C2,

while ethane-dominated TSR (initial TSR) occurred when the GSI was 0.01e0.1 and d13C1  d13C2, and methane-dominated TSR (advanced TSR) occurred when the GSI was above 0.1 and d13C1 < d13C2. The GSI values of P2c's gases in the Yuanba gas field were generally between 0.01 and 0.1 and d13C1  d13C2 (Table 2), which also indicate that methane-dominated TSR did not occur in the Yuanba gas field. In addition, the d13C values of the calcite cements provide evidence for limited ethane-dominated TSR. The d13C values of the calcite cements in porous dolostone ranged from
4.09‰ to þ4.56‰ (average of 2.28‰, except for the lowest value of
15.36‰) and were approximately 2.2‰ lighter than that of the dolostone host rock (þ3.18 to þ5.26‰, average of þ4.48‰, except for the lowest value of þ0.38‰). These calcite cements' d13C values were heavier than those that are typically reported for TSR calcite cements. For example, the d13C values of the calcite cements in the Jurassic Smackover Formation in the southeastern Mississippi salt basin range from
1.6 to
16.3‰ (Heydari and Moore, 1989); those in the Burnt Timber and Crossfield East gas fields in Alberta (Canada) range from
23.9 to
12.0‰ (Yang et al., 2001); and those in the Permian Khuff Formation in offshore Dubai (U.A.E.) were
28.5‰ (Videtich, 1994), reaching as low as
31.0‰ (Worden and Smalley, 1996). Zhu et al. (2005) also reported that the d13C values of calcite cement was as low as
18.2‰ in T1f in the northeastern Sichuan Basin. If ethane-dominated TSR occurred widely, the calcite cements' d13C values should be much lighter than the present values. This result supports that limited ethanedominated TSR occurred in the Yuanba gas field. Fresh water is produced during heavy hydrocarbon gas- or methane-dominated TSR according to R2 and R3. Whether a large

P. Li et al. / Marine and Petroleum Geology 75 (2016) 220e239 Table 3 Stable carbon and oxygen isotopes of limestone (L), dolostone (D), calcite cements in limestone (CL), and calcite cements in dolostone (CD) from the Yuanba gas field in the Sichuan Basin. Well

Strataa

Y11 Y11 Y11 Y11 Y11 Y11 Y11 Y122 Y122 Y123 Y123 Y123 Y123 Y123 Y16 Y16 Y205 Y205 Y221 Y224 Y224 Y224 Y224 Y224 Y224 Y224 Y224 Y224 Y273 Y273 Y28 Y28 Y9 Y9

1

P2c P2c1 P2c1 P2c1 P2c1 P2c1 P2c1 P2c1 P2c1 P2c2 P2c1 P2c1 P2c1 P2c1 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c2 P2c1 P2c1

Depth (m)

Sample type

dC13 (VPDB, ‰)b

dO18 (VPDB, ‰)

6832.52 6911.15 6911.50 6912.05 6913.75 6916.60 6916.75 6800.40 6800.40 6964.94 6988.16 6990.56 6992.36 7003.31 6958.50 6961.00 6461.50 6461.63 6688.30 6620.36 6632.11 6632.26 6636.11 6636.61 6636.61 6650.10 6650.10 6651.90 6826.50 6827.50 6807.44 6807.44 7067.65 7067.65

CL D D CD L CD CD CL L CL L CD D L D CL CD D L L D D CD CD D CD D CD D CD CD D CD D

3.07 4.93 5.16 3.49 4.08
15.36
0.06 2.28 2.79 3.64 4.13 4.56 3.59 3.55 5.26 3.10 2.44 3.18 4.12 3.78 4.71 4.82 3.82 3.31 4.81 2.49 5.16 4.26 3.50 2.41
4.09 0.38 2.45 4.15


6.39
5.33
4.79
5.61
5.40
5.87
5.83
5.64
5.48
6.84
5.81
6.16
6.34
6.12
5.51
5.28
7.73
5.28
5.74
5.83
4.99
3.88
6.39
6.37
3.96
5.64
3.71
6.46
4.62
8.33
7.70
7.07
5.82
4.24

a P2c1 ¼ first member of the Changxing Formation, P2c2 ¼ second member of the Changxing Formation. b VPDB ¼ Vienna Pee Dee Belemnite standard.

Fig. 10. Variation in d13C vs. d18O for the dolostone, limestone, and calcite cements in vugs from the Changxing Formation in the Yuanba gas field.

amount of water is produced is controversial (Machel, 2001; Yang et al., 2001; Hao et al., 2015), but evidence for fresh water production has been reported in several cases (Worden et al., 1996; Bildstein et al., 2001; Jiang et al., 2014). In particular, Worden

231

et al. (1996) reported that original formation water was diluted between four and five times by water from TSR. According to the reservoir water data in Table 4, the TDS in the Yuanba and Puguang gas fields (50e90 g/L), which have relatively higher H2S concentrations, is slightly lower than the TDS in the Jinan gas field (10e120 g/L), which has a relatively lower H2S concentration. Furthermore, no bottom water or edge water developed in some reservoirs with an H2S concentration above 5.0% in the Yuanba gas field, which implies that a large amount of water production during TSR and methane-dominated TSR did not occur in the Yuanba gas field. The above discussion proves that methane-dominated TSR did not occur; only oil-related and limited ethane-dominated TSR occurred in P2c's reservoirs in the Yuanba gas field, although the reservoirs met the required temperature for TSR and C2þ hydrocarbon gases had already been exhausted. The most probable reason is a lack of sufficiently dissolved sulfates. As shown in Table 4, the SO2
concentration was only 0e1.381 g/L in P2c's 4 reservoir water in the Yuanba gas field, only 0e1.474 g/L (typically below 1.000 g/L) in the reservoir water in the Puguang gas field, and 1.740e2.913 g/L in the Jiannan gas field, which exhibited low degrees of TSR (H2S commonly below 1.0%). The SO2
4 concentration that was used in the laboratory by Cross et al. (2004) was 3.250e4.250 g/L, which is much higher than the present SO2
4 concentration in the water in the Yuanba and Puguang gas fields. 5.3. Source of sulfates Sulfates are derived from anhydrite dissolution in most reported TSR geologic cases (Heydari and Moore, 1989; Worden and Smalley, 1996; Cai et al., 2004; Jenden et al., 2015). In addition, high H2S reservoirs (>10.0%) are usually adjacent to or interbedded within evaporitic rock (anhydrite layer) (Worden and Smalley, 1996; Heydari, 1997; Li et al., 2005). Other sulfate sources can facilitate TSR (Dixon and Davidson, 1996; Machel, 2001). Furthermore, sodium sulfate systems (Kiyosu and Krouse, 1993; Cross et al., 2004), magnesium sulfate systems (Pan et al., 2006; Ding et al., 2011; Zhang et al., 2012), and other systems can initiate TSR (Toland, 1960). Theoretically, TSR occurs if dissolved sulfates and hydrocarbons exist and meet under relatively high temperature (>140  C) conditions. The main sources of SO2
include seawater, buried 4 seawater, evaporated brines (pore water), and/or the dissolution of solid calcium (mainly gypsum and anhydrite) (Machel, 2001). TSR in P2c, T1f, and T1j in the northeastern Sichuan Basin has also been considered to be related to anhydrite (Cai et al., 2003; Li et al., 2005; Zhu et al., 2007). In fact, the anhydrite layers in T1f mainly developed in the eastern evaporated platform (Fig. 3B), and rare anhydrites were found in P2c (Li et al., 2014). Thus, we suspect that anhydrite is a prerequisite for TSR. Anhydrite was not observed in P2c in the Yuanba gas field because the reef and shoals in P2c developed in a warm and wet environment. The lateral distance from the eastern evaporated platform is greater than 100 km (Fig. 3B), and the vertical distance from the overlying anhydrite layers in T1j is 400e600 m (Fig. 2). Furthermore, approximately 200 m of tight limestone developed at the bottom of T1f, and no faults connect the anhydrite layers with P2c's reservoirs (Li et al., 2015a). We propose that anhydrite is not a prerequisite for TSR and that sulfates that are dissolved in reservoir water can initiate TSR. A practical phenomenon may explain the sulfate source in the Sichuan Basin. Almost all the reservoirs with relatively high H2S concentrations (>5.0%) developed in dolostone, for example, Puguang, Yuanba, Longgang, Xinglongchang, Luojiazhai, Tieshanpo, etc. (Fig. 17); that is to say, the sulfate that was required for TSR was most likely related to regional dolomitization (Li et al., 2014). The

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P. Li et al. / Marine and Petroleum Geology 75 (2016) 220e239

Table 4 Main cation and anion concentrations of reservoir water from the Puguang (PG), Yuanba (YB), and Jiannan (JN) gas fields in the Sichuan Basin. Gas field

PG PG PG PG PG PG PG PG YB YB YB YB YB YB JN JN JN JN JN a b c d

Well

PG8 PG8 PG9 PG9 PG10 PG10 PG3 PG3 Y123 Y123 Y9 Y9 Y16 Y224 J26 J26 J47 J47 XD1

Strataa

P2c P2c P2c P2c T1f T1f T1f T1f P2c P2c P2c P2c P2c P2c T1f T1f P2c T1f T1f

Depth (m)

5614e5625 5634e5643 6151e6175 6110e6130 6250e6270 6193e6202 5448e5469 5423e5443 6978e6986 6904e6918 6836e6857 7000e7020 6950e6974 6625e6636 3291e3329 3291e3329 3976e3986 3614e3643 3254e3263

Anion (g/L)b

Cation (g/L) Naþ þ Kþ

Ca2þ

Mg2þ

Cl


SO2
4

CO2
3

HCO
3

26.296 29.080 18.813 5.838 22.556 19.126 17.156 28.306 19.316 18.795 12.540 23.884 19.569 18.701 21.468 18.409 46.687 39.993 44.219

1.253 3.074 0.636 13.202 0.572 0.568 0.668 2.010 0.643 5.411 6.311 1.152 0.615 0.606 16.157 17.489 0.387 6.669 9.209

0.244 0.029 0.030 5.487 0.083 0.143 0.028 0.083 0.051 0.984 2.112 0.140 0.168 0.050 1.019 1.416 0.061 0.630 2.525

40.284 47.827 26.139 46.287 31.346 27.334 21.900 30.300 28.167 39.693 37.598 36.198 31.316 27.544 61.291 62.186 69.161 73.243 90.260

0.567 0 0.938 0 1.474 0.204 0.224 0.220 ND 0 ND 1.381 0.576 ND 4.064 1.487 2.913 1.740 1.728

1.166 1.079 1.342 ND ND 2.372 ND ND ND ND ND ND ND ND ND ND ND ND ND

2.372 2.135 3.084 3.559 6.176 1.059 ND ND ND 2.959 ND 3.514 ND ND 0.604 0.268 2.501 1.305 0.473

TDSc (g/L)

Water type

pH

H2S (%)

DWPd (m3)

72.182 83.224 50.982 74.373 62.207 50.806 39.800 60.900 47.555 67.842 58.561 66.269 52.245 46.901 104.603 101.255 121.778 123.580 148.414

Na2SO4 CaCl2 NaHCO3 CaCl2 NaHCO3 NaHCO3 NaHCO3 NaHCO3 CaCl2 CaCl2 CaCl2 Na2SO4 CaCl2 MgCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2

9.0 8.5 9.0 7.0 8.0 8.5 ND ND ND 8.1 ND 7.6 7.1 ND 6.0 6.0 ND ND ND

ND 14.6 ND 14.6 ND ND 58.34 49.66 25.7 4.09 12.11 ND 12.16 10.61 3.788 3.788 0.073 0.278 2.16

6.1 11.4 23.8 10.9 55.7 8.1 393.2 23.2 ND 290.0 2.6 30.9 19.7 21.6 ND ND 2.3 22.2 9.6

P2c ¼ Changxing Formation, T1f ¼ Feixianguan Formation. ND ¼ no data. TDS ¼ total dissolved solids. DWP ¼ Daily Water Production.

sulfates were enriched during dolomitic processes, as was the magnesium concentration. This magnesium sulfate system is favorable for TSR (Zhang et al., 2008b; Lu et al., 2011) because Mg2þ can promote the formation of contact ion pairs that are favorable for TSR (Ma et al., 2008; Tang et al., 2009; Zhang et al., 2012). This phenomenon can explain the close relationship between dolostone and reservoirs with high H2S concentrations. H2S mainly developed in porous dolostone reservoirs in P2c, whereas no H2S developed in limestone reservoirs in T1f in the Yuanba gas field, which also support this explanation. As shown in Table 4, the H2S concentrations in the Yuanba and Puguang gas fields were much higher than that in the Jiannan gas field, but the SO2
4 concentrations were much lower than that in the Jiannan gas field. This result indicates that the formation of H2S was 2
based on SO2
4 depletion. If all the SO4 in the water is transformed into H2S during TSR, the H2S concentration can be calculated by using the mass balance method. The mole number of SO2
4 (n) and the H2S concentrations (m) under standard conditions can be calculated as follows:

n ¼ ðV  P  Sw  M  1000Þ=ð96  1000Þ

(R4)

m ¼ ð22:4  nÞ=½V  P  ð1
Sw Þ  1000

(R5)

where V, P, Sw, and M are the rock volume, porosity, water saturation, and SO2
4 concentrations in water, respectively. The porosity from this study's core testing was approximately 10%. The water saturation in the gas zone was 10e20% (Fig. 11), so we consider that the water saturation in the paleo-oil zone was close to 20%. The present SO2
4 concentrations were approximately 1.5e4.0 g/L, while the H2S concentrations were generally below 5.0% (limited TSR) in the Jiannan gas field, so the original SO2
4 concentrations could be considered to range between 1.5 and 4.0 g/L. Thus, the calculated H2S concentrations ranged between 8.8% and 23.3%. In fact, some sulfur would have been incorporated into solid bitumen, which can be verified by the presence of sulfur-rich bitumen, and TSR would not have occurred if the SO2
4 concentration in the water was too low. The theoretical calculated H2S concentration reached a maximum value. However, the actual calculated H2S concentration

(8.8e23.3%) was close to the H2S concentration (1.20e12.16%) in P2c in the Yuanba gas field, which indicates that enriched SO2
4 during dolomitization can initiate TSR and produce a certain amount of H2S. Enriched sulfates in dolomitic processes have three main sources: the eastern evaporated platform in T1f, the overlying anhydrite layers in T1j, and condensed burial sea water. Although these sulfates can initiate TSR, the relative extent of TSR may be different, i.e., whether sufficient sulfates were present to ensure that TSR progressed and methane-dominated TSR occurred widely. At present, T1f in the eastern platform margin, which is adjacent to the evaporated platform, has a remarkably higher H2S concentration (5.0e2.0%) compared to other locations (Fig. 17) because the evaporated platform could have supplied sulfates to ensure that TSR progressed gradually, whereas only limited TSR (not methanedominated TSR in most cases) occurred in other reservoirs because no extra sulfates were added to the reservoir water during TSR reactions. Compared to the Permian Khuff Formation in Abu Dhabi, the burial depth of P2c's reservoirs in the Yuanba gas field is greater, while the present temperatures (140e160  C) are similar. The main difference is that the Khuff Formation is adjacent to anhydrite layers, and anhydrite nodules can be observed in the reservoirs (Worden and Smalley, 1996) that could have supplied sufficient sulfates for TSR; the H2S concentration here reaches 34.63% (Worden et al., 1995) and 38.0% (Videtich, 1994). In addition, the Jurassic Smackover Formation in Black Creek Field (Mississippi) is adjacent to anhydrite layers, and the H2S concentration here reaches 78% (Heydari, 1997). The H2S concentrations in these locations are remarkably higher than those in the Yuanba gas field. Based on the above discussion, the key explanation for non-methanedominated TSR in the Yuanba gas field and limited methanedominated TSR in the Puguang gas field is a lack of sufficient sulfates in the reservoirs (the current SO2
4 concentrations are below 1.0 g/L, or no SO2
4 is present). This reason may also explain why the H2S concentration in the northeastern Sichuan Basin is remarkably lower than the H2S concentration in other locations where TSR has occurred widely.

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Fig. 12. Variations in the CO2, H2S and gas souring index (GSI) of natural gases in the Yuanba gas field. P2c ¼ Changxing Formation, T1f2 ¼ second member of the Feixianguan Formation. Fig. 11. Variations in the porosity and water saturation in the Yuanba gas field (A) and Puguang gas field (B). T1f ¼ Feixianguan Formation, P2c ¼ Changxing Formation.

5.4. Controlling factors on the distribution of H2S The variation in H2S concentrations between the different gas reservoirs in the Yuanba gas field indicates that TSR occurred to various extents (Fig. 6). What is the cause of these differences in H2S concentration between different reservoirs and even within a single reservoir? TSR is a reaction between hydrocarbons and dissolved sulfates (Machel et al., 1995; Worden et al., 1996, 2000; Bildstein et al., 2001). In other words, TSR cannot occur between solid sulfates and hydrocarbons. Almost all laboratory experiments have been performed by using aqueous sulfates to initiate TSR (e.g., Kiyosu, 1980; Cross et al., 2004; Zhang et al., 2012; Yuan et al., 2013), and TSR did not occur with solid sulfates even at 420  C (Lu et al., 2010). Therefore, water is an essential media for TSR. TSR is suggested to occur in gas-water contact zones because these areas can dissolve sufficient hydrocarbons and sulfates for TSR (Machel et al., 1995; Machel, 1998; Bildstein et al., 2001), and TSR is also believed to occur in pure gas zones because a water film can form on anhydrite surfaces and dissolve anhydrites and hydrocarbons (Worden et al., 2000; Cai et al., 2004). In addition, methane-dominated TSR can produce fresh water, which can reduce the water salinity and dissolve more methane, thus promoting TSR (Worden et al., 1996).

If no gas-water contacts are present, TSR can only occur when the residual water saturation in the gas zones is sufficient to dissolve anhydrites (Machel, 2001). The reservoir water saturation was 10e20% (locally as high as 40%) in the Yuanba gas field and 5e20% in the Puguang gas field (Fig. 11). In addition, some reservoir water may be partly squeezed out because of over-pressure from oil cracking. Therefore, the water saturation can be above 20% when oil accumulates, which implies that considerable water is present in pure oil zones or gas zones to promote TSR. The sulfates that are required for TSR include enriched SO2
4 during dolomitization. As discussed in Section 5.3, the residual water in oil reservoirs can initiate TSR and produce certain amounts of H2S. As shown in Fig. 18, no H2S developed in P2c in the Y209 well or in T1f in the Y204 well, which supports that SO2
4 was related to dolomitization. In addition, the H2S concentration may also be related to the portion of the trap filled by paleo-oil. The solid bitumen in the Yuanba gas field is usually above 1.0% in the paleo-oil zone and below 1.0% in the water zone (porosity above 2.6%) (Li et al., 2015a). Therefore, paleo-oil-water contacts and the portion of the traps that are filled by paleo-oil can be distinguished by systematic solid bitumen quantification. No paleo-oil-water contacts developed in the Y2 well (Fig. 18A), whereas a paleo-oil-water contact developed in the Y123 and Y224 wells at 6949 m and 6651 m, respectively (Fig. 18BeC). In addition, no paleo-oil-water contacts were detected in the Y273, Y101, Y102, and Y104 wells, which indicate the portion

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Fig. 13. Variations in ln (C1/C2) with the gas souring index (GSI) of natural gases from the Changxing Formation (P2c) and the second member of the Feixianguan Formation (T1f2) in the Yuanba gas field.

Fig. 14. Variations in the methane carbon isotopes (d13C1) and ethane carbon isotopes (d13C2) with the gas souring index (GSI) of natural gases from the Changxing Formation (P2c) and the second member of the Feixianguan Formation (T1f2) in the Yuanba gas field.

Fig. 15. Variations in the difference between methane carbon isotopes and ethane carbon isotopes (d13C1ed13C2) with the gas souring index (GSI) of natural gases from the Changxing Formation (P2c) and the second member of the Feixianguan Formation (T1f2) in the Yuanba gas field.

Fig. 16. Variations in the difference between methane carbon isotopes and ethane carbon isotopes (d13C1ed13C2) with the ethane carbon isotopes (d13C2) of natural gases from the Changxing Formation (P2c) and the second member of the Feixianguan Formation (T1f2) in the Yuanba gas field.

of the trap filled by paleo-oil were large. According to a paleostructure reconstruction (Li et al., 2015a, their Fig. 7B), these wells with large portion of the traps that were filled by paleo-oil were at relatively higher positions, and the Y224 and Y123 wells were at relatively lower positions when oil accumulated in the Yuanba gas field. In addition, the Y12 and Y124-c1 wells were at relatively lower positions. Although no systematic solid bitumen data could be collected from the two wells, a paleo-oil-water contact most likely developed in the trap. No obvious positive relationship could be observed between the concentration and the thickness of the dolostone reservoir (Fig. 19). The H2S concentration of gas from the paleo-oil zone was generally below 8.0%, whereas the H2S concentration of gas from a paleo-oil zone with an oilwater contact and from a paleo-oil zone with a probable oilwater contact was above 8.0% in the Yuanba gas field. These reservoirs experienced similar thermal histories, so the difference in H2S concentrations between these reservoirs is probably related to 2
the quantity of SO2
4 . The SO4 that was required for TSR mainly existed in residual water in pure oil reservoirs, whereas SO2
4 from bottom water could have also been involved in TSR in reservoirs with paleo-oil-water contacts because TSR is more favorable in oilwater or gas-water contact zones (Machel et al., 1995; Machel, 1998; Bildstein et al., 2001). This phenomenon explains the great difference in H2S concentrations between different reservoirs. Actually, the quantity of SO2
4 controls the H2S concentration (the extent of TSR). The differences in H2S concentrations in a single reservoir may be caused by gravitational differentiation from structural adjustment during late uplift. As discussed in Section 5.2, the H2S was mainly produced during oil-involved and limited heavy hydrocarbon gas-dominated TSR. According to the burial and thermal history (Fig. 4), the maximum reservoir burial depth and temperature reached approximately 8000 m and 240  C, respectively. The reservoir oil began to crack at 150e160  C (Barker, 1990; Isaksen, 2004; Tian et al., 2008) and completely cracked into gas at approximately 210  C (Tian et al., 2008). Therefore, TSR should have occurred before late uplift in the Yuanba gas field. According to a paleo-structural reconstruction, remarkable uplift occurred in the northwest and an anticline developed in the Yuanba gas field (Li et al., 2015a). This structural adjustment must have caused the gas to re-migrate and accumulate in the reservoir. The molecular weight of H2S is much heavier than that of the hydrocarbon gases

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Fig. 17. H2S concentrations of T1f and P2c's gases in the main gas fields in the northern and eastern Sichuan Basin. The data for the Puguang (PG) gases are from Hao et al. (2008), that for the Yuanba (YB) gases are from Li et al. (2015a), that for the Jiannan (JN) gases are from Li et al. (2015b), that for the Longgang (LG) gases are from Du et al. (2010), that for the Maoba (MB) gases are from Liu et al. (2013), and that for other gases are from Cai et al. (2004) and Zhu et al. (2005).

(methane and ethane) in the reservoir. Consequently, H2S is more likely to accumulate in lower positions in reservoirs, which can create differences in the H2S concentration in a single reservoir. For example, the concentration increased from 5.14% and 5.20% to 5.59% in the Y27, Y271, and Y273 wells, respectively (Fig. 7). No gaswater or paleo-oil-water contacts (traps that were fully filled by paleo-oil) developed in the reservoir. The fact that the H2S concentration was higher at relatively lower positions may not be related to oil (gas)-water contacts. In addition, the current SO2
4 concentration in the water zone is low and cannot initiate TSR (discussed in Section 5.2). Thus, the gravitational differentiation during the late uplift since 100 Ma during the Late Cretaceous most likely caused the different H2S concentrations in single reservoirs. The Puguang gas field exhibits similar properties. The southwestern Puguang gas field was a relatively high position that formed during late uplift (Du et al., 2009), and the H2S concentrations in the southwestern position (e.g., PG6 and PG2 wells) were also lower than that at lower positions (e.g., PG4 and PG101 wells) in the northeastern area (Fig. 8). Even in the PG6 and PG2 wells, the H2S concentration increased as the burial depth increased. 5.5. Origin of CO2 The roughly positive correlation between H2S and CO2 (Fig. 12A) implies their similar origin. As discussed in Section 5.1, the H2S in P2c in the Yuanba gas field was mainly derived from TSR. Therefore, the CO2 in P2c should also have a close relationship with TSR. CO2 that oxidizes from hydrocarbons is always depleted in d13C. For example, the CO2 d13C values decrease from
9‰ to
15‰ as TSR gradually progresses (Worden and Smalley, 1996), reaching as low as
28.0‰ in the Khuff Formation in Saudi Arabia (Jenden et al., 2015) and as low as
29.0‰ in the Foothill regions in western Alberta, Canada (Krouse et al., 1988). However, the CO2 d13C values

only ranged from
3.9‰ to
0.7‰ in P2c in the Yuanba gas field (Fig. 20), which is remarkably heavier than the anticipated values. This CO2 should be considered inorganic in origin according to the classification of Dai et al. (1996). However, these CO2 d13C values are much lighter than the d13C values of dolostone and limestone host rock (2.5e5.5‰), which indicates that organic carbon was incorporated into the CO2 during TSR. This process can be verified by the roughly positive correlation between H2S and CO2. Relatively heavy CO2 d13C values may be related to rebalance between CO2 and inorganic fluid systems. The CO2 d13C values increased slightly as the GSI increased (Fig. 20). Hao et al. (2015) explained that relatively heavy CO2 d13C values result from 12C that is preferentially deposited in calcite, and residual enriched 13C is rebalanced within inorganic fluid systems during TSR. Similar explanations have been proposed for relatively heavy CO2 d13C values (Krouse et al., 1988; Mankiewicz et al., 2009). Thus, the CO2 d13C values will be close to the d13C values of corresponding carbonate host rock. Relatively heavy CO2 d13C values may also be related to carbonate dissolution. Carbonate dissolution occurs during late uplift as the fluid system would be unsaturated in carbonate because of decreases in the reservoir's temperature and pressure (Huang et al., 2010). CO2 that is enriched in d13C may result from carbonate dissolution during late uplift. However, the water saturation in the gas zone was approximately 10% in the Yuanba gas field (Fig. 14A). In addition, a closed system does not favor deep burial carbonate dissolution (Hao et al., 2015). Therefore, we consider that carbonate dissolution during late uplift was quite limited and may not have significantly contributed to the CO2 in the Yuanba gas field. In addition, CO2 that was derived from the thermal decomposition of carbonates may have contributed to the relatively heavy d13C values. TSR did not occur in T1f2 in the Y204 well because the H2S concentration was as low as 0.003% (Table 2). However, the CO2

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Fig. 18. Distribution of solid bitumens in the Changxing Formation (P2c) in the Y2 well (A), Y123 well (B), and Y224 well (C), which shows the interpreted gas-water contact (GWC) and paleo-oil-water contact (POWC). SB ¼ solid bitumen content, POL ¼ paleo-oil layer, POB ¼ paleo-oil bottom, Rd ¼ deep investigated double lateral resistivity log (ohm.m), Rs ¼ shallow investigated double lateral resistivity log (ohm.m). P2c1 ¼ first member of P2c, P2c2 ¼ second member of P2c. Fig. 6 shows the well locations.

Fig. 19. Variations in the H2S concentration and thickness of dolostone in the Yuanba gas field. POZ ¼ paleo-oil zone, POZWC ¼ paleo-oil zone with an oil-water contact, POZPOWC ¼ paleo-oil zone with a probable oil-water contact.

concentration was 2.54% and the CO2 d13C value was
0.6‰, which is heavier than the values of P2c's gases (
3.9 to
0.7‰). The CO2 in T1f2 was probably derived from the thermal decomposition of carbonates as the reservoir experienced a maximum temperature of approximately 240  C (Fig. 4). A similar phenomenon occurred in

Fig. 20. Variations in CO2 carbon isotopes with the gas souring index (GSI) of natural gases from the Changxing Formation (P2c) and the second member of the Feixianguan Formation (T1f2) in the Yuanba gas field.

the Permian carbonate reservoir of the NW-German Basin, in which the carbonate reservoir rocks reached a maximum temperature from 200 to 250  C, and the d13C-enriched CO2 could most likely be attributed to carbonate decomposition from 100 to 150  C (Fischer et al., 2006). P2c's reservoir in the Yuanba gas field has a similar thermal history and even a higher temperature. Thus, the thermal

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decomposition of carbonates could have also contributed to the CO2 in P2c. Many gas reservoirs have high CO2 concentrations and d13C values, which indicate the thermal decomposition of carbonates (Whycherley et al., 1999). In summary, we propose that P2c's CO2 is the co-result of TSR, its related balance between CO2 and inorganic fluid systems, and carbonate thermal decomposition according to the roughly positive correlation between CO2 and H2S, the relatively heavy CO2 d13C values, and the high thermal history (maximum temperature of approximately 240  C). 6. Conclusions The following conclusions can be drawn based on the present study. (1) The H2S concentration (1.20e12.16%), sulfur-rich solid bitumen (atomic H/C ratios > 0.03), and calcite cements with lighter d13C values than those of the dolostone host rock prove that the H2S originated from TSR and that oil-involved TSR occurred in the Yuanba gas field. (2) No obvious increase in the d13C1 values was observed with increasing GSI, which indicates that methane-dominated TSR did not occur. The increase in d13C2 values with increasing GSI and the good negative correlation between the d13C2 and d13C1ed13C2 values indicate that heavy hydrocarbon gasdominated TSR occurred. However, the calcite cements' d13C values (
15.36‰ to þ4.56‰) in dolostone were heavier than the reported TSR calcite cements and the GSI was generally below 0.1, which implies that only limited heavy hydrocarbon gas-dominated TSR occurred. (3) The sulfates that were required for TSR in P2c in the Yuanba gas field mainly included enriched SO2
4 during dolomitization. Insufficient sulfates most likely prevented methanedominated TSR from occurring in the Yuanba gas field, and the H2S concentration in the northeastern Sichuan Basin was remarkably lower than that in the Khuff Formation in Abu Dhabi and the Smackover Formation in Mississippi. (4) The H2S concentration is controlled by dolomitization and the quantity of SO2
4 . H2S mainly develops in dolostone reservoirs. Except for the SO2
4 in residual water in the paleo-oil zone, SO2
4 from bottom water can also be involved in TSR, so oil reservoirs with bottom water have more SO2
4 and can produce more H2S than pure oil reservoirs. This phenomenon may explain the great differences in H2S concentrations between reservoirs. Gravitational differentiation during late uplift most likely creates differences in H2S concentrations in a single reservoir, and the H2S concentration is higher at relatively lower positions. (5) The d13C values of CO2 (
3.9 to
0.3‰) were remarkably heavier than those of hydrocarbon gases, and CO2 may have been a co-result of TSR, its related balance between CO2 and inorganic fluid systems, and the thermal decomposition of carbonates. Acknowledgments This study was supported by the National Natural Science Foundation of China (41103020, U1663210) and Science Foundation of the China University of Petroleum, Beijing (KYJJ2012-01-07). We acknowledge the support that was provided by Tonglou Guo, Xiaoyue Fu, Renchun Huang, and Jinbao Duan from the SINOPEC Exploration Company. Special thanks are given to the associate editor Daniel S Alessi and two anonymous reviewers for their critical and constructive reviews, which greatly improved the

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