Origins and fates of H2S in the Cambrian and Ordovician in Tazhong area: Evidence from sulfur isotopes, fluid inclusions and production data

Marine and Petroleum Geology 67 (2015) 408e418

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Research paper

Origins and fates of H2S in the Cambrian and Ordovician in Tazhong area: Evidence from sulfur isotopes, fluid inclusions and production data Chunfang Cai a, b, *, Guoyi Hu c, HongXia Li a, Lei Jiang a, Wenxiang He b, Baoshou Zhang d, Lianqi Jia a, Tiankai Wang a a

Key Laboratory of Petroleum Resources Research, Institute of Geology and Geophysics, Chinese Academy of Sciences, Beijing 100029, PR China Key Laboratory of Exploration Technologies for Oil and Gas Resources, Ministry of Education, School of Water Resource and Environment, Yangtze University, Caidian, Wuhan, Hubei 430100, PR China c Research Institute of Petroleum Exploration and Development, PetroChina, Beijing 100083, PR China d Research Institute of Petroleum Exploration and Development, Tarim Oilfield Company, PetroChina, Korla, Xinjiang 841000, PR China b

a r t i c l e i n f o

a b s t r a c t

Article history: Received 14 January 2015 Received in revised form 19 March 2015 Accepted 8 May 2015 Available online 27 May 2015

Gases, oils, solid bitumen samples and fluid inclusions were analyzed for chemical composition and d13C and d34S values, and production data were collated, to elucidate the origin and fates of the H2S in the Tazhong area. The H2S in the Ordovician was measured to have d34S values from 12.1‰ to 23.4‰, which are significantly lighter than the counterpart in the Cambrian (33.0‰), indicating that the H2S did not migrate from the Cambrian, but may have been derived from thermochemical sulfate reduction in situ, as partially supported by 12C-rich CO2 in fluid inclusions and TSR calcites with d13C values from
3.6‰ to
17.7‰ in the Ordovician. The H2S rich gas subsequently mixed with H2S-poor, 13C rich methanedominated gas as indicated by the roughly negative correlations of H2S content to dryness and gas/oil ratio, and CH4 from fluid inclusions having d13C values 1.2e3.6‰ lighter than the associated free gas. The H2S has been dissolved in formation water, precipitated as pyrite and incorporated into oils and solid bitumens, resulting in the generation of alkylthiolanes, alkylthiols and alkyl 2-thiaadamantanes, and increase in d34S values and S/C ratios of the solid bitumen. The content of H2S produced from the water intervals or petroleumewater transition zones is significantly contributed from exsolved gas and thus higher than that of the gas-cap gas in the reservoirs. Thus, H2S contents cannot be used to indicate TSR extents in the Ordovician. However, in the Cambrian, whole oil and saturates show positive shifts in d13C values with increasing H2S contents, indicating that the H2S in the Cambrian was derived from TSR by liquid hydrocarbons. © 2015 Elsevier Ltd. All rights reserved.

Keywords: TSR H2S Oil Methane Sulfur isotope Carbon isotope Tarim Basin

1. Introduction H2S is toxic, corrosive and economically-damaging and identifying its origins and fates is critical to lower the risks during petroleum exploration and development in the Sichuan Basin (Cai et al., 2004). High H2S concentration (>10%) in reservoirs results from thermochemical sulfate reduction (TSR) of petroleum (Orr, 1974; Machel et al., 1995; Worden and Smalley, 1996). If TSR

* Corresponding author. Key Laboratory of Petroleum Resources Research, Institute of Geology and Geophysics, Chinese Academy of Sciences, Beijing 100029, PR China. E-mail address: [email protected] (C. Cai). http://dx.doi.org/10.1016/j.marpetgeo.2015.05.007 0264-8172/© 2015 Elsevier Ltd. All rights reserved.

occurs in a closed system, the H2S content, H2S/(H2S þ C1-6) and CO2/(CO2 þ C1-6) can be used to reflect the TSR extent of the reaction (Krouse et al., 1988; Worden and Smalley, 1996; Cai et al., 2003, 2004). However, some case studies show that H2S may have migrated up from deeper reservoirs (Manzano et al., 1997; Cai et al., 2005) in both the gas and solution (either in water or in oil) phase. The partitioning in the receiving reservoir would be influenced by water chemistry, oil chemistry and PVT conditions. The H2S produced from waterepetroleum transition shows much higher concentrations than that from a gas interval (Cai et al., 2013), and it is quite possible for those abnormally high H2S concentrations (between 32% and 95%) not to represent a gas-cap gas composition as reported previously (Heydari, 1997; Cai et al., 2003, 2005; 2013; Hao et al., 2008).

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In the Tarim Basin, small amounts of H2S and abundant pyrite in the Ordovician and Silurian was first proposed to have been generated by thermochemical reduction of the Cambrian sulfates (Cai et al., 2001a). However, when subsequently drilled wells produced higher H2S, and different d34S values were measured for pyrite and H2S, two generations of TSR were proposed with the present H2S derived from thermochemical reduction of sulfates from formation water (Cai et al., 2008, 2009b). Gas with more than 40% H2S was reported in this area (Li et al., 2015) and some researchers believed that the H2S was derived from the Middle Cambrian anhydrite-bearing strata based on the distribution of anhydrite (Li et al., 2010, 2015; Zhu et al., 2014). The gas in this area has been shown to have mixed with 13C-rich methane dominated gas (Wang et al., 2014), however, it is not clear if the mixed gas is H2S-rich or not. The following questions remain unsolved: 1) A gas released from water intervals has a much higher H2S content than a gas interval (Cai et al., 2013). Thus, does the high H2S (40%) in this area represent composition of a gas-cap gas? 2) Was the H2S in the Ordovician derived from the Middle Cambrian anhydrite-bearing strata? 3) What kind of organic matter was involved in TSR? To solve these questions, we collected samples from the Cambrian and Ordovician in the Tazhong area, measured H2S for d34S values, oil for d13C and d34S values, gases in fluid inclusions for chemical composition and d13C, and solid bitumens for elemental composition and d34S values. Daily production data were collated to check variation in H2S concentration and water/petroleum ratio. From the these measurements, we hoped to determine the source and fates of the H2S.

409

Carboniferous sequence is composed of marine sandstone and mudstone and micrite and bioclastic limestone. The Permian consists of transitional terrestrial-marine facies detrital sediments with intercalated volcanic rocks; and the Mesozoic and Cenozoic are mainly composed of terrestrial sandstones and mudstones. Presently, petroleum has been produced from the Carboniferous, Silurian, Lower Ordovician (O1y) and Middle and Upper Ordovician (O2yj and O3l), and newly from the Cambrian. Condensate oils have been produced from the Middle Cambrian Awatage (Cam2a), gases were discovered in the and WusonggeereXiaoerbulake (Cam 1x) formations in well ZS1, and condensate oils and gases were produced from Xiaoerbulake (Cam1x) formation in well ZS1C (a lateral well of the ZS1) and ZS5 (Fig. 3). The majority of the oil in the Cambrian and Ordovician reservoirs is proposed to have been derived from the Cambrian source rock (Cai et al., 2015), not from the Upper Ordovician as suggested by Li et al. (2010, 2015) and others. Peak oil generation from the Cambrian source rocks occurred during the late Caledonian-early Hercynian period (S1 e D3) (Zhao et al., 2008). Petroleum may have remigrated and newly generated from the Upper Ordovician during the late Yanshan - Himalayan period (K2 e N) (Cai et al., 2009a & b and references therein). Faults crosscutting the Cambrian and Ordovician and their associated fractures have been considered to be the main conduits for upward hydrocarbon migration from the Cambrian (Cai et al., 2001b; LÜ et al., 2004). 3. Samples and methods 3.1. Sample collection, and H2S, bulk oil and solid bitumen d34S measurement

2. Geological setting The Tazhong Uplift is located in the central Tarim Basin (Fig. 1). It is surrounded by the Manjiaer Sag in the north, the Tangguzibasi Depression in the south, the Bachu Uplift in the west and the Tadong Sag in the east. Oceanic spreading occurred during the Cambrian-Early Ordovician. At the end of Early Ordovician, a NWtrending basement-involved fault developed, resulting in the formation of the tectonic framework and carbonate platform. The erosion of the eastern area occurred due to NWeSE directed tilting during late Ordovician (Jia, 1997; Ren et al., 2011). The Devonian, Silurian and even Ordovician strata were eroded and the most important unconformity developed during the late Devonian, which was followed by the formation of NNE strike-slip faults (Wu et al., 2012). The general stratigraphic column of the Tazhong Uplift (Fig. 2) was described previously in Cai et al. (2001a, b; 2009a, b) and Li et al. (2010). Briefly, the Cambrian strata consists of the Lower Cambrian Xiaoerbulake and Wusonggeer formations (Fm.), the Middle Cambrian Shayilike Fm. and Awatage Fm. and the Upper Cambrian Qiulitage Fm. (Fig. 2). The Lower Cambrian section is composed of platform or platform-marginal facies thick dolomites with intercalated dark mudstones and shales, which are considered to be the main source rocks (Cai et al., 2009b). The Middle Cambrian is composed of supratidal anhydrite-bearing dolomites and anhydrite. Bedded anhydrite 20 me98 m thick are present in the eastern Z4, ZS1 and ZS5 wells. The thicker anhydrite is expected to occur in the west because >350 m thick anhydrite was encountered in F1, He4 and Tong1 wells in the Bachu Uplift, to the southwest to the middlewestern part of the Tazhong Uplift (Fig. 3). The Lower Ordovician includes the Penglaipa Fm (O1p) open platform facies thick dolomite and the Yingshan Fm. (O1y) thick limestone and local dolomite. These are covered by Upper Ordovician marlstone and reef and shoal facies grainstone with small amounts of Middle Ordovician carbonates in the western part. The Silurian to

H2S and oils from 8 wells in the Tazhong area were sampled at the well head separators. The methods for H2S and bulk oil d34S measurement were reported in Cai et al. (2001a; 2009b). In brief, H2S-bearing gas was bubbled through 2 L glass jars containing zinc acetate (3 g) to precipitate ZnS. The solution with ZnS was put aside overnight and then filtered with a 0.45 m filter on site. In the laboratory, ZnS was transformed to Ag2S by adding HCl and passing the evolved H2S under an inert atmosphere through AgNO3 solution at a pH of 4. Samples of oil or solid bitumens (1e4 g) were combusted in a Parr bomb apparatus at ~25 atm oxygen to oxidize organically bound sulfur to sulfate. Dissolved sulfate was then precipitated as BaSO4. Ag2S and BaSO4 were converted to SO2 by combustion in a quartz tube for isotopic analysis using the method of Bailey and Smith (1972). Isotopic determinations were carried out on a Thermo Finnigan Delta S mass spectrometer, calibrated by a series of IAEA standards. Results are presented as d34S relative to the Vienna Canyon Diablo Troilite (VCDT) standard. The reproducibility for d34S measurement is ±0.3‰. 3.2. Whole oils and fractions stable carbon isotope analyses Stable C isotopic compositions of the saturates and aromatics were determined following procedures similar to those described by Sofer (1980). Carbon dioxide was prepared by combusting (850  C, 2 h) aliquots (0.5e1 mg) of petroleum samples in clean, evacuated quartz tubes containing Cu(II)O, Ag and Cu metals. Following combustion the samples were allowed to cool slowly (1  C/min) to room temperature in order to ensure reduction of any nitrous oxides. The resultant CO2 was separated cryogenically and C isotope ratios were measured using a VG SIRA 12 mass spectrometer. All data were corrected for 17O effects (Craig, 1957) and reported in conventional delta (d) notation in per mil (‰) relative to VPDB. Accuracy and reproducibility of C isotopic data were assessed

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Fig. 1. Sketch maps showing (a) location of the Tazhong uplift, Tarim Basin and (b) distribution of faults and locations of well and cross section AB in Fig. 4 (modified after Wang et al. (2014)).

by replicate analysis of the international standard NBS 22. The mean of 8 replicates (
29.60‰) was identical within experimental error to the value reported by Gonfiantini et al. (1995) and gave a precision (sn-1) of ±0.042‰. 3.3. Analyses of chemical composition and d13C of natural gas and gas extracted from fluid inclusions The chemical composition of gas samples was analyzed using a Finnigan MAT-271 mass spectrometer. Concentrations were calculated using a calibration curve obtained from synthetic standard gases. The analytical conditions were as follows: Ion source: EI; electronic energy: 86eV; mass range: 1e350 amu; resolution: 3000; accelerated voltage: 8 kV; emission: 0.200 mA; vacuum:

<1.0  10
7Pa. The concentration of gas was calculated in accordance with the measurement law of mass spectrometry (State Standard of China GB/T 6041e2002 and GB/T10628-89). Carbon isotope compositions of methane, ethane, propane and CO2 were measured with a Finnigan MAT-252 instrument. The analytical conditions were as follows: gas chromatographic column: Porapak C (25 m  0.53 mm  20 mm); constant temperature of 30  C for 5 min, oven temperature from 30  C to 200  C at a heating rate of 10  C/min, constant temperature of 200  C for 5 min; pure helium as a carrier gas. The analytical error in the d13C values was less than 0.3‰. In order to measure stable carbon isotope of some trace gas components (e.g., C2, C3) in very dry gas samples, we inject 100e200 mL gas. Each sample was measured three times, and the results of the three measurements averaged.

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411

Fig. 2. General stratigraphic column of the Tazhong uplift (modified from Wang et al. (2014)).

The method for gas extraction from fluid inclusions and analyses for chemical composition and isotopes were reported by Chen and Hu (2002), Hu et al. (2005) and Tao et al. (2014). Briefly, 10e20 g of calcite sample was put into a vacuum tank and then attached to a

crushing machine for 15e20 min. The collected gas was then measured for gas composition using an Agilent 6890N gas chromatograph and for d13C on a Delta Plus XL GC-C-IRMS. Carbon isotope values are reported as d13C and calibrated to the Vienna

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Fig. 3. Thickness distribution of the Middle Cambrian anhydrite and anhydritic dolomite.

Fig. 4. Cross section AB showing distribution of the Cambrian strata, faults, oil (red) and gas (yellow). (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

Peedee belemnite (VPDB) standard with a standard deviation of ±0.3‰. 3.4. Analyses of elemental composition of solid bitumen samples Solid bitumen samples were hand picked from dolomite, and then treated with hot 6N HCl to dissolve carbonate. After dilution with distilled water and centrifugation, the remaining solid bitumen was separated from the residue (precipitate) using heavy liquids (KBr þ ZnBr) with density 1.8e1.9 g/cm3. The solid bitumen was dry overnight at temperatures of about 50  C. 0.5e1.5 mg each dry solid bitumen was put into the tin cap, loaded into a EURO EA3000 and combusted under pure oxygen. The H, S, N and C contents were analyzed with an analytical precision of ±0.5%. 4. Results 4.1. Distribution of H2S contents and its relation to production data H2S in the petroleum pools without significant amounts of coproduced water has concentrations from null to 11% by mole of

the gas with the highest value in the Cambrian (Table 1). The H2S from the Lower Ordovician Yinshan Fm. (O1y) ranges mainly from 1.0% to 7.4% in the gas composition and is <1.2% from the Upper Ordovician Lianglitage Fm. excluding a gas sample from the ZG511 well, which was produced from water interval and has a H2S content of 2.43%. H2S content does not show increase with depth (Fig. 5). Gases with H2S contents higher than 3% are found within the area between ZG8 strike-slip fault and the TZ82 strike-slip fault (Fig. 1). Gases with H2S >5% were produced from wells ZG102, ZG43, ZG431, ZG432, ZG433C, ZG501, ZG52, ZG6, ZG9 and TZ75, among which water-dominated fluid was produced from ZG102, ZG1C and ZG9 wells. From well ZG6, 29,000 m3 gas together with 109 m3 oil was produced daily on Oct. 4, 2011. The gas was measured to contain 40% H2S. However, the value was measured again to be 7.8% on Oct. 15, 2011when 24,000 m3 gas and 89 m3 oil were produced daily, and was increased to 12.0% on June 3, 2013, and to 14.9e15.5% with water/(water þ oil) ratios from 0.53 to 0.99 since August 24, 2013.

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413

Table 1 H2S content, d34S, gas dryness coefficient, gas/oil ratio and associated oil sulfur content and d34S values. Well

Depth

Strata

H2S

d34SH2S‰

Oil S%

d34Soil‰

Dryness

Gas/oil

TZ621 TZ621 TZ821-1 TZ83 TZ83-3 ZG511 ZG10 ZG103 ZG11 ZG12 ZG13 ZG22 ZG431 ZG462 ZG8 ZG8 TZ201C TZ62-2 TZ83 ZG106 ZG43 ZG432 ZG433C ZG44-H2C ZG45 ZG46 ZG5 ZG501 ZG51 ZG6 ZG7 TZ4-7-38 TS1 ZS1 ZS1 ZS1C

4933 4868 5237 5411 5614 4924 6202 6191 6238 6219 6504 5670 5413 5417 6064 6118 5615 4932 5674 6120 5150 5325 6133 6055 5643 5363 6405 6236 5230 6080 5875 3961 7100 6461 6831 6520

O3l O3l O3l O3l O3l O3l O1yeO3l O1yeO3l O1yeO3l O1yeO3l O1yeO3l O1yeO3l O1yeO3l O1yeO3l O1yeO3l O1yeO3l O1y O1y O1y O1y O1y O1y O1y O1y O1y O1y O1y O1y O1y O1y O1y O1p 23 22 21 21

0.15 e 1.19 0.10 1.10 2.43 3.12 0.37 0.56 0.05 1.51 1.87 5.80 0.01 3.95 3.95 1.21 0.23 2.61 0.66 7.09 7.45 4.88 0.37 1.38 1.45 3.45 6.98 4.10 7.80 4.38 2.78 0.01 0.04 3.78 11.00

15a e 12.1 e 14.2 e e e 23.4 e e 17 e e e e 13.9 17.1a e e e e

0.4 e 0.08 e e e 0.34 0.11 0.4 0.0464 0.15 0.14 0.58 0.1 e 0.17 0.219 0.1 0.38 e e e e e e e e e e e e e e e e e

19.1a 12.5 30.1 17.5a e e e

0.973 e 0.972 e e 0.942 0.943 0.936 0.928 0.953 0.917 0.928 0.842 0.921 e 0.918 0.927 0.977 0.99 0.915 0.881 0.849 0.862 0.929 0.883 0.963 0.939 0.882 0.974 0.926 0.924 0.910 0.97b e 0.988 0.986

e

15.5 e e e e e e e e e e 33 e

19.8 e e 17.8 e e 13.60 e 21.23 16.7a 18.5a e e e e e e e e e e e e e e 23.0 e e

189 12667 e e 991 2843 4508 2799 3244 231 2089 606 1913 e 1169 4375 7697 47694 1822 1496 169 199 e 696 9944 2913 187 3232 62 1135 e e e e e

2 represents the Cambrian. a from Cai et al. (2009b). b from Zhai et al. (2007).

4.2. Relationships among H2S contents, natural gas dryness, gas/oil ratios and d34S values

Fig. 5. Variation of H2S concentration with depth (H2S produced from water intervals and waterepetroleum transitions are not plot).

The gases have a wide range of dryness coefficient from 0.84 to 0.99 (Table 1). Interestingly, gases from ZG501 and ZG432 wells have the highest H2S concentrations but show dryness coefficient of 0.88 and 0.85, respectively, which are close to the lowest value. A gas from well ZG5 shows higher dryness coefficient of 0.94 but lower H2S of 3.45% than that of the nearby ZG501 well (6.98%). When all data from the Ordovician were plotted, an exponential relationship between gas/oil ratio and H2S content is found with correlation coefficient R2 of 0.39 (Fig. 6A), and a weak negative relationship occurs between H2S content and dryness coefficient of the gas from the Ordovician (Fig. 6B). That is, fluid containing high H2S gases tends to have low gas/oil ratio (<300 m3/m3) except the ZG43 petroleum pool that yields a ratio of about 1500 m3/m3. Interestingly, gases from the Cambrian show variable chemical and isotopic composition. No significant amounts of H2S were detected from the TS1 well in the Upper Cambrian (Cam3) in the Tabei Uplift (Fig. 1) and from ZS1 well in the Middle Cambrian (Cam2). The H2S is 3.78% in the Lower Cambrian from the ZS1 well, and 11% in the Lower Cambrian in the ZS1C well. The ZS1-Cam2 gas shows the lowest dryness coefficient and methane d13C1. The TS1Cam3 gas has the heaviest d13C1 and d13C2 values, and shows dryness coefficient (0.97) slightly lower than ZS1-Cam1 and ZS1CCam1 gases (0.99).

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4.4. Alkanes and CO2 d13C values of gas from fluid inclusions and free gas Methane from fluid inclusions from six calcite cement samples was measured to have d13C values from
45.2 to
38.2‰. The values are lower than those of the associated free gas, respectively (Table 3). The differences range mainly from
1.2 to
3.6‰ except for the measurement of
0.2‰. CO2 from the fluid inclusions have d13C values from
5.9 to
13.2‰ (n ¼ 8), and are similar to those of the present free gases (
5.7‰ and
8.9‰, respectively). 4.5. Bulk oil sulfur contents and d34S values Oils have sulfur contents from 0.08% to 0.4% and d34S from 12.5‰ to 30.1‰ (n ¼ 6) (Table 1). The d34S values do not show correlation with the sulfur contents and associated H2S concentrations. Interestingly, all bulk oils have d34S values heavier than or close to the associated H2S produced from the Ordovician except for sample from ZG11 (Fig. 7). In contrast, oil produced from 6439 to 6458 m from the Cambrian has a d34S value of 23.3‰, about 10‰ lighter than the H2S (33.0‰) in the Lower Cambrian. 4.6. d34S values and S/C ratios of solid bitumens

Fig. 6. Relationships of H2S concentration to gas/oil ratio (a) and dryness coefficient (b).

Three solid bitumen samples ZG9-B1, ZG9-B2 and ZG431-B3 were measured to have d34S values of 20.0‰, 17.9‰ and 15.5‰, and S/C atomic ratio of 0.13, 0.06 and 0.02 (Table 4), respectively. A positive correlation occurs between S/C atomic ratio and d34S value. 5. Discussion

H2S produced mainly from the Lower Ordovician were measured to have d34S values from 12.1 to 23.4‰ in this study (n ¼ 6). The values are similar to those mainly from the Upper Ordovician (14e18.5‰; Cai et al., 2009b) and are much lighter than that produced from the Cambrian (33.0‰). No correlation occurs between H2S content and its d34S value (Table 1).

4.3. Relationships of oil and its fraction d13C values to H2S content Seven oils were measured to have bulk d13C values from
33.5 to
29.8‰ (n ¼ 7), saturates from
33.7 to
31.2‰ and aromatics from
31.1 to
29.1‰ (n ¼ 4). There exists no correlation of H2S content to bulk oil and saturates d13C value for all these oils (not shown). However, for the Cambrian oils and gases, with H2S increasing from 0.035% to 11.0%, whole oil and saturates d13C values show positive shifts of 3.7‰ and 2.4‰, respectively (Table 2).

H2S concentrations in gas compositions and H2S/(H2S þ SC1-6) are widely used to indicate TSR extents, and thus the wide range of the H2S concentrations from nil to >40% in this area may suggest large differences in TSR extents. However, this may not be the case as: 1) Some gases exsolved from water intervals or petroleumewater transition have been shown to have much higher H2S than a gas-cap gas (Cai et al., 2010, 2013); 2) The gas may have mixed with late charged gas; 3) The H2S may have been incorporated into oils (Cai et al., 2001, 2009b). 5.1. H2S concentrations increased from exsolution gas? The gas produced from well ZG6 was reported to have H2S of 40% (Li et al., 2015). However, that value was measured for the first time on Oct. 4, 2011. The H2S then decreased to 7.8% when measured for the second time on Oct. 15, 2011 when 24,000 m3 gas and 89 m3 oil were produced daily. Subsequently, H2S increased to 15.5% when measured on August 24, 2013 during which 72,000 m3

Table 2 d13C values of oils and the associated gas and H2S contents of ZS1 and ZS1C wells. Well

Depth(m)

Strata

Oil

ZS1 ZS1 ZS1 ZS1C TZ201C ZG44H2 ZG22 ZG11

Associated gas

d CWhole oil (‰)

d CSaturates (‰)

d Caromatic (‰)

13

13

13

6426e6497 6439e6458

22 22


33.5
33.0


33.7
33.0


31.1
30.8

6444e6861 5615 6055 5670 6238

21 O1y O1y O1yeO3l O1yeO3l


29.8
31.4
30.9
31.6
31.0


31.3
31.20


29.07
30.20

H2S (%)

d13C1

d13C2

Dryness

6439e6488

0.035


44.7


35.5

0.746

6579.6e6835 6861e6944

3.78 11.0 1.21 0.369 1.865 0.56


42.1
41.4


35.0
24.8

0.988 0.986

Depth (m)

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415

Table 3 Chemical composition and d13C values of gas-cap gases and the associated gases extracted from fluid inclusions. Fluid inclusion Well

Depth (m)

TZ30 TZ3 TZ3 TZ82 TZ824 TZ44 TZ62 TZ621

5062.6 / 3764.8 5457.01 5592.93 4843.7 4750.83 4868.14

Natural gas Age

O3 O O O O

d13C, ‰（VPDB） CO2

CH4


8.2
11.7
14.4
9.6
10.4
10.9
5.9
13.2


38.2


41.4
43.8
45.2
39.1
40.2

Chemical composition（%）

Depth (m)

N2

CO2

CH4

C2H6

0 0 0 0 53.7

30.7 46.2 43.8 13.2 9.9

64.2 46 48.9 83.4 33.9

5 7.8 7.3 3.5 2.5

gas, 74 m3 oil and 82 m3 water were produced daily. No data are available to calculate the exact contribution of exsolved gas from the 82 m3 formation water. However, assuming that the gas produced from well ZG6 has a similar composition under similar pressures and temperatures to well ZG9 (Table 4), a rough calculation shows about 111,922 mol H2S, 11,947 mol CH4, 1599 mol N2 and 31,078 mol CO2 can be released from the formation water saturated with gas when the water reached at the surface. That is, 2740 m3 H2S, 292 m3 CH4, 39 m3 N2 and 761 m3 CO2 were released. In fact, the gas produced has H2S of 11,160 m3 (72,000 m3  15.5%) on the surface condition (1 atm), about 25% (2740/11,160) contribution from the exsolved gas. Thus, reasonable H2S concentrations of the gas-cap gas or gas phase on condition of the reservoir for this well is from 7.8 to 12.0%, not 40% as published by Li et al. (2015). A gas produced from well ZG9 well may have partially or totally exsolved from water intervals. Present-day water intervals in this well have a bottom-hole temperature of ~150  C, a pressure of ~75 Mpa, and formation water total dissolved solids (TDS) of ~199,000 mg/l, i.e., TDS of 3.4 M NaCl equivalent. The gas was measured to contain 616,000 mg/m3 H2S under 1 atm, or 43%, CH4 of 36.5%, C2H6þ of 0.1%, N2 of 7.7% and CO2 of 12.7%. CH4, N2, H2S and CO2 have been shown to have great differences in solubility (Table 5), and solubility of these species is controlled by temperature, pressure and dissolved solids in solution (Duan et al., 1992; Duan and Sun, 2003; Duan and Wei, 2011). Once the saturated formation water arrived at the surface, the pressure

5430e5487 5613e5621 4854e4888 4773e4825 4851e4885

d13C, ‰（VPDB）

Alkanes

CO2

C1

C2

C3

iC4

nC4


5.7


39.8
40.2
44
38.9
38.5


34.0
36.0
38
31.7
34.9


31.0
32.7
33.1
30.3
32.0


29.4
32.8
32.4
28.6
30.2


29.6
31.4


8.9


28.7
30.2

decreased to 0.1 Mpa and temperature dropped to ~20  C. The amounts of CH4, H2S, N2 and CO2 gas released from the formation water depend on the difference between the solubility of the individual species under the assumed gas composition and real reservoir condition and that in the surface (Cai et al., 2013). Presently, chemical composition of gas phase on condition of the reservoir in the ZG9 well is unknown. To determine the possible range for the gas, we assume that the formation water was saturated with free gas, and free gas has H2S of 13%, CO2 of 14%, N2 of 13% and CH4 of 60% (Table 6). To produce gas with the present gas composition, the gas may have 51% from exsolved gas and 49% from a gas-cap gas (Table 5). Similarly, other 4 gas-cap gas compositions were assumed and the mixing proportions are calculated in Table 6. It shows that with increasing H2S contents in a gas-cap gas, the mixing proportion from the exsolved gas decreases. Depending on the mixing proportions, the gas-cap gas saturated with formation water in the well ZG9 reservoirs may contain 5e20% H2S (Table 6). Similarly, other gases from water interval or petroleumewater transition are estimated to have gas-cap gas H2S in this area not higher than 15%. 5.2. Origin of sour gas H2S in reservoir gases can originate from bacterial sulfate reduction (BSR), oil cracking or thermochemical sulfate reduction (TSR) (Cai et al., 2001a; 2002). Although some pyrite in this area with d34S values as low as
17.3‰ may have originated from BSR, the H2S is clearly not of bacterial origin because d34SH2S values are significantly heavier those of the pyrites and calcites and replaced sulfate minerals were measured to have fluid inclusion homogenization temperatures >120  C (Cai et al., 2001a, 2008). Field observations indicate that there is no significant or small sulfur isotope fractionation during the cracking of oils to H2S (Orr, 1974; Kesler et al., 1994), which is supported by hydrous pyrolysis experiments on a sulfur rich shale (Amrani et al., 2012). Hence, the observation that H2S in the Ordovician has d34S values lighter than or close to the associated oils (Fig. 7) is consistent with the H2S originating from oil cracking. However, other evidence suggest that this is not the case. If significant cracking of oil occurred, residual oil and its fractions are expected to have positive shifts in d13C value of about 3.5‰ as a result of kinetic isotopic fractionation (Clayton,

Table 4 d34S values and S/C ratios of solid bitumens from ZG9 and ZG341 wells.

Fig. 7. A cross plot showing relationship between H2S d34S and oil d34S values.

Sample No

Strata

Depth (m)

d34S ‰

S/C

ZG9-B1 ZG9-B2 ZG431-B3

O1y O1y O1y

6260.8 6265 5439

19.96 17.87 15.50

0.13 0.06 0.02

Note: AR is atomic ratio.

AR

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C. Cai et al. / Marine and Petroleum Geology 67 (2015) 408e418

Table 5 Solubility of CH4, CO2, N2 and H2S in aqueous solution from model calculation. Formation water

3.4M NaCl

3.4M NaCl Solubility difference（mol/kg） Percentage

Gas partial pressure (MPa)

Temperature ( C)

9.75 9.75 45 10.5 0.1

150 127 150 150 20

Solubility (mol/kg H2O) H2S

CH4

N2

CO2

1.4314 0.0198 0.1463 0.0006 0.1457 7.6%

0.067 1.3649 71.5%

0.0003 0.0195 1%

0.3993 0.0203 0.3790 19.9%

Table 6 Change in contribution of dissolved H2S and free H2S to the present gas with assumed free gas composition in the reservoirs. Assumed free gas composition

Surface gas composition（%） H2S

H2S H2S H2S H2S H2S

¼ ¼ ¼ ¼ ¼

2.5%,CO2 ¼ 5%,N2 ¼ 5%, CH4 ¼ 87.5% 5%,CO2 ¼ 5%,N2 ¼ 5%, CH4 ¼ 85% 10%,CO2 ¼ 7%,N2 ¼ 10%, CH4 ¼ 73% 13%,CO2 ¼ 14%, N2 ¼ 13%, CH4 ¼ 60% 20%,CO2 ¼ 10%, N2 ¼ 10%, CH4 ¼ 60%

CO2

CH4

N2

impossible 43 13.2 43 13 43 17 43 11

41.5 39 33 39

2 5 7 7

1991). The “fractionation” only occurs in an instantaneous context or at a fixed point during a partially completed process. In contrast, if the cracking is essentially complete, then a 13C mass balance suggests that the starting isotopic value must be the same as the final isotopic value. Li et al. (2015) have found that there exists no significant shift in oil d13C value with increasing maturity parameters, if correct, suggesting that no significant partial cracking of oil occurred. Organosulfur compounds such as alkyl-thiolanes, alkylthiols and alkyl 2-thiaadamantanes can arise via back reactions with H2S (Hanin et al., 2002; Cai et al., 2009b; Wei et al., 2012). Hence, the similar d34S values between the H2S and associated oils can arise from such reactions provided the initial sulfur content of the oil is low. The H2S produced from the Ordovician measured here and in previous studies (Cai et al., 2008, 2009b) have d34SH2S values 15e20‰ lighter than the counterpart in the Cambrian (33‰). As kinetic isotope effects are not typically observed in petroleum reservoirs due to the complete reduction of available sulfate (Orr, 1974; Machel et al., 1995), the large differences indicate that the H2S in the Ordovician has not up-migrated from the Cambrian reservoirs where H2S may have been generated from thermochemical reduction of Cambrian sulfates. We, therefore, conclude that the H2S likely originated from in situ TSR in the Upper Cambrian and Ordovician as no sulfate minerals with d34S values similar to the H2S have been found in the Ordovician Yingshan Fm. Dissolved sulfates in formation water may have been the reactive reactants of TSR as proposed previously (Cai et al., 2008, 2009b; 2010; Basuki et al., 2008; Wynn et al., 2010). The H2S d34S values, mainly from 12 to 18‰, are similar to those of the Upper Cambrian anhydrite veins in the paleo-high in the eastern Tazhong uplift and are a possible source of the H2S (Jia et al., 2015). Anhydrite veins have been found only in the Upper Cambrian not in the Ordovician, and are limited to two wells (TZ75 and TC1); thus, it is quite possible that this anhydrite is not to be the main sulfur source for the H2S. Thermochemical reduction of dissolved sulfates in formation water has been proposed for the origin of H2S in the thermomineral springs of the Cerna Valley, Romania (Wynn et al., 2010), in the Nisku gas pools (Machel et al., 1995) and in the NE Sichuan Basin (Cai et al., 2010) with significant sulfur isotope fractionation occurring during the transformation of the sulfates to sulfides. The

Dissolved gas %

Free gas%

Dissolved H2S%

Free H2S%

Dissolved gas/dissolved gas

Dissolved H2S/free H2S

69 55 51 38

31 45 49 62

96.4 89.5 85 71.3

3.6 10.5 15 28.7

2.23 1.22 1.04 0.61

26.78 8.52 5.67 2.48

H2S in this case has d34S values significantly lighter than the early Ordovician seawater (~22e26‰, Claypool et al., 1989), thus it is possible for the H2S to have been derived from the dissolved sulfate of formation water. Further research is required to prove this hypothesis. 5.3. Organic reactants involved in TSR In the study area, potential organic reactants include liquid hydrocarbon, wet gas and methane. As suggested in the above, the H2S-related parameter is influenced by factors such as mixing with late charged gas and exsolution from formation water. Thus, it is irrelevant that methane and ethane do not have d13C values that correlated with H2S contents in the Ordovician (Li et al., 2010). Similarly, relationship between H2S content and bulk oil and saturates d13C value cannot be used to indicate if the liquid hydrocarbons were involved in TSR or not. Although the ZS1C oil in the Lower Cambrian has no detectable biomarkers in their 191 and 217 traces (not shown) and cannot be used to determine its source rock, it is quite possible for this oil to have a similar source rock as the ZS1 oil in the Middle Cambrian from the same well. Positive shift of 2.4‰e3.7‰ in d13C values of whole oil and saturates in the Cambrian with H2S increasing from 0.035% to 11.0% may have resulted from: the maturation of the hydrocarbons; and/or TSR. The first hypothesis alone is less likely as no significant difference in associated H2S contents between the two oils would be expected. Thus, the positive shift in d13C value probably indicates that TSR alteration of liquid hydrocarbons occurred resulting in 12C-bonds being oxidized preferentially. The proposal is supported by CO2 extracted from fluid inclusions of calcites, which has d13C values from
5.9‰ to
14.4‰ (Table 2). The values are consistent with part of carbon has been derived from the oxidization of hydrocarbons, and are similar to TSR calcites in the Ordovician that have d13C values from
6.0‰ to
9.4‰ (Cai et al., 2001a). 5.4. H2S diluted by late charged H2S-poor dry gas A poor correlation (Fig. 6B) could arise because H2S may have been present as different phase and lost as incorporated into oil and precipitated as pyrite. The roughly negative correlation between

C. Cai et al. / Marine and Petroleum Geology 67 (2015) 408e418

dryness and H2S content may arise from several scenarios; either TSR of methane proceeded to higher extents than by wet gas and liquid hydrocarbons; or H2S-poor dry gas mixed with H2S-rich wet gas. Chemistry and isotopic composition of fluid in fluid inclusion are used to determine which is the most likely hypothesis. Eleven thin sections of reservoir grainstones from wells TZ621, TZ72 and TZ823 were analyzed for fluid inclusions in calcite cements and veins by laser Raman microspectroscopy. H2S content was found to range from 2.6 to 7.5 mol% (Table 4 of Cai et al., 2009b). The values are significantly higher than those of the associated gas that have less than 0.2 mol% H2S (Table 1). The calcites are considered to have precipitated during the late Hercynian to the early Himalayan Orogenies (late Permian to Eocene). Thus, it is quite possible for H2S-poor gas to have been charged after the precipitation of the calcites, likely during late Himalayan Orogeny or Neogene period. Methane-dominated gas has been proposed to charge into the Ordovician reservoirs during late Himalayan Orogeny (Wang et al., 2014). The hypothesis is supported by gases extracted from fluid inclusions, which show lighter methane d13C values than the free gases associated the fluid inclusions (Table 3). This evidence indicates that the present gas has mixed with gas dominated by 13Crich methane after the precipitation of the calcites, likely during Neogene. The hypothesis 1 is less possible in that all reservoirs contain alkane gas and liquid hydrocarbons. Liquid hydrocarbons have been shown to be oxidized preferentially to methane and ethane (Machel et al., 1995). Thus, it is very likely for the hypothesis 2 to apply in this area. 5.5. H2S precipitation as metal sulfides and incorporation into oils and solid bitumens Small amounts of pyrite and occasional sphalerite are present in this area (Cai et al., 2008, 2009b). Some of the sulfides may have precipitated from the present H2S and show d34S values ranging from 14.6 to 22.3‰ (n ¼ 6; Cai et al., 2009b; Jia et al., 2015) similar to the H2S in the Ordovician. This is expected as no significant S isotope fractionation during pyrite precipitation. Although such sulfides have been encountered in many wells, only very small amounts of the H2S may have precipitated due to limited amounts of available Fe in the carbonates, similar to the NE Sichuan Basin (Cai et al., 2014). TSR-H2S have been proposed to back react with hydrocarbons to generate alkythiolanes, alkythiols and alkyl thiaadamantanes in the Tazhong area (Cai et al., 2009b, 2015; Li et al., 2012). Alkythiolanes were first reported from TSR area from the Lower Ordovician in TZ83 well by Cai et al. (2009b) and have been detected from ZG5 and ZG7 wells in this study area by Li et al. (2010). Alkylthiols have been reported from TSR cases by Orr (1974) and Cai et al. (2003), and range in concentrations of 1.6e140.5 mg/ml oil in oils from the study area, with >50 mg/ml oil in samples from wells ZG7, ZG6, ZG21, ZG8, ZG22 and ZG501 (Li et al., 2012). The concentrations of alkylthiols do not correlate with the associated H2S concentrations. Alkyldibenzothiophenes (>6000 mg/g) have been reported in oils from ZG6, ZG7, ZG8 and ZG21 wells. Aromatic fraction is dominated by alkyldibenzothiophenes (>50%) in oils from the TZ83, ZG5 and ZG501 wells (Cai et al., 2009b; Li et al., 2012). The oils with high concentrations of the above organic sulfur compounds are associated with H2S >3% (Table 1), suggesting that at least part, if not the majority, of the compounds have been generated from the TSR-H2S incorporation. Thus, a significant amount of the H2S is present as organic sulfur in oils. TSR-H2S has been reported to incorporate into solid bitumen in many cases (Powell and MacQueen, 1984; Sassen et al., 1988; Cai

417

et al., 2001a, 2010; Kelemen et al., 2008). Limited solid bitumen is found to occur in the Ordovician in the Tazhong area, and the H2S which could have been incorporated into solid bitumen is small in amount. However, the ZG9-B1 solid bitumen show evidence for TSR-H2S incorporation as indicated by its d34S value being close to the TSR-H2S in this area, and has a higher S/C atomic ratio when compared to the ZG9-B2 and ZG43-B3 solid bitumen samples (Table 4; Powell and MacQueen, 1984). 6. Conclusions Based on the present data, we conclude that most of the TSR-H2S in the Ordovician in the Tazhong area has been partitioned among various phases including S incorporated into oils. Small amounts of sulfur was precipitated as pyrite and incorporated into solid bitumen. The H2S may have been derived from incomplete reduction of dissolved sulfates and thus, has d34S values significantly lighter than the early Ordovician to Cambrian seawater. The involvement of liquid hydrocarbons in TSR resulted in positive shifts in d13C values of whole oil and saturates in the Cambrian with increasing H2S contents, and the generation of 12C-rich CO2 in fluid inclusions and TSR calcites. The H2S-rich gas subsequently mixed with H2S-poor dry gas, resulting in CH4 from fluid inclusions having d13C values 1e4‰ lighter than the associated free gas after the host calcite precipitation during late Himalayan Orogeny (Neogene). The concentration of H2S produced from the water intervals or petroleumewater transition zones is significantly higher than that of the gas-cap gas in the reservoirs and is related to exsolved gas/free gas ratios during the production. H2S concentrations in this case cannot be used to indicate TSR extents in the Ordovician. Acknowledgments This work is financially supported by China National Funds for Distinguished Young Scientists (41125009) and Special Major Project on Petroleum Study (2011ZX05008-003). Two anonymous reviewers are sincerely acknowledged for helpful comments on an earlier version of this manuscript. References Amrani, A., Deev, A., Sessions, A.L., Tang, Y.C., Adkins, J.F., Hill, R.J., Moldowan, J.M., Wei, Z.B., 2012. The sulfur-isotopic compositions of benzothiophenes and dibenzothiophenes as a proxy for thermochemical sulfate reduction. Geochim. Cosmochim. Acta 84, 152e164. Bailey, S.A., Smith, J.W., 1972. Improved methods for the preparation of sulphur dioxide from barium sulphate for isotope ratio studies. Analytical Chemistry 44, 1542e1543. Basuki, N.I., Taylor, B.E., Spooner, E.T.C., 2008. Sulfur isotope evidence for thermochemical reduction of dissolved sulfate in Mississippi Valley-type zincelead mineralization, Bongara area, northern Peru. Econ. Geol. 103, 783e799. Cai, C.F., Hu, W.S., Worden, R.H., 2001a. Thermochemical sulphate reduction in Cambro-Ordovician carbonates in central Tarim. Mar. Pet. Geol. 18, 729e741. Cai, C.F., Franks, S.G., Aagaard, P., 2001b. Origin and migration of brines from Paleozoic strata in Central Tarim, China: constraints from 87Sr/86Sr, dD, d18O and water chemistry. Appl. Geochem. 16, 1269e1283. Cai, C.F., Worden, R.H., Wang, Q.H., Xiang, T.S., Zhu, J.Q., Chu, X.L., 2002. Chemical and isotopic evidence for secondary alteration of natural gases in the Hetianhe Field, Bachu Uplift of the Tarim Basin. Org. Geochem. 33, 1415e1427. Cai, C.F., Worden, R.H., Bottrell, S.H., Wang, L.S., Yang, C.C., 2003. Thermochemical sulphate reduction and the generation of hydrogen sulphide and thiols (mercaptans) in Triassic carbonate reservoirs from the Sichuan basin, China. Chem. Geol. 202, 39e57. Cai, C.F., Xie, Z.Y., Worden, R.H., Hu, G.Y., Wang, L.S., He, H., 2004. Methane-dominated thermochemical sulphate reduction in the Triassic Feixianguan Formation East Sichuan Basin, China: towards prediction of fatal H2S concent rations. Mar. Pet. Geol. 21, 1265e1279. Cai, C.F., Worden, R.H., Wolff, G.A., Bottrell, S.H., Wang, D.L., Li, X., 2005. Origin of sulfur rich oils and H2S in tertiary lacustrine sections of the Jinxian Sag, Bohai Bay Basin, China. Appl. Geochem. 20, 1427e1444.

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