Fluid inclusion and stable isotopic studies of thermochemical sulfate reduction: Upper permian and lower triassic gasfields, northeast Sichuan Basin, China

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Fluid inclusion and stable isotopic studies of thermochemical sulfate reduction: Upper permian and lower triassic gasfields, northeast Sichuan Basin, China Kaikai Li a,b,c,⇑, Simon C. George c, Chunfang Cai d,e,f,⇑, Se Gong g, Stephen Sestak g Stephane Armand g, Xuefeng Zhang h a School of Energy Resources, China University of Geosciences (Beijing), Beijing 100083, China Key Laboratory of Marine Reservoir Evolution and Hydrocarbon Enrichment Mechanism, Ministry of Education, China c Department of Earth and Planetary Sciences and MQMarine Research Centre, Macquarie University, NSW 2109, Australia d Key Lab of Petroleum Resources, Institute of Geology and Geophysics, Chinese Academy of Sciences, Beijing 100029, China e College of Earth and Planetary Sciences, University of Chinese Academy of Sciences, Beijing 100049, China f Key Laboratory of Oil and Gas Resources and Exploration Technology, Yangtze University, Wuhan 430100, China g CSIRO Energy Business Unit, North Ryde, NSW 2113, Australia h Institute of Oil and Gas, Peking University, Beijing 100871, China b

Received 1 July 2018; accepted in revised form 21 November 2018; Available online 26 November 2018

Abstract Fluid inclusions hosted in different stages of TSR-derived diagenetic minerals are expected to record compositions and isotopes of paleo-fluids at the time of trapping during different TSR extents. Here we report the first set of data on carbon isotopes of CH4 and CO2 and hydrogen isotopes of H2O trapped in fluid inclusions in TSR calcites. We find that the NE Sichuan sour dolostones have initially experienced oil- and wet gas-dominated TSR, as recorded in H2S-bearing oil inclusions with lower homogenization temperatures (Th) values (e.g.,
137 °C) and the coexistence of C2+ hydrocarbon gas and H2S in fluid inclusions. The subsequent dry gas-dominated TSR occurred in higher reservoir temperatures (> about 161.5 °C) when most C2+ hydrocarbons were exhausted. The three-stage TSR resulted in CH4 d13C values becoming progressively heavier from 46.7‰ to 29.6‰, H2O d2H values shifting negatively from 36.4‰ to 67.8‰ and salinities decreasing to as low as 0.9 wt% NaCl. The dry gas-dominated TSR reaction seems to be the most efficient at water production, which, however, was limited by available reactive sulfate, and shows significant differences within the reef and shoal reservoirs along the platform margin, and the anhydrite-bearing reservoirs in the paleo-lagoon area. The TSR reaction within the porous shelf-margin reservoirs is capable of causing carbonate dissolution owing to high porosity and good connectivity of the micropore network and the resulting mass transport away from TSR sites. This resulted in CO2 d13C positive shift from 9.3‰ to +6.3‰, and a positive correlation of this parameter with Th. In contrast, in the tight anhydrite-bearing reservoirs, slow mass transport and quick saturation of calcium and dissolved CO2 in the pore waters is expected to precipitate TSR calcite near the anhydrite crystals, resulting in calcite crystals having more depleted d13C values (1.4‰ to 18.9‰). This study shows that there are essential differences in the process and effects of TSR reaction due to geological differences in the settings of TSR sites. Ó 2018 Published by Elsevier Ltd.

⇑ Corresponding authors at: School of Energy Resources, China University of Geosciences (Beijing), Beijing 100083, China (K. Li). Key

Lab of Petroleum Resources, Institute of Geology and Geophysics, Chinese Academy of Sciences, Beijing 100029, China (C. Cai). E-mail addresses: [email protected] (K. Li), [email protected] (C. Cai). https://doi.org/10.1016/j.gca.2018.11.032 0016-7037/Ó 2018 Published by Elsevier Ltd.

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Keywords: Fluid inclusion; TSR; Carbonate dissolution; Carbon isotope; Hydrogen isotope; Sichuan Basin

1. INTRODUCTION Thermochemical sulfate reduction (TSR) is a welldocumented process that occurs at elevated temperatures (>120 °C) and involves the reaction between sulfate and hydrocarbons to produce hydrogen sulfide, elemental sulfur, calcite, carbon dioxide and organic sulfur compounds (e.g., Machel et al., 1995; Worden and Smalley, 1996; Krouse et al., 1988; Cai et al., 2003; 2016). The overall process can be summarized as the simple reaction: SO4 2 þ hydrocarbons ! H2 SðHS Þ þ CO2 ðHCO3  Þ  H2 O  S  altered hydrocarbons

ð1Þ

The variations of chemical and stable isotopic compositions in hydrocarbons and minerals have been extensively used in experiments to understand the role of the organic and inorganic reactants (e.g., Manzano et al., 1997; Zhang et al., 2008), hydrocarbon alteration (e.g., Kelemen et al., 2010; Cai et al., 2016), rate-controlling factors during TSR (e.g., Worden et al., 2000; Bildstein et al., 2001) and the effect of TSR on rock and fluid properties (e.g., Worden et al., 1996; Machel, 2001). However, there is still considerable confusion on explanation of some chemical and isotopic features and understanding of some basic issues about TSR. Thermocatalytic experiments on medium-molecularweight hydrocarbons, e.g., n-octadecane, have shown that methane increases in 13C with extent of cracking (Frank and Sackett, 1969; Sackett et al., 1978). As TSR alteration proceeds, methane d13C values seem to respond more complex to alteration of hydrocarbons. Claypool and Mancini (1989) claimed that methane d13C value did not increase with increasing amount of H2S in the oil pools within Smackover and Norphlet formations in southwestern Alabama. In contrast, a positive relationship between methane d13C value and gas souring index [GSI = H2S/(H2S + C1-6)] has been well documented in light hydrocarbon gas reservoirs, e.g., the Devonian and Mississippian formations in western Canada (Krouse et al., 1988), the Permian Khuff Formation of Abu Dhabi and Saudi Arabia (Worden et al, 1996; Jenden et al., 2015) and the Triassic Jialingjiang and Feixianguan Formations (Cai et al., 2003; 2004; 2013). A similar trend was also reported in the experiments of TSR alteration on C1-5 hydrocarbons (Pan et al., 2006). However, Hao et al. (2008) and Liu et al. (2013) claimed that methane d13C values remain constant throughout wet gas-dominated TSR stage, and increase at methanedominated TSR stage. Further work is therefore required to trace the behaviour of methane d13C values throughout TSR alteration, including the involving process of oil-, wet gas- and dry gas-dominated TSR. The possible occurrence of post-TSR migration or alteration of natural gas in the hydrocarbon-water-rock system (e.g., Worden et al., 1995) would increase uncertainties of

data interpretation. A positive shift in d13C of CO2 in the present-day gas reservoirs was regarded as compelling evidence for the occurrence of TSR-induced dissolution of dolomite in the NE Sichuan Basin (Cai et al., 2014; Liu et al., 2014a). The shift was either ascribed to re-equilibration of CO2 with the 13C-enriched water-rock system in the Mobile Bay gas field (Mankiewicz et al., 2009), or to preferential precipitation of 12C-rich CO2 as TSR associated calcite in the NE Sichuan Basin (Hao et al., 2015), in which no significant carbonate dissolution and porosity change was proposed during TSR. Considering that typical TSR settings are generally hydrodynamically closed (Machel, 2001), some information related to mass transfer and isotopic variation would be recorded in the closed system. Fluid inclusions in diagenetic minerals formed by TSR are examples of tiny closed system time-capsules and are representative of the parent mineralizing fluids (Roedder, 1984; Karlsen et al., 1993). Oil-, wet gas- and methane- stages of TSR are proposed to occur in the NE Sichuan Basin based on methane and ethane d13C values (Hao et al., 2008; Liu et al., 2013; Jiang et al., 2015), however, the lines of evidence are not conclusive. New data are required to determine if multi-stage TSR occurred in NE Sichuan, which will help explain other methane-dominated TSR cases worldwide. Information about chemical and isotopic composition of fluid during different TSR stages is possible to have been recorded in fluid inclusions. However, very few studies have focused on the compositions and stable isotopes of fluid inclusion gases related to TSR (Yang et al., 2001). Reduced fluid inclusion salinity and water d18O values with the extent of TSR reaction was documented in the Permian Khuff Formation in Abu Dhabi and invoked to support the water generation during TSR (Worden et al., 1996). The balanced reactions for methane and ethane can be written as: CaSO4 þ CH4 ! CaCO3 þ H2 S þ H2 O

ð2Þ

2CaSO4 þ C2 H6 ! 2CaCO3 þ H2 S þ S þ 2H2 O

ð3Þ

18

Light d O value of water produced by TSR was considered to be derived from the TSR-induced breakdown of anhydrite and oxygen fractionation of anhydrite, despite that the water from anhydrite breakdown in the Devonian Wabamun Group of southwestern Albera was reported to have heavy d18O values (Yang et al., 2001). A similar negative shift in d18O values of water was calculated in the T1f Formation of the NE Sichuan Basin and attributed to water production during TSR (Jiang et al., 2015). In contrast, Machel (1987, 1998) claimed that the depleted d18O values of the saddle dolomite from the Devonian Nisku reef trend in the Alberta Basin resulted from transfer of oxygen 2 from the SO2 4 into the CO3 groups rather than the formation of TSR water. Machel (1998, 2001) also claimed that volumetrically minor to negligible water was released during TSR and some sub-reactions even consume water.

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Reactions (1), (2) and (3) suggest that hydrogen in hydrocarbon reactant would go into water if water is released during TSR. The water released during TSR is more likely to have significantly lighter d2H values derived from hydrocarbon reactants (mainly from 250‰ to 85‰; Schoell, 1980; Yeh and Epstein, 1981) compared with many H2S-free saline formation waters (mainly from 0‰ to 26‰, Moldovanyi et al., 1993; Clayton et al., 1966). This will pull down d2H of the water trapped in fluid inclusions, which can be used to assess whether water is produced during TSR or not. The accumulation of high H2S concentrations in the Upper Permian Changxing Formation (P3ch) and Lower Triassic Feixianguan Formation (T1f) in the NE Sichuan Basin in China have been demonstrated to be due to TSR based on multiple lines of evidence (Cai et al., 2004; Zhu et al., 2005; Ma et al., 2008; Liu et al., 2013). The alternation of potential reactants for TSR from oil to wet hydrocarbon gases (C2-C5), and lastly to methane might have resulted in great diversity in methane d13C values following TSR, and in the amounts of TSR-derived water (Cai et al., 2003, 2004, 2013; Pan et al., 2006; Hao et al., 2008). CH4, H2S, CO2 and H2O have been detected in high levels within the fluid inclusions of diagenetic minerals using laser Raman microprobe spectroscopy (e.g., Xie et al., 2006; Zhu et al., 2006). Data from these fluid inclusions are expected to provide valuable information about TSR in the NE Sichuan Basin. This paper presents the first data on the carbon isotopes of CH4 and CO2, and hydrogen isotopes of H2O, released from fluid inclusions hosted in TSR-derived calcite crystals. Carbon and oxygen isotope analyses were also performed on both TSR and non-TSR calcite samples. The aims are to (1) assess the role of methane in TSR and the dissolution-precipitation process in the hydrocarbonwater-rock system, and (2) to determine if water is newly generated and what is the amount during TSR. The results provide some insights into the TSR mechanism, and have application for predicting the porosity of deep-buried carbonate reservoirs, so have global theoretical and practical significance. 2. GEOLOGICAL SETTING The Sichuan Basin is a rhombic basin with an area of 2.3  105 km2 in southwestern China. The basin has a complex tectonic and sedimentary history and has experienced five orogenies, including the Caledonian-Hercynian movement (Ordovician-Permian), the Indosinian movement (Upper Permian-Upper Triassic), the Yanshan movement (Jurassic-Cretaceous) and the Himalayan movement (Paleogene-Quaternary). The NE-trending structures started developing during the late Indosinian orogeny, then formed their basic styles during the middle Yanshan orogeny, and finalized adjustment during the Himalayan orogeny. The NW-trending structures started evolving during the late Yanshan orogeny, and reached their final shape during the Himalayan orogeny (Ma et al., 2007). Potential source rocks for the NE Sichuan Basin gases are mainly marine rocks including Lower Cambrian shales

and mudstones, Lower Silurian shales, and Upper Permian coals, mudstones, and muddy limestones (Ma et al., 2008; Fig. 2). Geochemical signatures show that the Upper Permian source rocks mainly contributed hydrocarbons to the P3ch and T1f reservoirs in the NE Sichuan Basin (Cai et al., 2017). The distribution of the P3ch and T1f reservoirs is controlled by depositional facies and the effective reservoirs are mainly developed in platform-margin reef and shoal environments (Ma et al., 2007). The platformmargin reef facies, mainly developing in the P3ch formation, is made up of gray limestones and the dolomites of a sponge reef, and gray limestones and dolomites of a framework sponge reef (Fig. 2). The platform-margin bank facies, chiefly developed in the P3ch and T1f formations, is made up of thickly-bedded to massive oolitic and bioclastic dolomites and dolarenites (Ma et al., 2007; Fig. 2). The evaporite beds of the lagoon-tidal flat facies in the Leikoupo (T2l) and Jialingjiang (T1j) formations, as well as in the upper part of the Feixianguan Formation (T1f4 member and the top of the T1f3 member), may serve as regional caprocks for the underlying T1f1-2 and P3ch carbonate reservoirs (Ma et al., 2008; Fig. 2). Massive evaporite sediments in the T1f1-2 Formation also formed in lagoon-tidal flats around the areas of the Jz1 and Y1 wells (Fig. 3), and show a trend of decreasing thickness with increasing distance to the evaporated lagoon (Jiang et al., 2002; Chen, 2005). The P3ch-T1f reefs and shoals were subjected to occasional exposure related to high-frequency sea-level fluctuations during early diagenesis. Then the reservoirs experienced continuous and rapid burial and reached their maximum burial depths of over 8000 m and temperatures of approximately 220 °C at 80 Ma at the end of the Cretaceous. The reservoirs were then uplifted to the present depths of 4000–6000 m and cooled to <120 °C during the Neogene (Hao et al., 2008; Li et al., 2012). There are no great differences in the burial and geothermal history between the sour and sweet gas reservoirs, except that the latter have experienced deeper maximum burial (Cai et al., 2014). The major oil generation period for the Upper Permian source rocks was between 210 Ma and 190 Ma (T3-J1, Wang et al., 2010). The cracking of oil to natural gas was proposed to have occurred during the Middle Jurassic (Hao et al., 2008; Wang et al., 2010). Large H2Srich gas accumulations have been discovered recently in the Upper Permian Changxing Formation (P3ch) and Lower Triassic Feixianguan Formation (T1f) in the NE Sichuan Basin, located in the Puguang, Luojiazhai, Dukouhe, Tieshanpo, Maobachang, Longgang and Yuanba structures (Fig. 1a, b). 3. SAMPLES AND METHODS Rock samples were taken from several wells in the northeast Sichuan Basin (Tables 1, 2; Fig. 1B), and from the outcrop field sections HH, PLD and YGD (Fig. 1A). 230 thin sections were made from the core and outcrop samples and were half stained with Alizarin Red S to distinguish dolomite from calcite. Based on preliminary core and thin section examination, 34 post-bitumen calcites showing

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Fig. 1. (a) General map showing the location of important gas fields in the NE Sichuan Basin and the paleoenvironment during the Early Triassic. (b) Detailed map showing the geological structures on the platform on the east side of the Kaijiang-Liangping (K-L) Trough, which is the focus area of this study. The trend of gypsum thickness in (b) is based on Jiang et al. (2002) and Chen (2005), who used core observation and logging analysis techniques. PLD = the Panlongdong field section; YGD = the Yanggudong field section; HH = the Honghua field section.

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Fig. 2. Synthetic stratigraphy for the NE Sichuan Basin and comparison of lithology between the Yuanba and Puguang gas fields and the Jinzhuping gas-bearing structure.

coarse vug/fracture-filling spar, with solid bitumen or other hydrocarbon inclusions associated, are related texturally to TSR (Machel, 1987, 2001; Worden et al., 1995; Worden and Smalley, 1996; Cai et al., 2004; Li et al., 2012). Four prebitumen calcite samples with vug/fracture-filling textures and without solid bitumen or other hydrocarbon inclusions are typical of non-TSR diagenetic minerals (Li et al., 2012). These calcites were sub-sampled using a dentist’s drill, and were then crushed to powder for C and O isotope measurements. The powdered samples were dissolved in anhydrous H3PO4 to release CO2 gas, which was analyzed on a Finnigan MAT 251 mass spectrometer. d13C and d18O are reported as ‰ relative to the Pee Dee Belemnite (VPDB) standard, with a precision of ±0.1‰. Fluid inclusions were observed in double polished thick sections from sour gas reservoirs, using a calibrated Linkam

THM600 heating-cooling stage fitted with a ultraviolet (UV) lamp to determine whether they contained oil, gas or water. For microthermometry, only aqueous two-phase primary inclusions with a small size (<15 lm), regular shape and low vapor to liquid ratios (<15%) were measured for homogenization temperatures (Th). The results are reported with a precision of ±1 °C. Salinities were calculated from the final ice melting temperatures using the equation of Bodnar (1993) for the H2O-NaCl system. Carbon isotope analysis of fluid inclusion gases from crushed TSR-derived calcite samples were performed at both the Commonwealth Scientific and Industrial Research Organization (CSIRO) in Australia and the Research Institute of Petroleum Exploration and Development (Langfang Branch), PetroChina Ltd. For the CSIRO analyses, eight single-crystal calcite samples containing abundant

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Fig. 3. Photomicrographs showing different types of fluid inclusions in void-filling calcite cements. (a) Plane-polarized light (PL), well PG6, 5350.5 m, P3ch. (b) View taken under UV light, well PG6, 5350.5 m, P3ch. (c) Plane-polarized light (PL), well Yb101, 6904 m, P3ch. (d) View taken under UV light, well Yb101, 6904 m, P3ch. (e) Plane-polarized light (PL), well PG9, 5738.6 m, T1f3. (f) View taken under UV light, well PG9, 5738.6 m, T1f3.

hydrocarbon-bearing fluid inclusions were selected from the paleo-TSR regions where high concentrations of H2S, S-rich bitumen and/or elemental sulfur were detected. The surfaces of the calcite grains were successively cleaned by methanol and dichloromethane. Carbon isotope analyses of the fluid inclusion gases were conducted on an online crushing–trapping system comprising a gas-tight crusher and a concentrator with micro-trap connected to a gas chromatograph-combustion-isotope ratio mass spectrometer (GC-C-IRMS). Fluid inclusion gases were released by vertical vibration of the gas-tight crusher with the

pre-cleaned calcite grains loaded, and cyro-trapped in the micro-trap on the concentrator for 5 minutes using liquid nitrogen. The gases were then released by heating the trap to 250 °C to the GC-C-IRMS, via the GC injector and d13C was measured with a precision of ±0.5‰. A system blank was run before each crush to ensure that there was no contamination from the system. Duplicate analyses were performed on each sample. Carbon isotopes of fluid inclusion gases also were analyzed on four similar calcite samples at the Research Institute of Petroleum Exploration and Development (Langfang Branch), PetroChina Ltd.

92 Table 1 Carbon isotopic compositions of CH4 and CO2 trapped in fluid inclusions (d13CCH4; d13CCO2), carbon and oxygen isotopic compositions of the crushed TSR-derived calcite crystals (d13CCaCO3; d18OCaCO3), the difference in d13C between CO2 trapped in fluid inclusions and the host calcite, and the homogenization temperatures of the fluid inclusions (Th). The index H2S/(H2S + C1-6) is calculated using the molar concentrations of natural gas in the associated gas reservoirs. Sample number

Formation

Depth (m)

Mineral

Fluid inclusions and their host minerals

Dw3-1 Dw3-1* Dw102-1 Dw102-1* HH-1 HH-1* PLD-1 PLD-2 Yb11-1 Yb102-3 Yb224-1 Yb224-1* Yb204-2 Yb204-2* YGD-1 YGD-1* YGD-2 YGD-2* YGD-3 YGD-3*

T1f2 T1f2 T1f2 T1f2 P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch

4735 4735 4900.8 4900.8 Outcrop Outcrop Outcrop Outcrop 6917 6724 – – 6549 6549 Outcrop Outcrop Outcrop Outcrop Outcrop Outcrop

Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen

Void-filling calcite

D1 Jz1 Mb3 Pg3 Mb3 Mb3 Mb3 Mb3 Mb3 Pg2 Pg2 Pg5 Pg6 Pg6 Pg6 Pg6 Pg6 Pg6 Pg6

T1f2 T1f1 T1f4 T1f2 P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch

– 2978 3876 4953.7 4391.07 4382.8 4356.45 4349.26 4415.24 5279.77 5292.31 5295 5280.8 5297.7 5338.65 5247.1 5350.5 5323 5246.5

Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen Post-bitumen

d13CCO2 (‰ PDB)

d13CCH4 (‰ PDB)

d13CCaCO3 (‰ PDB)

d18OCaCO3 (‰ PDB)

Dd13C(CO2-CaCO3) (‰ PDB)

Th (°C)

H2S/ (H2S + C1-6)

Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite

7.20 5.40 6.30 6.80 6.30 8.40 1.90 2.10 9.30 2.40 4.48 5.50 1.50 7.00 0.75 0.35 1.38 3.05 5.89 3.07

30.1 31.3 34.7 36.3 30.0 30.6 37.2 36.9 29.6 30.1 29.8 30.3 33.1 31.1 46.7 45.0 23.3 23.0 43.1 42.7

1.43 1.70 1.41 1.08 1.10 2.11 11.9 11.8 9.50 3.70 0.04 1.70 3.64 3.10 8.56 8.10 5.56 3.80 14.0 –

6.67 to 6.67 6.56 9.24 9.52 6.60 6.14 3.30 7.10 6.00 13.6 5.76 5.50 6.65 6.20 4.55 4.20 5.76 5.70 6.38 –

3.97 5.5 4.89 5.72 5.2 6.29 10 9.7 0.2 6.1 4.44 3.8 5.14 10.1 7.81 8.45 6.94 6.85 8.14 –

185.0 – 145.8 – 165.0 – 126.0 137.0 170.1 176.2 173.8 – 161.5 – 133.1 – 133.1 – 137.4 –

15.8 – 2.3 – – – – – 7.0 4.9 11.2 – – – – – – – – –

Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite Calcite

– – – – – – – – – – – – – – – – – – –

– – – – – – – – – – – – – – – – – – –

2.60 13.4 7.76 1.45 2.80 1.64 0.28 1.36 5.46 1.01 1.96 2.37 0.64 2.02 1.96 0.65 2.21 1.13 0.26

6.30 6.50 6.29 7.24 7.09 5.25 5.95 7.96 4.62 7.95 7.38 7.83 5.79 5.04 5.36 6.85 4.58 8.09 7.20

– – – – – – – – – – – – – – – – – – –

– – – – – – – – – – – – – – 176.2 150.6 178.9 – 146.0

16.4 6.9 – – – – – – 9.9 17.3 – – – – 16.2 – 16.2 – –

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Subject

Pg8 Pg8 Pg8 Void- filling calcite

P3ch P3ch P3ch Lj1 Lj1 Mb2 Pg6

5644 5640.5 5525 T1f2 T1f2 T1f2 T1f3

Post-bitumen Calcite Post-bitumen Calcite Post-bitumen Calcite – 3471 4344 4875.5

– – – Pre-bitumen Pre-bitumen Pre-bitumen Pre-bitumen

Calcite Calcite Calcite Calcite

– – – – – – –

2.12 1.82 0.08 – – – –

5.21 7.80 9.42 0.61 1.24 2.16 2.61

– – – 7.20 6.20 6.63 5.18

– – – – – – –

– – – 99.8 112.3 109.7 104.6

– – – –

– No measurement or data available. * Repeated samples.

Sample number

Formation

Depth (m)

Host mineral

d13D (‰ SMOW)

Measured d13Ocalcite (‰ PDB)

Calculated d13Owater (‰ SMOW)

Th (°C)

H2S/(H2S + C1-6)

Dw3-2 Dw102-1 Dw102-2 HH-1 HH-2 Yb11-1 Yb204-2

T1f2 T1f2 T1f2 P3ch P3ch P3ch P3ch

4720 4900.8 4824 Outcrop Outcrop 6917 6549

Calcite Calcite Calcite Calcite Calcite Calcite Calcite

39.0 36.4 58.9 50.7 67.8 63.4 41.0

6.67 9.24 7.81 6.14 5.00 6.0 6.65

10.14 8.42 11.04 12.98 15.52 13.45 12.22

134.0 145.8 161.7 165.0 187.3 170.1 161.5

– – – – – 7.0 2.5

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Table 2 Hydrogen isotopic compositions of fluid inclusion waters, and the corresponding homogenization temperatures of the fluid inclusions (Th). The d18O values of the fluid inclusion water were calculated based on the oxygen isotope equilibrium fractionation equation between calcite and pure water: 1000 lna = 2.78  106/T2 -2.89 (O’Neil et al., 1969). The index H2S/(H2S + C1-6) is calculated using the molar concentrations of natural gas in the associated gas reservoirs.

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Calcite samples (15 g) were cleaned as above, and crushed off-line in a stainless steel container with ball bearings to collect fluid inclusion gases (Yang et al., 1995; Gong et al., 2007), which were then measured for d13C on a Thermo Finnigan Delta Plus IRMS. The method of Yang et al. (1995) was adopted to determine the hydrogen isotope compositions of the fluid inclusion water. 15 g of pure giant coarse milky white calcite crystals from 7 samples (Table 2) were soaked in acetone for about 3 hours and then ethanol overnight, dried and then crushed in a stainless steel container with ball bearings. The released water was cryogenically transferred into vacuum tubes immersed in liquid N2 and then reacted with zinc to produce H2. The d2H values were analyzed on a Finnigan MAT 252 mass spectrometer. Results are reported as ‰ relative to the VSMOW standard, with a precision of ±0.2‰. Laser Raman Microspectrometry (LRM) was used to characterize the gas compositions inside the fluid inclusions in the void-filling calcite crystals. The Raman system used was a JY/Horiba Lab-Ram HR Raman spectrometer, using a He/Ne laser kit 632.8 nm/17 mW, a 40 Olympus objective with 0.5 numerical aperture, and a 600 grooves/mm grating with a spectral resolution of about 1 cm1. Formation water samples were collected from the P3ch and T1f formations in various sour gas fields (e.g. Puguang, Dukouhe, Luojiazhai and Maobachan) and (Table 3; Fig. 1). All the water samples were filtered through glass wool to remove any solids and oil droplets. Then the major ionic compositions of the samples were analyzed using ion chromatography. The total dissolved solids (TDS) were calculated by summing the cation and anion concentrations. Details of the measurement procedure conducted is described in Connolly et al. (1990). 4. RESULTS 4.1. Fluid inclusion petrography, microthermometry and gas composition Abundant diverse fluid inclusions were observed in voidfilling calcite cements (Fig. 3), including 2-phase aqueous inclusions and single-, two- and three-phase hydrocarbon inclusions, e.g., solid bitumen inclusions, pure gas inclusions and a few oil inclusions. The aqueous inclusions display achromatic transparent characteristics and wide vapor to liquid ratios from 2% to 25% and do not fluoresce (Fig. 3a, b). The gas inclusions have greyish black colors with a brighter centre under polarized light, and mostly do not fluoresce (Fig. 3a, b, c, d). Some of them exhibit weak white fluorescence due to the presence of minor oil. These are readily distinguished from the solid bitumen inclusions that are black under polarized light and do not fluoresce (Fig. 3d, e, f). The oil inclusions commonly exhibit yellow and light yellow colors under polarized light and fluoresce yellow–white under UV light (Fig. 3e, f). Within the TSR-derived calcite crystals, greatly varying proportions of oil and gas inclusions were observed. The Th and salinities of 2-phase aqueous fluid inclusions in non-TSR calcite crystals range from 95.5 °C to 116 °C

(n = 22) and from 7.3 to 21 wt% eq. NaCl (n = 22), respectively. The values are slightly higher than those of the bulk dolomites reported previously (Jiang et al., 2014, Fig. 4) The Th and salinities of TSR-derived calcite crystals from sour gas reservoirs range from 120 °C to 215.7 °C (n = 98) and from 0.9 to 21 wt% eq. NaCl (n = 98), respectively. There is a weak inverse relationship between salinity and temperature for the sour gas reservoirs (R2 = 0.31, Fig. 4), showing that salinity decreases as the temperature of calcite increases. Typical Raman spectra of gas compositions in fluid inclusions are reported in Fig. 5 for several samples. H2S peaks are present in each spectrum at a very low Raman shift value of 2600 cm1 (usually 2609 cm1). CO2 peaks can be identified in HH-1, YGD-2 and YGD-3 at 1282 cm1 and/or 1383 cm1. Strong CH4 peaks are present in D5 and HH-1 at 2909 cm1 and a weak C6H6 peak is observed in HH-1 at 3062 cm1. The exclusive presence of C6H6 peak without peaks of other C2+ hydrocarbon gas has been also reported previously (Xia et al., 2012) and can be attributed to that aromatic compounds are more stable at pyrolysis conditions relative to saturated hydrocarbons (Behar et al., 2002). Two peaks that are present in YGD-3 at 2958 cm1 and 3067 cm1 are assigned to C2H6 and C6H6, respectively. CH4 and other hydrocarbon gas are almost absent from the spectra or below detection limit in PLD-1 and YGD-2. The gas wetness was obtained using the semi-quantitative data of fluid inclusion gas compositions, being from numerical estimation of relative peak areas (Fig. 6; Xie et al., 2006; Zhu et al., 2006; Xia et al., 2012). There is a first increasing trend of wetness as Th increases from 119 °C to 137 °C and a subsequent decreasing trend with increasing Th. The wetness approaches a value of less than 10% at temperatures above 165 °C. 4.2. d13C and d18O of CH4 and CO2 trapped in fluid inclusions and void-filling calcite The carbon isotopic compositions of CH4 and CO2 trapped in fluid inclusions and their host calcite samples are listed in Table 1. Reproducibility of the measurements was determined for eight samples by repeat analyses, and these show reasonable replication (±1‰ for CH4 d13C values and ±1.8‰ for CO2 d13C values, Table 1). The CH4 from fluid inclusions in the crushed calcite crystals have d13C ratios mainly ranging from 46.7‰ to 29.8‰ with one abnormally positive d13C value (23.3‰, n = 12, with 7 replicates). Five samples have more depleted fluid inclusion CH4 d13C values (46.7‰ to 34.7‰) compared with those for methane and ethane in the P3ch and T1f gas reservoirs in the NE Sichuan Basin (34.5‰ to 27.5‰, Liu et al., 2013; Cai et al., 2004, 2013; Hao et al., 2015; Fig. 7a). The plot of the fluid inclusion CH4 d13C values and Th shows a wide scatter of d13C values at Th of 126–137.4 °C, a less scatter at Th of 145.8–161.5 °C and almost no change at Th of 165–185 °C (Fig. 7b). The Th values show positive correlative relationships to H2S/(H2S + C1-6) (Fig. 7c). The CO2 in the fluid inclusions in the crushed calcite crystals has a wide range of d13C values from 9.3‰ to

Table 3 Comparison of formation water chemistry associated with sour gas between in reef and shoal reservoirs and evaporite-bearing reservoir. Well

Depth (m)

Strata

Na+ + K+ (g/ L)

Mg2+ (g/ L)

Ca2+ (g/ L)

Cl (g/ L)

SO2 4 (g/ L)

HCO 3 (g/ L)

TDS (g/ L)

Water Type

H2S (%)

Sour gas in reef and shoal reservoir

Pg3b Pg6 Pg10b Pg10b Pg11 D5a Pg8b Pg8b Pg8 Pg9b Mb3 Mb3 Yb123 Yb123b Yb224b Yb9b Yb9b Yb16b

5448–5469 5423.6–5432.5 6250–6270 6193–6202 5705.0–5715.5 4784.5–4823 5614–5625 5634–5643 6110.0–6130.0 6151–6175 4609–4630 4340–4420 6978–6986 6904–6918 6625–6636 6836–6857 7000–7020 6950–6974

T1f2 P3ch T1f1-2 T1f1-2 T1f2 T1f1 P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch P3ch

16.5 22.3 22.6 19.1 10.3 43.0 26.3 – – 18.8 16.5 14.4 18.7 18.8 18.7 12.1 23.9 19.6

0.03 0.1 0.1 0.1 0.01 0.4 0.2 0.03 6.5 0.03 0.1 0.05 0.05 1.0 0.1 2.1 0.1 0.2

0.7 24.0 0.6 0.6 0.1 0.8 1.3 3.1 15.6 0.6 0.6 0.6 – 5.4 0.6 – 1.2 0.6

21.9 158.4 31.3 27.3 12.1 66.4 40.3 47.8 54.4 26.1 25.5 23.1 28.2 39.7 27.5 37.6 36.2 31.3

0.2 0.4 1.5 0.2 3.6 0.8 0.6 0.000 0.000 0.9 0.3 0.3 – 0 – – 1.4 0.6

– 1.5 6.2 1.1 2.5 3.0 2.4 2.1 3.9 3.1 – – – 3.0 – – 3.5 –

39.8 92.3 62.2 50.8 28.7 114.4 72.2 83.2 87.0 51.0 42.9 38.4 47.6 67.8 46.9 58.1 66.3 52.2

NaHCO3 CaCl2 NaHCO3 NaHCO3 NaHCO3 MgCl2 Na2SO4 CaCl2 CaCl2 NaHCO3 NaHCO3 NaHCO3 CaCl2 CaCl2 MgCl2 CaCl2 Na2SO4 CaCl2

62.2 – – – – 15.9 – 6.9 – 14.7 34.7 – 25.7 4.1 10.6 12.1 – 12.2

Sour gas in evaporite-bearing reservoir

D3c D4c Lj4c Mb2 Pg5

3899 3848 3066 4145–4427.5 4830.00– 4868.00 3527.4–3579.5 3411–3430 5576.3–5615

T1j T1j T1j T1f3 T1f3

13.4 12.6 15.2 33.3 1.3

0.06 0.03 0.03 0.002 0.6

0.3 0.5 0.4 0.3 16.1

9.9 12.1 13.6 32.1 31.4

15.0 11.0 27.5 11.0 1.0

0.8 0.3 1.0 – 0.2

39.4 36.5 57.7 77.1 50.5

Na2SO4 Na2SO4 Na2SO4 Na2SO4 CaCl2

– – – – 11.3

T1f1 T1f1 T1f1

9.2 8.6 23.6

0.2 0 0

0.9 1.2 0.6

10.6 11.2 34.9

6.2 5.2 2.6

2.0 0.5 1.1

29.0 26.6 62.9

Na2SO4 Na2SO4 Na2SO4

14.2 – –

Po1a Z1a Zj1a

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Reservoir type

– No measurement or data available. TDS = total dissolved solids. a Data from Shen (2005). b Data from Li et al. (2016). c Data from Zhao et al. (2014).

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Fig. 4. Relationship between homogenization temperatures and salinities of the fluid inclusions from bulk dolomite, non-TSR calcite and TSR calcite samples from sour gas reservoirs.

+8.4‰ (n = 12, with 7 replicates) (Table 1). The range of values is similar to the reported data for CO2 in the reservoirs (12.9‰ to +3.3‰, Zhu et al., 2008; Liu et al., 2013; Cai et al., 2014) and is significantly heavier than

TSR-derived CO2 based on laboratory experiments (37.1‰ to 34.9‰, Pan et al., 2006). Two samples (DW3-1 and HH-1; both repeated) have slightly higher d13C values for CO2 in the fluid inclusions (+5.4‰ to +8.4‰; Table 1) compared with those of the bulk carbonates (0.8‰ to +4.9‰, Huang, 1994). Similarly, heavy carbon isotopes of CO2 beyond the range of the carbonate host rocks have been previously reported (Mankiewicz et al., 2009). There is no significant correlation between the d13C values of CO2 and CH4 trapped in the fluid inclusions (Fig. 7d). The d13C values of CO2 trapped in the fluid inclusions has a very weak positive correlation with the Th values (Fig. 7e). The non-TSR calcite samples have a narrow range of d13C values (1.4‰ to +2.6‰; n = 15, Fig. 8a), which is close to those of the contemporary seawater and bulk carbonates. In contrast, the TSR calcite samples from this study (Table 1) and from the literature have a wide range of d13C values from 18.9‰ to +3.6‰ (n = 112, Fig. 8a),

Fig. 5. Laser Raman spectra of gas compositions for the D5, HH-1, YGD-3, PLD-1 and YGD-1 samples. Note the difference in size and presence of the peaks of the hydrocarbon gases. The temperature data shown for each spectra are the measured Th values.

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Fig. 6. Fluid inclusion gas wetness as a function of Th (the wetness refers to the ratio of C2-6/C1-6).

with an average of 4.3‰. Most of the calcite samples that were selected for the crush experiment have lighter d13C values than the released CO2, with the differences being mainly between 0.2‰ and 10‰ (Table 1). There are weak positive correlations between the d13C values of the calcite and the CO2 (Fig. 8b) trapped in the fluid inclusions. There is no correlation between the d13C values of diagenetic calcite cements and Th (Fig. 8c). However, for the calcites with Th  119.7 °C, the d13C values have a positive correlation (R2 = 0.46) with the Th (Fig. 8c). A similar trend is also present based on the data from others (Jiang, 2009; Jiang et al., 2014, 2015). Interestingly, the replacive calcite crystals after anhydrite have lighter d13C values (1.4‰ to 18.9‰) than the TSR calcites in the reef and shoal facies (Fig. 9). 4.3. d2H and d18O values of the water in the fluid inclusions Measured d2H of the water in the fluid inclusions are from 67.8‰ to 36.4‰ (with an average of 51‰, n = 7, Table 2). d18O values of the fluid inclusion water were calculated based on the oxygen isotope equilibrium fractionation equation between calcite and pure water (O’Neil et al., 1969) to have from +8.4‰ to + 15.5‰ (n = 7, Table 2). Most of the d2H values are significantly lighter than those of the contemporary seawater (close to 0; Craig, 1961; Hagemann, 1970). There is no significant change or a slight decrease in the d2H values of the water in the fluid inclusions as the Th increases from 134 °C to 161.5 °C, followed by a first sharp increasing and then a gradual increasing trend from 161.5 °C to 170.1 °C and from 170.1 °C to 187.3 °C, respectively (Fig. 10). 4.4. Formation water chemistry The chemical compositions of the P3ch-T1j formation water from the sour gas reservoirs are shown in Table 3. There are significant vertical and regional heterogeneities in formation water chemistry. Generally, most of the formation water samples from the P3ch and T1f1-2 strata (reef and shoal facies) in NE Sichuan Basin have SO2 4 concentrations from 0 to 0.9 g/L, significantly lower than the P3ch (mean 2.2 g/L; Lowenstein et al., 2005) and T1f (mean 2.3 g/L; Horita et al., 2002) formation waters from other

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basins, respectively. In contrast, the formation water samples of the T1j Formation, which contains evaporite layers, have much higher SO2 concentrations (11.0–27.5 g/L). 4 The formation water samples from the T1f3 member have variable SO2 concentrations from 1.0 g/L to 11.0 g/L. 4 The T1f formation water samples collected from the lagoonal facies, e.g., from the Z1 and Zj1 wells, have higher SO2 concentrations (2.6–6.2 g/L) compared with those 4 from the reef and shoal facies. In addition, along the platform margin, the formation water samples associated with sour gas reservoirs commonly have lower SO2 4 concentrations (0–0.9 g/L, Table 3) than those with sweet gas (1.4–3.2 g/L, data from Shen (2005) and Li et al. (2016)). There are no significant differences in the total dissolved solid (TDS) concentrations throughout the sedimentary facies (Table 3). The formation water samples from the sour gas reservoirs have a wide TDS range from 26.6 g/L to 114.4 g/L, equal to 2.7 to 11.4 wt% NaCl. The values are close to most of the low-salinity values of the TSRderived calcites. 5. DISCUSSION 5.1. Process for variation of fluid inclusion CH4 d13C values

5.1.1. Oil-dominated TSR. TSR is most likely to have been initiated by liquid hydrocarbons at the relatively low Th of 133.1 °C and 137 °C, as is supported by the presence of oil inclusions (Fig. 3a, b, e, f) and H2S inclusions but not associated with hydrocarbon gas inclusions (Fig. 5). During this period, CH4 is likely present in volumetrically minor amounts as oil-dissolved gas, since an initial slow and nonautocatalytic stage is usually associated with the TSR reaction involving long-chain hydrocarbons (Xia et al., 2014). Similar small amounts of CH4 were also detected in reaction of liquid hydrocarbons with elemental sulfur (Kowalewski et al., 2010). Compared with the natural gas, CH4 released from fluid inclusions has a much wider spread of d13C values from 46.7‰ to 23.0‰ (Fig. 7a) and shows significant variation as Th increases. The large shift can be attributed to multiple sources with different carbon isotope signatures within the oil precursor, as proposed by Smith et al. (1985) and Tang et al. (2000). 5.1.2. Wet gas-dominated TSR As temperature gradually rose, TSR proceeded into wet gas-dominated stage, as indicated by the coexistence of C2+ hydrocarbon gas and H2S in the fluid inclusions with Th of 156.3 °C (Fig. 5). The detection of a wide concentration range of C2-6 gases with wetness from 5% to 55.9% in fluid inclusions in TSR-derived calcite crystals provided further evidence (Fig. 6; Xie et al., 2006; Zhu et al., 2006; Xia et al., 2012). The roughly decreasing trend of wetness and methane shifts to a trend of 13C enrichment at Th approximately >137 °C (Fig. 7b) hints at extensive oxidation of C2-6 gases and new generation and accumulation of methane. Similar positive shift in methane d13C is also reported in oxidization of C2-4 gases during TSR simulation

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Fig. 7. Scatter plots showing (a) the difference in the d13C values of CH4 in fluid inclusions, sour gas reservoirs and sweet gas reservoirs. The shift in methane d13C in the sweet reservoirs is supposed to result from hydrocarbon pyrolysis, while the shift in the sour reservoirs result either from hydrocarbon pyrolysis or TSR, and (b) the relationship of the d13C values of CH4 in fluid inclusions to Th, reflecting different effects of various stage of TSR on CH4 d13C values and (c) the relationship of H2S/(H2S + C1-6) to Th, and the relationships of d13C values of CO2 in fluid inclusions to the d13C values of CH4 in fluid inclusions (d), and to Th (e). The data for sour and sweet gas reservoirs are from Cai et al. (2004, 2013), Hao et al. (2008, 2015), Zhu et al. (2008) and Liu et al. (2013). Note that one data point has an abnormally positive d13C value of 23.3‰ in (a, b and d) and is an outlier, because it is significantly heavier than the reported methane d13C values in the reservoirs, which should be the end-products of continuous oxidation and therefore isotopically heaviest.

reactions with MgSO4 (Pan et al., 2006; Lu et al., 2010) and during non-TSR reactions with CuO (Kiyosu and Imaizumi, 1996). 5.1.3. Dry gas-dominated TSR CH4 was detected as the predominant gaseous organic compound and coexists with H2S in fluid inclusions with Th of 165 °C (Fig. 5). The minimum temperature of dry gas-dominated TSR is somewhat blurred based on available data. The variation in wetness with Th (Fig. 6) cannot be used to constrain the lower thermal limit because of the involving semi-quantitative data of fluid inclusion gas compositions, stemming from estimation of relative laser Raman peak areas (Xie et al., 2006; Zhu et al., 2006;

Xia et al., 2012) However, the abrupt change of d13CCH4 with temperature at 161.5 °C yields instructive clues regarding the corresponding threshold temperature of dry gas-dominated TSR. This proposal is consistent with the acceleration of water production rate when the Th is over 161.5 °C, as discussed in the following sections. Assuming that dry gas-dominated TSR commenced at 161.5 °C, CH4 d13C values show an increase from 33.1‰ to 29.6‰ throughout the stage (Fig. 7b) and the variation (3.5‰) is closed to the calculated value (2.9‰) based on the data of present-day gas compositions (Cai et al., 2004). This, together with the Th shows positive correlative relationships to H2S/(H2S + C1-6) or TSR extent (Worden et al., 1995; Cai et al., 2003; 2004) (Fig. 7c),

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Fig. 8. Cross plots showing relationships of d13C values of void-filling calcite samples with (a) their d18O values, (b) the d13C values of CO2 in hosted fluid inclusions, (c) the d13C values of CH4 in hosted fluid inclusions, and (d) the Th values. Note that the black circle in (d) represents one anomalous value. The trend line with R2 = 0.46 is only for the data from this study, not including the literature values.

indicates that CH4 becomes isotopically heavier as TSR proceeds during the stage of dry gas-dominated TSR. This is because the isotopically lighter methane reacts rapidly with dissolved sulfate, leaving the remaining methane isotopically heavier (Worden and Smalley, 1996; Cai et al., 2003; 2004; 2013; Jenden et al., 2015). The effects are also reflected in the perceptible increase of methane d13C with GSI and gas dryness (CH4/RCnH2n+2) (Cai et al., 2004; 2013; Hao et al., 2008, Liu et al., 2013). We have to point out that, with the present data, we cannot clarify exactly the effects of dry gas-dominated TSR on C-isotope fractionation effect, because of the uncertainty on the threshold temperature of dry gas-dominated TSR. However, the variation of CH4 d13C value in the NE Sichuan Basin is obviously not as vigorous as those reported in other methanedominated TSR cases worldwide (e.g., Worden et al., 1996) and in experimental work (Pan et al., 2006). At Th  165 °C, CH4 d13C values range from 30.1‰ to 29.6‰ and show no obvious increasing trend with temperature (Fig. 7b), implying dwindling dry gas-dominated TSR reaction. This is consistent with the proposal that a final, or late-stage TSR reaction continues at a slower rate (Orr, 1990; Machel, 2001; Pan et al., 2006; Mankiewicz et al., 2009; Xia et al., 2014). It is noteworthy that the extent of gas souring (GSI < 20%) in the T1f reservoirs in the NE Sichuan Basin is much lower than that in the Khuff Formation of Abu Dhabi (GSI = 50%; Worden and Smalley, 1996), although the former reservoirs experienced similar

high temperatures (up to 220 °C) and longer duration of temperatures >150 °C (>140 Ma vs. <60 Ma, Gumati, 1993; Li et al., 2012). It seems that the extent of the slow dry gas-dominated TSR reaction has, to a large extent, been limited at an advanced stage in the NE Sichuan Basin. As shown in Table 3, the SO2 4 concentrations of the formation water from the sour gas reservoirs in reef and shoal facies are generally pretty low (mostly lower than 0.9 g/L) compared with those from the contemporary seawater (2.2 g/L, Lowenstein et al., 2005) and those from the sweet gas reservoirs (1.4–3.2 g/L, Shen, 2005; Li et al., 2016), indicating that the depleted SO2 4 in the formation water is attributed to its consumption by TSR. Unlike in the evaporite-bearing strata, where the dissolution of gypsum or anhydrite might have constantly released SO2 4 into the pore waters, in the high-energy shelf-margin reservoirs, the slow transport rate of aqueous sulfate from evaporative units to the remote reaction sites would have greatly limited the TSR reaction, as suggested by Worden et al. (2000). One more possible limiting factor is the long duration of formation temperatures >200 °C (110 Ma; Li et al., 2012) in the NE Sichuan Basin. It might have greatly obstructed formation of MgSO4 contact ion-pairs (CIP) in the pore waters (pH  6.5–8.5) because a magnesium-h ydroxide-sulfate-hydrate complex will be formed instead at temperatures in excess of 200 °C (Ma et al., 2008). The [MgSO4]CIP, however, is proposed as a dominated reactive sulfate species for TSR in the typical petroleum

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Fig. 9. Map of the regional variation in d13C values of TSR-related calcite crystals on the east side of the Kaijiang-Liangping (K-L) Trough in the NE Sichuan Basin. The available data are from Table 1 and Li et al. (2012, 2014), Jiang et al. (2014, 2015) and Zhu et al. (2005), and are presented as average values.

reservoir formation waters (Ma et al., 2008; Zhang et al., 2008, 2012). The effects of the heterogeneities in SO2 4 concentrations on dry gas-dominated TSR were also observed in a generally decreasing trend of the methane d13C values for the gas reservoirs from the paleo-lagoon areas (30.1‰ to 28.9‰) to the reef and shoal margin (33.7‰ to 29.8‰, data were from Cai et al. (2004, 2013), Hao et al. (2008, 2015), Zhu et al. (2008) and Liu et al. (2013), Fig. 11). A maturity effect on the d13C values can be ruled out because the reservoirs experienced similar maximum burial and temperatures (Huang et al., 2010; Cai et al., 2014) and there is poor relationship between the methane d13C values and the present depths (Fig. 12). The shift toward heavier d13C values in methane may signify larger isotopic fractionation and more intense oxidation of methane by sufficient sulfate, while the methane with relatively depleted d13C values reflects lower consumption of the methane due to the unsustainable migration of sulfate. A significant S-isotope fractionation (10–20‰) among S0, H2S and sulfate has been well demonstrated during experimental simulation of TSR with excessive dissolved sulfate (e.g., Na2SO4 solution, Kiyosu et al., 1990; Meshoulam et al., 2016), being correlated with initial cleavage of the S–O bond of sulfate (Goldstein and Aizenshtat, 1994) or equilibrium effects (Meshoulam et al., 2016). Similarly, in the paleo-lagoon areas, a negative shift in the d34S value (2.0–7.9‰, Fig. 13a) of the elemental sulfur can also

Fig. 10. Cross plot showing the relationship between d2H values of water extracted from fluid inclusions in the calcite crystals and the Th values of the fluid inclusions. The figure shows that isotopicallydistinct (low d2H) water was mostly produced during methanedominated TSR.

be attributed to the excessive sulfate relative to dissolved hydrocarbons. The accumulation of elemental S, showing bright yellow colours and extremely fine crystal sizes in core and cloudy appearance in thin section (Fig. 13b, c, d), might result from low availability or low rate of supply of organic compounds (Machel et al., 1995, 2001; AlonsoAzca´rate et al., 2001). Similar substantial kinetic S-isotope effect has been previously documented in some

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Fig. 11. Map of the regional variation in d13C values of methane in the present-day gas reservoirs on the east side of the Kaijiang-Liangping (K-L) Trough in the NE Sichuan Basin. Data were collected from Cai et al. (2004, 2013), Hao et al. (2008, 2015), Zhu et al. (2008) and Liu et al. (2013).

d34S values (9.7–19.1‰, Fig. 13a) close to the parent sulfate because no kinetic sulfur isotope fractionation is realized during TSR in such case (Machel, 1995). 5.2. Water generation during TSR?

Fig. 12. Relationship between d13C values of methane in the present-day gas reservoirs on the east side of the K-L Trough and the present-day burial depths. Data were collected from Cai et al. (2004, 2013), Hao et al. (2008, 2015), Zhu et al. (2008) and Liu et al. (2013).

case studies in the Cameros Basin, the Bongara mine, the Tarim Basin and the Sichuan Basin (Alonso-Azca´rate et al., 2001; Basuki et al., 2008; Cai et al., 2008; 2010). In comparison, in the grainstone reservoirs away from the evaporative area, the rate of TSR is limited by unsustainable supply and paucity of reactive sulfate, reduction of which went to completion. Then elemental sulfur shows

5.2.1. Evidence from fluid inclusion salinity and formation water TDS Formation of abundant low-salinity aqueous fluid inclusions and the regular decrease in salinity with the extent of the TSR reaction were first observed and invoked to confirm water production during TSR by Worden et al. (1996). For the NE Sichuan Basin, similar fluid inclusion data from the sour gas reservoirs were obtained in this study (Fig. 4) and have been also documented in our previous work (Li et al., 2012) and by others (e.g., Jiang et al., 2015). The low-salinity water might have been inherited from early diagenetic water, e.g., the eogenetic meteoric water (Li et al., 2012). However, the meteoric water in the pores was proposed to have subsequently been replaced by semi-saline to saline dolomitizing fluids from backreef lagoons (Jiang et al., 2014; Li et al., 2014). The moderate to high salinities of fluid inclusions detected in dolomite crystals by Jiang et al. (2014) imply a significant change in the diagenetic fluids (Fig. 4). This means that

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Fig. 13. (a) Map of the regional variation in d34S values of elemental sulfur (green values) on the east side of the Kaijiang-Liangping (K-L) Trough. The data were collected from Cai et al. (2004), Zhu et al. (2005) and Zhu et al. (2008). The photographs show the distribution of elemental sulfur. (b) Core specimen, D5 well, 4775.82 m, T1f1; (c) Cross-polarized light, Lj5 well, 2940.5 m, T1f1; (d) Core specimen, Jz1, 2990.8 m, T1f1; (e) Scanning electron microscope image showing sulfur-rich pellets wrapped in solid bitumen, which has been previously reported (Jiang et al., 2002; Zhu et al., 2008; Li et al., 2014), Pg2 well, 4977 m, T1f2; (f) Energy-dispersive X-ray spectrum of the pellet highlighted in red in (e). Note the two d34S data points in the Mb3 and Pg6 wells (10.1‰ and 9.8‰, respectively) were determined for elemental sulfur extracted from solid bitumen (Zhu et al., 2008). (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

the TSR reaction was initiated in a brackish or saline pore-fluid environment, which is further supported by the medium to high salinities of water trapped in fluid inclusions in non-TSR calcite (Fig. 4). The salinity of this initial water likely depended on the mixing ratio of the early pore water and the more saline dolomitizing fluid. The water was then heterogeneously diluted by the new TSR-derived water to form the wider spread in the salinity of the fluid inclusions (mostly from 1 to 20 wt% NaCl, Fig. 4). In the sour gas reservoirs, the formation water with the lowest TDS value (26.6 g/L) is considered to have undergone the most extreme dilution by early meteoric water and/or new water derived from TSR (Fig. 4). Considering that the dilution effect of the meteoric water might have been removed by displacement of the subsequent saline dolomitizing fluids, as mentioned above, the TSR-derived water

is very likely to exert a profound influence on formationwater salinity in some locations. There seem to be significant heterogeneities in the occurrence of TSR and imperfect mixing between TSR-derived water and the pre-existing pore water, as proposed by Worden et al. (1996). 5.2.2. Evidence from d2H values of fluid inclusion water Most of the fluid inclusion water samples collected from the TSR-derived calcite crystals have lighter d2H values (Table 2) compared with contemporary seawater. Since the latitude of the Sichuan Basin during the Late Permian and Early Triassic was close to the equator (Renne et al., 1995), meteoric water is speculated to have had a d2H close to zero based on the proposed atmospheric Rayleigh process (Craig, 1961), as vapor is removed from polewardmoving tropospheric air. It is unlikely that much of this water with isotopically heavy hydrogen was trapped in

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the analysed fluid inclusions. Instead, the addition of TSRderived water with significantly lighter d2H values derived from hydrocarbon reactants is likely to be responsible for the negative shift in d2H of the fluid inclusion water. The published d2H data of methane and ethane in the P3ch-T1f gas reservoirs in the NE Sichuan Basin have a narrow range from 89‰ to 131‰ (Liu et al., 2014b). Since the hydrogen in TSR generated water is coming from the hydrocarbons, the relatively heavier d2H values of the fluid inclusion water samples compared with those of the reactive hydrocarbons can be ascribed to mixing of TSR-derived water and formation water. If the average d2H value (51‰) of the fluid inclusion water samples is used, and if the d2H values of the pre-TSR formation water are presumed to range from 37.5‰ (i.e., the most depleted d2H value of the formation water) to 0‰ (i.e., d2H of the contemporary seawater), then the mixing ratio of TSR-derived water and formation water is calculated to be from 1:2.9 to 1:0.8. It seems that water generated during TSR is of volumetric importance, at least in relatively localized TSR reaction sites. The overall decrease of the d2H values of the fluid inclusion waters with increase of Th (Fig. 10) provides another clue regarding TSR as a water-generation reaction. The relationships between the two parameters as Th increases from 134 °C to 161.5 °C suggest that, in general, there is a very slight decrease in the d2H values (Fig. 10), probably indicating volumetrically minor water was produced during the oil- and wet gas-dominated TSR stage, as reported previously from Tarim basin (Li et al., 2017). The subsequent sharp decrease in d2H when Th increases from 161.5 °C to 170 °C hints at an acceleration of water production as early dry gas-dominated TSR proceeds (Fig. 10). At higher Th, the d2H values continue to decrease, but with a lower slope (Fig. 10), possibly indicating dwindling water production during late dry gas-dominated TSR stage. Despite some uncertainties, it seems that the change of water production rate during TSR is consistent with three stages of TSR, i.e., liquid hydrocarbons, C2+ hydrocarbon gases and dry gas stages. The occurrence of the dry gasdominated TSR reaction (>161.5 °C) seems to be the most efficient for water production and for negative shift in water hydrogen isotopes. This observation is consistent with the proposal for net mass balance reactions for multiple types of hydrocarbon gases and sulfate (Pan et al., 2006): SO4 2 þ Mg2þ þ CH4 ! MgCO3 þ H2 S þ H2 O

ð4Þ

3SO4 þ 3Mg þ 4C2 H6 ! 3MgCO3 þ 4CH4 þ3H2 S þ CO2 þ H2 O

ð5Þ

3SO4 þ 3Mg þ 2C3 H8 ! 3MgCO3 þ 2CH4 þ3H2 S þ CO2 þ H2 O

ð6Þ

2

2

2þ

2þ

5SO4 2 þ 5Mg2þ þ 4n-C4 H10 þ H2 O ! 5MgCO3 þ 8CH4 þ 5H2 S þ 3CO2

ð7Þ

It can also be speculated that different hydrocarbon reactants result in variation in the amount of water produced during TSR, thus resulting in the controversy on water generation during TSR. This proposal is supported by the fact that the sour gas provinces, where water production during

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TSR was documented (e.g., Worden et al., 1996; Yang et al., 2001; Vandeginste et al., 2009; Jiang et al., 2015), without exception, experienced light hydrocarbon gas-dominated or methane-dominated TSR. As for the Devonian Nisku Formation of western Canada and Ordovician carbonate reservoir in the Tarim Basin, where heavy hydrocarbons induced the TSR reaction, volumetrically minor to negligible water was released during TSR (Manzano et al., 1997; Machel, 2001; Li et al., 2017). Especially in the NE Sichuan Basin, the combined effects of a decrease in TSR rate as the hydrocarbon phase becomes methane rich, a shortage of reactive sulfate and/or limited [MgSO4]CIP across a long duration of formation temperatures >200 °C likely retarded water production during the advanced TSR stage (Fig. 10). 5.3. Dissolution of carbonate minerals during TSR? Theoretically, as the TSR reaction proceeds in the water system being dominated initially by dissolved matrix carbonate, the production of TSR-derived CO2 with an isotopically light carbon source (i.e., hydrocarbons, Machel, 1995) will result in lighter d13C values of total CO2 in reservoirs. In this study, no correlation is found to occur between the fluid inclusion CO2 and CH4 d13C values (Fig. 7d). This means that the TSR-derived CO2 might not be the only carbon source in the system. As an alternative, inorganic CO2 may have been added to lead to enrichment in 13C and thus a change in the trend of isotopically lighter CO2. The significantly positive d13C values of the CO2 (Table 1), compared with the TSR-derived CO2 on the TSR reaction of gaseous hydrocarbons with MgSO47H2O at 350 °C for a duration of 288 h (Pan et al., 2006), indicates a substantial contribution of inorganic carbon. This might be ascribed to either re-equilibration of CO2 with the dissolved carbonate of heavy carbon isotope signature in the water film (Mankiewicz et al., 2009; Hao et al., 2015), or bulk dolomite dissolution. However, a weak positive relationship between the d13C values of CO2 in the fluid inclusions and the corresponding Th (Fig. 7e) indicates that the positive shift in the CO2 d13C yields as a function of increasing thermal stress, which would promote the thermodynamically favourable TSR reaction (Machel, 2001). That is, the constant enrichment in 13CCO2 is more likely to be correlated with the TSR process and the resulting dissolution of carbonates. Most of the crushed calcite crystals and other selected calcite samples have d13C values 5‰  10‰ lighter than the CO2 trapped in fluid inclusions in each sample (Table 1, Fig. 7b). This, together with the positive correlation between their d13C values (Fig. 8b), hints at a preferential sequestration of 13C-depleted CO2 into the calcite cements, with a positive shift in d13C for the residual CO2. Similar cases have been previously documented (e.g., Hao et al., 2015, and references therein). Another plausible explanation is that the calcite cements might have precipitated rapidly in the 12C-rich diagenetic solutions, where the TSR reaction occurred, and may not have reached isotopic equilibrium with the free CO2 gas. As the temperature increases from below to above 119.7 °C, there is a dramatic shift from heavy to light d13C values of the calcite (Fig. 8c),

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suggesting that 119.7 °C is the minimum temperature for TSR in the NE Sichuan Basin. For the TSR-derived calcites, the d13C values show a positive correlation (R2 = 0.46) with Th (Fig. 8c), which is consistent with data from Jiang et al. (2014, 2015) with slightly lower R2 of 0.26. However, this trend is completely opposite to that of the Khuff Formation in Abu Dhabi (Worden and Smalley, 1996). A progressive increase in the mixing ratio of TSRderived CO2 and 13C-rich CO2 in the residual pore waters may explain this occurrence. Worden et al. (2000) claimed that within these anhydrite-bearing strata, TSR-derived calcite tended to grow on the surface of anhydrite crystals as replacive masses due to the low porosity and permeability of anhydrite crystals (Fig. 14a). That is, the aqueous calcium (from dissolved anhydrite) and newly formed 12Crich bicarbonate (from TSR) did not travel far from the sites of TSR and precipitated as calcite crystals directly adjacent to anhydrite. The TSR reaction became transport controlled as the calcite began to isolate remnant anhydrite from dissolved hydrocarbon gases.

In contrast, in the NE Sichuan Basin, there seems to be a distinctive setting of TSR sites, probably resulting in different dissolution-precipitation processes. The reactive sulfate for the TSR reaction in oolitic shoal and reef reservoirs was demonstrated to have been derived from the early refluxing of evaporative brines from the back-reef restricted lagoons (Li et al., 2014), and may have reacted with the available hydrocarbons during TSR. Assuming that calcium released from anhydrite were precipitated close to the sites of TSR, then the calcite cements should be distributed uniformly in the pores. However, the cements are present as occasional intergrown aggregations in the thin sections (Fig. 14c, d). One possible scenario is that, unlike the anhydrite-bearing strata, the better petrophysical properties and greater amounts of preserved pore waters (Fig. 14c, d) offered the possibility of short distance transport of the solutes away from the TSR sites within the system. As TSR-derived calcite precipitated in open void spaces elsewhere, Ca2+ in the initial water was quickly consumed and Ca2+ concentrations decreased rapidly because of no continuous calcium

Fig. 14. Schematic representation of the essential differences in TSR settings, rate-controlling steps for the TSR reaction, and related dissolution-precipitation processes during TSR for anhydrite-bearing reservoirs and high-energy grainstone reservoirs. The simplified version of rate-controlling steps for TSR is revised from Worden et al. (2000). The way in which reactive sulfate is supplied to the site of TSR (step 2) and precipitation of calcite (step 5) has a profound influence on carbonate alteration. The photographs are used for showing the location of the TSR reaction zone and replacive calcite: (a) Thin section photomicrograph, plane-polarized light (PL), Khuff Formation, Abu Dhabi (Worden et al., 2000); (b)-(d) from NE Sichuan Basin; (b) Core specimen of dolomite with vugs filling calcite, anhydrite and elemental sulfur, Po1 Well, 3468.7 m, T1f2; (c) Thin section photomicrograph, with abundant pores stained blue and calcite stained pink, D4 well, 4235.6 m, T1f2; (d) Thin section photomicrograph, plane-polarized light (PL), D4 well, 4235.6 m, T1f2. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

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supply from anhydrite dissolution. This might have provided an environment conducive to significant dissolution of dolomite minerals to release Mg2+, which is thermodynamically favourable to form [MgSO4]CIP and promotes the TSR reaction (Ma et al., 2008; Cai et al., 2014). The carbonate dissolution led to sustained release of 13C-rich CO2, which was captured in the fluid inclusions and incorporated into the TSR-derived calcite. Clearly, the magnitude of carbonate dissolution during TSR seems to be influenced by the ability to transport reactants to the surface of the minerals, and move the dissolved ions away from the site. The reported deep carbonate dissolution and porosity alteration in the TSR regions with the co-occurrence of hydrothermal activity (Biehl et al., 2016) also highlights the importance of fluid movement and solute transport. In the NE Sichuan Basin, the settings of TSR sites in the back-reef lagoon areas with gypsum associated (Fig. 14b) are similar to those of the Khuff Formation in Abu Dhabi (Fig. 14a, Worden and Smalley, 1996) but different from those of the reef and shoal margin. Slow mass transport and a quick saturation of calcium in the pore waters resulted in the growth of replacive calcite at the very edges of anhydrite nodules (Fig. 14b). These regional differences may have exerted a profound influence on the d13C of TSR-derived calcites, which become heavier from the paleo-lagoon area to the platform margin (Fig. 9). The lighter d13C values suggest a substantial contribution of organic carbon from the oxidation of hydrocarbons by TSR, whereas the heavier values reflect incorporation of more inorganic carbon released from carbonate dissolution. This, in turn, gives compelling evidence for the close relationship between the carbonate dissolution-precipitation process and the different settings of the TSR sites. 6. CONCLUSIONS

(1) TSR was initiated by liquid hydrocarbons in the NE Sichuan Basin to form H2S-bearing oil inclusions with lower Th values (e.g.,
137 °C) in TSR-derived calcite crystals. Subsequently, wet gas-dominated TSR proceeded and led to the coexistence of C2+ hydrocarbon gas and H2S in fluid inclusions. Dry gas-dominated TSR occurred in higher reservoir temperature (> about 161.5 °C) when most C2+ hydrocarbons were exhausted. (2) Extremely depleted CH4 d13C values (as low as 46.7‰) were first reported in fluid inclusions in the NE Sichuan Basin. The positive shift in CH4 d13C values (from 46.7‰ to 33.1‰) was initiated by oil- and wet gas-dominated TSR, and then promoted by dry gas-dominated TSR to reach the final d13C value (29.6‰). (3) The extent of dry gas-dominated TSR in the NE Sichuan Basin was limited by the availability of dissolved sulfate. Within the high-energy shelf-margin reservoirs, the sulfate has been almost completely consumed by TSR, resulting in more depleted methane d13C, lesser amounts of elemental sulfur,

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and d34S values close to the parent sulfate. In contrast, within the anhydrite-bearing reservoirs in the paleo-lagoon area, the reactions of excessive dissolved sulfate with hydrocarbons resulted in 13C enrichment in the methane, accumulation of elemental sulfur, and significant fractionation of the sulfur isotopes. (4) The d2H and salinity data of fluid inclusion water suggest water generation during TSR. Dry gasdominated TSR seems to be much more efficient at water production compared with oil- and wet gas-dominated TSR. The process resulted in the d2H values of fluid inclusion water shifting from 36.4‰ to 67.8‰ and salinities decreasing to as low as 0.9 wt% NaCl. The final decline of water production rate is consistent with the slower rate of the dry gas-dominated TSR reaction due to the shortage of reactive sulphate. (5) The occurrence of TSR in the high-energy shelfmargin reservoirs led to intense dolomite dissolution. The addition of the released inorganic CO2 into the system promoted the positive shift in d13C of the CO2 trapped in the fluid inclusions from 9.3‰ to +6.3‰ as well as that of the TSR-derived calcite. In contrast, in the paleo-lagoon area, extensive carbonate precipitation was the predominant process, resulting in more depleted calcite d13C values (1.4‰ to 18.9‰). (6) These results show that differences in the geological settings for the occurrence of TSR worldwide (e.g., sedimentary settings, reservoir temperature and TSR extent) could result in a great diversity in the appearance and effects of the TSR reaction. In the NE Sichuan Basin, the combined occurrence of long duration of high reservoir temperatures, alteration of multiple hydrocarbon reactants and different settings of TSR sites have resulted in great diversity in methane d13C values following TSR, the amounts of TSR-derived water and in carbonate dissolutionprecipitation processes.

ACKNOWLEDGMENTS We would like to thank three anonymous reviewers for giving us constructive suggestions, which were helpful in improving the quality of the manuscript. This work was financially supported by the National Natural Science Foundation of China (Grant Nos. 41572129 and 41730424) and the Special Major Project on Petroleum Study (2017ZX05008003-040). This paper was written whilst Dr. Kaikai Li was a visiting scholar at the Department of Earth and Planetary Sciences, Macquarie University, Australia, the support of which is gratefully acknowledged.

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