Alteration of solid bitumen by hydrothermal heating and thermochemical sulfate reduction in the Ediacaran and Cambrian dolomite reservoirs in the Central Sichuan Basin, SW China

Accepted Manuscript Alteration of Solid Bitumen by Hydrothermal Heating and Thermochemical Sulfate Reduction in the Ediacaran and Cambrian Dolomite Reservoirs in the Central Sichuan Basin, SW China Pengwei Zhang, Guangdi Liu, Chunfang Cai, Meijun Li, Ruiqian Chen, Ping Gao, Chenlu Xu, Weichao Wan, Yiying Zhang, Mengya Jiang PII: DOI: Reference:

S0301-9268(18)30259-6 https://doi.org/10.1016/j.precamres.2018.12.014 PRECAM 5236

To appear in:

Precambrian Research

Received Date: Revised Date: Accepted Date:

13 May 2018 5 December 2018 14 December 2018

Please cite this article as: P. Zhang, G. Liu, C. Cai, M. Li, R. Chen, P. Gao, C. Xu, W. Wan, Y. Zhang, M. Jiang, Alteration of Solid Bitumen by Hydrothermal Heating and Thermochemical Sulfate Reduction in the Ediacaran and Cambrian Dolomite Reservoirs in the Central Sichuan Basin, SW China, Precambrian Research (2018), doi: https:// doi.org/10.1016/j.precamres.2018.12.014

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Alteration

of

Solid

Bitumen

by

Hydrothermal

Heating

and

Thermochemical Sulfate Reduction in the Ediacaran and Cambrian Dolomite Reservoirs in the Central Sichuan Basin, SW China

Pengwei Zhanga,b, Guangdi Liua,b,*, Chunfang Caic,d,e*, Meijun Lia,b, Ruiqian Chena,b, Ping Gaof, Chenlu Xud, Weichao Wana,b, Yiying Zhanga,b, Mengya Jianga,b a

State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China b College of Geosciences, China University of Petroleum, Beijing 102249, China c Key Laboratory of Exploration Technologies for Oil and Gas Resources of Ministry of Education, Yangtze University, Wuhan, Hubei 430100, China d Key Laboratory of Petroleum Resources Research, 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 Petroleum Exploration and Production Research Institute of SINOPEC, Beijing 100083, China * Corresponding authors E-mail addresses: [email protected] (G. Liu), [email protected] (C. Cai), [email protected] (P. Zhang)

Abstract: Solid bitumen in reservoir rocks is an allochthonous organic matter formed from bitumen or liquid hydrocarbons by various alteration processes. In this study, two types of altered solid bitumen have been identified in both the Ediacaran Dengying and Cambrian Longwangmiao formations in the Central Sichuan Basin using petrographic, microthermometric, chemical, and isotopic data. The hydrothermally altered bitumen (type 1) is associated with the pore-filling saddle dolomite and quartz in which homogenization temperatures of some fluid inclusions are more than 10 oC higher than the maximum burial temperature of the Dengying Formation. It has various anisotropic

textures with significantly high bireflectance values (Rbmax - Rbmin, %) between 3.89% and 9.21%. Moreover, the hydrothermal alteration led to

13

C-enrichment in the type 1

bitumen compared to the normally matured bitumen derived from the same source. On the other hand, the thermochemical sulfate reduction (TSR)-altered bitumen (type 2) has S/C atomic ratios of up to approximately 0.06. The δ34S values of type 2 bitumen are close to those of the carbonate-associated sulfate and similar to the TSR-derived H2S in the same reservoirs. A strong negative correlation exists between S/C atomic ratios and δ13C values in the type 2 bitumen in the Dengying Formation, which is interpreted as a result of an increasing incorporation of the

13

C-depleted ethanethiol into the bitumen

during TSR. This interpretation is consistent with the fact that the remaining ethane became isotopically heavier as TSR proceeded. In addition, the reactive sulfate for TSR was primarily derived from the hydrothermal sulfate, such as barite. This is evidenced by the replacement of hydrothermal barite by the

34

S-enriched pyrite and the small

differences in δ34S value between the barite and the type 2 bitumen (or the TSR-derived H2S) in the same strata. We suggest that TSR in the Ediacaran and Cambrian hydrocarbon reservoirs was probably initiated by hydrothermal activity.

Keywords: Ediacaran and Cambrian; Solid bitumen; Carbon and sulfur isotopes; Hydrothermal activity; TSR; Sulfur source.

1. Introduction Solid bitumen is a black amorphous substance that exists in pore spaces of both carbonate and siliciclastic reservoirs in petroliferous basins. It is generally considered to be an allochthonous organic matter formed from bitumen or liquid hydrocarbons by various alteration processes (Curiale, 1986; George et al., 1994; Machel et al., 1995; Mossman and Nagy, 1996). Due to a close association between organic matter and mineralization, solid or semi-solid bitumen has also been found in several types of hydrothermal ore deposits (e.g., Zumberge et al., 1978; Powell and Macqueen, 1984; Gorzhevskiy, 1987; Goodarzi and Macqueen, 1990; Parnell, 1992; Parnell et al., 1993; Wilson, 2000; Wilson and Zentilli, 2006). Physical, chemical, and optical properties of bitumen can respond irreversibly to elevated temperatures, heating rates, exposure times to a given temperature, hydrothermal reactions, and radiation-induced effects (Mossman and Nagy, 1996). In particular, bitumen is very sensitive to temperature changes. Optical properties of solid bitumen can be used as an indicator of its formation temperatures or the temperature ranges that the host rocks have experienced (Goodarzi et al., 1993). Previous studies have shown that anisotropic solid bitumen is closely associated with anomalous heating events (Khorasani and Murchison, 1978; Creaney et al., 1980; Goodarzi and Stasiuk, 1991; Goodarzi et al., 1993; Wilson, 2000). Bitumen is able to develop granular anisotropic textures via mesophase spheres when exposed to abnormal heating, which are similar to those produced in coal during carbonization. As a result of hydrothermal alteration, bitumen is generally converted to solid (semi-coke

or coke with granular mosaic textures), liquid (tar), and volatile (gas) matters. The gaseous constituents may subsequently solidify into pyrolytic carbon, which preferentially infills cracks and fissures within the bitumen (Goodarzi et al., 1993). The formation mechanism of the granular texture has been described in detail in previous studies (e.g., Brooks and Taylor, 1965, 1966; Marsh, 1973; White, 1975, 1976; Marsh and Cornford, 1976; Forrest and Marsh, 1983). Mesophase spherules are generally considered to be formed by parallel stacking of polynuclear aromatic hydrocarbon molecules in the early stage of mesophase transformation. Thereafter, the mesophase spheres grow in size and coalesce into larger anisotropic bodies to form semi-coke or coke, a highly anisotropic form of carbon (Brooks and Taylor, 1965; Marsh and Cornford, 1976). Texture evolution of mesophase pitch during carbonization can be shown in the following order: fine-grained mosaic, medium-grained mosaic, coarse-grained mosaic, coarse-flow, domain, and ultimately fibrous textures (Brooks and Taylor, 1965; White, 1976; Grint and Marsh, 1981). On the other hand, highly aromatic, insoluble solid bitumen in reservoir rocks may also be formed by thermochemical sulfate reduction (TSR) (Kelemen et al., 2008, 2010; Cai et al., 2010, 2017). TSR generally occurs in deeply buried carbonate reservoirs and contributes elevated concentrations of H2S to natural gas (Orr, 1974, 1977; Worden and Smalley, 1996; Machel, 2001; Cai et al., 2003). It can be represented by the following simplified reaction: Hydrocarbons + SO42- → altered hydrocarbons + solid bitumen + H2S + CO2 ± S ± H2O

Thiols and other organosulfur compounds (OSCs) are commonly generated during TSR (Orr, 1977; Cai et al., 2003, 2009, 2015, 2016a, 2016b; Wei et al., 2007, 2012; Amrani, 2014; Liu et al., 2014a; Walters et al., 2015) and are more easily oxidized by the HSO4– ion or MgSO4 contact-ion-pair to produce various lower valance sulfur species, including SO3, S2O3, S8, and H2S (Ma et al., 2008; Zhang et al., 2012a). These sulfur species can in turn react with hydrocarbons to generate more H2S and OSCs, and thus will further sustain the autocatalytic TSR reaction (Zhang et al., 2008). Solid bitumen formed by TSR via sulfurization of crude oil or bitumen generally has higher S/C atomic ratios and lower N/C ratios than that formed by thermal chemical alteration (TCA). The δ34S values of TSR-altered bitumen are close to those of the parent sulfate (Powell and Macqueen, 1984; Cai et al., 2001, 2010, 2017; Kelemen et al., 2008, 2010; Liu et al., 2009a; King et al., 2014). Moreover, TSR-altered bitumen is depleted in 13C compared to TCA-derived bitumen (Sassen, 1988; Cai et al., 2017). The depletion of 13

C in TSR-altered bitumen may result from the incorporation of isotopically depleted

alkanes or saturates via sulfurization and polymerization (Machel et al., 1995; Cai et al., 2017). Thus, S/C and N/C atomic ratios and δ13C and δ34S values can be used to distinguish TSR-altered bitumen from TCA-derived bitumen (Powell and Macqueen, 1984; Machel et al., 1995; Kelemen et al., 2008, 2010; Cai et al., 2010, 2017; King et al., 2014). In addition, S/C ratios and δ34S values of solid bitumen are believed to be alternative proxies for the extent of TSR (Cai et al., 2017). The largest H2S-bearing natural gas field in China, with total reserves of more than

1.0×1012 m3, has recently been discovered in the Ediacaran Dengying and Cambrian Longwangmiao formations in the Moxi-Gaoshiti area of Central Sichuan Basin. Few studies on the origin of H2S in the Longwangmiao Formation have been reported. Moreover, considerable controversy exists regarding the occurrence of TSR in the Dengying Formation. Some researchers suggest that the Dengying Formation may not have undergone TSR based on the low concentrations of H2S (< 5%) and the absence of any remarkable correlation between methane δ13C values and H2S concentrations (e.g., Zheng et al., 2014; Qin et al., 2018). Conversely, sulfur isotope data from anhydrite, H2S, and pyrite demonstrate that a moderate TSR may have occurred in the Dengying Formation in the Weiyuan gas field lying to the southwest of the study area (Zhu et al., 2015). Case studies of TSR from the Weiyuan and other gas fields have shown convincingly that the anhydrite is the dominant source of reactive sulfate for TSR (Krouse et al., 1988; Worden and Smalley, 1996; Heydari, 1997; Cai et al., 2003, 2004; Zhu et al., 2011, 2015). Nevertheless, evaporites were barely deposited in the Central Sichuan Basin during the Early Cambrian, as interpreted from various geological, logging, and seismic data (Lin et al., 2014; Xu et al., 2016). Anhydrite or gypsum was also rarely observed in either core or thin-section samples from the Dengying Formation in the Moxi-Gaoshiti gas field. Therefore, it is necessary to investigate the source of reactive sulfate for TSR in the Dengying and Longwangmiao formations. TSR may have taken place only on the surface of solid bitumen (Yang et al., 2018). Consequently, the molecular component within bitumen may have not been altered greatly by this

reaction, as indicated by the low S/C atomic ratios and the lack of any clear relationship between S/C ratios and N/C ratios (Tian et al., 2013). More evidence is needed to determine whether, and to what extent, TSR occurred in the two reservoirs. In addition, extensive precipitation of saddle dolomite in the Dengying Formation has been interpreted to reflect migration of hot dolomitizing fluids (Liu et al., 2016; Jiang et al., 2016; Feng et al., 2017; Peng et al., 2018). Hydrothermal fluids are able to facilitate TSR by providing a high temperature environment, and thus TSR may be closely associated with hydrothermal activity (Liu et al., 2016). Because hydrothermal activity and TSR can result in changes in optical and geochemical characteristics, respectively, of solid bitumen, correlating optical and geochemical data can yield insights into the association between the two natural processes. Solid bitumen in the study area may be a suitable geological object for the further study on the relationship between TSR and hydrothermal activity. The specific objectives of this study are as follows: (1) to determine the occurrence of hydrothermal activity and TSR and their effect on solid bitumen; (2) to investigate the source of reactive sulfate for TSR; and (3) to reveal the relationship between hydrothermal activity and TSR.

2. Geological setting The Sichuan Basin, located in southwest China, is a large hydrocarbon-bearing sedimentary basin with an area of approximately 18×104 km2 (Zhai, 1992). It is a

superimposed basin that experienced complex tectonic movements and evolved from a craton

basin

(Ediacaran-Late

Middle

Triassic)

to

a

foreland

basin

(Late

Triassic-Cretaceous) (Wang et al., 2002). As a tectonic unit of the Upper Yangtze Platform, the northeast-trending Sichuan Basin is bounded by the Longmenshan fold-thrust belt in the northwest, the Micangshan uplift in the north, the Dabashan fold-thrust belt in the northeast, and the Yunnan-Guizhou-Sichuan-Hubei fold belt in the east and south (Zhai, 1992). According to the basement configuration, the basin can be subdivided into three major tectonic units as follows: (1) the north-western depression; (2) the central uplift; and (3) the south-eastern folded zone (Fig. 1A) (Chen et al., 2017a). The Sichuan Basin experienced marine sediment deposition from the Ediacaran to the Middle Triassic and then terrestrial deposition during the Late Triassic to Eocene, with a total thickness of up to approximately 12,000 m. The Ediacaran-Middle Triassic carbonate strata have undergone multiple tectonic events (Hao et al., 2008). Consequently, several paleo-uplifts and regional unconformities developed within the basin and these structures significantly influenced the carbonate reservoir qualities and hydrocarbon accumulations (Zhu et al., 2015). The Indosinian Orogeny caused the change from a marine to a terrestrial depositional environment. The Upper Triassic sediments are dominated by lacustrine-alluvial sandstones with locally distributed coal beds. The Jurassic and Cretaceous sediments are composed of terrestrial mudstones, black shales, and red sandstones (Cai et al., 2003). The Yanshanian Orogeny resulted in

folding and deformation of the basin edge, and thereafter, the Sichuan Basin was entirely uplifted during Himalayan collision (Liu et al., 2013, 2014b). The Ediacaran Dengying and Cambrian Longwangmiao formations are the main producing layers of the Moxi-Gaoshiti gas field in the Central Sichuan Basin (Fig. 1A; Fig. 2) (Zou et al., 2014; Zhu et al., 2015). A shallow-water carbonate platform developed in the basin during Dengying deposition, which was favorable for the deposition of algae-rich dolomites (Chen et al., 2017a). The Dengying Formation can be subdivided into four members from bottom to top (i.e., Z2dn1, Z2dn2, Z2dn3, and Z2dn4) based on enrichment degrees of algae and structural characteristics. The first member of the Dengying Formation (Z2dn1) is depleted in algae, whereas the second member (Z2dn2) is characterized by algal dolomites with botryoidal and stromatolite structures (Yao et al., 2014). The third member (Z2dn3) is dominated by grey fine-crystalline dolomites intercalated with algal dolomites, but thin-bedded black argillaceous dolomites or mudstones have been found at the base of the Z2dn3 in the Central Sichuan Basin (Wei et al., 2013; Gao et al., 2017). The fourth member (Z2dn4) consists primarily of silt-sized dolomites, algal dolomites, and dolarenites (Fig. 2) (Wei et al., 2013; Luo et al., 2015). Unconformities at the top of the Z2dn2 and Z2dn4 formed during the first and second episodes of the Tongwan Movement, respectively (Li et al., 2014a). The Z2dn2 and Z2dn4 dolomite reservoirs have been significantly flushed by meteoric water beneath the unconformity surface, leading to the formation of dissolution pores and vugs (Wei et al., 2013; Li et al., 2014a; Yao et al., 2014; Luo et al., 2015). Therefore, the

Z2dn2 and Z2dn4 are major gas-bearing intervals in the Dengying Formation (Fig. 2) (Wei et al., 2013; Zhu et al., 2015; Chen et al., 2017a). During Longwangmiao deposition, a distally steepened, southeast-trending carbonate ramp developed in the Sichuan Basin and adjacent areas (Du et al., 2016). The Longwangmiao Formation can be subdivided into two members from bottom to top (i.e., Є1l1 and Є1l2), which represent two successive eustatic cycles (Jin et al., 2014; Shen et al., 2018). However, only the second member of the Longwangmiao Formation (Є1l2) was deposited in the Central Sichuan Basin and developed a regional high-quality reservoir primarily composed of oolitic dolomites and dolarenites (Yao et al., 2013; Jin et al., 2014; Shen et al., 2018). The reservoir space is dominated by dissolution pores and vugs that were formed by meteoric water flushing during the Caledonian period (Fig. 2) (Jin et al., 2014; Zhou et al., 2015; Chen et al., 2017b). The potential source rocks consist of the Lower Cambrian shales and the Upper Ediacaran mudstones, argillaceous dolomites, and algal dolomites (Fig. 2) (Wei et al., 2013, 2017; Shi et al., 2018). Although the Upper Ediacaran Doushantuo Formation (Z2ds) shales are enriched in algae and dominated by sapropelic organic matter, they are non-existent or very thin in the Central Sichuan Basin (Zou et al., 2014; Zhu et al., 2015). Thus, the Z2ds shales are unlikely to be a potential source rock (Zhu et al., 2015; Chen et al., 2017a). The Dengying Formation was primarily deposited in a shallow-water oxidizing environment (Fang et al., 2003). However, a rapid rise in sea level during the Early Z2dn3 led to local deposition of black argillaceous dolomites or

mudstones in the Central Sichuan Basin, with thicknesses between 10 m and 30 m (Wei et al., 2013, 2017; Gao et al., 2016). The Z2dn3 source rock contains abundant benthic macroalgae and is characterized by sapropelic organic matter (Zhu et al., 2015). During the Early Cambrian, a major transgression resulted in widespread deposition of black shales in the Yangtze Platform (Gao et al., 2016). The Lower Cambrian source rocks, including the Maidiping and Qiongzhusi formations, directly overlie the Dengying Formation, with thicknesses between 100 m and 400 m. Their distribution is controlled by the Mianzhu-Changning intracratonic rift (Wei et al., 2013, 2017). The Qiongzhusi Formation source rock is primarily composed of black shales enriched in trilobite and shell fossils. The Maidiping Formation source rock is dominated by siliceous and carbonaceous shales and contains some small shell fossils and collophanites. Both of them are characterized by sapropelic organic matter (Wei et al., 2017). Previous studies have shown that hydrocarbons in the Longwangmiao Formation were solely derived from the Qiongzhusi shales, while those in the Dengying Formation may have been generated from both the Qiongzhusi shales and the Z2dn3 mudstones or argillaceous dolomites (Zhu et al., 2015; Hao et al., 2017; Chen et al., 2017a, 2017b). Fig. 3 shows that the Upper Ediacaran and Lower Cambrian source rocks became marginally mature as a result of subsidence during the Silurian; however, the hydrocarbon generation stopped at the end of the Silurian due to Caledonian uplift (Yao et al., 2003). Thereafter, the two source rocks subsided again during the Permian to Cretaceous. They were buried to a maximum depth of greater than 6000 m at the end of

the Cretaceous; correspondingly, temperatures in the two strata increased to approximately 220 oC, which is more than sufficient for thermal cracking of crude oil (Barker, 1990). Peak oil generation occurred during the Permian to Triassic. Subsequently, crude oil in the Dengying and Longwangmiao formations was cracked to natural gas from the Jurassic to the Cretaceous (Yao et al., 2003; Zou et al., 2014; Wei et al., 2014, 2015). Finally, the Himalayan Orogeny resulted in gas remigration in the two reservoirs (Zou et al., 2014). The Lower Cambrian shales, Upper Permian mudstones, and Lower Triassic evaporites can act as effective regional seals for the hydrocarbon accumulations in the Central Sichuan Basin (Wei et al., 2013; Zhang et al., 2015).

3. Samples and methods 3.1. Samples collection More than 120 core samples were collected from 16 wells (Fig. 1B) for petrographic observation, fluid inclusion microthermometry, bitumen rotational reflectance measurement, and scanning electron microscope/energy-dispersive X-ray spectra (SEM/EDS) analysis. Nine solid bitumen samples from the Longwangmiao Formation and thirteen samples from the Dengying Formation were analyzed for S/C and N/C atomic ratios and δ13C and δ34S values. Bitumen-bearing dolomite samples were ground to small grains with sizes between 1 mm and 3 mm with an agate mortar. Pure bitumen grains were then handpicked from the crushed samples under a binocular microscope with a magnification of ×10. Two pure pyrite samples were also obtained

from the two reservoirs in the same way. In addition, three dolomite samples from the Longwangmiao Formation and six samples from the Dengying Formation were analyzed for content and sulfur isotope composition of water-soluble sulfate (WSS) and carbonate-associated sulfate (CAS). Eight natural gas samples were collected from the Dengying Formation for chemical and isotopic analyses. They were sampled directly into double-ended stainless steel bottles (volume, 1 L; maximum pressure, 22.5 MPa) at wellheads. Sampling pressures were generally greater than 5.0 MPa. The inside surfaces of these bottles were coated with polytetrafluoroethylene film to make sure that no H2S was lost by reaction with steel. The gas collecting device was flushed with natural gas for approximately fifteen minutes before sample collection to ensure no air contamination. All the bottles filled with natural gas were immersed into a water bath for leak testing.

3.2. Analytical methods 3.2.1. Microscopic observation Petrographic observations were performed with a Leica DM 2500P microscope and polished thin sections. Microthermometric measurements of fluid inclusions were performed using a Linkam Model THMSG 600 heating-cooling stage attached to a Leica Model DMRXP optical microscope. After temperature calibration, the ice melting temperatures (Tm) and homogenization temperatures (Th) were measured in primary two-phase (liquid + vapor) inclusions following procedures outlined by Lu et al. (2004).

Precision of microthermometric analysis was generally within ±1 oC. Aqueous fluid salinities were calculated using Tm and the equation of Hall et al. (1988) and Bodnar (1993). To differentiate hydrothermally altered bitumen samples from normally matured ones, the rotational reflectance of bitumen was measured according to the method described by Luo et al. (2016, 2017, 2018). Bitumen-bearing dolomite samples were mechanically polished to provide a flat and smooth surface for microscopic observation. Rotational reflectance measurements were performed using a Leica microscope equipped with a CRAIC microscope photometer. The reflectance measuring system was linearly

calibrated

with

various

standard

materials

(Sapphire,

Ro=0.589%;

Gadolinium-gallium-garnet, Ro=1.725%; Cubic zirconia, Ro=3.08%; Strontium titanate, Ro=5.36%). The maximum and minimum reflectance values (i.e., Rbmax and Rbmin, respectively, %) were measured at one site by rotating the microscope stage through 360o under the reflected light with a polarizer in the light path. The bireflectance value (Rbmax - Rbmin, %) was then calculated for each site. The analyses above were conducted at the State Key Laboratory of Petroleum Resources and Prospecting at the China University of Petroleum, Beijing (CUP). In addition, freshly broken surfaces of core sample fragments were coated with gold and then inserted into an FEI Quanta 200F scanning electron microscope (SEM) equipped with an energy-dispersive X-ray spectrometer (EDS) for petrographic observation. The atomic and weight percentages of elements were estimated with a

normalized standardless EDAX-ZAF quantification method. The SEM/EDS analysis was conducted at the Microstructure Laboratory for Energy Materials at CUP.

3.2.2. Stable sulfur isotope analysis of various sulfur species (1) Separation of solid bitumen Separation of solid bitumen was performed as described by Cai et al. (2010, 2017). Inorganic minerals, including carbonates, silicates, oxides, and pyrite, were removed from bitumen samples by treatments with HCl, HF, and CrCl2. Following heavy-liquid separation, pyrite concentrations of the remaining bitumen were determined by X-ray diffraction (XRD) techniques. The whole procedure was repeated until the pyrite concentrations were below detection limits (≤0.5% depending on conditions). For sulfur isotope analysis, the organically bound sulfur in the remaining bitumen was oxidized to sulfate through complete combustion at approximately 25 atm O2 pressure in a Parr bomb. The sulfate was dissolved in deionized water and then precipitated as BaSO4. If the concentrations of pyritic sulfur in the remaining bitumen were less than 8%, then the BaSO4 analyzed for δ34S values primarily represents the organic sulfur in the bitumen. The absolute error depends on the differences in δ34S value between bitumen and associated pyrite. (2) Extraction of WSS and CAS Core samples were cut to remove weathered surfaces and veins. Chips without pyrite or pyrite pseudomorphs were selected for extraction of WSS and CAS (Marenco

et al., 2008a; Chen et al., 2013). WSS was extracted according to the method described by Wotte et al. (2012). The selected core chips were ground to fine powders (utilizing a 200 mesh sieve) and then leached with a 10% NaCl solution for 24 hours under constant magnetic stirring. Thereafter, the slurry was filtered through a membrane filter (0.45 μm). After the resulting filtrate was acidified to a pH value less than 2 and heated until boiling, an 8.5% BaCl2 solution (10% of the filtrate volume) was added to precipitate WSS as BaSO4. The solution was kept at 80 oC for three hours and then left overnight at room temperature. The BaSO4 was separated from the solution by filtration with a membrane filter (0.45 μm), which was then dried and weighed. Powder samples were leached repeatedly until no more WSS could be liberated from them. Once the samples were free of the WSS phases, they were dissolved in 3 N HCl for the CAS extraction. The total amount of HCl was determined using the stoichiometric ratio and the initial sample mass (assuming the samples were pure dolomite), which ensured the dissolution of all the carbonate and minimized the risk of dissolving any sulfide phases (Marenco et al., 2008b). The HCl digestion step was performed within three hours to prevent pyrite oxidation (Chen et al., 2013). Thereafter, the CAS released from powder samples was precipitated as BaSO4 according to the procedure described above. (3) H2S and pyrite H2S-bearing natural gas from wellheads was bubbled gently through a saturated solution of zinc acetate to precipitate H2S as ZnS. The resulting ZnS was subsequently

transformed to Ag2S in the laboratory. Pyrite grains handpicked from crushed core samples were cleaned in an ultrasonic bath before sulfur isotope analysis. Sulfur isotope analysis was conducted at the Key Laboratory of Petroleum Resources Research at the Institute of Geology and Geophysics, Chinese Academy of Sciences. The dried BaSO4 was mixed with a 1:1 mixture of V2O5 and SiO2 and then combusted at 1100 oC under vacuum to produce SO2. Sulfides and Cu2O were generally mixed in a proportion of 1:10 and then combusted under the same condition to generate SO2. The resulting SO2 was sealed within pyrex tubing and analyzed on a Thermo Delta S mass spectrometer. Sulfur isotope values are expressed as per mil (‰) deviations from the sulfur isotope composition of the Vienna Canyon Diablo Troilite (VCDT) using the conventional delta (δ34S) notation. Isotopic results were generally reproducible within ±0.3‰.

3.2.3. Stable carbon isotope analysis of solid bitumen Carbon isotope analysis of solid bitumen was conducted at the State Key Laboratory of Petroleum Resources and Prospecting at CUP. Bitumen samples after pyrite removal (~0.1 mg) were combusted at 850 oC to produce CO2. The resulting CO2 was then analyzed on a Finnigan MAT-253 mass spectrometer. Isotope values are expressed as per mil (‰) deviations from the carbon isotope composition of the Vienna Peedee Belemnite (VPDB) using the conventional delta (δ13C) notation. Isotopic results were generally reproducible within ±0.1‰.

3.2.4. Elemental composition analysis of solid bitumen Elemental composition analysis of solid bitumen was conducted at the CHNOS Elemental Technology Co., Ltd in the Shanxi province. Bitumen samples after pyrite removal (~1 mg) were loaded into tin capsules and then combusted in a Vario El elemental analyzer for elemental analysis. The concentrations of C, H, N, and S in the bitumen were measured with a precision of ±0.5%.

3.2.5. Chemical composition and carbon isotope analyses of natural gas Chemical and carbon isotopic compositions of natural gas samples were measured following the method of Liu et al. (2013) at the Key laboratory of Gas Geochemistry at the Lanzhou Institute of Geology, Chinese Academy of Sciences. Chemical composition analysis was performed using a Finnigan MAT-271 mass spectrometer. Concentrations of various gas components were calculated with a calibration curve obtained from synthetic standard gases. Carbon isotope compositions of methane and ethane were determined using routine mass spectrometer techniques (a Finnigan MAT-252 mass spectrometer). Precision of carbon isotope analysis was generally within ±0.3‰. The associated analytical conditions were also outlined by Liu et al. (2013). Each sample was measured three times and the average of three measurements served as the final result.

4. Results 4.1. Petrographic characteristics 4.1.1. Dolomite Meteoric water flushing within the Dengying and Longwangmiao formations has resulted in the formation of dissolution pores and vugs (Fig. 4A and B) (Li et al., 2014a; Jin et al., 2014). Two types of dolomite are recognized in both reservoirs: one occurs as euhedral to subhedral crystals in the rock matrix (D1) (Fig. 5A) and the other as rhombohedral crystals in the dissolution vugs and fractures (D2) (Fig. 4C-F). In particular, D2 has sizes varying from a few millimeters to almost one centimeter (Fig. 4C-F) and generally shows curved cleavage traces and sweeping extinction in thin section (i.e., saddle dolomite) (Fig. 5B).

4.1.2. Quartz Quartz was also frequently found in the dissolution vugs and fractures (Fig. 4C, E, and F; Fig. 5C). It generally occurs as prismatic crystals, with sizes ranging from a few millimeters to approximately three centimeters (Fig. 4C and E). Some quartz crystals have primary bitumen inclusions that occur along trails parallel to the crystal boundaries (Fig. 6A and B), suggesting that the quartz was probably precipitated during or after the oil emplacement and bitumen formation.

4.1.3. Barite Barite coexists with saddle dolomite in the dissolution vugs in the Longwangmiao Formation and some barite crystals are lath-shaped (Fig. 5G and H). Both the barite and saddle dolomite were partially replaced by euhedral pyrite grains (Fig. 5G, H, J, P, and Q). In the Dengying Formation, barite occurs as thin layers (Fig. 5K, L, and R) and is inter-grown with fluorapatite and some aluminosilicate minerals (Fig. 5M, R, and S). The barite was also replaced by a significant amount of pyrite and sphalerite (Fig. 5I). In particular, some cubic pyrite grains are coated with a barite film (Fig. 5K). In addition, some dumbbell-shaped barite particles were also found in the vesicles of solid bitumen in the Dengying Formation (Fig. 5N; Gao et al., 2017).

4.1.4. Solid bitumen Solid bitumen is widely distributed in small dissolution pores (Fig. 5A), vugs (Fig. 4F), and fractures (Fig. 5B and C). Two types of solid bitumen are identified by reflected light microscopy: one has various anisotropic textures (Fig. 5E and F; Fig. 7A and E) and the other isotropic or very fine-grained mosaic texture (Fig. 5D; Fig. 7C and G). Moreover, the former bitumen has high bireflectance values ranging from 3.89% to 7.31% in the Longwangmiao Formation (n=25; Fig. 7B) and from 4.85% to 9.21% in the Dengying Formation (n=25; Fig. 7F), whereas the latter has extremely low bireflectance values varying from 0.17% to 0.51% in the Longwangmiao Formation (n=5; Fig. 7D) and from 0.41% to 1.51% in the Dengying Formation (n=5; Fig. 7H)

(Table 1).

4.2. Fluid inclusions A large number of primary gas-liquid fluid inclusions occur in the pore-filling saddle dolomite and quartz as described above. Microthermometric analyses were carried out on relatively large fluid inclusions, with sizes ranging from 5 μm to 20 μm (Fig. 6C and D). Some primary inclusions were trapped along trails parallel to the boundaries of quartz crystals (Fig. 6E). Little evidence exists regarding post-entrapment modification (i.e., stretching, necking down, and leaking; Bodnar, 2003). In addition, some CH4 inclusions with negative crystal shapes were also found in the quartz (Fig. 6F) and can be interpreted to reflect a significant thermal cracking of hydrocarbons during quartz precipitation (Liu et al., 2009b). Microthermometric results show that homogenization temperatures of fluid inclusions in the saddle dolomite range from 108 oC to 262 oC, with a peak between 180 o

C and 190 oC. Salinities of these inclusions primarily vary from 9 to 11 eq. wt% NaCl

(n=38; Table 2; Fig. 8). Quartz-hosted fluid inclusions display a bimodal distribution of homogenization temperatures: one is between 180 oC and 190 oC and the other between 240 oC and 250 oC. Salinities of these inclusions primarily vary from 18 to 21 eq. wt% NaCl (n=56; Table 2; Fig. 8).

4.3. S/C and N/C atomic ratios, δ13C, and δ34S values of solid bitumen Solid bitumen samples from the Longwangmiao Formation have S/C atomic ratios between 0.008 and 0.055, N/C atomic ratios between 0.0027 and 0.0067, δ13C values between -35.6‰ and -33.5‰, and δ34S values between 12.5‰ and 27.5‰ (n=9). Bitumen samples from the Dengying Formation have S/C ratios between 0.020 and 0.059, N/C ratios between 0.0055 and 0.0080, δ13C values between -36.0‰ and -34.4‰, and δ34S values between 18.6‰ and 26.2‰ (n=13) (Table 3). Two types of solid bitumen are identified based on S/C atomic ratios: one has S/C ratios of less than 0.03 and the other of greater than 0.03. The former bitumen is depleted in

34

S compared to the latter in the same reservoirs (Fig. 9A). However, no

obvious correlations exist between N/C ratios and S/C ratios in solid bitumen (Fig. 9B).

4.4. Concentrations and δ34S values of CAS and WSS CAS concentrations in the Longwangmiao Formation range from 14.2 ppm to 17.5 ppm (15.9 ppm on average; n=2), but those in the Dengying Formation are more heterogeneous and vary from 35.6 ppm to 208.1 ppm (93.4 ppm on average; n=4). Likewise, a wide variation exists in WSS concentrations in the Dengying Formation (372.2~516.0 ppm with an average of 459.2 ppm; n=6), whereas a narrow range is present in those in the Longwangmiao Formation (413.3~431.5 ppm with an average of 424.0 ppm; n=3) (Table 4). On the other hand, WSS is isotopically heavier in the Dengying Formation

(17.8‰~21.1‰; n=6) than in the Longwangmiao Formation (16.4‰~16.9‰; n=3). CAS in the Dengying Formation displays a range of δ34S values from 30.1‰ to 36.1‰ (n=3), although there is one outlier with a value of 25.1‰. The outlier may be the result of considerable oxidation of sulfides during the CAS extraction. CAS in the Longwangmiao Formation is also depleted in 34S (24.6‰~26.8‰; n=2) relative to that in the Dengying Formation. In addition, the δ34S values of CAS are much heavier than those of the associated WSS for most samples, suggesting that the extracted CAS may have not been influenced by the associated WSS. The great similarity of CAS δ34S data from dolomites and limestones in the Dengying Formation indicates that the sulfur isotope signatures of CAS probably have survived dolomitization (Table 4).

4.5. Sulfur isotope values of H2S and pyrite H2S samples from the Longwangmiao and Dengying formations have δ34S values ranging from 19.7‰ to 21.6‰ and from 19.6‰ to 28.2‰, respectively. One pyrite sample from the Longwangmiao Formation has a δ34S value of 19.1‰, and one from the Dengying Formation has a δ34S value of 19.4‰. The δ34S values of pyrite are close to those of the H2S in the same reservoirs, suggesting that the two types of sulfide may have the same origin (Table 5).

4.6. Chemical and carbon isotopic characteristics of natural gas Chemical and carbon isotopic compositions of natural gas samples from the

Dengying Formation are presented in Table 6. The table also shows chemical composition data collected from the Research Institute of Petroleum Exploration and Development, PetroChina Southwest Oil & Gas Field Company. Chemical and isotopic data published in previous work, including Sun (2008), Wang et al. (2013), Zheng et al. (2014), Wei et al. (2015), and Zhu et al. (2015), are also included in this study. Natural gas in the Dengying Formation is predominated by methane, with gas dryness values (CH4/ΣCnH2n+2) greater than 99.85%. No apparent correlations exist between gas dryness and depth (Fig. 10A). In contrast, gas souring index (GSI) values (H2S/(H2S+ΣCnH2n+2)) increase roughly with increasing depth. The highest GSI value in the Moxi area is 3.33%, while that in the Gaoshiti area is less than 3% (Fig. 10B). Methane and ethane have δ13C values ranging from -36.7‰ to -32.0‰ and from -31.9‰ to -24.9‰, respectively. The carbon isotope composition of methane is not correlated with depth (Fig. 11A), whereas the δ13C values of ethane increase roughly with increasing depth (Fig. 11B). In particular, gas with heavier ethane δ13C values occur in deeper reservoirs in the Moxi area (Fig. 11B).

5. Discussion 5.1. Effect of hydrothermal heating on solid bitumen 5.1.1. Evidence for hydrothermal heating Saddle dolomite and quartz occur widely in dissolution vugs and fractures in the Dengying and Longwangmiao formations (Fig. 4C-F; Fig. 5B and C). Primary

gas-liquid fluid inclusions in the two minerals have homogenization temperatures varying from 180 oC to 250 oC (Table 2; Fig. 8). Homogenization temperatures of some fluid inclusions are more than 10 oC higher than the maximal burial temperature of the Dengying Formation (~220 oC; Fig. 3). Moreover, salinities of the primary fluid inclusions range from 9 to 21 eq. wt% NaCl and are approximately 2~5 times higher than those of the normal seawater. The significantly elevated homogenization temperatures and salinities of primary inclusions have been used as evidence for a hydrothermal origin of the host minerals (e.g., Cai et al., 2008; Peng et al., 2018). Therefore, the microthermometric data noted above indicate that the saddle dolomite and quartz probably have been precipitated from the hot saline brines migrating from deep strata. A large amount of solid bitumen coexists with the saddle dolomite and/or quartz in the dissolution vugs and fractures (Fig. 4F; Fig. 5B and C). It is characterized by various anisotropic textures, such as coarse-grained to flow mosaic (Fig. 5E; Fig. 7E) and deformed fibrous textures (Fig. 5F; Fig. 7A). The significant anisotropy of solid bitumen further confirms the occurrence of abnormal heating events, such as hydrothermal activity, in the Dengying and Longwangmiao formations (Khorasani and Murchison, 1978; Creaney et al., 1980; Goodarzi and Stasiuk, 1991; Goodarzi et al., 1993; Wilson, 2000). The development of anisotropy in solid bitumen commonly depends on temperature, heating rate, and chemical composition of the parent material (Gize, 1986; Goodarzi et al., 1993; Stasiuk, 1997). In particular, a high temperature is

crucial to the formation of mesophase (i.e., anisotropic bitumen). Several laboratory simulation experiments have shown that the conversion from isotropic bitumen to mesophase generally occurred at temperatures of approximately 350 oC (Brooks and Taylor, 1965; White, 1976). As shown in Fig. 8, primary fluid inclusions in the quartz have homogenization temperatures of up to approximately 250 oC, which is close to the temperatures of mineralizing fluids associated with anisotropic bitumen in the El Soldado Cu deposit in Chile (~250 oC; Wilson, 2000). Therefore, the hydrothermal fluids in the study area may be able to convert isotropic bitumen to anisotropic bitumen. Due to significant differences in physicochemical condition between natural systems and simulation experiments, especially regarding the ambient pressure and fluid properties, the formation temperatures of mesophase can be distinctly different in the two environments. Nevertheless, the elevated homogenization temperatures of fluid inclusions and the various anisotropic textures of solid bitumen indicate that hydrothermal activity occurred in the Dengying and Longwangmiao formations and that the anisotropic solid bitumen was probably formed at high temperatures of up to approximately 250 oC. Solid bitumen has also frequently been observed as primary inclusions in the pore-filling quartz. In particular, some bitumen inclusions were trapped along trails parallel to the crystal boundaries (Fig. 6A and B). The frequent occurrence of primary bitumen inclusions, together with the widespread distribution of anisotropic solid bitumen, implies that there was at least one episode of hydrothermal activity during or

after the significant hydrocarbon emplacement in the study area. Previous studies have shown that only minor hydrocarbons were generated from the Cambrian and Ediacaran source rocks during the Silurian, and thereafter, peak oil generation occurred during the Permian to Triassic (Fig. 3) (Yao et al., 2003; Zou et al., 2014; Hao et al., 2017). Thus, we infer that the hydrothermal episode may be associated with a significant tectonic movement during or after the Permian. The Xingkai Movement and Emei Movement are two major tectonic events in the Sichuan Basin and adjacent areas (Liu et al., 2016). The Xingkai Movement occurred during the Early Cambrian (Liu et al., 2016), and thus predated the hydrocarbon generation, so the alteration of bitumen by hydrothermal activity associated with the Xingkai Movement was unlikely to have taken place in the Dengying and Longwangmiao formations. However, the anomalous heating events in the study area may have been induced by the eruption of the Emeishan Flood Basalts during the Permian (Ali et al., 2005). This significant tectonic movement not only gave rise to extensive Pb-Zn mineralization around the Sichuan Basin (Zhou et al., 2018), but also facilitated migration of hydrothermal fluids from deep to shallow strata within the basin (Huang et al., 2012, 2014). The deep-seated brines possibly migrated upward through faults to the Dengying and Longwangmiao formations, driven by tectonic deformation associated with the Emei Movement. Consequently, the pre-existing liquid or semi-solid bitumen in the two reservoirs was rapidly heated by the hydrothermal fluids, resulting in the formation of anisotropic solid bitumen (Goodarzi et al., 1989). Temperatures and heating rates of hydrothermal fluids must have decreased

progressively during migration within strata. The cooling process probably has weakened the effect of hydrothermal fluids on optical textures of solid bitumen. Petrographic examination reveals that some bitumen exists in the small dissolution pores or fractures with rare saddle dolomite and quartz (Fig. 5A) and has isotropic or very fine-grained mosaic texture (Fig. 5D; Fig. 7C and G). Its occurrences and optical textures are distinctly different from those of the hydrothermally heated bitumen as described above. Therefore, this bitumen was probably not altered by hydrothermal fluids. The two types of solid bitumen are also identified using the rotational reflectance data. Optically anisotropic bitumen samples from the Dengying and Longwangmiao formations have bireflectance values ranging from 4.85% to 9.21% and from 3.89% to 7.31%, respectively (Table1). These samples follow the bituminization curve of heat-affected bitumen in the Rmax versus Rmin plot (Fig. 12) (Goodarzi et al., 1993), further confirming that they have experienced hydrothermal alteration. In contrast, two bitumen samples without apparent optical anisotropy have bireflectance values between 0.17% and 1.51% (Table1). Both of them are plotted along the trend of normally matured bituminization in the same plot (Fig. 12), indicating that the two samples were likely to have been heated only by continued basin subsidence (Goodarzi et al., 1993; Wilson, 2000). The existence of normally matured bitumen also implies the heterogeneity of hydrothermal alteration in the two reservoirs.

5.1.2. Hydrothermal alteration of δ13C value of solid bitumen As shown in Table 3, the hydrothermally altered solid bitumen is enriched in

13

C

compared to the normally matured bitumen by up to 1.6‰ in the Dengying Formation and by up to 2.1‰ in the Longwangmiao Formation. This result indicates that the hydrothermal alteration can lead to 13C-enrichment in the solid bitumen (Fig. 13). Crude oil or bitumen may have experienced advanced levels of thermal cracking in an abnormal heating environment. More isotopically depleted alkanes can be released from the system; i.e., the abnormal heating events can further increase the carbon isotope fractionation between lower molecular weight hydrocarbons and remaining bitumen. Consequently, solid bitumen altered by hydrothermal fluids is isotopically heavier than bitumen heated only by basin thermal subsidence. Previous work by Zhu et al. (2013) also showed a comparable

13

C-enrichment in bitumen formed in the high-temperature

dolomite reservoirs (up to 2.1‰) relative to that in the low-temperature reservoirs in the Guizhou uplift. In addition, hydrothermal heating can also cause a dramatic increase in the carbon isotope values of kerogen (e.g., Schwab et al., 2005). Schwab et al. (2005) found that the Swiss Alps Liassic kerogen in the highest metamorphic zones is enriched in 13

13

C by approximately 14‰ relative to that in the diagenetic zones. The

C-enrichment of kerogen was probably attributed to a relatively greater

devolatilization of isotopically depleted methane at equilibrium with graphite. We conclude that hydrothermally altered solid bitumen tends to be enriched in compared to normally matured bitumen derived from the same source.

13

C

5.2. Effect of TSR on solid bitumen 5.2.1. Evidence for TSR Extensive hydrothermal activity may have resulted in incorporation of mantle-derived H2S into natural gas in the Dengying and Longwangmiao formations. The δ34S values of mantle-derived sulfides in the intrusive rocks, mid-ocean ridge basalts, and peridotites generally cluster around 0‰ (Thode et al., 1961; Sakai et al., 1984; Eldridge et al., 1995). H2S of volcanic origin also displays a narrow range of δ34S values from -1.2‰ to 5.5‰ (Nakai and Jensen, 1967). However, H2S samples from the two reservoirs have δ34S values of greater than 19‰ (Table 5), and thus are enriched in 34

S compared to the mantle-derived sulfides. These samples were certainly not derived

from a mantle sulfur source. In general, H2S in hydrocarbon reservoirs has three main sources as follows: (1) thermal decomposition of organosulfur compounds (OSCs) in kerogen or crude oil (TDS); (2) bacterial sulfate reduction (BSR); and (3) thermochemical sulfate reduction (TSR) (Orr, 1974, 1977). Sulfides produced by pure cultures of sulfate-reducing bacteria are depleted in

34

S by 5‰~46‰ relative to parent

sulfate. The resulting sulfur isotope fractionation can be even larger due to disproportionation of intermediate compounds, such as elemental sulfur and thiosulfate. In modern marine environment, sedimentary sulfides formed by BSR are depleted in 34S by up to approximately 70‰ relative to seawater sulfate (Canfield and Teske, 1996; Habicht and Canfield, 1997). Thus, the highly

34

S-enriched H2S in the two reservoirs

(Table 5) was unlikely to have been derived from microbial activities. As shown in Fig. 3, the Dengying and Longwangmiao formations have been subjected to temperatures of greater than 80 oC during and after peak oil generation. The formation temperatures were higher than the upper temperature limit of sulfate-reducing bacteria (Machel, 2001). Moreover, the formation water in the two reservoirs is characterized by high salinities (>70 g/L), and thus unfavorable for the proliferation of microbes (Zhu et al., 2015). The high formation temperatures and the high-salinity formation water further suggest that the contribution of BSR to H2S can be negligible. In addition, all the H2S samples from the Longwangmiao Formation have significantly heavier δ34S values than parent kerogen in the Lower Cambrian Qiongzhusi Formation (12.0‰~14.2‰; Zhang et al., in prep). Similarly, some H2S samples from the Dengying Formation are also enriched in

34

S relative to potentially parent kerogen in the Qiongzhusi and Dengying

formations (24.2‰; Zhang et al., in prep) (Fig. 14). These samples cannot be generated by the thermal decomposition of sulfur-containing kerogen or crude oil (Cai et al., 2010). We also found that the δ34S values of carbonate-associated sulfate (CAS) in the Dengying and Longwangmiao formations (30.1‰~36.1‰ and 24.6‰~26.8‰, respectively; Table 4) are comparable to those of the evaporites in the Ediacaran (20.4‰~43.3‰; Gorjan et al., 2000) and Lower and Middle Cambrian (20.2‰~35.5‰; Claypool et al., 1980; Strauss, 1993), respectively. This result implies that CAS may reliably record and preserve the sulfur isotope composition of paleo-seawater at the time of carbonate precipitation (Burdett et al., 1989; Hurtgen et al., 2002). The δ34S values of

H2S in the two reservoirs are close to those of the associated coeval seawater sulfate as represented by CAS and evaporites. The small isotope fractionation between H2S and parent seawater sulfate is generally interpreted as a result of nearly complete reduction of all dissolved sulfate during TSR (e.g., Orr, 1977; Krouse et al., 1988; Worden and Smalley, 1996; Yang et al., 2001; Cai et al., 2003, 2004). The sulfur isotope data noted above indicate that the highly

34

S-enriched H2S in the Dengying and Longwangmiao

formations was primarily derived from TSR. The occurrence of TSR is also evidenced by the replacement of hydrothermal barite by the 34S-enriched pyrite. The hydrothermal origin of barite will be discussed in Section 5.3.1. Petrographic observation reveals that some euhedral pyrite grains have replaced a lath-shaped barite crystal along its edge in the Longwangmiao Formation (Fig. 5H, J, P, and Q). A similar phenomenon was found in the Dengying Formation (Fig. 5I), where barite was replaced by pyrite and sphalerite with the remaining thin-laminated barite on the surface of euhedral pyrite grains (Fig. 5K, L, and R). The δ34S values of the replacive pyrite in the Longwangmiao and Dengying formations (19.1‰ and 19.4‰, respectively) are close to those of the TSR-derived H2S in the same reservoirs (Table 5). The heavy sulfur isotope signatures of replacive pyrite indicate a thermochemical origin for the replacement process; i.e., the conversion from hydrothermal barite to pyrite has proceeded via in situ TSR. The chemical and carbon isotopic data from natural gas in the Dengying Formation also suggest a TSR origin of H2S. As shown in Fig. 10B, the gas souring index (GSI)

values of natural gas increase roughly with increasing depth. This sourness-depth pattern is similar to that in the TSR-altered gas in the Khuff Formation in Abu Dhabi and the Feixianguan Formation in Sichuan Basin, where gas with higher GSI values tends to occur in deeper reservoirs (Worden and Smalley, 1996; Liu et al., 2013). Natural gas in the Gaoshiti area displays increases in CH4/ΣCnH2n+2 and ln(CH4/C2H6) ratios with increasing GSI (Fig. 15A and B), indicating that the souring process was probably associated with the preferential loss of ethane (Worden and Smalley, 1996; Cai et al., 2004; Hao et al., 2008; Liu et al., 2013). It is worth noting that the δ13C values of ethane also increase roughly with increasing depth and GSI (Fig. 11B; Fig. 16B). This trend can be interpreted as preferential rupture of

12

C-12C bonds in ethane during

oxidation by sulfate (i.e., TSR) (Krouse et al., 1988; Manzano et al., 1997; Pan et al., 2006). Both chemical and isotopic data suggest that TSR of ethane probably occurred in the Dengying Formation in the Moxi-Gaoshiti gas field.

5.2.2. TSR effect on N/C and S/C atomic ratios and δ34S value of solid bitumen The S/C atomic ratio can be used to distinguish solid bitumen formed by thermal chemical alteration (TCA) from bitumen by TSR alteration (Powell and Macqueen, 1984; Kelemen et al., 2008; Liu et al., 2009a; Cai et al., 2017). TCA-derived solid bitumen in the Alaskan Brooks Range and the NE Sichuan Basin have S/C atomic ratios varying from 0.004 to 0.020 and from 0.014 to 0.030, respectively (Kelemen et al., 2008; Cai et al., 2017). Organic solids formed by TCA in laboratory simulation experiments

also have S/C ratios less than 0.032 due to offsetting preservation and H2S elimination reactions (Kelemen et al., 2008). Thus, solid bitumen samples with S/C ratios less than 0.03 are considered to have a TCA origin (Kelemen et al., 2008; Cai et al., 2017). In contrast, other samples with S/C ratios between 0.031 and 0.059 are classified as TSR-altered (Table 3). This is supported by the fact that the δ34S values of the sulfur-enriched bitumen are similar to or slightly heavier than those of the TSR-derived H2S in the same reservoirs (Table 3; Fig. 14). The isotopically enriched sulfur in the bitumen was probably derived from the H2S of TSR origin. A positive correlation exists between S/C atomic ratios and δ34S values in bitumen samples from both the Dengying and Longwangmiao formations (Fig. 9A), which is similar to that in bitumen samples from the Permian and Triassic in the NE Sichuan Basin (Cai et al., 2017). This correlation further indicates that the TSR-derived H2S may have been progressively incorporated into the solid bitumen during TSR. H2S generated by TSR can back-react with hydrocarbons to produce 34S-enriched OSCs, which may be incorporated into solid bitumen via aromatization and polymerization. Consequently, the TSR-altered bitumen has higher S/C ratios and heavier δ34S values than the TCA-derived bitumen (Cai et al., 2010, 2017). In addition, the TSR-altered bitumen in the Longwangmiao Formation shows a tendency to be depleted in nitrogen with N/C atomic ratios as low as 0.0027, although the TCA-derived bitumen in the same reservoir is not characterized by the highest N/C ratio (Fig. 9B). A similar study by Cai et al. (2017) showed a negative correlation

between S/C ratios and N/C ratios in solid bitumen in the Permian and Triassic. The depletion of nitrogen in the TSR-altered bitumen was interpreted as a result of the incorporation of TSR-derived H2S. However, there is no such correlation in bitumen in the Dengying Formation (Fig. 9B). It is worth noting that bitumen in the Longwangmiao Formation was solely derived from the Qiongzhusi shales, while that in the Dengying Formation may have been generated from both the Qiongzhusi shales and the Z2dn3 mudstones or argillaceous dolomites (Zhu et al., 2015; Hao et al., 2017; Chen et al., 2017a, 2017b). Moreover, the nitrogen content of the Z2dn3 kerogen is much higher than that of the Qiongzhusi kerogen (0.0372 and 0.0070~0.0098, respectively; Zhang et al., in prep). Thus, bitumen in the Dengying Formation possibly varied in nitrogen content before TSR commenced due to heterogeneous contribution from the nitrogen-enriched Z2dn3 kerogen. The variable initial nitrogen concentrations may have obscured the effect of TSR on chemical composition of bitumen. In contrast, bitumen in the Longwangmiao Formation may have similar nitrogen concentrations prior to TSR, so the depletion of nitrogen in TSR-altered bitumen compared to TCA-derived bitumen is relatively obvious (Fig. 9B). Therefore, the N/C atomic ratio in solid bitumen is considered to be determined by both the parent source rocks (Kelemen et al., 2008) and the post-genetic processes, such as TSR (Cai et al., 2017).

5.2.3. TSR effect on δ13C value of solid bitumen A strong negative correlation exists between δ13C values and S/C atomic ratios in

the TSR-altered bitumen in the Dengying Formation (Table 3; Fig. 9C), indicating that some

13

C-depleted hydrocarbons may have been incorporated into the bitumen along

with the TSR-derived H2S. This trend is consistent with the depletion of

13

C in

TSR-altered bitumen relative to TCA-derived bitumen as reported by Sassen (1988) and Cai et al. (2017). Thiols and other OSCs have been detected in some TSR-altered gas reservoirs in the Sichuan Basin. In particular, the thiols were considered to be formed by reaction between TSR-derived H2S and hydrocarbons, as suggested by a positive relationship between concentrations of thiols and H2S in natural gas in the Lower Triassic (Cai et al., 2003; Liu et al., 2014a). As discussed in Section 5.2.1, ethane has been significantly involved in TSR in the Dengying Formation (Fig. 16B). The 13

C-depleted ethane would preferentially react with sulfate to generate isotopically

enriched H2S. The resulting H2S can back-react with the 13C-depleted ethane to produce 13

C-depleted ethanethiol, which may be subsequently incorporated into the bitumen.

Consequently, the δ13C values of the TSR-altered solid bitumen can be lighter than (Tables 3 and 6) or close to those of the remaining ethane (e.g., Cai et al., 2017). Oxidation of ethane by sulfate (i.e., TSR) is accompanied by large carbon isotope fractionations of up to 16.0‰ in natural systems (Krouse et al.,1988; Connan et al., 1996; Mankiewicz et al., 2009; Cai et al., 2013) and of up to 24.4‰ in simulation experiments (Pan et al., 2006). Because ethane has been significantly involved in TSR in the Dengying Formation, the δ13C values of the initial ethane were certainly much lighter than those of the remaining ethane (-31.9‰~-24.9‰; Zheng et al., 2014; Zhu et

al., 2015; Wei et al., 2015; this study). For the deep carbonate gas reservoirs formed by in situ cracking of crude oil in the Sichuan Basin, the initial ethane before oxidation by sulfate was also depleted in

13

C relative to the methane (Hao et al., 2008; Liu et al.,

2013). This basin-wide phenomenon is possibly related to various mixing processes (Dai et al., 2004; Hao et al., 2008; Liu et al., 2013). The isotopic reversal (i.e., δ13C-C2H6 < δ13C-CH4) was also observed in some gas samples from the Longwangmiao Formation (Wei et al., 2014, 2015). Therefore, we infer that the δ13C values of the initial ethane prior to TSR may be lighter than those of the methane in the Dengying Formation. No obvious increases in methane δ13C values were observed with increasing GSI in the natural gas in the Dengying Formation (Fig. 16A). This pattern distinctly differs from that in the gas in the Khuff and Feixianguan formations, where methane has reacted significantly during TSR and its δ13C values increase progressively with increasing GSI (Worden and Smalley, 1996; Cai et al., 2004, 2013; Hao et al., 2008, 2015; Liu et al., 2013). Therefore, methane has not reacted appreciably during the TSR process in the Dengying Formation. The S/C ratio and δ34S value of solid bitumen can also be used to reflect the extent of TSR (Cai et al., 2017). For the methane-dominated TSR in the Feixianguan Formation in the NE Sichuan Basin, the average S/C ratios and δ34S values of TCA-derived and TSR-altered bitumens are 0.022 and 7.7‰, and 0.059 and 17.4‰, respectively (Cai et al., 2017). The S/C ratio and δ34S value of bitumen increased by approximately 168% and 126%, respectively, as a result of TSR alteration.

However, solid bitumen in the Dengying Formation shows much lower increases in the S/C ratios and δ34S values (~90% and ~27%, respectively; Table 3) than that in the Feixianguan Formation. This result further indicates that bitumen in the Dengying Formation has experienced a lesser degree of TSR alteration. We conclude that the Dengying Formation has undergone a less advanced TSR (i.e., ethane-dominated TSR) and that the changes in carbon isotope composition of methane can be negligible. The δ13C values of methane vary from -36.7‰ to -32.0‰ (Zheng et al., 2014; Zhu et al., 2015; Wei et al., 2015; this study) and are similar to those of the bitumen in the same reservoir (-36.0‰~-34.4‰; Table 3). Thus, the δ13C values of the initial ethane were supposed to be lighter than those of the bitumen in the Dengying Formation. The 13

C-depleted ethane can be sulfurized via a back reaction with TSR-derived H2S to form

13

C-depleted ethanethiol during TSR. The resulting ethanethiol may be subsequently

incorporated into the bitumen through aromatization and polymerization, resulting in depletion of 13C in the TSR-altered bitumen relative to the TCA-derived bitumen (Fig. 9C) (Cai et al., 2017). Although some remaining ethane became isotopically heavier than bitumen as TSR proceeded (Tables 3 and 6), the amount of remaining ethane may have decreased exponentially with increasing concentrations of sour gas components (Fig. 15C). The contribution of the remaining 13C-enriched ethane to the carbon isotope composition of bitumen is possibly negligible. Consequently, the δ13C values of TSR-altered solid bitumen are negatively correlated with the S/C ratios (Fig. 9C). Solid bitumen in the Dengying and Longwangmiao formations can become

isotopically heavier during hydrothermal alteration (see discussion in Section 5.1.2) or isotopically lighter during TSR alteration (see discussion above). The carbon isotope composition of the sulfur-enriched, anisotropic bitumen samples may have been altered by both hydrothermal fluids and TSR (Table 3; Fig. 9C). As shown in Table 3, the TSR-altered solid bitumen in both reservoirs has been heated by hydrothermal fluids simultaneously, implying that TSR may be induced by hydrothermal activity. This is the likely reason why the TSR-altered bitumen samples have heavier δ13C values than the TCA-derived ones (i.e., GS11-14 and MX11-7) in the same reservoirs. The Dengying and Longwangmiao formations have experienced temperatures of up to approximately 220 oC (Fig. 3), which is more than sufficient for sulfate reduction of crude oil or natural gas (Krouse et al., 1988; Heydari and Moore, 1989; Worden et al., 1995; Cai et al., 2004; Worden and Smalley, 2004). If the reactive sulfate is available in the reservoirs, then bitumen without heating by hydrothermal fluids can be also altered by TSR in the high temperature environment. However, neither of the normally matured bitumen samples has experienced TSR alteration (Table 3). Therefore, we propose that hydrothermal fluids may provide not only the high temperature environment (Liu et al., 2016), but also the reactive sulfate to initiate TSR.

5.3. Source of reactive sulfate for TSR The reactive sulfate for TSR can be the dissolved sulfate (SO42-) derived from seawater, buried seawater, evaporative brines, and/or from dissolution of solid calcium

sulfate (primarily gypsum and anhydrite) (Machel, 2001). Most case studies of TSR have shown that the SO42- was primarily derived from anhydrite dissolution (Krouse et al., 1988; Worden and Smalley, 1996; Heydari, 1997; Cai et al., 2003, 2004; Zhu et al., 2011). However, evaporites were barely deposited in the Central Sichuan Basin during the Early Cambrian, as suggested by the geologic, logging, and seismic data (Lin et al., 2014; Xu et al., 2016). Anhydrite or gypsum was also rarely observed in either core or thin-section samples from the Dengying Formation in the study area. A small amount of anhydrite may exist in the micritic dolomites deposited in a low-energy lagoonal environment (Shan et al., 2016; Wang et al., 2016; Zhou et al., 2017). Nevertheless, the Dengying Formation has been significantly flushed by meteoric water during the Tongwan Movement (Li et al., 2014a). The flushing process probably has resulted in dissolution of anhydrite, as evidenced by the occurrence of anhydrite pseudocrystals in the dolomites (Chen et al., 2002; Shan et al., 2016). In addition, no SO42- was detected in any of the formation water samples from either the Dengying or Longwangmiao formation (Zhu et al., 2015). Therefore, it is necessary to identify the source of reactive sulfate for TSR in the Moxi-Gaoshiti gas field. Two possible sulfur sources are recognized as follows: (1) sulfate contained in hydrothermal fluids; and (2) CAS released during dolomitization.

5.3.1. Sulfate contained in hydrothermal fluids SEM examination revealed that some barite particles occur in the vesicles of solid

bitumen in the Dengying Formation (Fig. 5N) (Gao et al., 2017). Some bitumen samples have Ba concentrations of up to 2480 ppm (Gao et al., 2017), which is much greater than the average Ba concentration in the Earth's crust (~500 ppm; Fan et al., 1986). The significant enrichment of Ba in bitumen suggests that at least a portion of the Ba was not derived from the parent kerogen. As shown previously, some barite coexists with saddle dolomite in the Longwangmiao Formation (Fig. 5G and Q) and with fluorapatite in the Dengying Formation (Fig. 5M and S). Primary fluid inclusions in barite in the Longwangmiao Formation have homogenization temperatures of up to 240 oC (Zhang et al., in prep), which is significantly higher than the maximum burial temperature of the Longwangmiao Formation (<220 oC; Fig. 3). All these features indicate a hydrothermal origin of the barite. The Proterozoic basement in the Central Sichuan Basin is primarily composed of clastic and metamorphic rocks (Zhang et al., 2012b). Fan et al. (1986) found that such basement rocks in the Upper Yangtze Platform are highly enriched in Ba, with an average Ba concentration of 8848 ppm. We propose that the Ba in the hydrothermal barite may have been leached from the Proterozoic basement by hot brines and then transported into the Upper Ediacaran and Lower Cambrian reservoirs along deep-seated faults. Previous studies have shown that hydrothermal barite samples from the Upper Ediacaran and Lower Cambrian share a similar sulfur isotope composition (27.2‰~44.4‰ and 24.2‰~41.0‰, respectively; Table 5). Their δ34S values are also similar to those of the CAS in the Upper Ediacaran (primarily from ~20‰ to ~45‰; Zhang et al., 2003, 2004), indicating that the sulfur in the hydrothermal barite

may be derived from the Late Ediacaran seawater. However, the contribution of the Early Cambrian seawater to the formation of hydrothermal barite cannot be ruled out, as suggested by the δ34S values of CAS in the Longwangmiao Formation (24.6‰~26.8‰; Table 4). In addition, hydrothermal fluids can also precipitate a few other sulfate minerals, such as anhydrite. Gao et al. (2017) found some anhydrite coexisting with authigenic illite and solid bitumen in stylolite in the Dengying Formation (Fig. 5O). The anisotropic textures of solid bitumen suggest the occurrence of hydrothermal fluids in the stylolite, and the illite may be formed by recrystallization of insoluble clay residues in the hydrothermal environment (Gao et al., 2017). Thus, the anhydrite may be precipitated from hydrothermal fluids. This is also supported by the coexistence of anhydrite and hydrothermal minerals (including quartz and saddle dolomite) in dissolution pores in the Dengying Formation (Jiang et al., 2016). We conclude that hydrothermal fluids probably have transported some sulfate to the Dengying and Longwangmiao formations. Hydrothermal barite can act as a source of reactive sulfate for TSR, as evidenced by its replacement by the 34S-enriched pyrite (see discussion in Section 5.2.1). Moreover, the δ34S values of both TSR-altered solid bitumen and TSR-derived H2S are close to those of the hydrothermal barite in the Upper Ediacaran. A similar sulfur isotope pattern can be also observed in the Lower Cambrian (Fig. 14). Therefore, the isotopically enriched sulfur in the H2S and solid bitumen was probably derived from the barite in hydrothermal fluids; i.e., the hydrothermal sulfate dominated by barite is probably the

main source of reactive sulfate for TSR in the Moxi-Gaoshiti gas field. Although the Ediacaran and Cambrian hydrocarbon reservoirs have accessed sulfur from hydrothermal fluids, the total fluid system is believed to have remained essentially finite due to a limited duration of hydrothermal activity. This hypothetical closure of the sulfur system must, admittedly, have occurred at a very large scale to accommodate mass balance considerations. The heterogeneous Ba concentrations in solid bitumen (6~2480 ppm; Gao et al., 2017) and the occurrence of normally matured bitumen suggest that the hydrothermal fluids may have migrated within a restricted area. It is worth noting that one bitumen sample from the Dengying Formation was altered by hydrothermal fluids but not by TSR (i.e., MX23-23; Table 3). This finding indicates that the hot fluids may have contained a limited amount of sulfate. The sulfate must have been progressively depleted during the migration of hydrothermal fluids, because it can be removed from the fluids via precipitation as minerals (barite or anhydrite) or reduction by hydrocarbons. The limited sulfate availability in the hydrothermal fluids is probably the main reason why an advanced TSR (i.e., methane-dominated TSR) did not take place in the Dengying Formation (Fig. 16A and B). As discussed in Section 5.1.1, the Dengying and Longwangmiao formations may have experienced hydrothermal alteration associated with the eruption of Emeishan Flood Basalts during the Permian. The pre-existing isotropic bitumen has been rapidly heated by the hydrothermal fluids, resulting in the formation of anisotropic bitumen. As shown in Fig. 3, the temperatures of both reservoirs were generally less than 100 oC

during the Permian, and thus lower than the minimum temperatures of TSR (100~140 o

C; Machel, 2001). Therefore, the formation temperatures may not have been sufficient

to initiate TSR. Nevertheless, some fluid inclusions in the saddle dolomite and quartz have homogenization temperatures of up to 250 oC (Table 2), which is significantly higher than the initiation temperatures of TSR. These data imply that the hydrothermal fluids may have initiated TSR by providing the necessary high temperature environment (Liu et al., 2016). In conclusion, the hydrothermal fluids may have provided not only the initiation temperature, but also the reactive sulfate for TSR to proceed in the Dengying and Longwangmiao formations. Hydrothermal activity in the Upper Ediacaran was considered to be closely associated with the deep-seated wrench faults (Fig. 1B) (Feng et al., 2017). The Ediacaran reservoirs close to the wrench faults may have accessed more sulfate from hydrothermal fluids, and thus undergone a more advanced TSR than those far away from the faults. Therefore, the Ediacaran reservoirs characterized by elevated H2S concentrations may be spatially associated with the wrench faults. In order to predict TSR-related H2S concentrations in the Ediacaran reservoirs, it is thus important to understand the fault systems and tectonic evolution of the Central Sichuan Basin.

5.3.2. CAS source Limestone samples from the Dengying Formation in the Yichang section have CAS

concentrations ranging from 76 ppm to 549 ppm, with an average of 286.4 ppm (Zhang, 2003). The low-ordered dolomite formed during penecontemporaneous dolomitization in the Dengying Formation (Si et al., 2014; Wang et al., 2016) is expected to have higher CAS concentrations than the well-ordered limestone. This is because the Mg2+ in dolomite has a smaller radius than the Ca2+ in limestone, and thus can facilitate the incorporation of the tetrahedral SO42- into dolomite crystal lattices (Fichtner et al., 2017). Thereafter, the CAS concentrations in the Dengying Formation dolomites may have decreased linearly with increasing degrees of crystallographic order during burial diagenesis (Baldermann et al., 2015; Fichtner et al., 2017). For the Hauptdolomit Formation dolomites in the Eastern and Southern Alps, the average concentrations of CAS decreased linearly from 470 ppm in samples that experienced a burial temperature of 100 oC to values below analytical detection in samples subjected to burial temperatures of greater than 350 oC (Fichtner et al., 2017). The completely dolomitized Dengying Formation in the study area experienced a lower maximum burial temperature (~220oC; Fig. 3) than the Hauptdolomit Formation, and thus a small amount of CAS still remains in the Dengying Formation (35.6~208.1 ppm with an average of 93.4 ppm; Table 4). During burial dolomitization of the Dengying Formation, the migration of hydrothermal fluids enriched in Fe, Mn, and radiogenic

87

Sr has resulted in extensive

precipitation of saddle dolomite and significant alteration of dolomite reservoirs (Jiang et al., 2016; Feng et al., 2017; Peng et al., 2018). Hydrothermal fluids can facilitate the

recrystallization of matrix dolomite by providing a high temperature environment and CO2 (Zhu et al., 2010). Consequently, the recrystallized matrix dolomite generally has lighter δ18O values, higher 87Sr/86Sr ratios, and higher concentrations of Fe and Mn than the unaltered matrix dolomite. In particular, the former dolomite has a higher degree of crystallographic order than the latter (0.96 and 0.64, respectively; Jiang et al, 2016). Thus, a certain amount of CAS may have been released during the recrystallization of matrix dolomite associated with hydrothermal alteration (Baldermann et al., 2015; Fichtner et al., 2017). Our calculation shows that the CAS concentrations in the Dengying Formation decreased by approximately 67% during dolomitization (Table 4). The CAS released from the well-ordered dolomite may have been an alternative source of reactive sulfate for TSR (Wynn et al., 2010; Cai et al., 2010; Li et al., 2014b). It is worth noting that natural gas with elevated H2S concentrations (>5%) generally exists in the dolomite reservoirs in the Sichuan Basin (Cai et al., 2014; Li et al., 2016). This phenomenon further implies that at least a portion of the sulfate involved in TSR may have been derived from the regional dolomitization. On the other hand, the close association between dolomite reservoirs and elevated H2S concentrations may also be ascribed to the Mg2+ in formation water. The Mg2+ can contribute to the formation of MgSO4 contact-ion-pairs and then enhance TSR in the reservoir (Ma et al., 2008; Zhang et al., 2008, 2012a). A certain amount of Mg2+ probably has been transported into the Dengying Formation by hydrothermal fluids (Peng et al., 2018). The input of Mg2+ from hydrothermal fluids may have increased the concentrations of MgSO4 contact-ion-pairs

in the formation water. Consequently, TSR in the Dengying Formation may have been further accelerated by hydrothermal activity.

6. Conclusions (1) Two types of altered solid bitumen have been identified in both the Ediacaran Dengying and Cambrian Longwangmiao formations in the Central Sichuan Basin: one was altered by hydrothermal fluids (type 1) and the other altered by TSR (type 2). (2) The type 1 solid bitumen was probably formed at high temperatures of up to approximately 250 oC, and thus has various anisotropic textures with high bireflectance values between 3.89% and 9.21%. The hydrothermal alteration also led to 13

C-enrichment in the type 1 bitumen relative to the normally matured bitumen derived

from the same source. (3) H2S in the Dengying and Longwangmiao formations was generated via in situ TSR. Its δ34S values are heavier than those of the parent kerogen and close to the coeval seawater sulfate as represented by CAS in the same strata. In particular, ethane has been significantly involved in TSR in the Dengying Formation. (4) The type 2 solid bitumen has S/C atomic ratios of up to approximately 0.06. Its δ34S values are similar to or slightly heavier than those of the TSR-derived H2S in the same reservoirs. A strong negative correlation exists between S/C atomic ratios and δ13C values in the type 2 bitumen in the Dengying Formation, which may be attributed to an increasing incorporation of the 13C-depleted ethanethiol into the bitumen during TSR.

(5) The barite, a dominant hydrothermal sulfate, is probably the main source of reactive sulfate for TSR. The hydrothermal barite can be replaced by the

34

S-enriched

pyrite, and the δ34S values of both TSR-derived H2S and TSR-altered solid bitumen are close to those of the barite in the same strata. In addition, the CAS released during dolomitization can be an alternative source of reactive sulfate for TSR. (6) TSR in the Ediacaran and Cambrian hydrocarbon reservoirs was likely to have been initiated by hydrothermal activity. Prediction of H2S concentrations in the Ediacaran reservoirs demands a further understanding of the fault systems and tectonic evolution of the Central Sichuan Basin.

Acknowledgement The authors are very grateful to Editor Prof. Guochun Zhao, Dr. Clifford C. Walters, Dr. Dennis Jiang and one anonymous reviewer for their constructive comments and suggestions that greatly improved the manuscript. We also thank Southwest Oil & Gas Field Company, PetroChina for providing core and gas samples. This work was financially supported by National Key R&D Program of China (Grant No. 2017YFC0603106), Special Major Projects on Petroleum Study (Grant No. 2017ZX05008003-040), and Natural Science Foundation of China (Grant Nos. 41730424 and 41672143).

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Table captions

Table 1 Optical textures and rotational reflectance values of solid bitumen in the Dengying and Longwangmiao formations.

Table 2 Microthermometric results of fluid inclusions in the saddle dolomite and quartz in the Dengying Formation.

Table 3 Elemental compositions, stable isotope values, and alteration types of solid bitumen in the Dengying and Longwangmiao formations.

Table 4 Concentrations and sulfur isotope values of WSS and CAS in the limestones and dolomites.

Table 5 Sulfur isotope values of H2S, pyrite, and barite in the Upper Ediacaran and Lower Cambrian.

Table 6 Chemical and carbon isotopic compositions of natural gas in the Dengying Formation in the Moxi-Gaoshiti gas field.

Figure captions

Fig. 1. (A) Location and structural elements of the Sichuan Basin (modified after Zhai, 1992). (B) Locations of core and natural gas samples in the Moxi-Gaoshiti gas field (modified after Feng et al., 2017).

Fig. 2. Stratigraphic column showing source, reservoir, and cap rocks in the Ediacaran and Cambrian (modified after Zhu et al., 2015).

Fig. 3. Burial and thermal history of the Upper Ediacaran and Lower Cambrian in the Moxi-Gaoshiti gas field (modified after Zou et al., 2014).

Fig. 4. Photograghs showing dolomite, quartz, and solid bitumen in dissolution vugs and fractures. D1 – Matrix dolomite; D2 – Pore-filling dolomite; Qtz – Quartz; SB – Solid bitumen. (A) Dissolution pores and vugs in the algal dolomites in the Z2dn4, Well MX9, 5046.95 m; (B) Dissolution pores and vugs in the silt-sized dolomites in the Є1l, Well MX23, 4804.94 m; (C) Rhombohedral dolomite and prismatic quartz crystals in the dissolution vug in the Є1l, Well GS6, 4550.40 m; (D) Dolomite occurring as rhombohedral crystals in the fracture in the Z2dn4, Well GS20, 5194.33 m; (E) Rhombohedral dolomite and prismatic quartz crystals in the dissolution vug in the Z2dn4, Well GS20, 5209.39 m; (F) Dolomite, quartz, and solid bitumen coexisting in the dissolution vug in the Z2dn4, Well GS7, 5340.06 m.

Fig. 5. Photographs showing the occurrences and optical textures of solid bitumen, the replacement of hydrothermal barite by metal sulfides, and the associated SEM/EDS results. D1 – Matrix dolomite; D2 – Pore-filling dolomite (i.e., saddle dolomite); Qtz – Quartz; SB – Solid bitumen; Br – Barite; Py – Pyrite; Sp – Sphalerite. (A) Solid bitumen in the small dissolution pores in the Z2dn2, Well GS11, 5370.45 m, polarized light; (B) Solid bitumen coexisting with saddle dolomite in the fracture in the Z2dn4, Well GS18, 5135.14 m, cross-polarized light; (C) Solid bitumen coexisting with quartz in the

fracture in the Z2dn4, Well GS7, 5260.55 m, polarized light; (D) Solid bitumen with very fine-grained mosaic texture in the small dissolution pores in the Z2dn2, Well GS11, 5370.45 m, cross-polarized light; (E) Solid bitumen with coarse-grained to flow mosaic textures in the fracture in the Z2dn4, Well GS18, 5135.14 m, cross-polarized light; (F) Solid bitumen with deformed fibrous texture in the fracture in the Z2dn4, Well GS7, 5260.55 m, cross-polarized light; (G) Partial replacement of both saddle dolomite and barite by pyrite in the Є1l, Well MX39, 4920.75 m, cross-polarized light; (H) Partial replacement of lath-shaped barite by euhedral pyrite in the Є1l, Well MX39, 4920.75 m, cross-polarized light; (I) Partial replacement of barite by both pyrite and sphalerite in the Z2dn4, Well GS20, 5189.95 m, polarized light; (J) A cubic pyrite crystal partially replacing barite in the Є1l, Well MX39, 4920.75 m, SEM image. The red hollow squares P and Q represent the sites selected for EDS analysis and the resulting EDS curves are shown in photographs labeled with P and Q, respectively; (K) A cubic pyrite crystal coated with thin-laminated barite in the Z2dn4, Well GS20, 5189.95 m, SEM image; (L) A magnified SEM image of the thin-laminated barite shown in the (K). The corresponding EDS curve is shown in (R); (M) Granular fluorapatite in the Z2dn4, Well GS20, 5189.95 m, SEM image. The corresponding EDS curve is shown in (S); (N) Dumbbell-shaped barite in the vesicles of solid bitumen in the Z2dn4, Well AP1, 5048.00 m, SEM image (Gao et al., 2017); (O) Illite, anhydrite, and solid bitumen coexisting in the stylolite in the Z2dn2, Well GS2, 5390.29 m, SEM image (Gao et al., 2017); (P) An EDS result indicating pyrite (FeS2); (Q) An EDS result indicating barite (BaSO4); (R) An EDS result indicating barite with a small amount of fluorapatite and aluminosilicate minerals; (S) An EDS result indicating fluorapatite (Ca5F(PO4)3).

Fig. 6. Photographs showing fluid inclusions in the pore-filling saddle dolomite and quartz in the Dengying Formation. (A) Primary bitumen inclusions trapped along trails parallel to the quartz crystal boundaries in the Z2dn4, Well GS10, 5077.35 m, polarized light; (B) A reflected-light image of the bitumen inclusions shown in the (A); (C) Gas-liquid fluid inclusions in the saddle dolomite in the Z2dn4, Well GS7, 5293.16 m, polarized light; (D) Gas-liquid fluid inclusions in the quartz in the Z2dn4, Well GS7, 5286.74 m, polarized light; (E) Primary fluid inclusions occurring along trails

parallel to the quartz crystal boundaries in the Z2dn2, Well MX11, 5487.29 m, polarized light; (F) Methane and gas-liquid fluid inclusions in the quartz in the Z2dn4, Well GS10, 5077.35 m, polarized light.

Fig. 7. Photographs showing optical textures and associated rotational reflectance values of solid bitumen. (A) Solid bitumen with deformed fibrous texture in the Є1l, Well GS10, 4633.52~4633.62 m, polarized light. The red solid square B represents the site selected for rotational reflectance measurements and the resulting rotational reflectance curve is shown in photograph labeled with B; (B) Reflectance values (Rb, %) measured at site B when rotating the microscope stage through 360°; (C) Solid bitumen with isotropic texture in the Є1l, Well MX11, 4877.00~4877.17 m, polarized light; (D) Reflectance values (Rb, %) measured at site D when rotating the microscope stage through 360°; (E) Solid bitumen with granular and flow mosaic textures in the Z2dn4, Well MX9, 5033.37~5033.50 m, polarized light; (F) Reflectance values (Rb, %) measured at site F when rotating the microscope stage through 360°; (G) Solid bitumen with isotropic or very fine-grained mosaic texture in the Z2dn2, Well GS11, 5370.45 m, polarized light; (H) Reflectance values (Rb, %) measured at site H when rotating the microscope stage through 360°.

Fig. 8. Histogram of homogenization temperatures for fluid inclusions in the pore-filling saddle dolomite and quartz in the Dengying Formation.

Fig. 9. Plots of (A) δ34S, (B) N/Cat, and (C) δ13C versus S/Cat for solid bitumen in the Dengying and Longwangmiao formations.

Fig. 10. Plots of gas dryness (CH4/ΣCnH2n+2) and souring index (H2S/(H2S+ΣCnH2n+2)) versus depth for natural gas in the Dengying Formation. (A) Gas dryness versus depth; natural gas in both Moxi and Gaoshiti areas is extremely dry with dryness values greater than 99.85% and shows no relationship between dryness and depth; (B) Gas souring index versus depth; souring index values increase roughly with increasing depth for gas in the Moxi area, and gas in the Gaoshiti area has a

similar pattern, although with a less extreme sourness in the deep reservoirs.

Fig. 11. Plots of methane and ethane δ13C versus depth for natural gas in the Dengying Formation. (A) Methane δ13C versus depth; no obvious increases in methane δ13C value are observed with increasing depth; (B) Ethane δ13C versus depth; ethane δ13C values increase roughly with increasing depth.

Fig. 12. The maximum reflectance (Rbmax, %) versus the minimum reflectance (Rbmin, %) for solid bitumen in the Dengying and Longwangmiao formations (modified after Goodarzi et al., 1993).

Fig. 13. Carbon isotope versus average bireflectance for solid bitumen in the Dengying and Longwangmiao formations.

Fig. 14. The δ34S values of various sulfur species, including carbonate-associated sulfate (CAS), barite, kerogen, solid bitumen, pyrite, and H2S, in the Upper Ediacaran and Lower Cambrian.

Fig. 15. Comparison of different geochemical parameters for natural gas in the Dengying Formation. (A) Gas dryness (CH4/ΣCnH2n+2) versus souring index (H2S/(H2S+ΣCnH2n+2)); the sourest natural gas in the Gaoshiti area tends to be the driest, whereas there are no similar patterns for gas in the Moxi area; (B) ln(C1/C2) versus gas souring index; gas in the Gaoshiti area shows a positive correlation between ln(C1/C2) and souring index, whereas no similar patterns occur in gas in the Moxi area; (C) C2H6/CO2 versus acid gas concentration ((H2S+CO2)/(H2S+CO2+ΣCnH2n+2)); C2H6/CO2 ratios decrease exponentially with increasing acid gas concentrations for gas in both areas.

Fig. 16. Plots of methane and ethane δ13C versus gas souring index (H2S/(H2S+ΣCnH2n+2)) for natural gas in the Dengying Formation. (A) Methane δ13C versus gas souring index; no apparent increases in methane δ13C value are observed with increasing sourness; (B) Ethane δ13C versus gas

souring index; ethane δ13C values increase roughly with increasing sourness.

Fig. 1

Fig. 2

Fig. 3

Fig. 4

Fig. 5

Fig. 5 (continued)

Fig. 6

Fig. 7

Fig. 8

Fig. 9

Fig. 10

Fig. 11

Fig. 12

Fig. 13

Fig. 14

Fig. 15

Fig. 16

Table 1 Optical textures and rotational reflectance values of solid bitumen in the Dengying and Longwangmiao formations. Sample

A

Depth

Sampl

Ag

e no.

e

Solid bitumen no.

ge

Depth (m)

(m) R

R

mi

ma

Solid bitumen R

BR n

x

Optical texture

(% (

Optical texture

4633.52~

Deformed

1l

4633.62

fibrous texture

GS10-4

)

)

0.

6.

9. 6.2

GS7-2

Z2d

5260.55~5

Deformed

0.1

0

0

n4

260.64

fibrous texture

4

9

8

7

0.

6.

6

7

8

3

0.

7.

3

5

6

4

0.

6.

5

7

0

8

0.

7.

9. 0.3

2

5

5

0.

5.

9. 0.3

2

7

8

0.

5.

mosaic

4 9. 0.2

8

5

0.

6.

6

3

5

6

0.

4.

3 8. 0.3 2 8. GS205

Z2d n

4

5184.95~5

Coarse-grained

0.

5.

185.11

to

6

2

Є

4581.20~

Coarse-grained

0.

6.

9

0.3

8.0 3

texture

2

7 9 8.

1.5

6.6 2

2

8 0 7.

0.3

7.2 6

9

8 8 5.

1.1

4.8 9

6 MX13-

0 8.

flow mosaic

4.9 9

7.8 9

9

9

0.2 0

3.8 7

4 6

1

8

8.5 8

5.7

5

0 3

7

6

8.8 0

5.0 7

8 2

1

6

8.7 1

4.5 7

7 2

3

Coarse-grained

8.7 1

6.9 3

1 5

7

4

9.2 3

6.2

texture

)

)

9

1l

(%

%

7.1

8

(

%

5

4629.44

R

%

7

Є

x

(%)

6.0

MX12-

B

n

( )

Є

ma

Rmi

1

5 5

6.2

MX9-

Z2d

5033.37~5

Coarse-grained

0.2

6.

6.5

3

1l

4581.32

to

5

7

5

9

0.

6.

flow mosaic

4

10

n4

033.50

6

6

7

0.

6.

texture

6

0

0.

6.

6

5

texture

3

0.

6. 8

0

0

Є

0.

7.

Coarse-grained 4803.34

4

1l

4

3

8

0.

7.

to

9

3

6

2

0.

7.

texture

0.6

8

0

0

1

0.

7.

7. 0.1 2

9

0

0.

6.

7. MX23 -23

Z2d n

4

5214.76~5

Coarse-grained

214.88

to

1

8

5

Є 1l

4924.10~

0.

6.

4924.38

Coarse-grained 8

8

9

0.

6.

to

texture

9

1

4

0.

7.

texture

1

7

0.

7.

3

3

9

8.2 6

1

2 3 8.

0.4

7.8 2

8

0 8 8.

0.4

8.1 5

7

0 8 7.

MX944

Z2d n

2

5443.33~5

Coarse flow

0.3

6.9 3

443.44

mosaic

3

7 0 6.

0.2 texture

5.9 2

7

3 0 5.

6.6 0

9 8.

3

4

8.0

0.4

6.5 4

0.4 8

1

flow mosaic

5

5

6.4 4

1 8.

flow mosaic

7

MX26-

7.3 6

5.5 4

0.4 7

1

9

1 3

7.3 9

7.3 4

1

5

4 4

6.8 3

6.7 3

6

5

7 7.

5.8

6.8 4

6.2 5

5

flow mosaic

8

6

7.0 4

4 6.

0

MX23-

6.3

0.3

6.2 6

0.3 2

4

6

2

7

6.1 8

8

6. flow mosaic

1

6

9

1 5.9

7

to

0.1

5.2 4

6

8

4 3 8.

7.0

0.2

0

6

7.8 0 3

5

6

9

0.

7.

7.1

1.2

8.

7.6

3

4

6

1

8

8

MX11-

Є 1l

6

3.

4.

4877.00~

8 4. 0.3

Isotropic texture 7

0

9

2

3

4

3.

4.

4877.17

1

GS1114

Z2d n

2

4.2 5370.45

Isotropic to 9

1

6

3

3.

4.

very fine-grained

4

5

3.

4.

8

6

6

3.

4.

6

6

5

3.6

0.7 3

0

5 5 4.

3.5

0.9 5

0

7

Note: Rmax: the maximum rotational reflectance value of solid bitumen, %; Rmin: the minimum rotational reflectance value of solid bitumen, %; BR: bireflectance = Rmax  Rmin, %.

4 4.

0.3 2

0.5 5 9

0

9

4.0 texture

0.4 0

1 9 4.

1

6

1.5 6

mosaic 0.5

1

4. 3.1

7

6

1 0

0.1 9

0.4 7

7 4

Table 2 Microthermometric results of fluid inclusions in the saddle dolomite and quartz in the Dengying Formation. Well

Age

Depth

GS7

Z2dn4

GS7

Z2dn4

5286.74

Gas / liquid

Homogenization temperature (oC)

Host

Number of

Salinity (eq. wt.% NaCl)

(m)

mineral

samples

ratio

Range

Mean

Peak

Range

Mean

Peak

5293.16

Saddle dolomite

38

0.1 ± 0.05

108.0~262.0

179.7

180.0~190.0

6.5~21.0

13.0

9.0~11.0

Quartz

56

0.1 ± 0.05

120.0~215.0

170.9

180.0~190.0

3.4~23.1

18.7

18.0~21.0

230.0~330.0

262.3

240.0~250.0

13.9~23.1

19.5

18.0~21.0

Table 3 Elemental compositions, stable isotope values, and alteration types of solid bitumen in the Dengying and Longwangmiao formations. Sample no.

Age

Depth (m)

Solid bitumen δ34S (‰)

δ13C (‰)

S/Cat

N/Cat

TSR alteration

Hydrothermal alteration

24.5

-34.4

0.055

0.0042

Yes

Yes

-33.5

0.045

0.0065

Yes

Yes

GS10-4

Є1l

4633.52~4633.62

MX12-8

Є1l

4629.44

MX13-3

Є1l

4581.20~4581.32

22.3

-34.6

0.042

0.0067

Yes

Yes

MX23-4

Є1l

4803.34

27.5

-34.8

0.043

0.0046

Yes

Yes

MX26-1

Є1l

4910.30~4910.59

26.3

Yes

Yes

MX26-5

Є1l

4924.10~4924.38

26.2

-34.6

0.041

0.0062

Yes

Yes

MX32-15

Є1l

4668.99~4669.23

24.7

-34.9

0.041

0.0027

Yes

Yes

MX205-4

Є1l

4600.69

25.1

-35.1

0.045

0.0060

Yes

Yes

MX11-7

Є1l

4877.00~4877.17

12.5

-35.6

0.008

0.0060

No

No

GS7-20

Z2dn4

5260.55~5260.64

23.5

-35.2

0.031

0.0072

Yes

Yes

GS7-40

Z2dn4

5293.44~5293.51

23.9

-35.8

0.059

0.0067

Yes

Yes

GS18-2

Z2dn4

5135.14~5135.20

25.2

-35.3

0.034

0.0061

Yes

Yes

GS18-6

Z2dn4

5141.50

24.0

Yes

Yes

GS20-5

Z2dn4

5184.95~5185.11

22.7

Yes

Yes

GS20-15

Z2dn4

5196.71~5196.89

26.2

Yes

Yes

MX9-10

Z2dn4

5033.37~5033.50

20.5

-34.8

0.040

0.0080

Yes

Yes

MX9-11

Z2dn4

5045.93~5046.11

21.9

-35.0

0.038

0.0073

Yes

Yes

MX9-23

Z2dn3

5316.77~5316.81

-35.1

0.043

0.0069

Yes

Yes

MX9-29

Z2dn3

5318.47

20.2

-34.9

0.036

0.0067

Yes

Yes

MX9-44

Z2dn2

5443.33~5443.44

24.3

-35.6

0.046

0.0063

Yes

Yes

MX23-23

Z2dn4

5214.76~5214.88

-34.4

0.024

0.0057

No

Yes

GS11-14

Z2dn2

5370.45

-36.0

0.020

0.0066

No

No

18.6

Note: S/Cat: S/C atomic ratio; N/Cat: N/C atomic ratio.

-34.6

0.032

0.0055

Table 4 Concentrations and sulfur isotope values of WSS and CAS in the limestones and dolomites. Area

Sample no.

Age

Depth (m)

Lithology

WSS

CAS 34

Concentration (ppm) δ S (‰) Concentration (ppm) δ34S (‰) Moxi-Gaoshiti

MX13-8

Є1l

4587.5

Silt-sized Dolomite

413.3

16.8

gas field

MX13-10

Є1l

4590.6

Silt-sized Dolomite

431.5

16.4

14.2

24.6

MX13-18

Є1l

4629.5

Silt-sized Dolomite

427.2

16.9

17.5

26.8

GS18-3

Z2dn4

5139.4

Dolomicrite

516.0

18.3

63.8

30.1

GS18-15

Z2dn4

5209.0

Dolomicrite

472.2

17.8

66.1

36.1

MX11-16

Z2dn4

5138.0

Dolomicrite

503.6

18.7

GS20-27

Z2dn4

5223.9

Algal Dolomite

453.3

18.8

GK1-37

Z2dn

3

5179.6

Algal Dolomite

372.2

18.7

35.6

25.1

GK1-45

Z2dn3

5357.0

Argillaceous Dolomite

438.1

21.1

208.1

33.2

Y20*

Z2dn

Otc

Fine-grained Limestone

331.0

37.9

Y23*

Z2dn

Otc

Fine-grained Limestone

549.0

35.3

Y24*

Z2dn

Otc

Fine-grained Limestone

104.0

Y28*

Z2dn

Otc

Fine-grained Limestone

189.0

33.4

Y31*

Z2dn

Otc

Fine-grained Limestone

266.0

28.1

Y38*

Z2dn

Otc

Fine-grained Limestone

371.0

36.8

Y41*

Z2dn

Otc

Fine-grained Limestone

405.0

35.2

Y44*

Z2dn

Otc

Fine-grained Limestone

76.0

32.7

Yichang

Note: WSS: water-soluble sulfate; CAS: carbonate-associated sulfate; Otc: Outcrop; Data with * are from Zhang (2003).

Table 5 Sulfur isotope values of H2S, pyrite, and barite in the Upper Ediacaran and Lower Cambrian. Area

Sample no.

Age

Depth (m)

Sample feature

δ34S (‰)

Moxi-Gaoshiti gas field

MX13

Є1l

4575.5-4648.5

H2S

19.7

MX17

Є1l

4609.0-4673.0

H2S

21.6

MX201

Є1l

4547.0-4608.5

H2S

20.6

MX204

Є1l

4655.0-4685.0

H2S

20.4

GS2

Z2dn4

5023.0-5121.0

H2S

19.6

GS3

Z2dn4

5135.5-5365.5

H2S

21.5

GS105

Z2dn4

5206.0-5267.0

H2S

26.9

GS108

Z2dn4

5215.0-5246.0

H2S

26.2

GS109

Z2dn4

5628.0-5645.0

H2S

27.7

GS111

Z2dn4

5308.0-5367.0

H2S

28.2

MX105

Z2dn4

5299.0-5401.0

H2S

23.1

MX108

Z2dn4

5279.0-5315.5

H2S

25.1

MX39-3

Є1l

4920.8-4921.1

Pyrite

19.1

GS20-7

Z2dn4

5190.0-5190.1

Pyrite

19.4

XSD-B4*

Є1qx

Barite

31.6

XSD-B4*

Є1qx

Barite

31.4

XSD-B6*

Є1qx

Barite

31.1

Gong 1#

Є1n

Barite

41.0

Gong 2#

Є1n

Barite

40.5

Gong 3#

Є1n

Barite

35.9

Gong 4#

Є1n

Barite

39.1

Gong 6#

Є1n

Barite

24.2

Ba 8#

Є1n

Barite

38.0

Ba 8#

Є1n

Barite

33.0

Ba 9#

Є1n

Barite

36.2

Ba 16#

Є1n

Barite

37.4

Long 1#

Z2dn

Barite

41.5

Long 2#

Z2dn

Barite

44.4

Long 3#

Z2dn

Barite

36.6

Long 4#

Z2dn

Barite

38.0

Long 5#

Z2dn

Barite

39.4

Long 6#

Z2dn

Barite

37.4

Le 1+

Z2dn

Barite

27.2

Le 2+

Z2dn

Barite

27.5

Huayuan Pb-Zn deposit

Gongxi barite deposit

Lehong Pb-Zn deposit

Maozu Pb-Zn deposit Mao 2++ Z2dn Barite 30.4 Note: Є1qx: Lower Cambrian Qingxudong Formation; Є1n: Lower Cambrian Niutitang Formation; Data with * are from Duan (2014); Data with # are from Fan et al. (1986); Data with + are from Zhang (2008); Data with ++ are from Chen (2002).

Table 6 Chemical and carbon isotopic compositions of natural gas in the Dengying Formation in the Moxi-Gaoshiti gas field. Block

Well

Ag

Depth

Chemic

CH4/ΣCn

H2S/(H2S+Σ

δ13

e

(m)

al

H2n+2 (%)

CnH2n+2) (%)

C

compos

(

ition

‰

(%)

)

CH4

Moxi

MX

Z2d

5102-5

8*

n4

173

MX

Z2d

5149-5

11*

n4

208

MX

Z2d

5076-5

13*

n4

133

MX

Z2d

5063-5

17*

n4

152

MX

Z2d

5086-5

18*

n4

106

MX

Z2d

5299-5

105

n4

401

MX

Z2d

5279-5

108

n4

316

MX

Z2d

5422-5

8*

n2

459

MX

Z2d

5422-5

8*

n2

459

MX

Z2d

5424-5

92.16

93.47

90.53

91.93

92.67

90.51

91.23

91.34

90.54

92.60

C2H6

0.04

0.05

0.04

0.03

0.05

0.05

0.07

0.04

0.03

0.05

C3H8

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.01

0.00

0.00

83

H2

CO

N2

H2

He

CH

C2

S

2

4

H6

1.

5.9

0.

0.

0.0

99.

1.

04

0

81

00

50

96

12

2.

4.1

0.

0.

0.0

99.

2.

09

8

17

02

30

95

19

0.

7.4

0.

0.

0.0

99.

0.

91

7

99

02

30

96

99

1.

5.3

1.

0.

0.0

99.

1.

00

8

59

02

40

96

08

1.

4.8

0.

0.

0.0

99.

1.

59

1

83

01

30

95

69

1.

6.6

1.

0.

0.0

99.

1.

-32

66

1

07

00

15

94

80

.3

0.

6.3

1.

0.

0.0

99.

0.

-35

-27

68

2

48

00

00

92

74

.0

.3

1.

7.3

0.

0.

0.0

99.

1.

06

1

18

01

50

95

15

1.

7.4

0.

0.

0.0

99.

1.

00

5

91

01

60

97

09

3.

4.1

0.

0.

0.0

99.

3.

Gaoshiti

9*

n2

460

MX

Z2d

5424-5

9*

n2

460

MX

Z2d

5424-5

9*

n2

460

MX

Z2d

5445-5

11*

n2

486

MX

Z2d

5445-5

11*

n2

486

MX

Z2d

5380-5

17*

n2

410

MX

Z2d

5371-5

18*

n2

410

GS2

Z2d

5023-5

n4

121

GS2

Z2d

5193-5

*

n4

238

GS3

Z2d

5136-5

n4

366

GS3

Z2d

5155-5

*

n4

366

GS6

Z2d

4986-5

*

n4

132

GS6

Z2d

5200-5

*

n4

221

GS7

Z2d

5091-5

*

n4

345

GS9

Z2d

5090-5

92.33

92.54

90.49

90.02

91.69

90.62

90.57

92.21

90.36

91.68

91.34

90.93

92.99

90.41

0.05

0.05

0.03

0.03

0.07

0.04

0.05

0.04

0.05

0.04

0.04

0.04

0.04

0.04

0.00

0.00

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.01

0.01

0.01

0.00

84

02

3

17

01

30

95

16

3.

4.1

0.

0.

0.0

99.

3.

18

2

29

01

30

95

33

3.

4.0

0.

0.

0.0

99.

3.

17

4

16

01

40

95

31

0.

7.0

1.

0.

0.0

99.

1.

91

5

45

00

50

96

00

0.

7.6

1.

0.

0.0

99.

1.

94

5

29

00

50

97

03

2.

4.3

1.

0.

0.0

99.

2.

52

2

31

04

50

92

67

0.

6.3

2.

0.

0.0

99.

0.

66

3

26

00

90

96

72

0.

6.5

1.

1.

0.0

99.

0.

-32

-31

23

6

08

41

18

95

25

.2

.9

1.

6.6

0.

0.

0.0

99.

1.

10

0

02

02

20

96

18

1.

5.8

1.

0.

0.0

99.

1.

-32

78

6

69

00

13

95

93

.6

1.

6.5

0.

0.

0.0

99.

1.

58

5

13

00

20

96

69

1.

7.3

0.

0.

0.0

99.

1.

04

9

15

01

30

95

13

1.

7.9

0.

0.

0.0

99.

1.

00

1

09

00

30

95

09

1.

5.3

0.

0.

0.0

99.

1.

18

6

39

00

30

95

25

0.

7.7

0.

0.

0.0

99.

0.

*

n4

188

GS1

Z2d

5246-5

1*

n4

278

GS1

Z2d

5117-5

8*

n4

206

GS1

Z2d

5206-5

05

n4

267

GS1

Z2d

5215-5

08

n4

246

GS1

Z2d

5628-5

09

n4

645

GS1

Z2d

5308-5

11

n4

367

GS3

Z2d

5783-5

*

n2

810

GS1

Z2d

5403-5

0*

n2

431

91.42

91.74

88.31

90.25

91.31

61.64

85.33

91.21

0.04

0.04

0.09

0.05

0.10

0.08

0.03

0.04

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.01

Note: Data with * are from the Research Institute of Petroleu m Explorati

85

88

7

85

01

30

96

96

0.

6.0

1.

0.

0.0

99.

0.

77

9

61

01

50

95

83

0.

6.7

0.

0.

0.0

99.

0.

65

0

83

00

40

96

70

0.

9.2

2.

0.

0.0

99.

0.

-33

-28

10

5

00

00

00

90

11

.2

.4

0.

6.7

2.

0.

0.0

99.

0.

-33

-27

00

7

55

00

00

95

00

.9

.8

0.

7.1

1.

0.

0.0

99.

0.

-33

-29

00

8

33

00

00

89

00

.6

.0

0.

34.

3.

0.

0.0

99.

0.

-33

-30

00

86

32

00

00

88

00

.8

.4

2.

6.2

5.

0.

0.0

99.

2.

45

1

92

01

50

96

79

1.

6.8

0.

0.

0.0

99.

1.

05

5

76

00

80

95

14

on and Develop ment, PetroChi na Southwe st Oil & Gas Field Compan y.

86

Highlights: Two types of altered solid bitumen are recognized in the Ediacaran and Cambrian Hydrothermal alteration led to 13C-enrichment in the anisotropic bitumen TSR-altered bitumen shows a negative correlation between δ13C values and S/C ratios TSR was initiated by hydrothermal fluids with reactive sulfate dominated by barite

87