thermochemical sulphate reduction and the generation...

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Chemical Geology 202 (2003) 39–57

Thermochemical sulphate reduction and the generation of hydrogen

sulphide and thiols (mercaptans) in Triassic carbonate reservoirs

from the Sichuan Basin, China

Chunfang Caia,b, Richard H. Wordenb,*, Simon H. Bottrellc,Lansheng Wangd, Chanchun Yanga

a Institute of Geology and Geophysics, CAS, PO Box 9825, Beijing 100029, PR ChinabJane Herdman Laboratories, Department of Earth Sciences, University of Liverpool, 4 Brownlow Street, Liverpool L69 3GP, UK

cSchool of Earth Sciences, University of Leeds, Leeds LS2 9JT, UKdPetroleum Exploration and Development Institute, Southwest Sichuan Petroleum Corporation, Chengdu, Sichuan Province, PR China

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

0009-2541/$ - see front matter D 2003 Elsevier B.V. All rights reserved.

doi:10.1016/S0009-2541(03)00209-2

* Corresponding author. Tel.: +44-151-794-5184; fax: +44-151-

794-5196.

E-mail address: [email protected] (R.H. Worden).

1. Introduction

Elevated H2S concentrations (sour gas) have been

found in many deep carbonate gas reservoirs around

the world. The H2S is thought to originate from

C. Cai et al. / Chemical Geology 202 (2003) 39–5740

thermochemical sulphate reduction (TSR); a process

whereby sulphate minerals and petroleum react to-

gether (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 com-

pounds. Other sulphur-bearing compounds in sour

petroleum are only infrequently documented in geo-

chemical studies, although a great number of sul-

phur 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 gaso-

line range petroleum have been shown to be in-

volved 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 concentra-

tions >10% have been found only in the Lower and

Middle Triassic carbonates and evaporites. d34S val-

ues of the H2S are about + 25x (Sheng et al.,

1997), significantly more positive than those of Tri-

assic 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 concentra-

tions 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 trans-

gression 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 coal-

bearing strata.

The Lower and Middle Triassic sequence is divid-

ed into Feixianguan (T1f), Jialingjiang (T1j) and Lei-

koupo Formations (T2l), and is composed predomi-

nantly 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-

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).

C. Cai et al. / Chemical Geology 202 (2003) 39–57 41

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

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 experi-

enced a maximum burial rate, and had the highest

palaeo-temperature (>130 jC), at the end of Creta-

ceous (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 cap-

rocks in the Sichuan Basin (Fig. 2; Table 1). Sinian to

Middle Triassic reservoirs are predominantly carbon-

ate 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

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 sulphur-

poor Jurassic lacustrine source (Sheng et al., 1991;

Zhang et al., 1991; Li et al., 1994; Wang, 1994;

Huang et al., 1997).

Table 1

Reservoir units with their interpreted source rock types, maturities and ag

Reservoir Symbol Petroleum

type

Source

type

Re

vi

Jurassic J1t Oil and

gas

S-poor

lacustrine

shale

0.

Upper

Triassic

T3 Gas Coal 0.

Middle

Triassic

T2l1, T2l

3 Gas Coal 1.

Lower

Triassic

T1j, T1f Gas Marine

carbonate

1.

Permian P Gas Marine carbonate

and coal

1.

Carboniferous C Gas Marine black

shale

2.

Sinian Z Gas Marine black

shale

3.

3. Sampling and methods

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 stan-

dard industry techniques. The concentrations of thio-

phene 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 Kusa-

kabe, 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

es

gional

trinite Ro, %

Source age References for

source rock details

9–1.4 Jurassic Sheng et al., 1991;

Zhang et al., 1991;

Li et al., 1994;

Wang, 1994

9–1.4 Upper

Triassic

Huang et al., 1995, 1997

0–2.2 Upper

Permian

Huang et al., 1995, 1997

2–2.0 Triassic Sichuan Petroleum Bureau, 1989;

Zhang et al., 1991;

Dai et al., 1997

8–3.0 Lower and

Upper

Permian

Huang et al., 1995, 1997

6 Lower

Silurian

Huang et al., 1995, 1997;

Song et al., 1997

6–3.7 Lower

Cambrian

Chen, 1992;

Huang et al., 1997

Table 2

Chemistry and d13C and d34S values of natural gases from Wolonghe, Weiyuan and Moxi fieldsa

Field

name

Well Depth Age mC1 mC2 mC3 mCO2 100�C2–6/

C1 – 6

mH2S mN2 d13C1 d13C2 d13C3 dD d34S Thiols

Moxi Mo70 – T2l1 98.1 0.09 0.004 0.16 0.096 0.80 0.87 – – – – + 13.3 –

Moxi Mo75-1 – T2l1 98.7 0.07 0.004 0.15 0.075 0.38 0.72 – – – – � 6.0 –

Moxi Mo17 – T2l1 98.3 0.08 0.004 0.14 0.085 0.83 0.67 – – – – + 17.7 –

Wolonghe Wo2 1643 T1j51 96.3 0.46 0.080 0.16 0.558 2.61 0.32 – – – – + 22.2 1064

Wolonghe Wo3 1288 T1j51 96.4 0.45 0.076 0.14 0.543 2.36 0.51 � 32.7 � 28.9 � 24 – – 1102

Wolonghe Wo5 1799 T1j51 97.2 0.45 0.068 0.10 0.530 1.74 0.37 � 33.1 � 29.4 – – – –

Wolonghe Wo6 1588 T1j51 96.8 0.47 0.083 0.11 0.568 2.20 0.33 � 32.8 � 28.9 – – – –

Wolonghe Wo7 1541 T1j51 95.9 0.44 0.080 0.26 0.539 2.99 0.27 – – – – – –

Wolonghe Wo8 1188 T1j51 96.4 0.50 0.087 0.18 0.605 2.46 0.32 – – – – – –

Wolonghe Wo9 1977 T1j51 88.5 0.89 0.268 0.38 1.292 9.60 0.26 – – – – – –

Wolonghe Wo11 1492 T1j51 96.6 0.44 0.079 0.13 0.534 2.30 0.44 � 33.5 � 28.2 – – – 1000

Wolonghe Wo25 1676 T1j51 96.6 0.47 0.079 0.07 0.565 2.29 0.42 � 33 � 29 � 24 – – 1244

Wolonghe Wo27 1778 T1j51 96.5 0.46 0.080 0.12 0.556 2.44 0.31 � 33.1 � 29.2 – – – –

Wolonghe Wo33 2307 T1j51 95.3 0.50 0.081 0.43 0.606 3.23 0.38 – – – – + 26.5 –

Wolonghe Wo45 2105 T1j51 95.6 0.53 0.099 0.29 0.654 2.97 0.47 – – – � 136 + 24.7b –

Wolonghe Wo56 1464 T1j51– j

43 96.2 0.46 0.061 0.16 0.539 2.68 0.40 – – – – + 31 –

Wolonghe Wo28 2255 T1j43 96.6 0.45 0.079 0.13 0.545 2.36 0.29 – – – – – –

Wolonghe Wo63 2285 T1j43 77.4 0.23 0.041 0.75 0.349 18.83 2.69 – – – � 100 + 30.4 –

Wolonghe Wo19 1741 T1j43 96.7 0.44 0.076 0.23 0.531 2.47 0.05 � 32.6 � 28.9 – – – –


33 97.6 0.37 0.052 0.05 0.431 1.56 0.36 – – – – – 788


33 96.9 0.65 0.087 0.12 0.755 1.40 0.81 � 34.5 � 29.9 � 26 – – –


33 97.3 0.44 0.060 0.08 0.511 1.75 0.28 � 34.4 – – � 141 – –

Wolonghe Wo38 1798 T1j3 97.6 0.39 0.060 0.09 0.459 1.55 0.26 – – – – – –

Wolonghe Wo57 1860 T1j3 98.7 0.26 0.022 0.04 0.285 0.20 0.77 – – – – – –

Wolonghe Wo34 3066 P2 98.9 0.17 0.007 0.27 0.179 0.20 0.43 – – – – – –

Wolonghe Wo47 3390 P1 99.2 0.12 0 0.15 0.121 0.37 0.12 – – – – – –

Wolonghe Wo67 3291 P1 99.0 0.18 0.007 0.40 0.189 0.23 0.15 � 31.89 � 32.23 – – – –

Wolonghe Wo68 4046 P1 99.1 0.10 0.004 0.34 0.105 0.05 0.37 – – – – – –

Wolonghe Wo83 3413 P1 99.2 0.15 0.007 0.19 0.158 0.26 0.15 � 31.69 � 32.79 – � 140 + 5.7b –

Wolonghe Wo48 3817 C2 98.9 0.25 0.018 0.41 0.270 0.09 0.31 � 32.35 � 35.72 – – – –

Wolonghe Wo52 4594 C2 99.0 0.20 0.018 0.36 0.220 0.10 0.34 � 32.13 � 35.34 – – – –

Wolonghe Wo58 3771 C2 99.0 0.23 0.018 0.35 0.250 0.11 0.25 � 32.25 � 35.69 – – – –

Wolonghe Wo65 4138 C2 98.9 0.32 0.015 0.27 0.338 0.14 0.32 � 32.24 � 36.05 � 140 – –

Wolonghe Wo85 4518 C2 98.4 0.35 0.026 0.35 0.381 0 0.87 � 32.13 � 36.26 – – – –

Wolonghe Wo96 3951 C2 99.8 0.17 0 0 0.170 0 0 � 32.98 � 35.46 – � 140 + 5.8b –

Weiyuan Wei100 3000 Z2 93.4 0.07 0 1.98 0.075 0.60 3.98 � 32.38 � 31.82 – � 139 – –

Weiyuan Wei109 2832 Z2 93.5 0.04 0 1.89 0.043 0.67 3.87 � 32.37 � 31.19 – � 120 – –

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 d34Smeasurement in this current study are similar to those

by Sheng et al. (1997), who measured H2S d34Ssimultaneously 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

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 con-

tain < 5% by volume H2S by volume. Concentra-

Table 3

Maximum H2S percentages, d34S, 3He/4He, thiophene and thiol contents incorresponding strataa

Strata Rob

(%)

H2S

maxi (%)

Thiophenes

(mg/m3)

Thiols

(mg/m3)

Whole basin

(excluding the e

3He/4He

� 10� 8

d3

(x

J1t 0.9–1.4/

1.2 (n= 8)

0.6 0.90–6.40 <DTc –d –

T3 – –

T2l3 1.0–2.2/

1.6 (n= 3)

13.3 – – – –

T2l1 2.7 – – 1.1

(n= 1)

�+ 8

T1j 1.2–1.5 32.0 0.10–1.35 <DT to

1244

1.1–3.6

(n= 4)

+

+ 1

T1f 1.1–2.0/

1.6 (n= 4)

2.5 – – – ��

P 1.8–3.0/

2.2 (n= 9)

3.4 0.03–0.32 0.11–2.00 1.6–3.0/2.2

(n= 4)

+

+ 2

+ 1

C 2.6 (n= 1) 0.7 – – – –

Sinian 3.6–3.7

(n= 2)

3.4 0.10–0.20 0.14–4.04 0.6–2.8/1.7

(n= 2)

+

+ 1

a Data present in the form of range/average (number of samples).b 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. (19

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

natural gases and organic matter vitrinite reflectance Ro values of the

ast)

Eastern part

(including Wolonghe area)

4SH2S

)

3He/4He

� 10� 8

d34SH2S

(x)

– –

– –

6.0 to + 17.7/

.3 (n= 3)e– –

6.8 to + 29.1/

3.6 (n= 23)

1.89–3.62

(n= 2)

+ 22.9 to + 24.7 (n= 2)

+ 22.2 to + 31.0 / + 27.5 (n= 4)e

6.0 to + 4.81/

1.2 (n= 2)

– –

20.4 to + 29.7/

4.1 (n= 17),

3.3

1.83–2.20

(n= 2)

+ 5.7 to + 12.8/

+ 9.3 (n= 2)

2.09–2.72/2.50

(n= 6)

� 9.6 to + 8.5/

+ 2.2 (n= 7)

11.5 to + 14.4/

3.1 (n= 4)

– –

97) and Dai (1986).

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.

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.


in gas from Upper Triassic and Jurassic sandstone

reservoirs (Dai, 1986).

Gases from different systems have H2S with dif-

ferent 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 Forma-

tion (T1j) have d34S values from + 12xto + 16xwith two anomalous values of + 6.8xand + 29.1xin the Naxi area in the southeast of the basin (Table 3;

Fig. 1). Two samples from the Lower Triassic Feix-

ianguan Formation (T1f) and the basal Middle Triassic

Leikoupo Formation (T2l1) have the same most neg-

ative 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 corre-

spond 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. 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).

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).


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).

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 Juras-

sic freshwater – lacustrine sandstone reservoirs.

Sinian, Permian and Triassic carbonate reservoirs

routinely have gases with relatively low concentra-

tions ( < 0.20 mg/m3) of thiophenes (Fig. 7). The

Lower Jurassic sandstone reservoirs produce light

oil, condensate and associated natural gas, but con-

tain < 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. 9. Relationship between thiol and H2S content of gas in the

Triassic part of the section in Wolonghe).

Fig. 10. Relationship between d13CCH4and d13CC2H6

� d13CCH4for

samples from the whole basin and Wolonghe Field.


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 concentra-

tions 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 concen-

trations are associated with the highest H2S concen-

trations 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 be-

tween 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.

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

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).

d13CCH4values from Jurassic gas ranges from

� 37xto � 44xPDB. Gas samples from Triassic,

Permian and Sinian reservoirs have d13CCH4values

>� 36xPDB. The majority of gas samples from

Triassic, Permian and Sinian reservoirs have d13CC2H6

closer to d13CCH4than those from Jurassic reservoirs.

The gases with more negative d13CCH4generally

have a greater difference between d13CC2H6and

d13CCH4(Table 2). Two gas samples from Permian

reservoirs have d13CCH4values less negative than

d13CC2H6.

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.

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 d13CCH4values from � 34.5x

to � 32.6xPDB and d13CC2H6values from � 29.4x

to � 28.2xPDB. d13CC2H6values are always less

negative than d13CCH4values. d13CCH4

values lie in

between those of gases in Jurassic and Permian and

Sinian reservoirs (Fig. 10). Relationships between

d13CCH4and d13CC2H6

show that the gas in the

Triassic has more negative d13CCH4values and less

negative d13CC2H6values 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 thermochem-

ical sulphate reduction (Worden and Smalley, 1996).

There are positive relationships between both d13CCH4

and d13CC2H6with 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 has3He/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).

5. Discussion

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 d34Svalues are generally characteristic of an oxidized

(sulphate) sulphur source, rather than reduced sul-

phur 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 d34Ssulphide are the result of sulphate reduction. Given

the relatively high temperatures in the basin, reduc-

tion 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 migra-

tion 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 distri-

bution of thiophene compounds to consider. Al-

though 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 sedimen-

tary 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.


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 maxi-

mum 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 mini-

mum 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 compo-

sition, the rock fabric (e.g., anhydrite crystal size;

Worden et al., 2000), timing of petroleum emplace-

ment into the structure and wettability (where water-

wet 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 andMiddle

Triassic, which suggest that compartmentalisation is

predominant in the basin. Although anhydrite is abun-

dant within the Triassic section, it is concentrated

within the Fourth and FifthMembers of the Jialingjiang

Formation. Indeed, elevated H2S concentrations have

been found exclusively in the Fourth and Fifth Mem-

bers (Fig. 5) and H2S loss due to reactions in the

reservoir with elements such as Fe and Zn is insignif-

icant 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-Cou-

loume, 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:

3H2SðgÞ þ SO2�4 ðaqÞZ4So þ 2H2Oþ 2OH� ðR1Þ

followed by the subsequent further reduction of ele-

mental sulphur by hydrocarbons:

4So þ 1:33ð�CH2Þ þ 2:66H2O

Z4H2SðgÞ 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

ZHCO�3 ðaqÞ þ H2SðgÞ þ H2O 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


34S 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 Carbon-

iferous 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 (approxi-

mately + 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 (� 9.6x to

+ 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

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 con-

centrations ( < 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


rock type and source maturity (advanced maturation

can lead to increases in d13CCH4; 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 hydro-

carbons have been shown in some basins to in-

crease progressively (Krouse et al., 1988; Rooney,

1995; Worden and Smalley, 1996; Whiticar and

Snowdon, 1999). Positive relationships exist be-

tween d13CCH4and H2S/(H2S +SC1–6) and between

d13CC2H6and H2S/(H2S +SC1–6) in the Wolonghe

gases in the Triassic reservoirs. The positive rela-

tionship between methane and ethane carbon iso-

topes and the gas souring index values from the

Wolonghe Field (Fig. 11) may be a consequence of

TSR due to preferential reaction of 12C-hydrocar-

bons, 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. Further-

more, 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 com-

pounds 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 matu-

rity. The possible causes of the thiophene distribution

in the Sichuan Basin include:

(1) Thermally controlled cracking of organosulphur-

bearing materials (oil or kerogen).

(2) Back-reaction of H2S with hydrocarbons.

(3) Intermediate TSR reactant.

The source rocks of the natural gases in the Palae-

ozoic 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 kerogen-

sulphur content, it might be expected that the thio-

phene distribution would be the opposite of that

found. However, the petroleum with the S-poor source

rock has the highest thiophene concentrations. Thus,


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 func-

tion 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 concentra-

tions 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 sul-

phur is routinely incorporated into petroleum at rela-

tively 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-

Fig. 12. Relationship between vitrinite reflectance and thiophene concentr

thiophene concentrations seem to decrease in a systematic manner with in

ever, double bonds in hydrocarbons have been gen-

erated 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 non-

thiophenic 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 thio-

phene 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-

ation. The figure summarises a large volume of data but shows that

creasing source rock maturity.


lkylthiophenes after heating n-octadecane in the pres-

ence 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 reac-

tion 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 Juras-

sic 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 thermo-

chemical 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 asso-

ciated 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 com-

pounds. 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]

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