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www.elsevier.com/locate/chemgeo
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.
C. Cai et al. / Chemical Geology 202 (2003) 39–5742
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).
C. Cai et al. / Chemical Geology 202 (2003) 39–57 43
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 – – – –
Wolonghe Wo17 1652 T1j41– j
33 97.6 0.37 0.052 0.05 0.431 1.56 0.36 – – – – – 788
Wolonghe Wo37 1926 T1j41– j
33 96.9 0.65 0.087 0.12 0.755 1.40 0.81 � 34.5 � 29.9 � 26 – – –
Wolonghe Wo50 1902 T1j41– j
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).
C. Cai et al. / Chemical Geology 202 (2003) 39–5744
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.
C. Cai et al. / Chemical Geology 202 (2003) 39–57 45
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.
C. Cai et al. / Chemical Geology 202 (2003) 39–5746
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).
C. Cai et al. / Chemical Geology 202 (2003) 39–57 47
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.
C. Cai et al. / Chemical Geology 202 (2003) 39–5748
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.
C. Cai et al. / Chemical Geology 202 (2003) 39–57 49
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.
C. Cai et al. / Chemical Geology 202 (2003) 39–5750
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
C. Cai et al. / Chemical Geology 202 (2003) 39–57 51
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
C. Cai et al. / Chemical Geology 202 (2003) 39–5752
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,
C. Cai et al. / Chemical Geology 202 (2003) 39–57 53
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.
C. Cai et al. / Chemical Geology 202 (2003) 39–5754
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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