Thermochemical sulphate reduction and the generation of hydrogen sulphide and thiols (mercaptans) in Triassic carbonate reservoirs from the Sichuan Basin, China

Chemical Geology 202 (2003) 39 – 57 www.elsevier.com/locate/chemgeo

Thermochemical sulphate reduction and the generation of hydrogen sulphide and thiols (mercaptans) in Triassic carbonate reservoirs from the Sichuan Basin, China Chunfang Cai a,b, Richard H. Worden b,*, Simon H. Bottrell c, Lansheng Wang d, Chanchun Yang a a Institute of Geology and Geophysics, CAS, PO Box 9825, Beijing 100029, PR China Jane Herdman Laboratories, Department of Earth Sciences, University of Liverpool, 4 Brownlow Street, Liverpool L69 3GP, UK c School of Earth Sciences, University of Leeds, Leeds LS2 9JT, UK d Petroleum Exploration and Development Institute, Southwest Sichuan Petroleum Corporation, Chengdu, Sichuan Province, PR China b

Received 29 July 2002; accepted 20 June 2003

Abstract The Sichuan Basin in China is a sour petroleum province. In order to assess the origin of H2S and other sulphur compounds as well as the cause of petroleum alteration, data on H2S, thiophene and thiol concentrations and gas stable isotopes (d34S and d13C) have been collected for predominantly gas phase petroleum samples from Jurassic, Triassic, Permian and Upper Proterozoic (Sinian) reservoirs. The highest H2S concentrations (up to 32%) are found in Lower Triassic, anhydrite-rich carbonate reservoirs in the Wolonghe Field where the temperature has reached >130 jC. d34S values of the H2S in the Wolonghe Triassic reservoirs range from + 22 to + 31xand are close to those of Triassic evaporitic sulphate from South China. All the evidence suggests that the H2S was generated by thermochemical sulphate reduction (TSR) locally within Triassic reservoirs. In the Triassic Wolonghe Field, both methane and ethane seem to be involved in thermochemical sulphate reduction since their d13C values become less negative as TSR proceeds. Thiol concentrations correlate positively with H2S in the Triassic Wolonghe gas field, suggesting that thiol production is associated with TSR. In contrast, elevated thiophene concentrations are only found in Jurassic reservoirs in association with liquid phase petroleum generated from sulphur-poor source rocks. This may suggest that thiophene compounds have not come from a source rock or cracked petroleum. Rather they may have been generated by reaction between localized concentrations of H2S and liquid range petroleum compounds in the reservoir. However, in the basin, thiophene concentrations decrease with increasing vitrinite reflectance suggesting that source maturity (rather than source type) may also be a major control on thiophene concentration. D 2003 Elsevier B.V. All rights reserved. Keywords: H2S; Thermochemical sulphate reduction; Thiophenes; Thiols; Mercaptans; Stable isotopes; Natural gas; Sichuan Basin

1. Introduction * Corresponding author. Tel.: +44-151-794-5184; fax: +44-151794-5196. E-mail address: [email protected] (R.H. Worden). 0009-2541/$ - see front matter D 2003 Elsevier B.V. All rights reserved. doi:10.1016/S0009-2541(03)00209-2

Elevated H2S concentrations (sour gas) have been found in many deep carbonate gas reservoirs around the world. The H2S is thought to originate from

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thermochemical sulphate reduction (TSR); a process whereby sulphate minerals and petroleum react together (e.g., Orr, 1977; Krouse et al., 1988; Sassen, 1988; Worden et al., 1995; Machel et al., 1995; Heydari, 1997; Cai et al., 2001). Thermochemical sulphate reduction has been studied extensively by examining H2S contents, and the sulphur and carbon isotopic compositions of various gas phase compounds. Other sulphur-bearing compounds in sour petroleum are only infrequently documented in geochemical studies, although a great number of sulphur compounds have been reported in petroleum and source rocks (e.g., Hughes, 1984; Orr and Sinninghe Damste´, 1990; Sinninghe Damste´ et al., 1990). Light hydrocarbon gases, condensates and gasoline range petroleum have been shown to be involved in TSR (Krouse et al., 1988; Rooney, 1995; Worden and Smalley, 1996; Whiticar and Snowdon, 1999) although there are some who still consider that light hydrocarbons in general, and methane in particular, are relatively unreactive during TSR (Machel, 2001). Sour gas has been reported in reservoirs from the Upper Proterozoic (Sinian) through to the Jurassic in the Sichuan Basin, China (Sheng et al., 1982; Dai, 1986; Huang et al., 1995; Korsch et al., 1991; Wang, 1994; Sheng et al., 1997). However, H2S concentrations >10% have been found only in the Lower and Middle Triassic carbonates and evaporites. d34S values of the H2S are about + 25x (Sheng et al., 1997), significantly more positive than those of Triassic seawater sulphates reported by Claypool et al. (1980). From water chemistry and stable isotope data, both water- and petroleum-bearing Lower and Middle Triassic carbonate rocks are thought to be relatively closed systems, with the saline formation waters being a residue following evaporite precipitation (Zhou et al., 1997). In this paper, we present data on the concentrations of the sulphur-bearing organic compounds, thiophenes and thiols (also known as mercaptans), as well as H2S from the Sichuan Basin and explore relationships between their occurrence and TSR. We provide data from a Triassic gas field (Wolonghe) in the eastern part of the Sichuan Basin to address the origin of 34S-enriched H2S and the mechanism of TSR.

2. Geological setting The Sichuan Basin in southwest China (Fig. 1a) is a large, intracratonic basin with an area of about 230,000 km2. A west – east cross section is shown in Fig. 1b. The basement is Proterozoic continental crust. The Sichuan Basin represents one of China’s largest natural gas provinces with gas found in Jurassic, Triassic, Permian, Carboniferous and Upper Proterozoic (Sinian) strata, and oil produced locally from Jurassic strata (e.g., Li et al., 1994). Three large-scale gas fields (reserves >300
108 m3) and seventeen medium-scale gas fields (>50
108 but < 300
108 m3) have been found in the basin (Li, 1996). Marine sedimentation dominated in the Sichuan Basin from the Upper Sinian to the Middle Triassic. The Upper Sinian to Silurian sequence is composed of 2000 – 4000 m of shallow marine carbonates, and black shale, with limited anhydrite in the Upper Sinian and Cambrian (Fig. 2). Marine sedimentation was interrupted during the late Silurian Caledonian Orogeny when the Sichuan Basin was uplifted and exposed, resulting in minimal Devonian deposition (Fig. 1b). Middle Carboniferous sedimentation was limited to the eastern part of the Sichuan Basin. Middle Carboniferous anhydrite was found only near the Dachuan area, to the north of Linshui County and the west of Kaijiang County (Fig. 1; Lu et al., 1996). Following the Caledonian Orogeny, marine transgression occurred during the earliest Permian. The Lower Permian is composed of platform carbonates with a typical thickness of 300– 500 m. Submarine basalt eruption occurred at the end of the Lower Permian. The Upper Permian is composed of platform carbonates with alternating marine and terrestrial coalbearing strata. The Lower and Middle Triassic sequence is divided into Feixianguan (T1f), Jialingjiang (T1j) and Leikoupo Formations (T2l), and is composed predominantly of platform carbonates and evaporites (Fig. 2). Little anhydrite occurs in the Feixianguan Formation in the whole basin (Lan et al., 1995) except in the northeast part of the East Sichuan Basin (Yang et al., 1999), in contrast to thick, basin-wide anhydrite beds in the Jialingjiang and Leikoupo Formations. The Jialingjiang Formation includes five members. The Second, Fourth and Fifth Members contain 2- to 4-m-

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41

D

Fig. 1. Map showing (a) distribution of gas fields, (b) cross section of Wolonghe Field (modified from Tong, 1992; Li, 1996; Xu et al., 1998).

thick anhydrite beds, but the First and Third Members contain little anhydrite (Tian and Wei, 1985). As a result of the Yinzi Orogeny between the Middle and Upper Triassic, the Sichuan Basin was uplifted and exposed. Upper Triassic sediments are freshwater lacustrine –alluvial clastics with local coal beds. Jurassic and Cretaceous sediments are com-

posed of continental red sandstones, mudstones and black shale with a thickness of 2000– 5000 m (Huang et al., 1995). The basin acquired its present structure after the Neogene Himalayan Orogeny. The burial and geothermal history of Well Zuo 1 in the East Sichuan Basin (Figs. 1a and 3) shows that rapid sedimentation took place during the Lower Triassic, Middle and

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Fig. 2. Generalised stratigraphic column for the Sichuan Basin showing complex petroleum systems. Basin-scale anhydrite beds occur in the Lower and Middle Triassic while Sinian, Cambrian and Carboniferous strata contain anhydrite in local areas.

Upper Jurassic and that the Lower Triassic experienced a maximum burial rate, and had the highest palaeo-temperature (>130 jC), at the end of Cretaceous (Fig. 3). Significant uplifts occurred at the end of the Middle Triassic and during the Tertiary. Petroleum system analysis reveals that there are numerous potential source rocks, reservoirs and caprocks in the Sichuan Basin (Fig. 2; Table 1). Sinian to Middle Triassic reservoirs are predominantly carbonate while Upper Triassic and Jurassic reservoirs are mainly siliciclastic. The source rocks are commonly specific to reservoir horizons (Table 1); for example,

natural gas in the Sinian strata of the Weiyuan Field is considered to have been generated in Lower Cambrian source rocks while Carboniferous reservoirs have gas derived from Lower Silurian black shale (Huang et al., 1995, 1997; Song et al., 1997). In contrast, gas in Lower Permian reservoirs is considered to have a mixed origin from both Lower Permian carbonate and Upper Permian coal source rocks (Huang et al., 1995). Gas in Lower Triassic reservoirs is thought to have been generated from Triassic carbonate source rocks (e.g., Zhang et al., 1991; Dai et al., 1997) while gas in the Middle Triassic in the Moxi Field is thought

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3. Sampling and methods

Fig. 3. Diagram showing a typical burial and palaeo-temperature history constructed from Well Zuo 1 in the East Sichuan Basin. Isotherms are constrained by vitrinite reflectance and fluid inclusion measurements (modified from Wang et al., 1998).

to have an Upper Permian coal source (e.g., Huang et al., 1997). The Upper Triassic of the Zhongba Field has gas from Upper Triassic coal. Oil and gas in Jurassic reservoirs are considered to have a sulphurpoor Jurassic lacustrine source (Sheng et al., 1991; Zhang et al., 1991; Li et al., 1994; Wang, 1994; Huang et al., 1997).

Gas geochemistry data and concentrations of H2S dissolved in water have been collated from proprietary reports from the Sichuan Petroleum Bureau from 1965 through to the present (Table 2; Fig. 4). Petroleum and gas samples were collected and analysed using standard industry techniques. The concentrations of thiophene and thiol compounds as well as hydrocarbon gas d13C values have been integrated from data presented by Wang (1994), Huang (1990), Huang et al. (1995) and Xu et al. (1998). H2S-bearing natural gas samples from the Triassic Moxi and Wolonghe gas fields were bubbled slowly through a solution containing excess Zn acetate to precipitate ZnS at the well-head. In the laboratory at the School of Earth Sciences, Leeds University, UK, ZnS was transformed to CuS by adding HCl and passing the evolved H2S through CuCl2 solution at a pH of 4. SO2 gas for sulphur isotope analysis was produced by combustion of a mixture of the CuS and Cu2O at 1070 jC in a vacuum (Robinson and Kusakabe, 1975). The SO2 was cryogenically purified and analysed on a VG SIRA10 gas source isotope ratio mass spectrometer. Raw data were corrected using standard techniques (e.g., Craig, 1957) and reported relative to the V-CDT standard. Replicate analyses of

Table 1 Reservoir units with their interpreted source rock types, maturities and ages Reservoir

Symbol

Petroleum type

Source type

Regional vitrinite Ro, %

Source age

References for source rock details

Jurassic

J1t

Oil and gas

S-poor lacustrine shale

0.9 – 1.4

Jurassic

Upper Triassic Middle Triassic Lower Triassic

T3

Gas

Coal

0.9 – 1.4

T2l1, T2l3

Gas

Coal

1.0 – 2.2

T1j, T1f

Gas

Marine carbonate

1.2 – 2.0

Upper Triassic Upper Permian Triassic

Sheng et al., 1991; Zhang et al., 1991; Li et al., 1994; Wang, 1994 Huang et al., 1995, 1997

Permian

P

Gas

Marine carbonate and coal

1.8 – 3.0

Carboniferous

C

Gas

2.6

Sinian

Z

Gas

Marine black shale Marine black shale

3.6 – 3.7

Lower and Upper Permian Lower Silurian Lower Cambrian

Huang et al., 1995, 1997 Sichuan Petroleum Bureau, 1989; Zhang et al., 1991; Dai et al., 1997 Huang et al., 1995, 1997

Huang et al., 1995, 1997; Song et al., 1997 Chen, 1992; Huang et al., 1997

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Table 2 Chemistry and d13C and d34S values of natural gases from Wolonghe, Weiyuan and Moxi fieldsa Field name

Well

Depth Age

Moxi Moxi Moxi Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Wolonghe Weiyuan Weiyuan

Mo70 Mo75-1 Mo17 Wo2 Wo3 Wo5 Wo6 Wo7 Wo8 Wo9 Wo11 Wo25 Wo27 Wo33 Wo45 Wo56 Wo28 Wo63 Wo19 Wo17 Wo37 Wo50 Wo38 Wo57 Wo34 Wo47 Wo67 Wo68 Wo83 Wo48 Wo52 Wo58 Wo65 Wo85 Wo96 Wei100 Wei109

– – – 1643 1288 1799 1588 1541 1188 1977 1492 1676 1778 2307 2105 1464 2255 2285 1741 1652 1926 1902 1798 1860 3066 3390 3291 4046 3413 3817 4594 3771 4138 4518 3951 3000 2832

T2l1 T2l1 T2l1 T1j15 T1j15 T1j15 T1j15 T1j15 T1j15 T1j15 T1j15 T1j15 T1j15 T1j15 T1j15 T1j15 – j43 T1j43 T1j43 T1j43 T1j41 – j33 T1j14 – j33 T1j14 – j33 T1j3 T1j3 P2 P1 P1 P1 P1 C2 C2 C2 C2 C2 C2 Z2 Z2

mC1 mC2 mC3 mCO2 100
C2 – 6/ mH2S mN2 d13C1 C1 – 6

d13C2

98.1 98.7 98.3 96.3 96.4 97.2 96.8 95.9 96.4 88.5 96.6 96.6 96.5 95.3 95.6 96.2 96.6 77.4 96.7 97.6 96.9 97.3 97.6 98.7 98.9 99.2 99.0 99.1 99.2 98.9 99.0 99.0 98.9 98.4 99.8 93.4 93.5

– – – – – – – –  28.9  24  29.4 –  28.9 – – – – – – –  28.2 –  29  24  29.2 – – – – – – – – – – –  28.9 – – –  29.9  26 – – – – – – – – – –  32.23 – – –  32.79 –  35.72 –  35.34 –  35.69 –  36.05  36.26 –  35.46 –  31.82 –  31.19 –

0.09 0.07 0.08 0.46 0.45 0.45 0.47 0.44 0.50 0.89 0.44 0.47 0.46 0.50 0.53 0.46 0.45 0.23 0.44 0.37 0.65 0.44 0.39 0.26 0.17 0.12 0.18 0.10 0.15 0.25 0.20 0.23 0.32 0.35 0.17 0.07 0.04

0.004 0.004 0.004 0.080 0.076 0.068 0.083 0.080 0.087 0.268 0.079 0.079 0.080 0.081 0.099 0.061 0.079 0.041 0.076 0.052 0.087 0.060 0.060 0.022 0.007 0 0.007 0.004 0.007 0.018 0.018 0.018 0.015 0.026 0 0 0

0.16 0.15 0.14 0.16 0.14 0.10 0.11 0.26 0.18 0.38 0.13 0.07 0.12 0.43 0.29 0.16 0.13 0.75 0.23 0.05 0.12 0.08 0.09 0.04 0.27 0.15 0.40 0.34 0.19 0.41 0.36 0.35 0.27 0.35 0 1.98 1.89

0.096 0.075 0.085 0.558 0.543 0.530 0.568 0.539 0.605 1.292 0.534 0.565 0.556 0.606 0.654 0.539 0.545 0.349 0.531 0.431 0.755 0.511 0.459 0.285 0.179 0.121 0.189 0.105 0.158 0.270 0.220 0.250 0.338 0.381 0.170 0.075 0.043

0.80 0.38 0.83 2.61 2.36 1.74 2.20 2.99 2.46 9.60 2.30 2.29 2.44 3.23 2.97 2.68 2.36 18.83 2.47 1.56 1.40 1.75 1.55 0.20 0.20 0.37 0.23 0.05 0.26 0.09 0.10 0.11 0.14 0 0 0.60 0.67

0.87 0.72 0.67 0.32 0.51 0.37 0.33 0.27 0.32 0.26 0.44 0.42 0.31 0.38 0.47 0.40 0.29 2.69 0.05 0.36 0.81 0.28 0.26 0.77 0.43 0.12 0.15 0.37 0.15 0.31 0.34 0.25 0.32 0.87 0 3.98 3.87

– – – –  32.7  33.1  32.8 – – –  33.5  33  33.1 – – – – –  32.6 –  34.5  34.4 – – – –  31.89 –  31.69  32.35  32.13  32.25  32.24  32.13  32.98  32.38  32.37

d13C3 dD – – – – – – – – – – – – – –  136 – –  100 – – –  141 – – – – – –  140 – – –  140 –  140  139  120

d34S

Thiols

+ 13.3  6.0 + 17.7 + 22.2 – – – – – – – – – + 26.5 + 24.7b + 31 – + 30.4 – – – – – – – – – – + 5.7b – – – – – + 5.8b – –

– – – 1064 1102 – – – – – 1000 1244 – – – – – – – 788 – – – – – – – – – – – – – – – – –

a Depth is set as the middle point between perforation, in m; Age ‘‘Z’’ represents late Proterozoic; ‘‘ – ’’ represents no measurement or no sample. Thiols in mg/m3; other gas chemistry in mol% of total gas. d13C1, d13C2, d13C3 in x(PDB) and d34S in x(CDT). b From Sheng et al. (1997) and Xu et al. (1998).

standards confirmed the 2r uncertainty as F 0.2x. Other H2S d34S data and gas sample 3He/4He data were collected from material published by Sheng et al. (1997) and Xu et al. (1998). The results of the d34S measurement in this current study are similar to those by Sheng et al. (1997), who measured H2S d34S simultaneously with gas carbon isotope and chemistry, suggesting the results obtained by Sheng et al. (1997) can be justifiably incorporated into the current study.

4. Results 4.1. H2S concentration and d34S data 4.1.1. Whole basin Natural gas samples from the predominantly carbonate reservoirs of the Sinian to the Middle Triassic contain variable quantities of H2S. The maximum H2S concentrations in these reservoirs

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Fig. 4. Variation of CO2 molar percentage, H2S volume percentage of the natural gases and dissolved H2S concentrations in gas-field water versus depth in Wolonghe Field showing a similar variation of molar CO2 and H2S and elevated dissolved H2S in water.

range from 0.6 to 32.0% by volume (Table 3). Sinian, Carboniferous and Permian reservoirs contain < 5% by volume H2S by volume. Concentra-

tions of H2S>10% by volume have only been found in the Lower and Middle Triassic. Relatively low H2S concentrations ( V 0.6% by volume) are present

Table 3 Maximum H2S percentages, d34S, 3He/4He, thiophene and thiol contents in natural gases and organic matter vitrinite reflectance Ro values of the corresponding strataa Strata

J1t

Rob (%)

0.9 – 1.4/ 1.2 (n = 8)

T3 T2l3

Thiophenes Thiols H2S maxi (%) (mg/m3) (mg/m3)

0.6

T2l1

1.0 – 2.2/ 13.3 1.6 (n = 3) 2.7

T1j

1.2 – 1.5

T1f

1.1 – 2.0/ 1.6 (n = 4) 1.8 – 3.0/ 2.2 (n = 9)

P

C

2.6 (n = 1)

Sinian 3.6 – 3.7 (n = 2) a

Whole basin (excluding the east)

Eastern part (including Wolonghe area)

3

He/4He
10 8

d34SH2S (x)

3

He/4He
10 8

d34SH2S (x)

< DT c

–d

–

–

–

– –

– –

–

–

–

–

–

 6.0 to + 17.7/ + 8.3 (n = 3)e < DT to + 6.8 to + 29.1/ 1244 + 13.6 (n = 23) –  6.0 to + 4.81/  1.2 (n = 2) 0.11 – 2.00 1.6 – 3.0/2.2 + 20.4 to + 29.7/ (n = 4) + 24.1 (n = 17), + 13.3 – – –

–

–

1.89 – 3.62 (n = 2) –

+ 22.9 to + 24.7 (n = 2) + 22.2 to + 31.0 / + 27.5 (n = 4)e –

1.83 – 2.20 (n = 2)

+ 5.7 to + 12.8/ + 9.3 (n = 2)

0.90 – 6.40

32.0

0.10 – 1.35

2.5

–

3.4

0.03 – 0.32

0.7

–

3.4

0.10 – 0.20

–

1.1 (n = 1) 1.1 – 3.6 (n = 4) –

0.14 – 4.04 0.6 – 2.8/1.7 + 11.5 to + 14.4/ (n = 2) + 13.1 (n = 4)

2.09 – 2.72/2.50  9.6 to + 8.5/ (n = 6) + 2.2 (n = 7) – –

Data present in the form of range/average (number of samples). From Huang et al. (1995, 1997) and Xu et al. (1998). c DT represents detection limit. d No data available. e From this study; others were from Xu et al. (1998), Sheng et al. (1997) and Dai (1986). b

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Fig. 5. Diagram showing that high H2S contents occur in reservoirs close to anhydrite beds in Lower Triassic Jialingjiang Formation, Wolonghe Field. Also d34S values of anhydrite measured in the basin and the interpreted seawater isotopic curves from different authors are plotted for comparison.

in gas from Upper Triassic and Jurassic sandstone reservoirs (Dai, 1986). Gases from different systems have H2S with different d34S values (Table 3). Gas samples from Sinian reservoirs have a relatively narrow d34S range from + 11.5xto + 14.4x . Gas samples from Permian reservoirs are enriched with 34S and have d34S values between + 20.4xand + 29.7x(Sheng et al., 1982; Xu et al., 1998). Apart from the Wolonghe Field, discussed separately below, the majority of the gas samples from the Lower Triassic Jialingjiang Formation (T1j) have d34S values from + 12xto + 16x with two anomalous values of + 6.8xand + 29.1x in the Naxi area in the southeast of the basin (Table 3; Fig. 1). Two samples from the Lower Triassic Feixianguan Formation (T1f) and the basal Middle Triassic Leikoupo Formation (T2l1) have the same most negative d34S values (  6.0x). 4.1.2. Wolonghe Field In the Wolonghe Field, H2S concentrations in Triassic reservoirs (Jialingjiang Formation, T1j) range predominantly from 5% to 10% by volume (Table 3). The most elevated H2S concentrations occur between 1900 and 2400 m, which is also where the highest concentrations of CO2 are located (Fig. 4). As would be expected, dissolved H2S was detected in water

coproduced with gas with concentrations ranging from 106 to 2988 mg/l (Fig. 4). The Fourth and Fifth Members of Jialingjiang Formation have natural gas H2S concentrations of up to 32% and 18% by volume, respectively (Table 2). These two high values correspond to the intervals with the greatest quantity of anhydrite (Fig. 5). In contrast, the First and Third Members have relatively low H2S concentrations and

Fig. 6. H2S contents and d34S values of natural gases from Wolonghe Gas Field in the East and Moxi Gas Field in the Middle Sichuan.

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Thiophenes are cycloaromatic sulphur compounds whereas thiols are alkylsulphides (or mercaptans). 4.2.1. Thiophenes Thiophene concentrations (total of all compounds with thiophene structure) in natural gases range from 0.03 to 6.40 mg/m3 (at 1 atm pressure) in the Sichuan Basin (Fig. 7). Thiophene concentrations greater than 1.00 mg/m3 only occur in Lower Jurassic freshwater – lacustrine sandstone reservoirs. Sinian, Permian and Triassic carbonate reservoirs routinely have gases with relatively low concentrations ( < 0.20 mg/m3) of thiophenes (Fig. 7). The Lower Jurassic sandstone reservoirs produce light oil, condensate and associated natural gas, but contain < 0.6% H2S. Gas in Jurassic reservoirs is wetter (higher ratios of SC2 – 6/SC1 – 6, Fig. 8) than gas in Triassic, Permian or Sinian reservoirs. Gases in the Sinian, Permian and most Triassic reservoirs are dominated by methane, as shown in Fig. 8. In summary, elevated thiophene concentrations tend to

Fig. 7. Thiophene and thiol contents in natural gases from different parts of the basin. Relatively high thiophene but zero thiol concentrations were found in the Jurassic reservoir in the Middle Sichuan (the x axis scatter is here introduced to clearly differentiate dots with the similar y values) (thiol contents of Triassic Wolonghe gases are sourced from this study, Table 2, while other data came from Huang, 1990).

are essentially free of anhydrite (Sichuan Petroleum Bureau, 1989). We thus conclude that the local quantity of H2S seems to reflect directly the local quantity of anhydrite in the formation. d34S values from H2S from the Wolonghe Field range from + 22.4xto + 31.0x(Table 3; Fig. 6) and are close to those previously reported by Sheng et al. (1997) and Xu et al. (1998) (Table 3). 4.2. Thiophenes and thiols Low-molecular-weight (LMW) thiophenes, thiols and even carbon disulphide have been detected in natural gases from the Sichuan Basin (Huang, 1990).

Fig. 8. Gaseous hydrocarbon wetness (SC2 – 6/SC1 – 6) ratios in different areas showing the high ratios of gas in Jurassic reservoirs and much more negative values of gases in Triassic, Permian and Sinian reservoirs (the x axis scatter has been introduced to clearly differentiate dots with the similar y values) (data of East Sichuan plot from Table 2, while data of other parts of the basin are from Huang, 1990).

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Fig. 9. Relationship between thiol and H2S content of gas in the Triassic part of the section in Wolonghe).

be found in wet gases associated with light oils and condensates while methane-dominated gases have low thiophene concentrations. 4.2.2. Thiols Thiol compounds (also known as mercaptans) were not detected in the Jurassic natural gases, while high concentrations occur in Triassic, Sinian and Permian reservoirs, and especially in the Triassic reservoirs of the Wolonghe Field. Thiol concentrations are up to 1244 mg/m3 in the Wolonghe Field (Fig. 9; Table 3) although they range from less than the detection limit to 6.11 mg/m3 in the rest of the Sichuan Basin. The stratigraphic distribution of thiol compounds is thus totally different to that of the thiophenes. Low thiol concentrations tend to occur in gases with low H2S concentrations, whereas high concentrations are associated with the highest H2S concentrations in Lower and Middle Triassic strata (Huang, 1990), even though reservoir temperatures are similar. Five gas samples from the Wolonghe Field show that there is an approximately positive relationship between thiol and H2S concentrations (Fig. 9). This observation is similar to the observation of Ho et al. (1974) in which thiols in condensates were found to be associated with high H2S contents.

have the highest C2 – 6/C1 – 6 percentages and gases from both Permian and Sinian are the lowest while gas from Triassic reservoirs is shown to have a broad range of C2 – 6/C1 – 6 percentages (Fig. 8). d13 CCH4 values from Jurassic gas ranges from  37xto  44xPDB. Gas samples from Triassic, Permian and Sinian reservoirs have d13 CCH4 values >  36xPDB. The majority of gas samples from Triassic, Permian and Sinian reservoirs have d13 CC2 H6 closer to d13 CCH4 than those from Jurassic reservoirs. The gases with more negative d13 CCH4 generally have a greater difference between d13 CC2 H6 and d13 CCH4 (Table 2). Two gas samples from Permian reservoirs have d13 CCH4 values less negative than d13 CC2 H6 . 4.3.2. Wolonghe Field Wolonghe gas chemistry shows that gas samples from the Triassic have wetness values (C2 – 6/C1 – 6 percentages) ranging mainly from 0.1% to 0.7% (Table 3). The values tend to be much higher than those of gases from the Permian reservoir in Wolonghe which range from 0.1% to 0.2% (Fig. 8) and lie between those from the gases in the Jurassic in the Middle Sichuan Basin and those from the gases in the Sinian in the Southwest Sichuan Basin (Fig. 8). This suggests that the gas in the Triassic Wolonghe Field has a different chemical composition from the gas from other parts of the basin.

4.3. Gas chemistry and d13C – H2S relationships 4.3.1. Whole basin Gas chemistry data (Table 2) show that among gases from different systems, those from Jurassic reservoirs

Fig. 10. Relationship between d13 CCH4 and d13 CC2 H6  d13 CCH4 for samples from the whole basin and Wolonghe Field.

C. Cai et al. / Chemical Geology 202 (2003) 39–57

49

5. Discussion

Fig. 11. d13C values of methane and ethane versus H2S/ (H2S + SC1 – 6) for gases from the Wolonghe Field showing positive relationships.

Gas samples from the Triassic section of the Wolonghe Field have d13 CCH4 values from  34.5x to  32.6xPDB and d13 CC2 H6 values from  29.4x to  28.2xPDB. d13 CC2 H6 values are always less negative than d13 CCH4 values. d13 CCH4 values lie in between those of gases in Jurassic and Permian and Sinian reservoirs (Fig. 10). Relationships between d13 CCH4 and d13 CC2 H6 show that the gas in the Triassic has more negative d13 CCH4 values and less negative d13 CC2 H6 values than gases both from Permian reservoirs in the Wolonghe Field in the East Sichuan Basin and Sinian reservoirs in the Weiyuan Field in the Southwest Sichuan Basin (Table 3). A gas souring index [H2S/(H2S + SC1 – 6)] has been used previously to indicate the extent of thermochemical sulphate reduction (Worden and Smalley, 1996). There are positive relationships between both d13 CCH4 and d13 CC2 H6 with H2S/(H2S + SC1 – 6) (Fig. 11). Thus, gas samples with higher gas souring index values tend to have alkane gases most enriched in 13C. 4.4. Noble gas isotope data Helium gas present in petroleum accumulations has He/4He ratios ranging from 0.6
10 8 to 3.6
10 8. Helium isotope ratios from the Wolonghe Field range from 1.8
10 8 to 3.6
10 8 (Table 3). 3

The Sichuan Basin affords us the opportunity to examine the relationships between source type and maturity, petroleum type and sulphur geochemistry. What is clear is that different parts of the stratigraphy have distinct sulphur geochemical characteristics. The crucial question is why? It is noteworthy that the highest H2S and thiol concentrations are found in Lower Triassic reservoirs containing petroleum sourced from sulphur-enriched marine carbonate source rocks (Tables 1 and 2). However, the maximum H2S concentrations are hugely in excess of what would be anticipated from an organic source and their relatively high d34S values are generally characteristic of an oxidized (sulphate) sulphur source, rather than reduced sulphur typical of petroleum source rocks. Note that rare H2S d34S values of  6x(Tables 2 and 3) may be indicative that the carbonate source rock has indeed generated a small quantity of H2S. It is most likely that these elevated concentrations of high d34S sulphide are the result of sulphate reduction. Given the relatively high temperatures in the basin, reduction is more likely to have been thermochemical than biogenic (Sheng et al., 1982; Wang, 1994; Huang, 1990). The questions remain as to where sulphate reduction occurred in the basin (whether H2S migration occurred), whether TSR has occurred between gas phase hydrocarbons (especially methane) and sulphate and about the link between sulphide and thiol compounds. There is also the puzzling distribution of thiophene compounds to consider. Although they might be expected to follow the same pattern as other sulphur compounds in the petroleum system, they, in fact, have a different pattern to both thiols and H2S. These issues will be dealt with in the following discussion. One persistent possibility for sour gas in any crustal setting is that H2S has a primeval source (mantle or core). However, helium isotopes from the basin in general and the Wolonghe Field in particular indicate that the gas has been derived from sedimentary organic matter (Xu et al., 1998; Cai et al., 2001) and that there is negligible input of gas from mantle sources. This excludes a mantle or a deep crustal source of gas and implies that we must look for basinal, non-juvenile, sources of H2S.

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5.1. Origin of H2S in the Wolonghe Field 5.1.1. A local source of H2S? Formation testing showed that present bottom-hole temperatures of the Triassic reservoir in the Wolonghe Field are in the range 90 – 100 jC, and so are apparently too low for the present-day occurrence of TSR. Vitrinite reflectance (Ro) values range from 1.17% to 1.54% in the vicinity of the Wolonghe Field (Xu et al., 1998), but are mostly >1.35% (Huang et al., 1995; Wang, 1994). During the Neogene Himalayan Orogeny, uplift resulted in erosion of Tertiary and Cretaceous strata. Thus, based upon burial history, heat flow analysis and the Ro data, the base of the Upper Triassic was concluded to have had a maximum palaeo-temperature of not less than 130 jC (Fig. 3; Zeng, 1987; Wu et al., 1998; Liu et al., 2000). The minimum temperature required for TSR has been the subject of intense interest. In some basins, the minimum temperature for TSR is 140 jC or greater (Worden et al., 1995, 1998; Heydari, 1997), while other basins have experienced TSR at temperatures as low as 120 jC (Sassen, 1988; Rooney, 1995; Cai et al., 2001; Worden and Smalley, 2001). It is clear that there is no absolute universal minimum temperature. This is probably because the extent of reaction is a function of many controls including the time spent in the reaction window (a protracted burial history and the consequent slow heating would lead to lower minimum temperatures), petroleum type and composition, the rock fabric (e.g., anhydrite crystal size; Worden et al., 2000), timing of petroleum emplacement into the structure and wettability (where waterwet reservoirs are likely to undergo TSR more rapidly than petroleum wet systems; Worden and Heasley, 2000). With a maximum palaeotemperature of >130 jC in the Sichuan Basin in Lower Triassic strata prior to Neogene uplift, TSR and H2S generation were thus perfectly possible given the range of minimum temperatures reported from around the world. The large, stratigraphically defined differences in sulphur isotope composition and H2S contents suggest that H2S generation was localized within discrete stratigraphic reservoir intervals in the Sichuan Basin. This possibility is supported by the chemistry and isotope composition of the associated brines (Zhou et al., 1997) and formation pressure/depth data measured during drill-stem testing (DST) (Sichuan Petroleum

Bureau, 1989; Tong, 1992) from the Lower and Middle Triassic, which suggest that compartmentalisation is predominant in the basin. Although anhydrite is abundant within the Triassic section, it is concentrated within the Fourth and Fifth Members of the Jialingjiang Formation. Indeed, elevated H2S concentrations have been found exclusively in the Fourth and Fifth Members (Fig. 5) and H2S loss due to reactions in the reservoir with elements such as Fe and Zn is insignificant since practically no siliciclastics occur in the Jialingjiang Formation. These factors thus support both localized TSR and inhibited mixing of reservoir fluids. Both liquid and gas phase petroleum have been reported to be involved in TSR (e.g., Orr, 1974; Krouse et al., 1988; Connan and Lacrampe-Couloume, 1993; Rooney, 1995; Worden et al., 1996; Worden and Smalley, 1996; Cai et al., 2001). Only gas phase hydrocarbons are found in the Triassic of the Wolonghe Field, suggesting that it is most likely for TSR to have been caused by the chemical oxidation of short chain alkanes by sulphate. Reactions that have been reported include (e.g., Orr, 1974; Connan and Lacrampe-Couloume, 1993; Worden et al., 2000) the initial reduction of sulphate by pre-existing hydrogen sulphide: o  3H2 SðgÞ þ SO2 4 ðaqÞ Z 4S þ 2H2 O þ 2OH

ðR1Þ

followed by the subsequent further reduction of elemental sulphur by hydrocarbons: 4So þ 1:33ðCH2 Þ þ 2:66H2 O Z 4H2 SðgÞ þ 1:33CO2

ðR2Þ

although the direct reaction between aqueous sulphate and petroleum compounds has been suggested: SO2 4 ðaqÞ þ CH4

ðaqÞ

þ Hþ ðaqÞ

Z HCO 3 ðaqÞ þ H2 SðgÞ þ H2 O

ðR3Þ

The d34S values of anhydrite in the Lower Triassic Jialingjiang Formation in South China (Fig. 5) have been shown to range from + 24.7x to + 32.5x (Chen et al., 1981; Chen and Chu, 1988) and even up to + 35.8x(Lin et al., 1998). Thus, the local early Triassic evaporites had sulphate d34S values (Strauss, 1997) that are significantly more positive than those reported for Triassic oceans by Claypool et al. (1980) (Fig. 5). Despite theoretical isotope fractionation of

C. Cai et al. / Chemical Geology 202 (2003) 39–57 34

S during the reduction of sulphate, TSR routinely leads to sulphide with similar or the same d34S values as the initial sulphate (e.g., Machel et al., 1995). The local anhydrite d34S values in the Lower Triassic Jialingjiang Formation are close to both the formation water d34S (Lin et al., 1998) and the H2S d34S values in the Wolonghe Field, suggesting strongly that the H2S was generated by thermochemical sulphate reduction within the Triassic. 5.1.2. Migration of H2S into the reservoir? In direct contrast to the idea that the H2S was locally produced by TSR in the Triassic reservoirs, it has been suggested that the H2S migrated into the Triassic strata from Palaeozoic rocks (Sheng et al., 1997; Xu et al., 1998). Since sulphate minerals have not been found in deeper Cambrian and Ordovician carbonate rocks in the East Sichuan Basin (Tong, 1992), the two remaining possibilities for the primary sources of the TSR H2S are the Permian and Carboniferous carbonate reservoir rocks. d34S values of H2S resulting from TSR are usually close to those of the parent sulphates (e.g., Machel et al., 1995). H2S in the Triassic Wolonghe Field has positive d34S values (> + 22x) that are close to Carboniferous marine sulphate d34S values (approximately + 25x; Claypool et al., 1980), leading to the possibility of a Carboniferous source of the H2S gas found in the Triassic. However, there are two strong lines of evidence against this: (1) The Carboniferous section contains very low ( < 0.7%) H2S concentrations (Table 3). (2) Carboniferous H2S has low d34S values relative to Carboniferous marine sulphate (  9.6xto + 8.5x; Table 3), suggesting that TSR cannot have caused the minor amount of H2S in the Carboniferous section. The low d34S values and low H2S concentrations of Carboniferous H2S exclude the Carboniferous as a possible source for the H2S in Triassic reservoirs. Based upon the elevated d34S values of the gas in Triassic reservoirs of the basin and their similarity to those of H2S in the Permian in the Sichuan Basin (Table 3), Sheng et al. (1997) concluded that H2S in the Triassic in the basin might have originated in the Permian and then migrated into the Triassic. This

51

conclusion is unlikely to be correct since there are several contradictory lines of evidence: (1) Using the global data from Claypool et al. (1980), Permian seawater had d34S values from + 9xto + 14x(Orr, 1974). The values are too low for the d34S values of the H2S found in the Triassic reservoirs. (2) There is negligible anhydrite (and no signs of anhydrite replacement by TSR) in the Permian section so that TSR is unlikely to have been extensive in Permian strata. Compared with the gases reservoired in the Triassic, the gas in the Permian reservoirs has relatively low H2S concentrations ( < 3.4%) and similar d34S values to the gas in the Triassic Wolonghe Field (Table 2), suggesting that the H2S in the Permian might be derived from the Triassic (the opposite scenario to the one suggested by Sheng et al. (1997) and Xu et al. (1998). 5.1.3. Summary of the evidence for the occurrence of TSR in lower Triassic reservoirs The evidence supporting the indigenous production of H2S in the Lower Triassic by TSR is: (1) H2S concentrations are highest where there is most abundant anhydrite. (2) H2S has d34S values similar to the local anhydrite and aqueous sulphate. (3) There is a strong local compartmentalisation in the stratigraphy revealed by water geochemistry and isotopes. Compartmentalisation would strongly inhibit input from external sources. (4) Migration of H2S into Triassic reservoirs from the Permian or Carboniferous is unlikely on the basis of geochemical evidence. (5) Locally modified carbon isotopes of alkane gas compounds correlate with the degree of TSR, suggesting that TSR occurred in the reservoir to the presently reservoired hydrocarbons. This idea is explored in Section 5.2. 5.2. Source, maturity and post-depositional alteration of natural gases in the Sichuan basin In non-sour provinces the carbon isotope ratios of alkanes are thought to be affected by both source

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rock type and source maturity (advanced maturation can lead to increases in d13 CCH4 ; e.g., Tao and Chen, 1989; Sheng et al., 1991; Wang, 1994). Hydrocarbon gas carbon isotopes have been used to good effect to reveal details of the source rock type, depositional environment and thermal maturity (e.g., Schoell, 1984; Tao and Chen, 1989; Sheng et al., 1991; Wang, 1994; Berner and Faber, 1996; Huang et al., 1999). However, the range of gas isotope values in a single reservoir (Figs 10 and 11) may also be affected by secondary alteration after emplacement in the reservoir (e.g., Krooss and Leythaeuser, 1988; Prinzhofer and Huc, 1995; Cai et al., 2002). As TSR proceeds, d13C values of light hydrocarbons have been shown in some basins to increase progressively (Krouse et al., 1988; Rooney, 1995; Worden and Smalley, 1996; Whiticar and Snowdon, 1999). Positive relationships exist between d13 CCH4 and H2S/(H2S + SC1 – 6) and between d13 CC2 H6 and H2S/(H2S + SC1 – 6) in the Wolonghe gases in the Triassic reservoirs. The positive relationship between methane and ethane carbon isotopes and the gas souring index values from the Wolonghe Field (Fig. 11) may be a consequence of TSR due to preferential reaction of 12C-hydrocarbons, as a result of their weaker bond strengths (e.g., Krouse et al., 1988; Worden and Smalley, 1996), an example of kinetic isotope fractionation (e.g., Cramer et al., 2001). Fig. 11 demonstrates a general rule that hydrocarbon gas isotopes should not be used for maturity or source characterisation if they have undergone sulphate reduction. Furthermore, Fig. 11 suggests that even methane, the most thermodynamically stable of the alkanes, reacts with sulphate during TSR. This result is seemingly in contradiction to the recent assertion that methane is largely unreactive during TSR (Machel, 2001). 5.3. Origin of thiophene and thiols 5.3.1. Origin of thiols Thiol compounds were not detected in Jurassic petroleum accumulations, while high concentrations occur in the gas-bearing Triassic, Sinian and Permian reservoirs. Variable thiol concentrations occur within Triassic reservoirs with similar maturity but different H2S contents. Thiol concentrations increase with increasing H2S concentrations (Fig. 9) suggesting

that the concentration of H2S in a reservoir may control the formation of thiol compounds. This supports the conclusion that thiols can be formed by reaction between H2S and the hydrocarbon compounds found in gas phase petroleum (Ho et al., 1974). The generation of the most abundant H2S by TSR thus shows that there is a likely association between TSR and thiol production. One possible specific association is that H2S reacts with petroleum compounds that remain after TSR to produce a new suit of thiol compounds (see also Orr, 1977; Worden and Smalley, 2001). Note that such neoformed thiols in particular, and organosulphur fraction in general, would adopt the d34S of the original anhydrite as transmitted by the TSR H2S. 5.3.2. Origin of thiophene Relatively high thiophene concentrations tend to occur in association with light oil and condensate while low thiophene concentrations occur in dry gas (Figs. 7 and 8). The thiophene concentrations in the various petroleum fields are approximately inversely proportional to temperature and organic matter maturity. The possible causes of the thiophene distribution in the Sichuan Basin include: (1) Thermally controlled cracking of organosulphurbearing materials (oil or kerogen). (2) Back-reaction of H2S with hydrocarbons. (3) Intermediate TSR reactant. The source rocks of the natural gases in the Palaeozoic and Lower and Middle Triassic reservoirs, and the Upper Triassic and Jurassic reservoirs in the Sichuan Basin, are considered to be different (Table 1). Gas in Jurassic reservoirs with the high thiophene concentrations has been suggested to be derived from sulphur-poor type I kerogen while gas in the Lower and Middle Triassic with relatively low thiophene concentrations are related to sulphur-rich type II carbonate and evaporite source rocks (Table 1; Huang, 1990; Zhong et al., 1991; Wang, 1994; Dai et al., 1997). If the thiophenes were generated directly within the source rock as a function of the kerogensulphur content, it might be expected that the thiophene distribution would be the opposite of that found. However, the petroleum with the S-poor source rock has the highest thiophene concentrations. Thus,

C. Cai et al. / Chemical Geology 202 (2003) 39–57

the difference in thiophene concentrations is unlikely to be a consequence of source rock type. However, there is a good inverse relationship between source rock maturity (as revealed by vitrinite reflectance, Table 3) and thiophene concentration (Fig. 12). This suggests that thiophene concentrations may be a function of source rock maturity rather than source rock type. However, the thiophene concentrations may also be a function of the post generation alteration of petroleum. This possibility is explored below. That thiophene compounds have higher concentrations in gases associated with light oils or condensates than in single phase gas pools at relatively high temperature does not indicate that thiophenes are thermally unstable, as suggested by Huang (1990), but may indicate that light oils and condensates are more reactive to H2S, with thiophenes being the result. Evidence shows that isotopically distinct sulphur is routinely incorporated into petroleum at relatively high temperatures in reservoirs (e.g., Powell and Macqueen, 1984; Orr and Sinninghe Damste´, 1990; Manzano et al., 1997; Betchel et al., 2001; Cai et al., 2001; Worden and Smalley, 2001). It is typical for sulphur to become incorporated into double bonds or functionalized radicals during the early stage of diagenesis of organic matter (Vairavamurthy and Mopper, 1987; Sinninghe Damste´ et al., 1990). How-

53

ever, double bonds in hydrocarbons have been generated during high temperature hydrous pyrolysis of n-alkanes (Leif and Simoneit, 2000; Seewald, 2001), supporting the notion that sulphur can be incorporated into hydrocarbons during late diagenesis. Some thiophene compounds have been shown to be stable at elevated reservoir temperatures (e.g., Koopmans et al., 1995; Song et al., 1998), and significant breakdown of thiophenic structures to H2S has not been reported at temperatures less than about 200 jC (Aplin and Macquaker, 1993). Thermal and thermocatalytic studies have established that nonthiophenic sulphur (aliphatic as in thiols, acyclic and cyclic sulphides) evolve to produce H2S much more easily than thiophenic sulphur (Orr and Sinninghe Damste´, 1990). The relative lack of thiophenes in the Triassic and deeper reservoirs is thus unlikely to be due to their higher temperatures than in the shallower and cooler Jurassic reservoirs since thiophene compounds probably remain relatively stable in the deeper hotter reservoirs. Sheng et al. (1986) suggested that alkanes might react with H2S or elemental sulphur to generate thiolane. Thiolane compounds are thermally unstable and are thought to undergo dehydrogenation, thus generating thiophenes (Sinninghe Damste´ et al., 1990). Schmid et al. (1987) produced C18 2,5-dia-

Fig. 12. Relationship between vitrinite reflectance and thiophene concentration. The figure summarises a large volume of data but shows that thiophene concentrations seem to decrease in a systematic manner with increasing source rock maturity.

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C. Cai et al. / Chemical Geology 202 (2003) 39–57

lkylthiophenes after heating n-octadecane in the presence of sulphur for a period of 65 h in a simulation experiment at 200– 250 jC. The result supports the possibility that thiophenes can be generated by reaction between liquid phase alkanes and inorganic reduced sulphur compounds, as initially proposed by Orr (1974). Based on relative bond strengths, H2S can theoretically react more easily with higher molecular weight hydrocarbon chains than with methane to generate (thiolanes and thus) thiophenes. This is consistent with our observation that higher thiophene concentrations occur in wet gas associated with oils in Jurassic reservoirs and lower thiophene concentrations occur in dry gas dominated by methane in Lower and Middle Triassic, Permian and Sinian reservoirs. Thus, an alternative mechanism to generation from source rocks as an inverse function of temperature (Fig. 12) is to produce high thiophene concentrations in Jurassic reservoirs by reaction of longer chain alkanes with H2S or elemental sulphur. Longer-chain alkanes are only abundant in liquid phase petroleum and wet gases, so that more thiophene will be generated in Jurassic reservoirs than in the dry gases in Sinian, Permian and Triassic reservoirs. The origin of the thiophenes remains unresolved.

6. Conclusions (1) There is up to 32% H2S in the natural gas accumulations in the Triassic carbonates and evaporites of the Wolonghe Field, which is distinctly different from the relatively low H2S concentrations found in older and younger strata in the Sichuan Basin. (2) The H2S in Triassic reservoirs in the Wolonghe Field, with a maximum palaeotemperature of about 130 jC, has very high d34S values, close to those of its indigenous anhydrite, and H2S is concluded to have been generated by thermochemical sulphate reduction. (3) The H2S content, sulphur isotope and reported petroleum source rock data show that the H2S in the Triassic Wolonghe Field has not migrated from Palaeozoic strata but was generated in situ by thermochemical sulphate reduction. (4) The carbon isotope ratios of methane and ethane increase to higher values with our TSR parameter

suggesting that these apparently unreactive alkanes are actively involved in the reduction of sulphate. (5) In the Sichuan Basin, there is an apparent connection between organosulphur species and petroleum type. Thiophene compounds are associated with liquid petroleum in the Jurassic reservoirs while thiol compounds are associated with gas phase petroleum in Triassic reservoirs. The greatest quantities of thiophenes are found in petroleum generated by the lowest maturity source rocks. (6) The link between phase and thiophene compounds is uncertain, but may be a consequence of liquid phase thermochemical sulphate reduction or primary generation controlled by source maturity. The least mature source rocks may have produced the greatest quantity of thiophenes per unit of petroleum generation. (7) It is possible that thiol compounds were generated either during, or as a byproduct of, gas-phase thermochemical sulphate reduction in the Triassic carbonates. In the Triassic Wolonghe Field, thiol concentrations correlate positively with the locally produced TSR – H2S. This suggests that thiol compounds are the result of reaction between H2S and remaining post-TSR petroleum compounds. The coincidence of H2S and thiol compounds is thus genetic but limited, in the first case, by the occurrence of TSR. Acknowledgements The research was financially supported by the UK Royal Society, UK and the National Natural Sciences Foundation of China (grant no. 40173023). Ezat Heydari is warmly thanked for constructive comments on an earlier version of this manuscript. Melodye Rooney and Simon George are thanked for critical comment, which helped to improve the manuscript. [LW] References Aplin, A.C., Macquaker, J.H.S., 1993. C – S – Fe geochemistry of some modern and ancient anoxic marine muds and mudstones. Philosophical Transactions of the Royal Society of London, A 15 (344), 89 – 100.

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