Gas genetic type and origin of hydrogen sulfide in the Zhongba gas field of the western Sichuan Basin, China

Applied Geochemistry 26 (2011) 1261–1273

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Gas genetic type and origin of hydrogen sulfide in the Zhongba gas field of the western Sichuan Basin, China Guangyou Zhu a,b, Shuichang Zhang a,b, Haiping Huang c,d,⇑, Yingbo Liang a, Shucui Meng a, Yuegang Li e a

Research Institute of Petroleum Exploration and Development, PetroChina, Beijing 100083, China State Key Laboratory for Enhanced Oil Recovery, Beijing 100083, China c School of Energy Resource, China University of Geosciences, Beijing 100083, China d Department of Geosciences, University of Calgary, 2500 University Drive NW, Calgary, Canada AB T2N 1N4 e Northwest Sichuan Gas Field, PetroChina Southwest Oil and Gas Field Company, Jiangyou, 621101 Sichuan, China b

a r t i c l e

i n f o

Article history: Received 7 September 2010 Accepted 17 April 2011 Available online 22 April 2011 Editorial handling by R. Fuge

a b s t r a c t Natural gases and associated condensate oils from the Zhongba gas field in the western Sichuan Basin, China were investigated for gas genetic types and origin of H2S by integrating gaseous and light hydrocarbon geochemistry, formation water compositions, S isotopes (d34S) and geological data. There are two types of natural gas accumulations in the studied area. Gases from the third member of the Middle Triassic Leikoupo Formation (T2l3) are reservoired in a marine carbonate sequence and are characterized by high gas dryness, high H2S and CO2 contents, slightly heavy C isotopic values of CH4 and widely variable C isotopic values of wet gases. They are highly mature thermogenic gases mainly derived from the Permian type II kerogens mixed with a small proportion of the Triassic coal-type gases. Gases from the second member of the Upper Triassic Xujiahe Formation (T3x2) are reservoired in continental sandstones and characterized by low gas dryness, free of H2S, slightly light C isotopic values of CH4, and heavy and less variable C isotopic values of wet gases. They are coal-type gases derived from coal in the Triassic Xujiahe Formation. The H2S from the Leikoupo Formation is most likely formed by thermochemical SO4 reduction (TSR) even though other possibilities cannot be fully ruled out. The proposed TSR origin of H2S is supported by geochemical compositions and geological interpretations. The reservoir in the Leikoupo Formation is dolomite dominated carbonate that contains gypsum and anhydrite. Petroleum compounds dissolved in water react with aqueous SO4 species, which are derived from the dissolution of anhydrite. Burial history analysis reveals that from the temperature at which TSR occurred it was in the Late Jurassic to Early Cretaceous and TSR ceased due to uplift and cooling thereafter. TSR alteration is incomplete and mainly occurs in wet gas components as indicated by near constant CH4 d13C values, wide range variations of ethane, propane and butane d13C values, and moderately high gas dryness. The d34S values in SO4, elemental S and H2S fall within the fractionation scope of TSR-derived H2S. High organo-S compound concentrations together with the occurrence of 2-thiaadamantanes in the T2l reservoir provide supplementary evidence for TSR related alteration. Ó 2011 Elsevier Ltd. All rights reserved.

1. Introduction Hydrogen sulfide is generally an undesirable component of natural gas. Where present, H2S cannot only critically affect the economic value of hydrocarbon gas in the reservoir, but it is highly toxic, and corrosive for production equipment. Hydrogen sulfiderich gases have been found in many basins with the highest H2S up to 98% (Krouse et al., 1988; Machel et al., 1995; Worden and Smalley, 1996; Worden et al., 1996, 2000; Heydari, 1997; Manzano et al., 1997; Belenitskaya, 2000; Machel, 2001; Cai et al., 2003a, ⇑ Corresponding author at: Department of Geosciences, University of Calgary, 2500 University Drive NW, Calgary, Canada AB T2N 1N4. Tel.: +1 403 2208396. E-mail address: [email protected] (H. Huang). 0883-2927/$ - see front matter Ó 2011 Elsevier Ltd. All rights reserved. doi:10.1016/j.apgeochem.2011.04.016

2004; Zhang et al., 2005; Zhu et al., 2005, 2007a, 2010; Jafar et al., 2006). Bacterial SO4 reduction (BSR) and thermochemical SO4 reduction (TSR) are the two main processes for high H2S in oil and gas fields even though mantle and volcanic outgassing, kerogen decomposition, oil thermal cracking, asphaltene thermal degradation and reaction of S with hydrocarbons can contribute to a small portion of H2S. The SO4 for BSR can be from connate waters, anhydrite dissolution, injected seawater, or pyrite oxidation by injected water, however, BSR typically does not result in gases containing >5% H2S. TSR is the reaction of sulfate minerals (primarily anhydrite) and hydrocarbons to form H2S, CaCO3 and other minor components. Because anhydrite is often associated with carbonate sequences, TSR is commonly associated with deep, hot carbonate reservoirs. TSR is the most important process for formation of high

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H2S gases (>10% H2S) (Machel et al., 1995; Manzano et al., 1997; Machel, 2001). This reaction can lead to the complete destruction of petroleum accompanied by the generation of a large amount of H2S. The reaction mechanisms, dynamics of H2S, temperature regime, natural products, and geochemical characteristics of TSR have been well summarized in the literature on the basis of case studies, as well as the experimental and theoretical data (Krouse et al., 1988; Hutcheon et al., 1995; Worden et al., 1996, 2000; Heydari, 1997; Bildstein et al., 2001; Cross et al., 2004; Zhu et al., 2007b; Zhang et al., 2007, 2008b; Amrani et al., 2008; Zhang et al., 2008a). The rate of aqueous redox interaction between SO4 and hydrocarbons and diffusion-controlled dissolution of anhydrite and hydrocarbons are the two main rate-controlling processes for TSR (Bildstein et al., 2001). Hydrogen sulfide gas risk has become one of the major concerns for exploration in deeply buried carbonate reservoirs in China. Sichuan Basin is one of the most prolific natural gas producing basins, where TSR is common and widespread in the deep burial carbonate reservoirs. The gigantic gas pools recently discovered in the eastern Sichuan Basin such as the Puguang and the Luojiazhai gas fields are rich in H2S. Depositional facies, temperature regime, gas chemical and isotopic compositions and occurrence of pyrobitumen indicated high H2S content in natural gas to be the result of TSR alteration (Cai et al., 2004, 2010; Dai et al., 2004; Hao et al., 2008; Ma et al., 2008; Zhu et al., 2005). In contrast to the ubiquitous H2S occurrence in the east, H2S in the western Sichuan Basin is only locally distributed, mainly in the Middle Triassic Leikoupo Formation with relatively low content (average of H2S around 6%). The Leikoupo Formation consists of marine carbonate and evaporative succession and the dissolved sulfate derived from dissolution of solid calcium sulfate (mainly gypsum and anhydrite) can stimulate the occurrence of TSR. However, TSR appears to be common in geologic settings with temperatures of about 120–140 °C, and in some settings temperatures of 160–180 °C appear to be necessary (Machel, 2001). Current reservoir temperature of below 100 °C in the Leikoupo Formation at the western Sichuan Basin seems not ideal for TSR occurrence, while BSR is also unlikely to happen since most microorganism including SO4 reducers can rarely survive at temperatures above 80 °C under reservoir conditions (Head et al., 2003). In order to assess the origin of H2S and minimize the risk of encountering high H2S gas in the west Sichuan resource exploitation, natural gas and condensate samples from the Zhongba gas field have been thoroughly investigated in the present study. The results will provide deep understanding both the origin and destruction of H2S in petroliferous basins with similar depositional facies and thermal evolution history.

2. Geological background Sichuan Basin with an area of 190,000 km2, developed over preCambrian metamorphic rocks, and is a NE-trending rhombic and petroleum prolific basin on the Yangtze platform (Fig. 1). Based on the nature of basement, sedimentary sequence, reservoir lithology and petroleum genetic types, Sichuan Basin can be divided into four oil and gas accumulation zones, i.e., the eastern, western, southern and central blocks (Fig. 1). Over 20 gas fields with varying size have been discovered in the eastern Sichuan Basin (Wang et al., 2004), while only a few small gas fields have been discovered in the western Sichuan Basin. Zhongba gas field is one of the important gas fields located in the northwestern Sichuan region. Crude oil is limited to the Lower Jurassic clastic reservoirs of the central Sichuan Basin (Fig. 1). The tectonic evolution and stratigraphy of the basin have been investigated in detail by numerous studies (Cai et al., 2003a,b; Li

et al., 2005; Hao et al., 2008; Ma et al., 2008). The sedimentary sequences above the basement are well developed and preserved with a residual thickness of 8000–12,000 m (Fig. 2). Marine carbonates are dominant from the Sinian (Upper Proterozoic) through to the Middle Silurian and fine detrital rocks marine formed in the Upper Silurian. As a result of the late Silurian Caledonian Orogeny, a large hiatus occurred during the Devonian and Lower Carboniferous in the Sichuan Basin, with the Carboniferous Huanglong Formation (C3hl) only being developed in a part of the eastern Sichuan Basin. Marine transgression occurred during the Early Permian and the Lower Permian section is composed of platform carbonates interbedded with fluvial and lacustrine sandstones and mudstones. The Upper Permian Longtan (P2l) and Changxing (P2c) formations are composed of alternating marine and terrigenous carbonate, marl, mudstone and coal-bearing successions, which form one of the most important source rocks in the basin. The marine and terrigenous transitional facies continue to the Early Triassic with the Feixianguan (T1f) and the Jialingjiang (T1j) formations being deposited. The Indosinian Orogeny during the Middle to Late Triassic (episode I) made the basin tilt westward with deep marine facies in the west and shallow marine facies in the east when the Leikoupo (T2l) Formation was deposited. Limestone, dolomite and laminated gypsum and salt were developed in a restricted marine platform facies during that time period. The Indosinian tectonic movements at the end of the Triassic resulted in changes from marine to continental sedimentation in the whole Sichuan Basin. The Upper Triassic Xujiahe Formation (T3x) is virtually absent in the eastern Sichuan Basin, while this formation was deposited under freshwater conditions with lacustrine-alluvial sandstones, shales and sparse coal beds in the west. The Jurassic and Cretaceous sediments are composed of continental red sandstones, mudstones, black shale and laminated thin coal (Cai et al., 2003b). The Yanshanian Orogeny from the Late Jurassic to the Early Cretaceous resulted in uplift of the basin and folding at the basin margin. The Sichuan Basin was entirely uplifted due to the movement of the Pacific plate during the Tertiary Himalayan Orogeny. Zhongba gas field, situated in a low anticline in the front of the Longmengshan thrust zone, is controlled by a narrow, NE–SW oriented anticline, and is cut by the Zhangming and Jiangyou faults (Fig. 3). While gas accumulations occur in the Carboniferous, Permian and Lower Triassic strata in the eastern Sichuan Basin, commercial gas pay zones in the west are found only in the third member of the Middle Triassic Leikoupo Formation (T2l3) and the second member of the Upper Triassic Xujiahe Formation (T3x2) (Fig. 3, Table 1). The two gas pay zones are overlapping vertically, more or less 800 m apart. The shallow gas pool has a larger lateral extension than its deep counterpart (Fig. 3). The T2l3 gas pool has a marine carbonate reservoir with an enclosure area of 13.4 km2 and proven gas in place of 86.3  108 m3. Gas condensate in this pool is in a proportion of 65.45–74.28 g/m3 with reserves of 74  104 m3 (Peng and Yi, 2004). The burial depth of the pay zone is in the range of 3100– 3400 m and current reservoir temperature is around 88 °C. The gas reservoir is slightly over-pressured with an initial reservoir pressure of 35.3 MPa and pressure coefficient of 1.15. The H2S content of the T2l3 gas reservoir varies from 4.90% to 8.34% with an average value of 6.52% (Table 1). The T3x2 gas pool is reservoired in a set of delta facies sandstones with proven reserves of 100.5  108 m3 (An et al., 2003). This reservoir is characterized by a low proportion of condensate and is free of H2S. The burial depth of the pay zone varies from 2100 m to 3000 m and current reservoir temperature is 65–90 °C. The gas reservoir is normally pressured with a pressure coefficient of 1.07 (Table 1). The Leikoupo Formation was largely deposited as an evaporite platform facies with oolitic dolomite or limestone that contains

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Fig. 1. Distribution of major oil and gas in the Sichuan Basin (top) and schematic east–west cross section of the Sichuan Basin showing the range of burial depths (below) (modified from Zhai, 1992).

anhydrite nodules within the reservoirs. The residual thickness of the formation is 500–600 m and it can be divided into three members, i.e., T2l1, T2l2 and T2l3, respectively (Fig. 2). The second member (T2l2) is a tight zone which consists of massive gypsum, dolomite and laminated dolomitic gypsiferous rock with a thickness of about 200 m. Mercury injection capillary pressure analysis shows very low permeability, and it forms the bottom seal for the gas reservoir. The lower part of the T2l3 member, main gas reservoir in the study area, is composed of gray, fine crystal algal dolomite with a thickness of about 100 m. Both primary porosity from intergranular, intragranular, intercrystal and intracrystal pores and secondary porosity through particle dissolution are well developed in this interval. Pinholes along fractures are more than 40 pores/ cm2 and porosity is in the range 0.24–11.95% with an average value of 3.94% (unpublished data). The upper part of the T2l3 member with a residual thickness around 100 m is another tight zone with

an average porosity of 1.485% and permeability of 0.8239 millidarcy (md). It forms the top seal for the T2l3 gas pool and separates H2S-rich gas from sweet gas in the T3x2 reservoir. The Xujiahe Formation (T3x) was deposited under non-marine conditions, where sandstones, shales and coals were formed. Sandstones deposited in delta facies are only developed in the second member of the formation (T3x2) with an effective thickness of 60–100 m. The T3x2 pool has a fracture-pore type reservoir with an average porosity of 5.6% and permeability usually below 1 md. Mudstone developed in the T3x3 member forms a direct seal for the gas reservoir (Luo and Wang, 1996; Qu, 2004). 3. Material and methods Eight natural gases and three condensates were collected from production wells, eight anhydrite and four sulfur samples were

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Fig. 2. Stratigraphic column and petroleum system components in the western Sichuan Basin with enlarged portion showing principal pay zone in the Zhongba gas field and reservoir properties of T2l3 member.

collected from drilling cores and one sulfur sample was collected from a local refinery factory. Light hydrocarbons and biomarkers were analyzed by gas chromatography–mass spectroscopy (GC– MS) on an HP6890 GC interfaced to a quadrupole HP5973 mass selective detector (MSD). Thiaadamantanes were obtained from the non-hydrocarbon fraction by chromatography on AgNO3 impregnated silica gel eluted with dichloromethane (DCM) and DCM/MeOH (1:9, v/v) mixed solvent. Concentrated samples were injected on an Equity-5 column (60 m  0.25 mm  0.25 lm) with an initial temperature of 50 °C, held for 2 min, programmed at 3 °C/ min to 200 °C and 10 °C/min to 320 °C for a hold time of 20 min. Helium was used as carrier gas. 2-Thiaadamantanes were assigned by comparison of mass spectra with published data (Wei et al., 2007, and references therein). The molecular composition of hydrocarbon gases was determined on an Agilent 6890N gas chromatograph equipped with a flame ionization detector (FID). The fused silica capillary column is Poraplot Q (30 m  0.25 mm  0.25 lm) with a He carrier and temperature program: initial 70 °C held for 5 min, increased to 180 °C at 15 °C min1, held for 15 min. Carbon isotope compositions of natural gases were measured with an Isochrom II isotope ratio mass spectrometer connected to an Agilent 6890 gas chromatograph through a combustion chamber (GC–IRMS) with a He carrier and temperature program: initial 50 °C held for 3 min, increased to 150 °C at 15 °C/min, held

8 min. Carbon isotope compositions are reported in the usual dnotation relative to the PDB standard. The reproducibility of the duplicate C isotope measurement is ±0.5‰. Sulfur isotope analyses of the gypsum, S and H2S were performed on a Finnigan-MAT 253 mass spectrometer. The sulfides were combusted to SO2 using a flash elemental analyzer (Finnigan™) prior to isotopic analysis. CDT was used as an international reference for S isotopic (d34S) values with an analytical precision of ±0.2‰. The formation water analysis data for common anion and cation concentrations were collected from unpublished reports of the Sichuan Oil and Gas Company.

4. Results 4.1. Chemical composition of natural gas There is a distinct compositional difference between the two reservoirs, even though analyses of gas composition listed in Table 2 cover several years of sample collection. Gas from the T2l3 reservoir has a CH4 content in the range of 81.36–85.54% and wet gas contents (C2–C6 hydrocarbons) from 2.44% to 5.56% with an average value of 3.33%. Gas densities vary from 0.65 to 0.68 g/ cm3 and gas to oil ratios (GOR) are between 13,463 and

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Fig. 3. Structural map of the T2l3 gas reservoir top (upper left), T3x2 gas reservoir top (upper right) and cross section of the Zhongba gas field showing gas distributions (below) (modified from Zhai, 1992).

Table 1 Basic parameter for T2l3 and T3x2 gas reservoirs in Zhongba gas field. Pool 2

Closure area (km ) Proven reserve (m3) Burial depth (m) Lithology Thickness (m) Average porosity (%) Temperature (°C) GOR (m3/m3) Pressure coefficient CH4 (%) Cþ 2 (%) H2S (%)

T2l3

T3x2

13.4 86.3  l08 3100–3400 Dolomite 100 3.94 88.3 13,463–15,279 1.15 84 3.6

24.5 100.52  l08 2100–3000 Sandstone 60–100 5.6 75 30,000 1.07 90 9.5

6.52

0

15,279 m3/m3. This reservoir is characterized by a high content of H2S and CO2, with a small amount of condensate oil production (Table 2). The average H2S concentration is 6.65%, and average CO2 concentration is 4.23%. Gas from the T3x2 pool contains a high proportion of CH4 (81.08–92.9%) with relatively low dryness (C1/Cþ 1 = 0.84–0.93), consistent with the low thermal maturity of the natural gases in the western Sichuan Basin (Cai et al., 2003b). Gas densities vary from 0.76 to 0.86 g/cm3. Condensate oil produced from this pool is less than that from the T2l3 pool. The condensate contains 82.7% of saturated hydrocarbons, reflecting primary origin rather than being derived from evaporative fractionation (Thompson, 1988). No H2S has been detected from this reservoir and CO2 content varies from 0.03% to 0.84%.

4.2. Isotopic composition of natural gas The variation of d13C values in CH4 and C2H6 for the Zhongba gases, together with the known origin gases in the western Sichuan Basin, is displayed in Fig. 4. The stable C isotope ratios of the Zhongba gas components show large difference between the two reservoirs (Table 3). The T2l3 gases are characterized by slightly heavy isotopic CH4 and light but widely variable isotopic values in the wet gas components. The d13C values of CH4 fall in a narrow range from 36.9‰ to 33.8‰, while the d13C values for ethane (C2) span a wide range from 31.1‰ to 27.1‰. Propane (C3) has the largest variation of d13C values from 30.3‰ to 22.1‰, and butane (C4) has d13C values in the range from 30.4‰ to 26.5‰. Carbon isotopes of natural gas from the T3x2 gas reservoir are characterized by slightly light isotopic CH4 and heavy but uniform isotopic values of the wet gas components. The d13C values of methane, ethane, propane and butane are in the range of 37.25‰ to 35.79‰, 26.04‰ to 25.01‰, 23.6‰ to 23.11‰ and 25.12‰ to 22.41‰, respectively. 4.3. Light hydrocarbons and diamondoid hydrocarbons in condensate oil Light hydrocarbons are important components of petroleum and are very useful for gas and oil genetic classification, maturity assessment and oil-source correlation (Thompson, 1983, 1988; Mango, 1987, 1990, 1997). Light hydrocarbons are commonly regarded as products of thermal cracking of heavy molecular weight

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Table 2 Chemical compositions of natural gas in Zhongba gas field (%) (partial data from Sichuan Oil and Gas Company unpublished reports). Well

Strata

Ch19 Zhl8 Zh21 Zh23 Zh24 Zh3 Zh40 Zh42 Zh46 Zh8 Zh80 Zh81

3

Ch22 Zh11 Zh13 Zh14 Zh16 Zh17 Zh18 Zh19 Zh2 Zh20 Zh24 Zh25 Zh29 Zh3 Zh31 Zh32 Zh34 Zh44 Zh47 Zh5 Zh52 Zh53 Zh54 Zh6 Zh60 Zh62 Zh55 Zh8 Zh9

Cþ 2

Depth (m)

CH4

C2H6

C3H8

C4H10

T2l T2l3 T2l3 T2l3 T2l3 T2l3 T2l3 T2l3 T2l3 T2l3 T2l3 T2l3

3351–3355 3100–3232.1 3298–3319.5 3040–3155 3145–3253 3392–3460 3110–3126.5 3322.4–3410 3075–3139 3382.7–3450 3075–3166 3191–3289

82.64 82.98 85.11 83.01 82.39 84.01 83.14 84.42 85.54 85.18 85.23 81.36

1.86 1.69 1.73 1.85 1.78 1.76 4.51 2.71 1.7 1.73 1.58 3.85

0.56 0.68 0.54 0.8 0.72 0.51 0.6 0.55 0.462 0.52 0.49 0.49

0.38 0.72 0.35 0.96 0.97 0.27 0.177 0.276 0.287 0.31 0.37 0.541

2.8 3.09 2.62 3.61 3.47 2.54 5.56 3.92 2.45 2.56 2.44 4.88

T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2 T3x3 T3x2 T3x2 Tx3 T3x2 T3x2 T3x2 T3x2

2218–2604 2845.3–3004.4 3768.5–3939 3265.8–3289.2 2426–2529 2427.6–2494 2250–2430 2589.5–2612 2314.6–2501.1 2509.3–2674 2565–2666 2505–2666 2269–2361 2541–2625 2522–2950 2851.1–3050 2409.1–2373 2494–2600

91.23 83.26 90.83 83.34 88.47 89.72 88.34 89.1 90.89 88.54 91.83 89.87 88.34 90.6 88.79 84.47 89.93 88.55 90.46 87.35 90.08 92.9 90.41 81.98 87.37 88.65 87.54 90.49 90.29

5.79 9.46 6.24 8.7 6.63 6.99 6.46 7.72 6.09 8.06 5.53 6.31 8.69 5.82 8.05 9.85 5.81 8.2 5.82 7.21 6.23 5.17 5.91 6.81 9.74 8.15 8.29 5.82 6.14

1.63 4.19 1.24 3.88 2.25 1.73 2.05 1.84 1.56 1.86 1.45 1.85 1.81 1.52 1.83 3.48 1.71 1.96 1.67 2.32 1.78 1.19 1.71 3.34 1.94 1.88 1.98 1.61 1.81

0.66 1.87 0.48 2.07 0.564 0.358 0.95 0.394 0.44 0.353 0.67 0.429 0.348 0.426 0.355 0.4 0.4 0.411 0.774 1.21 0.746 0.438 0.735 1.79 0.723 0.776 0.892 0.75 0.471

8.08 15.52 7.96 14.65 10.03 9.45 9.46 10.33 8.44 10.61 7.65 9.01 11.16 8.11 10.56 13.73 8.51 10.95 8.722 10.74 8.76 6.8 8.8 11.94 12.4 10.81 11.16 8.18 8.9

2464.6–2529 2355–2480 2015.1–2100 2964.5–3016 2054.7–2094 2500.5–2607 2618.5–2737.6 2514–2635 2238–3100

H2S

CO2

N2

Ar

He

H2

7.65 6.75 5.25 5.99 7.11 7.72 5.67 6.86 5.76 8.34 6.39 6.24

5.67 4.51 5.43 5.2 4.95 4.06 4.18 3.29 4.17 1.43 4.01 4.66

1.15 1.67 1.36 1.37 1.89 1.39 1.11 0.79 1.77 2.12 1.41 1.31

0

0.056

0.005

0.053 0.067 0.063

0.03 0.05 0.09 0.05 0.05 0.07 0.004 0 0.001 0.08 0.007 0.007

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0.5 0.06 0.1 0.32 0.43 0.46 0.76 0.3 0.31 0.46 0.24 0.34 0.34 0.97 0.32 0.08 0.38 0.32 0.5 0.11 0.4 0.03 0.34 2.62 0 0.29 0.81 0.05 0.16

0.03 0.69 0.95 0.7 0.38 0 0.9 0 0.09 0.13 0.56 0.32 0.01 0.07 0.11 0.72 0.46 0.01 0.28 1.72 0.4 0.03 0.25 2.81 0 0 0 0.85 0.03

0.06 0.071

0.003

0.018 0.019 0.012 0.017 0.016

0.002

0.019 0.016 0.016 0.01

0.005

0.018 0.021

0.012 0.003 0.002

0.021 0.017 0.016 0.018 0.016 0.011 0.017

0.03 0.04 0.05 0.06 0.002 0.005 0.04 0.004 0.01 0.005 0 0.003 0.005 0.014 0 0.05 0.006 0.014 0.04 0.006 0.04 0.011 0.07 0.009 0.004 0.009 0.06 0.017

metals were catalytic agents in the generation of light hydrocarbons. Three condensate oil samples from Well Zh81 (T21), Well Zh47 (T3x) and Well Zh54 (T3x) were analyzed for their light hydrocarbon compositions and some geochemical parameters are listed in Table 4. Diamondoid hydrocarbons are very resistant to biodegradation and thermal destruction. Because diamondoid hydrocarbons share the three-dimensional configuration of C atoms found in the lattice of diamond crystals, they are the most thermally stable of complex saturated hydrocarbons in the Earth’s crust (Petrov, 1987). Consequently, diamondoid hydrocarbons are progressively concentrated by thermal cracking as other oil components are destroyed (Dahl et al., 1999). The concentrations of 2,3-dimethyladamantane in wells Zh54, Zh47 and Zh81 are 80, 82 and 131 lg/g oil; while concentrations of 3- and 4-methyldiamantane are 473, 435 and 3755 lg/g oil. High diamondoid hydrocarbon concentration in the T2l3 oil (well Zh81) reflects high maturity and a high degree of thermal cracking. 5. Discussion Fig. 4. Carbon isotope ratios (d13C) of methane and ethane for the Zhongba hydrocarbon gases.

hydrocarbons in pre-existing oil at elevated temperatures (Tissot and Welte, 1984), however, Mango (1990) proposed that transition

There have been many discussions on the potential sources of H2S in petroleum reservoirs (Krouse et al., 1988; Goldhaber and Orr, 1995; Worden et al., 1996; Heydari, 1997; Machel, 2001; Zhang et al., 2005). Bacterial SO4 reduction is unlikely in the studied area since reservoir temperature is above 80 °C, which forms

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G. Zhu et al. / Applied Geochemistry 26 (2011) 1261–1273 Table 3 Carbon isotopic values (d13C) of hydrocarbon gases and carbon dioxide from selected wells in Zhongba gas field.

a

Well

Strata

Depth (m)

d13CPDB (‰) C1

C2

C3

C4

C5

C6

CO2

Zh23 Zh21 Zh46 Zh81 Zh18a Zh21a Zh24a Zh54 Zh29a Zh34a Zh31 Zh39 Zh71

T2l3 T2l3 T2l3 T2l3 T2l3 T2l3 T2l3 T3x2 T3x2 T3x2 T3x2 T3x2 T3x2

3040–3155 3298–3319.5 3075–3139 3191–3289 3100–3232.1 3298–3319.5 3145–3253 2410 2269–2361 2409.1–2373 2522–2950

35.1 34.8 35.26 33.8 36.9 35.4 35.7 36.3 36.73 36.09 37.25 35.79 35.99

29.2 28.9 30.01 27.1 27.7 31.1 30.3 25.1 25.51 26.04 25.43 26 25.01

27.9 26.9 26.24

30.4 28.8 26.49

29.9 29.3

29.2

5.3 7.1 6.3 6.9

22.1 30.3 27.9 23.6 23.3 23.2 23.29 23.11 23.23

29.6 29.8 27.9 23.3 23.5

24.3

6.1

22.5 25.12 22.41

Data from Qin et al. (2007).

Table 4 Light hydrocarbon geochemical parameters of condensate oil in Zhongba gas field. Well Formation Depth (m)

Zh81 T2l3 3231.7

Zh47 T3x2 2389.97

Zh54 T3x2 2410

nC6 nC7 nC8 CC6 CC7 CC8 Benzene/nC7 Isoheptane value Invariant ratio (kl) V-ratio J-ratio

0.621 0.446 0.265 0.05 0.514 0.688 0.045 2.369 1.267 0.6962 2.113

0.32 0.251 0.095 0.18 1.874 4.452 0.185 1.559 1.127 0.4471 1.8371

0.307 0.216 0.086 0.186 2.303 5.394 0.247 1.611 1.134 0.5353 1.848

nC6: peak area of nC6/(sum of peaks from 2,2-dimethylbutane to nC6); nC7: peak area of nC7/(sum of peaks from 2,2-dimethylpentane to nC7); nC8: peak area of nC8/ (sum of peaks from methyl cyclohexane to nC8); CC6: cyclopentane/nC6; CC7: (methylcyclopentane + cyclohexane + dimethylcyclopentane)/nC7; CC8: (methylcyclohexane + ethylcyclopentane + 1, cis 4-dimethylcyclohexane)/nC8; isoheptane value: (isoheptane + 3-methylhexane)/(1, cis 3-, 1, trans 3-, 1, trans 2-dimethylcyclopentane); invariant ratio (k1): (2-methylhexane + 2,3-dimethylpentane)/(3methylhexane + 2,4-dimethylpentane); V-ratio: normal alkanes/cycloalkanes (sum of compounds eluted between nC3 and nC8); J-ratio: isoalkanes/cycloalkanes (sum of compounds eluted between nC3 and nC8).

the upper limit of life under reservoir conditions even though some Hyperthermophilic archaea and bacteria do exist in oil reservoirs where temperature is up to 100 °C (Setter et al., 1993; Aref, 1998; Head et al., 2003). Thermal decomposition of organic S-containing petroleum and kerogen is mechanism for H2S generation. Temperatures of more than 175 °C are thought to be required to cause the decomposition of organic matter to generate H2S (Aplin and Coleman, 1995). A plot of burial history shows that temperatures of the Triassic strata were never at 175 °C, therefore, it is unlikely that a significant quantity of reduced S could be derived from the decomposition of organic matter. Thermal decomposition of organic matter can also be excluded as the dominant cause because the major gas sources are S-poor coal and shale. However, current reservoir temperature of below 100 °C is not supportive of thermochemical SO4 reduction. The presence of H2S in the western Sichuan Basin is worthy of investigation. 5.1. Thermal history and time of TSR There are two main source rock intervals within the western Sichuan Basin, the Permian Maokou and Longtan formations and the Upper Triassic Xujiahe Formation. The Lower Permian Maokou

Formation (P1m) is dominated by Type I kerogen with average total organic carbon (TOC) of 0.58% (Cai et al., 2003b). The Upper Permian Longtan Formation contains alternating marine and terrigenous mudstone and coal with TOC values of mudstone in the range from 0.86% to 7.47% (average of 2.91%) and d13C values of the kerogen from 24.0‰ to 23.5‰ PDB. The vitrinite reflectance (%Ro) values of the Maokou and Longtan formations are 2.05– 2.70% and 1.89–2.63%, respectively (Cai et al., 2003b; Wang et al., 2004). The organic materials are highly mature and liquid hydrocarbons generated at an earlier stage may have undergone thermal cracking to form natural gas and solid bitumen. The Xujiahe Formation is dominated by terrestrial origin type III kerogen and coal-measure source rock in the western Sichuan Basin (Zhang, 1994). A paralic shore delta facies from shallow marine to semiclosed gulf was deposited during the Late Triassic in the study area. The main source rock with a thickness of about 200 m was developed in the first member of the Xujiahe Formation (T3x1) with TOC in the range of 0.62% to 6.78% and kerogen types of II2 and III. The vitrinite reflectance of the Xujiahe Formation source rocks is 0.9– 1.1%, which reflects the peak oil to wet gas generation stage. Since the Leikoupo Formation has no hydrocarbon generation potential, the source of the gas reservoired in the T2l3 pool is either from the Permian source rocks or from the Triassic Xujiahe source rocks. The C isotopes of the light C2H6 and heavy CH4 in gases from the T2l3 reservoir most likely suggest a mixed origin from the Permian and Triassic source rocks. The minimum temperature to initiate TSR has been controversial for many years, however, most studies suggest that TSR begins in the range 120–140 °C, depending on the hydrocarbons in the reservoir, and that higher temperatures are required to initiate TSR for CH4 than for heavier hydrocarbons (Worden et al., 1996, 2000; Machel, 2001). The T2l3 gas reservoir depth of 3250 m is equivalent to a temperature of 88.3 °C under the current geothermal gradient of 2.35 °C/100 m. This temperature does not meet the requirement for the occurrence of TSR even though condensate may require relatively low temperature. However, current reservoir temperature cannot rule out historical TSR occurrence. Burial and thermal history analysis (Fig. 5) shows that the Leikoupo Formation has undergone considerable uplift and cooling since the Cretaceous. The T2l3 reservoir has experienced high temperatures over 120 °C with the maximum temperature up to 140 °C for a long time after the Middle Jurassic. Because of uplift and erosion since 100 Ma in the western Sichuan Basin, current temperatures are significantly lower than the maximum temperature experienced and geothermal gradients are also diminished in comparison to the heat flow during the Mesozoic (Hao et al., 2008). Although TSR is unlikely to be occurring today due to low reservoir temperature,

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it most likely occurred during the Late Jurassic and Early Cretaceous and TSR was slowed and gradually stopped afterwards. It should be noted that using the current reservoir temperature to constrain conditions of TSR occurrence is inappropriate in most cases where geo-history is more complicated than continuous subsidence. Analysis of the timing of gas generation suggests that only those gases derived from the Permian source rock would be affected by TSR and the time of formation of H2S would have been the Late Jurassic to Early Cretaceous. The Xujiahe Formation source rock reached the major oil window with a limited amount of gas generation during that time period. After TSR ceased, the T2l3 pool may have received another gas charge from the Xujiahe source rock. However, sandstone reservoirs in the Upper Triassic Xujiahe Formation never experienced temperatures higher than 140 °C before they were uplifted and cooled to the present temperature, which rules out the possibility of TSR. The lack of H2S in the T3x2 pool is also related to the absence of SO4 in the reservoir formation water. 5.2. Reservoir lithology and formation water compositions The occurrence of H2S in the Zhongba gas field is limited to the Leikoupo Formation reservoir, where evaporite deposits are well developed especially in the second member which contains large masses of oxidized S in the form of gypsum or anhydrite. Thinbedded gypsiferous rock was also developed in the third member of the Leikoupo Formation. No H2S is found in the Xujiahe Formation reservoirs, which are formed in pure clastic rocks (devoid of anhydrite). This strongly suggests that primary sedimentology exerts a major influence on the occurrence of H2S, particularly the distribution of anhydrite is likely to be critical. Although a full study of facies, sedimentology, diagenesis and mineralogy of the Leikoupo Formation has yet to be made, buried evaporites constitute a significant source of SO4 for deep formation waters, which undergo TSR with organic compounds to produce H2S. Some crystalline dolomite within the reservoir is a by-product of TSR, due to dolomitization. This process acts as the main mechanism to enhance reservoir porosity and permeability in the eastern

Sichuan Basin (Zhu et al., 2005, 2007a; Ma et al., 2008; Hao et al., 2008). However, oxidation of organic matter in the presence of anhydrite is limited by the availability of transition metals in the rock or formation waters as these metals lead to base metal sulfide precipitation and the loss of fluid phase sulfide. The source of Mg2+ for TSR dolomitization in the Zhongba gas field is not obvious. Partial dissolution of the dolostone via pressure solution may provide some Mg for dolomite growth (Machel, 2001), but major Mg concentrations may be derived from clay minerals such as illite or outside sources. Further investigation is needed for the TSR source of Mg. The TSR reaction is usually considered to take place within an aqueous medium. Despite the lack of comprehensive water analyses of samples from the Zhongba gas field, partial water compositions compiled from internal reports of the Sichuan Oil and Gas Company clearly illustrate the systematic difference between two reservoirs. Both T3x2 and T2l3 gas reservoirs contain Ca–Cl type water, but their salinities and ion contents are different (Table 5). The T3x2 gas reservoir, non-marine sandstones, is characterized by the presence of bottom water, free of H2S and of low salinity. Barium is a distinctive element in the T3x2 reservoir formation water with Ba2+ concentrations in the range of 365 mg/L to 1868 mg/L. The availability of SO4 or soluble SO2 4 is limited or even absence. The non-detectable SO2 in the formation water of T3x2 4 2+ gas pool is possibly due to the excess of Ba even though no BaSO4 precipitation has been observed. The formation water of the T2l3 reservoir is characterized by free of Ba, high H2S content, high aqueous SO4 concentration and high salinity. The aqueous H2S content is 182–1081 mg/L and SO4 concentration ranges from 239 to 1109 mg/L. The salinity calculated as the sum of dissolved species equivalent to total dissolved solids (TDS) amounts to 106,000–112,000 mg/L, much higher than that in the Xujiahe Formation. The reactive SO4 for TSR is dissolved SO2 that is derived from dissolution of solid CaSO4. The rate of 4 anhydrite dissolution has a primary influence on the rate of TSR reaction (Bildstein et al., 2001). Initially formed H2S is dissolved in the formation water and it evolves as a separate gas phase in TSR settings once its concentration exceeds its aqueous solubility. If dissolution of solid SO4 is slower than the rate of SO4 reduction,

Fig. 5. Burial and thermal history represented by Well Zh18 in the Zhongba gas field.

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G. Zhu et al. / Applied Geochemistry 26 (2011) 1261–1273 Table 5 Compositions of formation water in the Zhongba gas field. Well

Depth (m)

pH

Cation/ion (mg/L) +

Na + K T2l3

T3x

2

Zh11 Zh3 Zh7 Zh7 Zh8 Zh11 Zh20 Zh22 Zh28 Zh31 Zh36 Zh37 Zh4 Zh60

3768–3900 3282–3460 3423–3531 3423–3531 3383–3450 3065–3100 2509–2674 2825–3073 2679–2685 2522–2590 2568–2629 2432–2481 2535–2586 2555–2575

5.2 6.9 4.9 3.9 3.9 6.2 7 6.2 6.6 6.4 7.2 6.3 7.3 4.8

34,732 28,628 42,133 40,783 37,340 12,531 20,611 19,850 18,962 22,279 22,336 22,221 23,945 17,260

+

Ca

2+

2+

5569 11,110 2388 2314 3019 14,533 1148 848 4318 1117 1049 1267 1167 4931

2+



Mg

Ba

Cl

SO2 4

1706 5116 379 320 516 7395 242 57 738 198 148 135 167 813

0 0 0 0 0 350 1203 926 911 1868 1736 1807 1322 365

66,544 77,668 68,626 65,902 63,539 48,526 34,832 32,622 39,176 37,572 37,282 37,532 39,833 37,269

835 776 736 1109 239 0 0 0 0 0 0 0 0 0

the system can easily run out of dissolved SO4. High aqueous SO4 concentration, together with high concentrations of H2S within the Leikoupu Formation reservoir, suggests that the SO4 reduction reaction has ceased under current reservoir conditions; otherwise, most of the SO4 would have been consumed by thermochemical SO4 reduction since TSR destroys SO2 4 at the expense of H2S.

5.3. Hydrocarbon gas geochemistry TSR is the reaction of sulfate minerals and hydrocarbons to form H2S and other non-hydrocarbon gases mainly CO2. Compared to the T3x gas reservoir, the high H2S and CO2 content in the T2l3 reservoir are the direct evidence of TSR (Table 2). Since heavy hydrocarbons (C2+) are more easily involved in TSR than CH4, TSR will result in increasing dryness of natural gas and relative depletion in C2+ hydrocarbons. Fig. 6 shows the variation in H2S concentration as a function of burial depth and gas dryness. With the increase of burial depth, both H2S content and gas dryness gradually increase as high temperature favors the occurrence of TSR. In contrast to the eastern Sichuan Basin where the correlations between H2S content and depth, and H2S content and gas dryness are obvious due to current active TSR (Hao et al., 2008), a weak correlation with a large degree of scatter in both H2S content to present depth and dryness is probably due to inactive TSR and mixing. Isotopic values for ethane from the T2l3 gas reservoir are lighter than coal-type gases from the Xujiahe Formation but heavier than other Permian origin gases, reflecting complexity of gas origin and possible secondary alteration processes in the Zhongba gas field (Fig. 4). A wide range of variation in ethane d13C values could be

(a) 3000

Depth (m)

3100 3200 3300 3400

5

6

7

CO 3

2077 797 1905 2015 1186 2710 574 207 542 492 562 490 530 1140

0 0

8

0 0 0 0 0 0 0 0 0 0 0

H2S (mg/L)

Salinity (g/L)

Water type

428 831 1081 581 182 0 0 0 0 0 0 0 0 0

111.46 124.1 116.68 112.44 105.84 86.05 58.69 54.51 64.65 63.53 63.11 63.45 66.96 61.79

CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2 CaCl2

5.4. Condensate oil geochemistry According to the interpretation of Thompson (1988), with increasing maturity, oils contain more normal alkanes and less branched alkanes, cyclic alkanes and aromatic hydrocarbons. He proposed the heptane value and isoheptane value as maturity parameters. High proportions of n-C6, n-C7 and n-C8, high isoheptane value and a low proportion of cyclic alkanes and low

(b)

H2S (%) 4

HCO 3

a mixing curve between the Permian marine source and the Triassic terrestrial source. However, these variations can also be explained by kinetic isotope fractionation of C in hydrocarbons during TSR, a phenomenon reported previously for dry gas TSR provinces (Worden and Smalley, 1996). Slightly heavier isotopic values of ethane and propane were caused by the early stage of TSR, which involved chemically reducing SO4 to sulfide at the expense of wet gas since the overall reactivity of ethane and propane were faster than CH4. Once most of the ethane and propane were exhausted by TSR, CH4 became involved. The d13C values of CH4 do not change much in the T2l3 gas reservoir (Table 3) suggesting that CH4 was not significantly involved in TSR. Varying C1/ (C2 + C3) values and a wide variation of d13C in wet gas components suggest that TSR mainly occurred in wet gas components. Low variation of gas sourness suggests a low degree of TSR alteration and incomplete reaction, i.e. only part of the hydrocarbons were reduced to produce H2S. The C isotope values of CO2 from 5.3‰ to 6.1‰ (Table 3) are heavier than those typical of organic origin from hydrocarbon oxidation as a product of TSR, suggesting possible mixing of CO2 between TSR and carbonate decomposition through acidolysis in TSR.

9

0.98

Gas Dryness

Pool

H2S (%) 4

5

6

7

8

9

0.97 0.96 0.95 0.94 0.93

3500 Fig. 6. Gas compositional variations in the Zhongba gas field. (a) H2S content vs. depth; (b) H2S content vs. gas dryness.

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benzene/n-C7 ratios suggest that condensate from the Leikoupo Formation is more mature than those from the Xujiahe Formation (Table 4). Mango (1990) found that ratios of some light hydrocarbon components in crude oils are invariable regardless of their absolute concentration if they are from a common source. One invariant ratio k1 [(2-methylhexane + 2,3-dimethylpentane)/(3methylhexane + 2,4-dimethylpentane)] is widely used in oil–oil correlation studies and particularly in oil–condensate and condensate–condensate correlations. The invariant ratio k1 of the T2l crude oil separates from the T3x oils, suggest different sources for the Zhongba oils. The V-ratio [normal alkanes/cycloalkanes (sum of compounds eluted between n-C3 and n-C8)] and J-ratio [isoalkanes/cycloalkanes (sum of compounds eluted between n-C3 and n-C8)] exhibit similar resolving power, consistent with different sources for these two oil systems. Although no detailed oil-source correlation was performed in the present study, limited geochemical analysis of condensates draws a similar conclusion as Cai et al. (2003b) that both gas and condensate in the T3x pool are derived from shales and coals of the Triassic Xujiahe Formation, while those in the T21 pool are a mixture of the Triassic and Permian sources. Without TSR, the main controls on aromatic S compounds in oils are source-rock depositional environment and thermal maturity (Hughes et al., 1995). However, the concentration of aromatic S compounds increases with H2S content during TSR because these compounds are formed as by-products (Orr, 1974). Data from the Zhongba condensate oils show that organic S compounds in the aromatic hydrocarbon fraction are dominated by DBTs, including dibenzothiophenes (DBT), methyl-dibenzothiophenes (MDBT), dimethyl-dibenzothiophenes (DMDBT) and trimethyl-dibenzothiophenes (TMDBT) with small amounts of ethyl-dibenzothiophenes. Benzothiophenes with three and four methyls were detected in low concentration. Higher organo-S compound concentrations in Well Zh81 condensate from the T2l3 pool than Well Zh54 and Well Zh47 condensates from the T3x2 pool provides supplementary evidence for the possible occurrence of TSR in the T2l3 reservoir (Table 6). Several studies have shown that occurrence of thiaadamantanes and thiadiamantanes are the result of sulfurisation processes occurring under high temperature conditions in deeply buried petroleum reservoir-rocks which have undergone the effects of TSR (Hanin et al., 2002; Wei et al., 2007; Jiang et al., 2008). These sulfides are sulfurised analogs of alkyladamantanes and alkyldiamantanes. These thiadiamondoid compounds might have been formed by acid catalyzed rearrangement of tricyclic sulfides as described for diamondoid hydrocarbons which can be formed by drastic rearrangement of polycyclic hydrocarbons. Therefore, alkylated 2-thiaadamantanes in petroleum give clues to sulfurisation processes affecting petroleum which has undergone high thermal stress. A series of 2-thiadiamantanes are detected in the GCMS of m/z 154, 168, 182 and 196 in Well Zh81 (Fig. 7), while no such compounds can be detected in the T3x oil from Well Zh54 and Zh47. The occurrence of thiadiamondoid compounds including

Table 6 Concentration of organo-sulfur compounds in crude oil of wells Zh54, Zh47 and Zh81 (lg/g). Well

TMBT

TeMBT

DBT

MDBTs

DMDBTs

TMDBTs

TeMDBTs

Zh54 Zh47 Zh81

0.0 0.1 1.8

0.0 0.5 7.1

1.2 59.7 439.6

12.5 168.9 1121.8

31.5 208.3 1400.6

22.1 114.9 435.2

7.1 41.6 61.3

TMBTs: trimethyl-benzothiophenes; TeMBTs: tetramethyl-benzothiophenes; DBT: dibenzothiophene; MDBTs: methyl-dibenzothiophenes; DMDBTs: dimethyl-dibenzothiophenes; TMDBTs: trimethyl-dibenzothiophenes; TeMDBTs: tetramethyldibenzothiophenes.

thiaadamantanes and thiadiamantanes may indicate the existence of TSR although more quantitative work is called for to verify their genetic correlations. 5.5. Sulfur isotope TSR involves the reduction of SO4 by hydrocarbons and leads to H2S and elemental S as the main forms of sulfur. Sulfur isotopes (d34S) are suitable for tracing the consequences of mass transfer and fractionation because they are naturally labeled isotopically and because there are a restricted number of sources and sinks for S (Claypool et al., 1980; Krouse et al., 1988; Worden et al., 1997; Zhu et al., 2007b; Zhang et al., 2008b). Some field observations and experimental data have illustrated that S isotopes fractionate between sulfate and sulfide during TSR, with the lighter isotopes preferentially entering the reduced S compounds (e.g., H2S and elemental S). The kinetic S isotope fractionation during the initial abiological S–O bond rupture, in the temperature range of interest, is about 20‰ at a temperature of 100 °C, about 15‰ at 150 °C, and about 10‰ at 200 °C and further decreases with increasing temperature (Kiyosu and Krouse, 1990; Machel, 2001). TSR-type reactions during low grade metamorphism, the main origin of the S° veins, cause significant S isotopic fractionations between SO4 (around +20‰) and reduced products (S° is around 11‰) (Alonso-Azcárate et al., 2001). Conversely, in many other deep sour gas reservoirs, H2S, S°, and the associated metal sulfides, have nearly the same S isotope composition as the parent SO4 (Orr, 1974; Worden and Smalley, 1996; Worden et al., 1997). Worden et al. (1997) considered that SO4 reduction does not lead to isotope fractionation. This apparent paradox arises because in natural TSR systems there is complete reaction of anhydrite that dissolves so preventing any isotope fractionation. In the experimental systems, the SO4 is already in solution thus avoiding the essential anhydrite dissolution step that characterizes the kinetics of natural TSR systems (Worden et al., 2000). The d34S values in SO4 represented by anhydrite from the Leikoupo Formation in the Zhongba gas field vary from 21.09‰ to 26.47‰ CDT with an average value of 23.78‰. The d34S values of H2S from two production wells are 9.24‰ and 14.71‰, respectively. Elemental S, a common by-product of TSR, is only found in wells that contain H2S gas suggesting that there is a genetic link between the two. The d34S values of S from the core of the reservoir fall in a narrow range of 14.11–15.04‰ with an average value of 14.59‰. One sample elemental S separated from a natural gas desulfurization plant for the Zhongba gas had a d34S value of 11.89‰, which is close to d34S value of S in the reservoir (Table 7, Fig. 8). The BSR-derived H2S usually shows large S isotopic fractionation, which is more than 20‰ lighter than the sulfate–S (Machel, 2001, and references therein). A large number of data from the Sichuan Basin indicate that the d34S in TSR-derived H2S is generally 8–12‰ lower than SO4 (Cai et al., 2003a, 2010; Li et al., 2005; Zhu et al., 2005, 2007a,b; Hao et al., 2008). The d34S in the studied H2S and S is around 9‰ lower than that in anhydrite contained in the reservoir, within the fractionation scope of TSR-derived H2S. Therefore, the H2S in the T2l3 gas reservoir of the Zhongba gas field is most likely of TSR origin. Obvious S isotope fractionation in the studied sample suite is possibly caused by a degree of partial reaction during TSR, as Machel et al. (1995) suggested that kinetic fractionations are only ‘preserved’ if the reactions do not go to completion or if the system is open. Little or no isotopic fractionation between the reactant and the product S would be measurable in closed systems when most or all SO4 has been reduced. However, the possibility that pre-existing organo-S compounds act as a supplementary source of reservoir H2S cannot be ruled out. The low abundances of S in source kerogen and oil may limit the amount of H2S produced.

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s

m/z 154

21.80

2-thiaadamantane

22.00

22.20

22.40

22.60

22.80

s

23.00

23.20

23.40

23.60

5-methyl-2-thiaadamantane

23.80

24.00

24.02

s

m/z 168

1-methyl-2-thiaadamantane 21.80

22.00

22.20

22.40

22.60

22.80

23.00

s

23.20

23.40

23.60

23.80

24.00

24.02

1,5-dimethyl-2-thiaadamantane

s

m/z 182

s

1,3-dimethyl-2-thiaadamantane

5,7-dimethyl-2-thiaadamantane 21.80

22.00

22.20

22.40

22.00

22.80

23.00

23.20

23.40

23.60

23.80

24.00

24.02

23.40

23.60

23.80

24.00

24.02

Trimethyl-2-thiaadamantane

m/z 196

21.80

22.60

22.20

22.40

22.60

22.80

23.00

23.20

Fig. 7. GC–MS fragmentograms of alkylated 2-thiaadamantanes in Well Zh81 oil from the T2l pool.

Table 7 Sulfur isotopic values within different sulfur species in Zhongba gas field. Well

Strata

Depth (m)

Sample type

d34S (‰)

Zh6 Zh46 Zh46 Zh46 Zh46 QL1 QL1 QL1 Zh81 Zh21 QL1 QL1 QL1 QL1 Refinery station

T2l2 T2l2 T2l2 T2l3 T2l2 T2l3 T2l3 T2l2 T2l3 T2l3 T2l3 T2l3 T2l3 T2l3

3807 3175 3305 3157 3243.98 3717.15 3919 3923.32 3289 3319.5 3751.85 3731.52 3755.44 3751.81

Anhydrite Anhydrite Anhydrite Anhydrite Anhydrite Anhydrite Anhydrite Anhydrite H2S H2S Sulfur Sulfur Sulfur Sulfur Sulfur

24.17 23.23 22.98 21.61 21.09 26.47 25.63 25.06 9.42 14.71 15.04 14.11 14.62 14.57 11.89

6. Conclusions Geochemical analyses of gases and condensates from the Zhongba gas field indicate there are two types of natural gas accumulations in the Triassic reservoirs. Gases produced from the Xujiahe Formation are derived from the Upper Triassic coal and are characterized by high wet gas content, no H2S and heavy isotopic values of wet hydrocarbon gas components, while gases produced from the Middle Triassic Leikoupo Formation are characterized by high H2S and CO2 content, a high gas dryness coefficient and widely variable C isotopic values of wet hydrocarbon gas components, representing a mixture of the Permian oil-type gas and the Triassic coal-type gas. Molecular ratios of light hydrocarbons and absolute concentrations of diamondoid hydrocarbons also suggest two different sources responsible for oil and gas accumulation in the Zhongba area and hydrocarbons in the T2l3 reservoir are more mature than hydrocarbons in the T3x2 reservoir. TSR is the most likely factor responsible for the occurrence of H2S and CO2 in the Leikoupo Formation reservoir. Well developed gypsiferous deposits and high SO4 concentrations in the formation waters provide perquisite condition for TSR. Burial and thermal history analysis shows that the Leikoupo Formation has undergone considerable uplift and cooling since the Cretaceous. TSR in the studied area mainly occurred during the Late Jurassic to Early Cretaceous and ceased in the Late Cretaceous. A wide range of isotopic values in wet gas components but near constant isotopic values of CH4 suggest that TSR mainly occurred with wet gas but CH4 was not significantly involved. The d34S values in SO4, elemental S and H2S fall within the fractionation scope of TSR-derived H2S, meanwhile, the coexistence of soluble SO4, gaseous CH4 and H2S within the reservoir in the western Sichuan Basin is consistent with incomplete reactions. The occurrence of 2-thiaadamantanes in condensate from the Leikoupo Formation reservoir might be the result of sulfurisation processes occurring under high temperature conditions. Acknowledgements

Fig. 8. Sulfur isotopic composition of anhydrite, hydrogen sulfide and sulfur in the Zhongba gas field.

Professors Wang Yigang, Wang Lansheng and Zhang Zengrong from the Southwest Oil and Gas Company, PetroChina are acknowl-

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edged for data contribution and sample collection. This work was supported by the National Natural Science Foundation of China (Grant No.: 40602016; 40773032). H.H. gratefully acknowledges the China National Natural Science Foundation (40973034) and Program for Changjiang Scholars and Innovative Research Team in University (IRT0864) for partially supporting this work. We would also like to thank Professor Richard Worden, Dr. Tongwei Zhang and Professor Ron Fuge for their valuable comments which helped to greatly improve the content and quality of the paper. References Alonso-Azcárate, J., Bottrell, S.H., Tritllac, J., 2001. Sulfur redox reactions and formation of native sulfur veins during low grade metamorphism of gypsum evaporites, Cameros Basin (NE Spain). Chem. Geol. 174, 389–402. Amrani, A., Zhang, T.W., Ma, Q.S., Ellis, G.S., Tang, Y.C., 2008. The role of labile sulfur compound in thermochemical sulfate reduction. Geochim. Cosmochim. Acta 72, 2960–2972. 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