Biomarkers and C and S Isotopes of the Permian to Triassic Solid Bitumen and Its Potential Source Rocks in NE Sichuan Basin.
Natural gases from the Upper Permian Changxing ([P.sub.3]ch) to Lower Triassic Feixianguan Formation ([T.sub.1]f) from northern Sichuan Basin are associated with abundant solid bitumen and are thus considered to have been derived from oil cracking in the reservoirs. The solid bitumen and associated gases may have mainly derived from Upper Permian Longtan Formation based on correlation of biomarkers and [delta][sup.13]C values of the source rocks and solid bitumen (pyrobitumen) in reservoirs [1-4]. However, the conclusion may not be effective, based on the consideration of the following two aspects.
Thermochemical sulfate reduction (TSR), redox reactions between petroleum and sulfates in deeply buried reservoirs, is concluded to occur in this area [5-7] and results in alteration in the solid bitumen . TSR is found to result in negative shift in [delta][sup.13]C values  (Machel et al., 1995) and positive shift in [delta][sup.34]S due to incorporation of [sup.12]C-rich alkanes and [sup.34]S-rich TSR sulfides [8, 10-14] (Cai et al., 2001); thus, [delta][sup.13]C and [delta] [sup.34]S values can be used as effective tools for oil-source rock correlation only where there has been little or no TSR and oil generation occurred at a closed or semiclosed system in which the source rock was rapidly buried during the period [13-16]. In such a burial environment with oil cracking to solid bitumen and the associated gas, the solid bitumen and its parent kerogen are expected to have similar [delta][sup.13]C and [delta][sup.34]S values; thus it is possible to use [delta][sup.13]C and [delta][sup.34]S values for the purpose of the correlation between source rock and solid bitumen and consequently to determine the source rock for the gases.
On the other hand, natural gases in eastern gas fields show significant differences in chemical composition and [delta][sup.13]C values from those in western gas fields (Cai et al., 2011) [18-20]. The geochemical features are found to have been controlled by kerogen type and/or maturity [21,22], and thus, the two-side gases were proposed, although not proven, to have been derived from different source rocks (Cai et al., 2011). If so, significant differences in geochemical features in the associated solid bitumen are expected.
In this study, solid bitumen from the Upper Permian and Lower Triassic and source rocks from the Lower Cambrian, Lower Silurian, and Upper Permian were analyzed for molecular composition and [delta][sup.13]C and [delta][sup.34]S values. The specific objectives of this study are to determine (1) if any differences exist in molecular composition between western and eastern solid bitumen; (2) what the differences among potential source rocks of different ages are; and (3) from which source rock the solid bitumen and the associated gases were likely derived.
2. Geological Setting
Commercial natural gas is being produced from the Lower Permian Changxing Formation and Upper Triassic Feixianguan Formation in MB, PG, LJ, and Po gas fields in the east and HB, YB, and LG gas fields in the west, of the northern Sichuan Basin, southwestern China (Figure 1(a)). The geological setting has been published in Cai et al. , Cai et al. (2014), Ma et al. , and Jin et al. . It is a late Mesozoic-Cenozoic foreland basin overlying an Ediacaran-Middle Mesozoic passive margin. The basement framework of the basin was established during the Chengjiang tectonic movement (about 750 Ma) with western and eastern lows of ductile basement separated by a central uplift of brittle lithologies. A major marine transgression occurred during early Ediacaran with the deposition of Doushantuo Formation mudstone and shale and Dengying Formation dolostone and cherty dolostone. A second major marine transgression resulted in the deposition of open-to restricted-marine facies shale, siltstone, limestone, and dolostone during the Cambrian. A third marine transgression during the Early Ordovician to the Early Silurian resulted in the widespread deposition of black shales in an open marine environment. Marine sedimentation was interrupted during the late Silurian Caledonian Orogenywhen the Sichuan Basin was uplifted and exposed, resulting in minimal Devonian deposition. Middle Carboniferous sedimentation was limited to the eastern part of the Sichuan Basin. Following the Caledonian Orogeny, marine transgression occurred during the earliest Permian. The Lower Permian is composed of platform carbonates with a typical thickness of 300-500 m. Submarine basalt eruption occurred at the end of the Lower Permian. The Upper Permian Longtan Formation is composed of platform carbonates with alternating marine and terrestrial coal bearing mudstone and marlstone (Figure 1(c)). During the Changxing period of the latest Permian, a rapid basement subsidence took place mainly in the Kaijiang and Liangping areas (Wei et al., 2004), resulting in the Kaijiang-Liangping Trough separating a semi-isolated evaporated carbonate platform to the east from a large, shallow, carbonate platform to the west during the period from the Changxing to the Feixianguan (Early Triassic) (Figure 1(b)). Lower Triassic Feixianguan Fm is considered to deposit in a range of environments from basinal through a narrow slope to open platform and evaporated platform environments. The Upper Permian Changxing Formation reefal dolostone and the Lower Triassic Feixianguan Formation shelf and platform-margin shoal oolitic dolostone are the main reservoirs. As a result of the Yinzi Orogeny between the Middle and Upper Triassic, the Sichuan Basin was uplifted and exposed. Upper Triassic to Cretaceous sediments are composed of freshwater lacustrine-alluvial clastics with local coal beds with thickness of 2000-5000 m.
The potential source rocks of paleo-oils for the gases and the associated solid bitumen include Lower Cambrian black shale ([Cam.sub.1]), Lower Silurian Longmaxi Fm ([S.sub.1]l) mudstone and shale, Upper Permian Longtan Fm ([P.sub.3]l) or isochronous Wujiaping Fm ([P.sub.3]w) mudstone, shale, and marlstone, and Upper Permian Dalong Fm ([P.sub.3]d) or isochronous Changxing Fm ([P.sub.3]ch) shale and mudstone [24-26]. Organic matter in these source rocks is primarily type I sapropelic and [II.sub.1] humic-sapropelic kerogens and exhibits similar biomarker composition but different [delta][sup.13]C values [1-3].
Upper Permian Dalong Fm or Changxing Fm source rocks are dark gray, gray black carbonaceous shale, calcareous mudstone, siliceous mudstone, and silicates with a thickness up to 30 m and TOC up to 13.5% . These source rocks have a limited distribution and occur along the Guangyuan-Wangcang Trough, the Kaijiang-Liangping Trough, and the Chengkou-Exi Trough. The source rocks have bitumen reflectance ([R.sub.b]) of 4.4% or [R.sub.0] equivalent ([ER.sub.o]) of 3.1% in well HB1 ([ER.sub.o] = 0.618[R.sub.h] + 0.40)  and [R.sub.n] from 1.4% to 2.2% (or [ER.sub.o] of 1.3 to 1.8%) in the Wanyuan area. Organic matter in the Changjianggou section at Guangyuan shows much lower maturity with [R.sub.b] of 0.69% or [ER.sub.o] of 0.8% [17, 27].
Upper Permian Longtan ([P.sub.3]l) Fm source rocks include gas-prone marine-terrigenous transitional facies black shale, mudstone, and laminar coal seams in the middle and southern part of NE Sichuan Basin [8, 23, 28, 29] and deep water shelf facies oil-prone source rocks in the Bazhong-Dazhou depression in the northern Sichuan Basin such as in wells HB1, MB3, and PG5 [4, 29]. The source rocks in the Bazhong-Dazhou area were measured to have TOC from 0.6 to 10.8% with an average of 2.06% (n = 53) and thickness from 40 m to 140 m with the maximum of 160 m in MB, PG, and DU gas fields . [R.sub.b] for the marlstone was measured to have an average of 4.3% (n = 5) or [ER.sub.o] of 3.1% .
Lower Silurian Longmaxi Fm ([S.sub.1]l) mudstone and shale have total organic carbon values (TOC) up to 6.5% and are approximately 105 m thick with TOC > 1.0% in the Shizhu area in the southeast of the gas fields . It is 55 m thick in the Wuxi area east of the gas fields . The source rocks have [R.sub.b] values from 4.2% to 4.9% or [ER.sub.o] from 3.0% to 3.4% at Shizhu. Source rocks with higher TOC were deposited in anoxic deep water shelf during the deposition of lower Longmaxi Fm Subsequently, the environment becomes shallower during the period of middle and upper Longmaxi with lower TOC .
Lower Cambrian black shale and mudstone have cumulative thickness of 180 m to 200 m, 20 m to 100 m of which are sediments with TOC > 1% in the Shatan-Nangjiang area. Toward the east around the Wuxi area, the thickness increases to 150 m to 180 m . The depositional environment was changed from a shallow inner shelf to deep shelf. [ER.sub.o] calculated from [R.sub.b] for the organic matter is higher than 2.5% (Liang and Chen, 2005) .
3.1. Samples. Twenty-one outcrop source rock samples were collected from Ludu, Guanzi, Tongjiang, Huayingshan, Zhenba, and Wangyuan in the north Sichuan. Seven source rock samples were taken from well-cuttings in Huayingshan and the HB and YB gas fields (Figure 1). The twenty-eight samples represent potential source rocks for the gas and solid bitumen in the NE Sichuan gas fields, of which twelve were measured for [R.sub.b] or [R.sub.0], twenty-two for biomarker composition using GC-MS, ten for Rock Eval pyrolysis, and nine for pyrite sulfur isotopes.
Twenty bitumen samples were obtained from the Lower Triassic Feixianguan Fm ([T.sub.1]f) and Upper Permian Changxing Fm ([P.sub.3]ch) from MB, PG, LJ, Du, Po, YA, and TD gas fields in the east to the PG gas field and YB, LG, and HB gas fields in the west to the PG gas field, northern Sichuan Basin (Figure 1), and were analyzed for biomarker composition using GC-MS. Among these samples, three in association with [H.sub.2]S < 0.5% in gas composition were analyzed for carbon isotopes.
3.2. Analytical Methods
3.2.1. Biological Markers. About 120 g source rock samples were powered for 3 minutes using a grinding machine and then Soxhlet extracted using dichloromethane (DCM) for 72 hours. Source rock extracts were weighed and then deasphalted using a 40x excess of hexane. All of the deasphalted samples were fractionated on a silica: alumina column chromatography using n-pentane, dichloromethane (DCM), and methanol as developing solvents to yield the saturated, aromatic, resin (NSO) fraction, respectively. The saturated and aromatic hydrocarbon fractions were analyzed separately using a Hewlett Packard 6890GC/5973MSD-mass spectrometer. The gas chromatograph (GC) was fitted with a HP-5MS capillary column (30 m x 0.25 mm x 0.25 [micro]m). The temperature of sample injection was 300[degrees]C and the oven was held at 50[degrees]C for 1min. The temperature was then increased from 50[degrees]C to 310[degrees]C at a rate of 3[degrees]C/min and then held at 310[degrees]C for 18 min. Helium was used as a carrier gas (1.0 mL/min). Operating conditions were ion source, 230[degrees]C; emission current, 34.6 [micro]A; quadruple temperature, 150[degrees]C; and electron energy, 70 eV.
Identification of aryl isoprenoids was achieved through analysis of mass spectra, retention time, and comparison with literature data [33-36].
3.2.2. Vitrinite and Bitumen Reflectance Measurement. Vitrinite and bitumen reflectance were measured on MPV-III microphotometer 12213 using the Chinese standard SY/T5124-1995. The values are reported using an average of more than 15 measurements.
3.2.3. Pyrite [delta][sup.34]S Measurement. Pyrite sulfur was released from mudstones or shales by adding a mixture of hot 6 N HCl and Cr[Cl.sub.2] under [N.sub.2] with a gas flow carrying the [H.sub.2]S to a trap where it was recovered as [Ag.sub.2]S. The [Ag.sub.2]S precipitate was analyzed for S-isotope at the Institute of Geology and Geophysics, Chinese Academy of Sciences (IGGCAS), on a Finnigan Delta S gas source mass spectrometer. Sulfur isotope results are generally reproducible within [+ or -] 0.3[per thousand].
3.2.4. Separation and [delta][sup.13]C and [delta][sup.34]S Measurement of Kerogen and Solid Bitumen. The methods for separation and [delta][sup.34]S measurement of kerogen and solid bitumen were reported previously . Fresh rock samples were finely ground and treated with hot 6 N HCl, a mixture of 6 N HCl and 40% HF, and then 6N HCl, to dissolve minerals. Pyrite was further removed from the remaining kerogen or solid bitumen by adding a mixture of hot 6 N HCl and Cr[Cl.sub.2] under [N.sub.2] with a gas flow carrying the [H.sub.2]S to a trap where it was recovered as [Ag.sub.2]S. After dilution with distilled water and centrifugation, the remaining solid bitumen or kerogen was separated from the residue (precipitate) using heavy liquids (KBr + ZnBr) with density of 1.8 to 1.9 g/[cm.sup.3] and of 2.0 to 2.1 g/[cm.sup.3], respectively. The residual kerogen and solid bitumen were collected and reground to expose new pyrite surfaces and the whole procedure was repeated once more. After the two treatments, the residual kerogen or solid bitumen was further analyzed using X-ray diffraction (XRD) to determine whether pyrite was below the detection limits ([less than or equal to] 0.5% depending on conditions). If not, additional treatments were made.
For organic carbon analysis, about 5 mg dry kerogen or solid bitumen was combusted at 850[degrees]C to collect C[O.sub.2]. Isotope ratio measurements were carried out with a Thermo Delta S mass spectrometer, calibrated with a series of IAEA standards (IAEA-600, [delta][sup.13]C = -27.771[per thousand], VPDB). Results are presented as [delta][sup.13]C values relative to the VPDB standard. The reproducibility for measurement was [+ or -] 0.2[per thousand].
For organic sulfur analysis, about 350 to 900 mg dry kerogen or solid bitumen was combusted in a Parr bomb at ca. 25 atm [O.sub.2] to oxidize organically bound sulfide to sulfate. Dissolved sulfate was precipitated as BaS[O.sub.4]. This procedure was done only when the residual kerogen samples contained pyrite sulfur/total sulfur < 0.08. The maximum amount of pyrite present after the chromium reduction was determined by measuring the dissolved iron at pH < 2 using an atomic absorption spectrometer (assuming that all Fe occurs as pyrite in the kerogen). This process guarantees that the BaS[O.sub.4] analyzed for [delta][sup.34]S mostly reflects the organic sulfur in the kerogen, with the absolute error depending on the difference in [delta][sup.34]S value between the kerogen and associated pyrite. BaS[O.sub.4] was directly decomposed to [SO.sub.2] by heating at 1700[degrees]C in a quartz tube for isotopic analysis using the method of Bailey and Smith . Isotopic determinations were carried out on a Thermo Delta S mass spectrometer by comparing with an internal standard SA1 ([delta][sup.34]S = 15.15[per thousand], VPDB) and calibrated by a series of IAEA standards. Results are presented as [delta][sup.34]S relative to the Vienna Canyon Diablo Troilite (VCDT). The reproducibility for [delta][sup.34]S measurement is [+ or -] 0.3[per thousand].
4.1. Vitrinite or Bitumen Reflectance, Rock Eval Pyrolysis, and EOM/TOC Ratios of the Potential Source Rocks. The Cambrian shales have [R.sub.b] about 4.2% or equivalent vitrinite reflectance ([ER.sub.o]) of 3.0% (n = 2) ([ER.sub.o] = 0.618 [R.sub.b] + 0.40; ), the Lower Silurian and Upper Ordovician have [R.sub.b] from 2.0 to 2.9% or [ER.sub.o] of 1.6% to 2.2% (n = 6), and the lowest [R.sub.b] occurs in the Upper Permian Dalong Fm chert (Table 1). The Upper Permian Longtan Fm and Dalong Fm yielded vitrinite reflectance values of about 1.7% (n = 4). [ER.sub.o] and [R.sub.b] values show decrease toward younger strata. The results are similar to those from Fu et al. .
Based on Rock Eval pyrolysis [T.sub.max] and hydrogen index (HI) relationship , Upper Permian Dalong Fm mudstone and shale are oil-prone kerogen ranging from marginally mature, with [T.sub.max] from about 430[degrees]C and HI from 120 to 300 mg HC/g ToC for samples CJ43 and CJ36, to highly mature with [T.sub.max] from 467[degrees]C to 540[degrees]C and HI of 4 to 52 mg HC/g TOC for four other samples (Table 2). The organic matter from Upper Permian Wujiaping Fm, Lower Silurian Longmaxi Fm, and Lower Cambrian shales is overmature and has Tmax of about 603[degrees]C and HI less than 10 mg HC/g TOC. This feature is consistent with the very low S1 values or free hydrocarbons contents from 0.01 to 0.04 mg HC/g rock for the samples (Table 2).
Extracted organic matter (EOM) from the black mudstone and shale ranges from 19 to 622 ppm (n = 19), and EOM/TOC ratios range from 0.03% to 1.67% (n = 18) (Table 3). All the Silurian, Ordovician, and Cambrian samples show EOM/TOC less than 0.8% and the Upper Permian samples show much higher values.
4.2. Potential Source Rock Biomarkers. Organic matter extracted from Lower Silurian Longmaxi Fm, Upper Permian Longtan Fm, and Dalong Fm source rocks shows very similar distributions of 191 and 217 traces, including abundant gammacerane, and "V" shape in the distribution of [C.sub.27]-[C.sub.29] regular steranes (Figure 2). The high percentages of [C.sub.29] steranes detected from the Silurian and Cambrian are attributed to algae such as benthic brown algae or macro algae, acritarchs, cryptospores, and arthropods, rather than a terrestrial origin ( and references therein). The majority ofthe analyzed samples show [C.sub.29]/[C.sub.30] 17[alpha], 21[beta]-hopane ratio < 0.8 and [C.sub.23] tricyclic terpane/[C.sub.30] 17[alpha], 21[beta]-hopane ratio < 0.3 (Table 3).
Among maturity-related parameters, [C.sub.29] [alpha][alpha][alpha] sterane 20S/(20S + 20R) ratios range from 0.47 to 0.58 (Table 3), being mostly close to the equilibrium value of 0.55, suggesting that the source rocks are mature to overmature, commensurate with the [R.sub.0] or [R.sub.b] values. Ts/(Ts + Tm) ratios range from 0.30 to 0.52 and [C.sub.29]Ts/([C.sub.29]Ts + [C.sub.29]H) from 0.11 to 0.30. Similar case was reported from the Cambrian overmature source rocks in the Tarim Basin with Ts/(Ts + Tm) ratios from 0.21 to 0.49 (n = 12; [15, 39]; (Li et al., 2010)); thus other factors such as lithology, Eh, and pH during the deposition besides maturity may have effects on these ratios [15, 39, 40].
There exist no significant differences in part of biological precursor- and/or environment- related parameters for the four suites of the source rocks. The analyzed samples have Pr/Ph ratios from 0.53 to 1.17, and [C.sub.35]/[C.sub.34] hopane ratios are mainly greater than 0.5, indicating reduced depositional environments. All analyzed samples have [C.sub.24] tetracyclic terpane/[C.sub.26] tricyclic terpane ratio < 0.7 and [C.sub.29]/[C.sub.30] hopane ratio < 0.8. The values are consistent with shale/mudstone rather than carbonate depositional environments . The analyzed samples have [summation][C.sub.27]-[C.sub.29] regular steranes/[summation][C.sub.29]-[C.sub.33] 17[alpha]-hopanes ratios from 0.33 to 0.85 and gammacerane/[C.sub.30] 17[alpha], 21[beta]-hopane ratios from 0.12 to 0.37 with slightly higher values in P3l source rocks (Table 3). Compared with other suites of the source rocks, P3d source rocks show relatively high [C.sub.27]/[summation][C.sub.27]-[C.sub.29] regular steranes ratios (Table 3).
Interestingly, [P.sub.3]l source rock sample 10-VI-16 shows significantly higher [summation][C.sub.27]-[C.sub.29] regular steranes/[summation][C.sub.29]-[C.sub.33] 17[alpha]-hopanes ratios and lower [[delta].sub.13] C values of kerogen than four other [P.sub.3]l source rock samples from the same well 10-VI (Tables 1 and 4).
A pseudo homologous series of aryl isoprenoids were revealed from mass chromatograms of m/z 133 in the Upper Permian Dalong Fm and some Silurian source rocks (samples HYS-6, HYS-8, HYS-11, and TJ-7-104, but not from Guanba, Shiniulan, and ZB21, Figure 3 and Table 1). The major components possess the 2, 3, 6-trimethyl substituted pattern with a predominance of [C.sub.16]-[C.sub.24] homologues. The aryl isoprenoids were considered to result from aromatic carotenoids of the green sulfur bacteria (Chlorobiaceae) [33-35, 42, 43]. However, a North Sea oil has been found to have aryl isoprenoids derived from mixtures of C-C bond cleavage of isorenieratanes and [beta]-isorenieratanes derived from aromatisation of [beta]-carotene; thus green sulfur bacteria Chlorobiaceae are not the unique source of the aryl isoprenoids . No aryl isoprenoids were detected in the samples analyzed from the Cambrian and Upper Permian Longtan Fm.
4.3. Molecular Composition of Extractable Organic Matter of Solid Bitumen. Organic matter extracted from Feixianguan Fm and Changxing Fm solid bitumen from wells HB101 and YB101 in western gas fields and wells TD10 and Du4 in eastern gas fields and PL-37 outcrop yield highly similar distribution in 191 and 217 traces, including abundant gammacerane and "V" shape in the distribution of [C.sub.27]-[C.sub.29] regular steranes (Figure 4; Table 4). Organic matter extracted from solid bitumen samples has C29 [alpha][alpha][alpha] sterane 20S/(20S + 20R) ratios from 0.50 to 0.58 (Table 4), being close to the equilibrium value. The samples have Ts/(Ts + Tm) ratios from 0.47 to 0.59 and [C.sub.29]Ts/([C.sub.29]Ts + [C.sub.29]H) from 0.25 to 0.31. The bitumen samples have Pr/Ph ratios from 0.41 to 0.88 and [C.sub.27] [alpha][alpha][alpha] 20R sterane > [C.sub.28] [alpha][alpha][alpha] 20R < [C.sub.29] [alpha][alpha][alpha] 20R (Table 4). All the values of the parameters are similar to most of the source rocks analyzed except the bitumen from wells LG11, LJ2, HL5 (sample HL5-4), and PG2 (sample PG2-3) showing higher [C.sub.35]/[C.sub.34] hopane ratios (>1.0).
Interestingly, [C.sub.16]-[C.sub.23] aryl isoprenoids were detected from extracts from solid bitumen from wells HB101, LG82, and YB101 in the western gas fields (Figure 5). No aryl isoprenoids were detected from the solid bitumen from wells in the east, such as TD10, YA1, TS5, PG11, and MB4.
4.4. Potential Source Rock Kerogen and Pyrite [delta][sup.34]S Values and Their Changing Trend. A pyrite from Lower Cambrian black shale was measured to have [delta][sup.34] S value of 13.5[per thousand]. The value is heavier than those of two pyrite samples from Upper Ordovician Wufeng Fm and Lower Silurian Longmaxi Fm mudstone and shale with [[delta].sub.4]S value of -3.2[per thousand] and -4.3[per thousand], respectively (Table 1). A much lighter [delta][sup.34] S value of-14.8[per thousand] was measured from Longtan Formation mudstone pyrite and the lightest values from -21.3[per thousand] to -34.5[per thousand] (n = 4) were measured with an average of -27.5[per thousand] in the Dalong Formation mudstone pyrites. That is, the pyrite [delta][sup.34]S values show negative shift from early Cambrian to the latest Permian. The changing trend is similar to the kerogen [[delta].sub.34]S values from 3.5[per thousand] to 14.5[per thousand] (n = 2) in the Lower Cambrian, -4.4[per thousand] to 15.9[per thousand] (n = 8) with an average of 5.0[per thousand] in the Upper Ordovician and Lower Silurian, -6.6[per thousand] to 4.1[per thousand] with an average of -0.45[per thousand] in the Upper Permian Longtan Formation, and -30.6[per thousand] to 5.5[per thousand] (n = 4) with an average of -14.5[per thousand] in the Upper Permian Dalong Formation in the Lu, Wangyuan, Guanzi, and CJG outcrops.
4.5. Solid Bitumen [delta][sup.13]C and [delta][sup.34]S Values. Three solid bitumen samples from wells LG82, LG11, and HB101 in the western gas fields were associated with [H.sub.2]S < 0.5% in gas composition and were measured to have [delta]13C values from -25.1 to -26.7[per thousand] (n = 3). The values are similar to the two previously reported values of -26.5 and -27.3[per thousand] (Table 5). The [delta][sup.13]C values are within the range of the [P.sub.3]d and [P.sub.3]l kerogens and significantly heavier than the O3w and [S.sub.1]l kerogens and the Cambrian kerogens (Figure 6(a)). The two kerogen samples have [delta][sup.34]S values of 9.6[per thousand] and 5.8[per thousand], which are close to the heavier values of the [P.sub.3]d kerogens and the [P.sub.3]w and [P.sub.3]1 kerogens (Figure 6(b)).
5.t. Source Rock Depositional Environment: Kerogen [delta][sup.34]S Values and Aryl Isoprenoids. Samples from the Cambrian, Silurian, and Upper Permian Longtan Fm with [R.sub.0] higher than 1.7% yield very low EOM/TOC and [S.sub.1] (Tables 1 and 3). Saturated biomarkers and aryl isoprenoids were detected at correspondingly low levels. An obvious question to be addressed is whether the EOM within these overmature samples is syngenetic, migrated petroleum, or contaminants. Although it is impossible to prove that these compounds are syngenetic, their occurrence and distributions are consistent with other observations. Aryl isoprenoids have been detected in the Tarim Basin from the Cambrian overmature anoxic source rocks and highly mature oils derived from these sources, although their concentrations and carbon number decrease with increasing maturity [13, 15, 16, 42, 45]. The NE Sichuan Basin study area is similar to the Tarim Basin in that both are characterized by rapid burial [6, 8, 12, 23]; thus, some molecular markers in the study area may be related to the deposition environment and/or OM sources although it is hard to be proved.
The occurrence of aryl isoprenoids in the Lower Silurian Longmaxi Fm and Upper Permian Dalong Fm alone is not enough to indicate the presence of green sulfur bacteria in the photic zone anoxic water column during the deposition . However, elevated gammacerane/[C.sub.30] 17[alpha], 21[beta]-hopane ratios (Table 2), which have been used to infer marine stratification during source rock deposition , and [delta][sup.34]S values as light as -34.5[per thousand] in the Upper Permian Dalong Fm pyrite are consistent with the distribution of aryl isoprenoids, indicating that green and purple sulfur bacteria may have been thriving in stratified euxinic environment. Green and purple sulfur bacteria are capable of recycling of [H.sub.2]S generated by bacterial sulfate reduction, resulting in the generation of isotopically light intermediate valence sulfur species (e.g., elemental sulfur) or even of oxidized sulfate. This elemental sulfur or sulfate in turn maybe reduced to even lighter [H.sub.2]S by subsequent bacterial sulfate reduction . Subsequently, the isotopically light [H.sub.2]S was precipitated mainly as pyrite with very light [delta][sup.34][S.sub.py] values of -32.6[per thousand] and -34.5[per thousand] in Dalong Fm shales GZ17 and GZ18, respectively. The differences in [delta][sup.34]S values between sulfate and pyrite are up to 48.5[per thousand] as found in the GZ18 shale (assuming that late Permian seawater has a [delta][sup.34]S of 14[per thousand]; ). Small amounts of isotopically light [H.sub.2]S may have been incorporated into labile organic matter in water columns and sediment/water boundary with formation time overlapping with pyrite precipitation . Most of the organic sulfur may have been formed during early diagenesis in sediments, a relatively closed system to sulfate supply, and thus possess significantly heavier <?34S values than the associated pyrite ( and references therein). Kerogen samples have [delta][sup.34]S values from -30.6[per thousand] to 15.9[per thousand] and, except a Cambrian sample ZB19, are from 4[per thousand] to 27[per thousand] heavier than the coexisting pyrite (Table 1). Alternatively, the [sup.34S] enrichment may have resulted from equilibrium isotope fractionation during the incorporation of polysulfides  or bacteriogenic sulfide , in which aqueous [[S.sub.x].sup.2-] species have been shown to be [sup.34]S enriched by a value between about 3[per thousand] and 6[per thousand] at equilibrium compared with coexisting H[S.sup.-].
The pyrite and organic sulfur from euxinic environment as recorded in samples GZ17 and GZ18 show lighter sulfur isotopes than from noneuxinic environment from overlying Longtan Fm (samples 10-VI-40 and 10-VI-56) at the Huayinshan area. This result is consistent with Engel and Zumberge (2007) who showed that oils derived from kerogens deposited from euxinic environment have significantly lighter [delta][sup.34]S values than those derived from noneuxinic source rocks.
Aryl isoprenoids were detected from the Lower Silurian shale samples HYS-6, HYS-8, HYS-11, and TJ-7-104, but not samples Guanba, Shiniulan, and ZB21. These samples show similar maturity; thus, it is less likely for the OM maturity to control the occurrence of aryl isoprenoids. Instead, the distribution may result from euxinic environment or aromatisation of carotenoid [beta]-carotene . It is hard to determine which one is the origin for the Lower Silurian aryl isoprenoids without analyses of carbon or sulfur isotopic composition. The Lower Silurian shales do not show significantly lighter kerogen [delta][sup.34]S values than shales without the distribution of aryl isoprenoids in the Lower Silurian (Table 1). These features are different from the [P.sub.3]d euxinic source rocks with very light sulfur isotopic composition. However, isotopically heavy organic sulfur was reported from euxinic basins across the Frasnian-Famennian boundary in the Kowala-Holy Cross Mountains, Poland  and during the Early Cambrian in the Tarim Basin , where organic sulfur is proposed to have been formed in sediments without significant amounts of [H.sub.2]S contributed from the overlying water columns. Therefore, the euxinic environment for the Lower Silurian shales cannot be ruled out. The shales are characterized by uncommon bioturbation, occasional planar lamination, and abundant graptolites but low diversity of fossils , suggesting that it was deposited in a restricted and anoxic even euxinic environment .
5.2. Correlation of Solid Bitumen with Kerogen Based on [delta][sup.13]C Values and Biomarkers. In the study area, rapid sedimentation and burial occurred during the Late Permian to the Middle Cretaceous when the peak oils were expected to generate from the Cambrian, Silurian, and Upper Permian and the oils in reservoirs were cracked to gas and solid bitumen; thus, the generation and cracking of the oils are expected to occur in semiclosed or closed systems where the thermal processes may have no significant carbon and sulfur isotope fractionation; that is, kerogen and its final cracking product, solid bitumen, may have similar [delta][sup.13]C and [delta][sup.34]S values .
Solid bitumen which was not altered by TSR as indicated by the associated [H.sub.2]S < 0.5% has [delta][sup.13]C values of -26.5[per thousand] and -27.3[per thousand](Table 5). These values are within the range from -26.8[per thousand] to -27.8[per thousand] for the [P.sub.3]l kerogen samples in the Bazhong-Dazhou depression, but different from those for P3l samples from well 10-VI at Huayinshan area, and [P.sub.3]d source rock (Table 1, Figure 6). Unfortunately, no source rocks from the Bazhong-Dazhou depression have been analyzed for molecular composition to distinguish the two suites of [P.sub.3]l source rocks with different [delta][sup.13]C values in this study. However, sample 10-VI-16 source rock has a [delta][sup.13]C value of -28.1[per thousand] close to source rocks in the Bazhong-Dazhou depression and shows that [C.sub.27]-[C.sub.29] steranes were dominated by [C.sub.27] sterane and [C.sub.27]-[C.sub.29] sterane/[C.sub.29]-[C.sub.33] hopane ratio (of 0.85) higher than other samples (<0.65) from well 10-VI with heavier [[delta].sup.3]C values (Table 3). These characteristics indicate that organic matter in the sample 10-VI-16 is contributed more from marine planktonic algae including dinoflagellates, chrysophytes, and diatoms (Volkman, 1986)  and less from terrigenous plant inputs.
In contrast, [P.sub.3]l source rock samples from well 10-VI in the Huayingshan area (except sample 10-VI-16) have [C.sub.27]-[C.sub.29] steranes dominated by [C.sub.29] sterane, a lower sterane/hopane ratio (<0.70), and [delta][sup.13]C values 2[per thousand] to 5[per thousand] heavier than those in the Bazhong-Dazhou depression. Here, terrigenous plant input may have been significant. The Cambrian and Silurian source rock samples have [delta][sup.13]C values from -1.3[per thousand] to -5.5[per thousand] lighter than the non-TSR-altered solid bitumen. The significant differences between the source rock and the solid bitumen suggest that these samples are less likely to have been parent source rocks for the solid bitumen, assuming that the kerogen and subsequent oil cracking occurred in relatively closed system and no significant fractionation occurred during the cracking.
In summary, the non-TSR altered solid bitumen may have been derived from the P3l/P3w oil-prone kerogen or sapropelic-dominated source rocks in the Bazhong-Dazhou depression based on [delta][sup.13]C values and biomarkers, supporting the conclusions made by Borjigen et al.  and Jin et al. .
5.3. Correlation of Solid Bitumen with Kerogen Based on Aryl Isoprenoid Distribution and [delta][sup.34]S Values. Aryl isoprenoids, molecular indicators of photic zone euxinia or aromatisation of carotenoid [beta]-carotene, were detected in several Dalong Fm (P3d) and Lower Silurian source rocks. The P3d source rocks with aryl isoprenoids have [delta][sup.34][S.sub.kero] as low as -31[per thousand], while the Lower Silurian source rocks showvariable [delta][sup.34][S.sub.kero] values. No aryl isoprenoids were detected from the analyzed solid bitumen in the eastern gas fields suggesting that the precursor oils of the eastern solid bitumen are unlikely derived from the Dalong Fm ([P.sub.3]d) or the Lower Silurian source rocks. In contrast, part of the [P.sub.3]l/[P.sub.3]w source rocks have [delta][sup.34][S.sub.kero] values from 0.1[per thousand] to 4.1[per thousand], which are close to those of the solid bitumen with values as low as 5.8[per thousand] (Table 2). These source rocks show no detectable aryl isoprenoids. Thus, the source rocks can be correlated with the solid bitumen in the eastern gas fields. In contrast, aryl isoprenoids have been detected from the solid bitumen in wells HB101, YB101, and LG82 in the western gas field (Figure 5). The precursor oil for this solid bitumen may have source rocks different from those in the east, or at least may have precracking oils mixed with oils derived from other source rocks containing aryl isoprenoids. Because the western solid bitumen shows [[delta].sup.3]C values from -27.3 to -25.1[per thousand] and [delta][sup.34]S value of 5.8[per thousand] (Table 5), which are significantly different from the P3d source rock but within the range of the [S.sub.1]l kerogen isotopic composition (-28.7 to -30.8[per thousand] for [delta][sup.13]C and -4.4 to 15.9[per thousand] for [delta][sup.34]S, Table 1), thus, a significant contribution from the [S.sub.1]l but not [P.sub.3]d source rock can be concluded although limited data are available. This proposal is supported by the low maturity for the [P.sub.3]d source rock in the west with [R.sub.o] of 0.8%. The low maturity indicates that it is unlikely for the oil derived from the P3d source rock to have been cracked to gas and solid bitumen as found in the western gas fields.
Potential source rocks for Upper Permian and Lower Triassic solid bitumen in NE Sichuan Basin show significant differences in maturity, C and S isotopic compositions, and depositional environment with Lower Silurian ([S.sub.1]l) and Upper Permian Dalong Formation (P3d) source rocks containing aryl isoprenoids. Oils from the [S.sub.1]l (and less likely from P3d due to lower maturity) source rocks may have migrated to the western gas fields but not to the east, which was followed by second phase of emplacement of oils from the Upper Permian Longtan Formation ([P.sub.3]l) to both western and eastern gas fields. Subsequently, the oils were cracked to solid bitumen and natural gases, resulting in significant differences in the chemical and carbon isotopic compositions in the western and eastern natural gases (Cai et al., 2011) [19, 20] and aryl isoprenoids occurrence only in the western solid bitumen but not in the east. This case-study tentatively shows that [delta][sup.13]C and [delta][sup.34]S values along with biomarkers have the potential to be used for the purpose of solid bitumen and source rock correlation in a rapidly buried basin. More work should be done to confirm it.
Conflicts of Interest
The authors declare that they have no conflicts of interest.
This work is financially supported by China National Funds for Distinguished Young Scientists (Grant no. 41125009) and NSFC Grant no. 41672143.
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Chunfang Cai, (1, 2, 3) Chenlu Xu, (2) Wenxiang He, (1) Chunming Zhang, (1) and Hongxia Li (2)
(1) Key Laboratory of Exploration Technologies for Oil and Gas Resources of Ministry of Education, Yangtze University, Wuhan, Hubei 430100, China
(2) Key Laboratory of Petroleum Resources Research, Institute of Geology and Geophysics, Chinese Academy of Sciences, Beijing 100029, China
(3) College of Earth Sciences, University of Chinese Academy of Sciences, Beijing 100049, China
Correspondence should be addressed to Chunfang Cai; caLcf@mail.iggcas.ac.cn
Received 16 February 2017; Revised 22 April 2017; Accepted 11 June 2017; Published 13 August 2017
Academic Editor: Timothy S. Collett
Caption: FIGURE 1: Diagrams showing (a) location of major gas fields, (b) period, and (c) generalized stratigraphy. Possible source rock and reservoir intervals are marked. (Modified from Hu et al. (2014) .) distribution of sediment facies during the Changxing-Feixianguan deposition period, and (c) generalized stratigraphy. Possible source rock and reservoir intervals are marked. (Modified from Hu et al. (2014) .)
Caption: FIGURE 2: Partial GC-MS chromatograms (m/z =191 and 217) for extractable organic matter from the Upper Permian DalongFm (LD-7) and Longtan Fm (10-VI-16,10-VI-40), Lower Silurian (HYS-06), and Lower Cambrian (TJ-7-153) (28/3 is C28 tricyclic terpane and M is moretane; see note in Table 3 for other abbreviations).
Caption: FIGURE 3: GC-MS selected ion mass chromatograms (m/z 134) for extractable organic matter from source rocks from Lower Silurian (HYS-6, HYS-8, HYS-11, and TJ-07-104) and Upper Permian (GZ18 and LD-7) showing abundant aryl isoprenoids.
Caption: FIGURE 4: Partial GC-MS chromatograms (m/z = 191) for extractable organic matter from solid bitumen samples.
Caption: FIGURE 5: GC-MS selected ion mass chromatograms (m/z 134) for extractable organic matter from solid bitumen from western gas fields (wells YB101, HB101, and LG82) and eastern gas fields (wells TD10, YA1, TS5, PG11, and MB4). Abundant aryl isoprenoids are found to occur in wells in the west not in the east.
Caption: FIGURE 6: (a) Comparison of [delta][sup.13]C values and (b) cross-plot of [delta][sup.13]C and [delta][sup.34]S values, from non-TSR altered solid bitumen and different source rocks. Note: SR is source rock in short.
TABLE 1: Potential source rock TOC and aryl isoprenoids (AI), its kerogen vitrinite reflectance [R.sub.0], and S/C atomic ratio and [delta][sup.34]S values. [[delta].sup.13]C and values. Area Sample Age Depth (m) Lithology number Tongjiang TJ7-60 Cam. Otc Black shale TJ7-153 Cam. Otc Black shale Wanyuan ZB19 Cam. Otc Black shale Huayinshan HYS-3 [O.sub.3]w Otc Siliceous shale HYS-6 [S.sub.1]l Otc Black shale HYS-8 [S.sub.1]l Otc Black shale HYS-11 [S.sub.1]l Otc Black shale Guanba Guanba [S.sub.1] Otc Black shale Shiniulan Shiniulan [S.sub.1] Otc Black shale Chengkou ZB21 [S.sub.1]l Otc Black shale Tongjiang TJ7-104 [S.sub.1]l Otc Black shale HB HB1 [P.sub.3]l 5662~5713 Black mudstone PG PG5 [P.sub.3]l 5586~5747 Mudstone PG5 [P.sub.3]l 4891~5157 Cal. mudstone JX JX1 [P.sub.3]l 4727~4763 Cal. mudstone YB YB3 [P.sub.3]l 7123~7203 Cal. mudstone Zhenba ZB-09-01 [P.sub.3]l Otc Black limestone Huayinshan 10-VI-4 [P.sub.3]l 333.5 Black mudstone 10-VI-16 [P.sub.3]l 363.5 Black mudstone 10-VI-30 [P.sub.3]l 413.8 Black mudstone 10-VI-40 [P.sub.3]l 446.3 Black mudstone 10-VI-56 [P.sub.3]l 482.6 Black mudstone Ludu LDI-7 [P.sub.3]d Otc Black mudstone Zhenba ZB14-1 [P.sub.3]d Otc Black chert Wangyuan ZB17-3 [P.sub.3]d Otc Black shale Guanzi GZ17 [P.sub.3]d Otc Black shale GZ18 [P.sub.3]d Otc Black shale CJG CJ43 [P.sub.3]d Otc Black shale Area Sample [TOC.sup.a] [R.sub.b] AI number (%) /[ER.sub.o](%) Tongjiang TJ7-60 2.17 4.2/3.0 X TJ7-153 2.35 4.3/3.1 X Wanyuan ZB19 5.26 -- X Huayinshan HYS-3 2.63 2.0/1.6 X HYS-6 8.72 2.1/1.7 [check] HYS-8 1.96 -- [check] HYS-11 1.99 -- [check] Guanba Guanba -- -- X Shiniulan Shiniulan -- -- X Chengkou ZB21 -- 2.9/2.2 X Tongjiang TJ7-104 -- 2.8/2.1 [check] HB HB1 1.5 -- -- PG PG5 -- -- -- PG5 -- -- -- JX JX1 -- -- -- YB YB3 -- -- -- Zhenba ZB-09-01 1.21 -- -- Huayinshan 10-VI-4 3.11 /1.7 X 10-VI-16 1.26 -- X 10-VI-30 1.96 /1.7 X 10-VI-40 2.46 -- X 10-VI-56 4.33 /1.7 X Ludu LDI-7 4.83 -- [check] Zhenba ZB14-1 7.20 2.2/1.8 X Wangyuan ZB17-3 3.59 /1.8 X Guanzi GZ17 -- -- [check] GZ18 -- -- [check] CJG CJ43 0.33 0.7/0.8 [check] Area Sample [delta][sup.13] [delta][sup.34] number C (a) [S.sub.ke] (a) Tongjiang TJ7-60 -- -- TJ7-153 -31.9 3.5 Wanyuan ZB19 -30.7 14.5 Huayinshan HYS-3 -30.0 7.5 HYS-6 -28.7 15.9 HYS-8 -29.1 -0.4 HYS-11 -29.5 5.3 Guanba Guanba -- 7.2 Shiniulan Shiniulan -- 6.8 Chengkou ZB21 -29.7 -4.4 Tongjiang TJ7-104 -30.8 1.9 HB HB1 -27.8 26.7 PG PG5 -27.5 * -- PG5 -27.6 * -- JX JX1 -27.0 * -- YB YB3 -26.8 -- Zhenba ZB-09-01 -27.6 0.1 Huayinshan 10-VI-4 -24.2 -- 10-VI-16 -28.1 4.1 10-VI-30 -23.2 -- 10-VI-40 -23.0 0.6 10-VI-56 -22.7 -6.6 Ludu LDI-7 -27.1 -- Zhenba ZB14-1 -26.5 -1.7 Wangyuan ZB17-3 -26.4 5.5 Guanzi GZ17 -272 -27.1 GZ18 -26.5 30.6 CJG CJ43 -272 -- Area Sample [delta][sup.34] number [S.sub.py] Tongjiang TJ7-60 TJ7-153 -- Wanyuan ZB19 13.5 Huayinshan HYS-3 -3.2 HYS-6 -- HYS-8 -- HYS-11 -- Guanba Guanba -- Shiniulan Shiniulan -4.3 Chengkou ZB21 -3.9 Tongjiang TJ7-104 -- HB HB1 -- PG PG5 -- PG5 -- JX JX1 -- YB YB3 -- Zhenba ZB-09-01 -- Huayinshan 10-VI-4 -- 10-VI-16 -- 10-VI-30 -- 10-VI-40 -- 10-VI-56 -14.8 Ludu LDI-7 -- Zhenba ZB14-1 -21.3 Wangyuan ZB17-3 -21.4 Guanzi GZ17 -32.6 GZ18 -34.5 CJG CJ43 -- --: no data available; (a) from Cai et al. ; (*) from Borjigen et al. ; X: no; [check]: yes. [delta][sup.34][S.sub.ke] and calcareous; CJG: Changjianggou; equivalent vitrinite reflectance [[delta.sup.34][S.sub.py]: kerogen and pyrite [delta][sup.34]S; cal.: [ER.sub.0] = 0.618 [R.sub.b] + 0.40 . TABLE 2: Rock Eval pyrolysis data of the potential source rocks. Sample Age [S.sub.1] [S.sub.2] number (mg/g) /(mg/g) ZB-19 Cam 0.01 0.04 ZB-21 [S.sub.1]1 0.04 0.33 ZB-09-01 [P.sub.3]w 0.02 0.09 GZ-15 [P.sub.3]w 0.04 1.33 ZB-14-01 [P.sub.3]d 0.26 2.30 ZB-17-03 [P.sub.3]d 0.21 1.81 LD-7 [P.sub.3]d 0.01 0.21 LD-10 [P.sub.3]d 0.02 0.12 CJ-36 [P.sub.3]d 0.14 14.02 CJ-43 [P.sub.3]d 0.06 0.98 Sample [S.sub.1]/([S.sub.1] [S.sub.1] [T.sub.max] number + [S.sub.2]) + [S.sub.2] ([degrees]C) ZB-19 0.20 0.05 605 ZB-21 0.11 0.37 603 ZB-09-01 0.18 0.11 605 GZ-15 0.03 0.03 603 ZB-14-01 0.10 2.56 477 ZB-17-03 0.10 2.02 469 LD-7 0.05 0.22 540 LD-10 0.14 0.14 530 CJ-36 0.01 0.01 436 CJ-43 0.06 0.06 429 Sample [S.sub.3] TOC (%) HI OI number (mg/g) ZB-19 0.15 5.3 0.76 2.9 ZB-21 0.16 6.0 5.5 2.7 ZB-09-01 0.49 1.2 7.4 40 GZ-15 0.44 15.7 8.5 2.8 ZB-14-01 0.35 7.2 32 4.9 ZB-17-03 0.14 3.6 50 3.9 LD-7 -- 4.8 4.3 -- LD-10 -- 2.3 52 -- CJ-36 6.00 11.1 126 54 CJ-43 0.20 0.33 297 61 [T.sub.max]: temperature of maximum of S2 peak; S1: liquid hydrocarbon potential; S2: residual petroleum potential; PI: production index [S.sub.1]/([S.sub.1] +[S.sub.2]); HI: hydrogen index, in mg HC/g TOC; OI: oxygen index, in mg HC/g TOC. TABLE 3: Biomarker parameters of potential source rocks from the NE Sichuan Basin. Sample Strata EOM ppm EOM/ Pr/Ph Pr/n number TOC (%) [C.sub.17] TJ7-153 E1 86 0.37 0.72 0.85 TJ7-58 E1 19 0.08 1.03 0.77 ZB-19 E1 56 0.11 0.96 0.63 HYS-3 [O.sub.3w] 46 0.17 0.75 0.59 HYS-6 [S.sub.1] 23 0.03 0.63 0.79 HYS-8 [S.sub.1] 91 0.46 0.79 0.87 HYS-11 [S.sub.1] 76 0.56 0.90 0.86 TJ7-104 [S.sub.1] 84 -- 0.80 0.83 ZB-21 [S.sub.1] 214 0.36 1.03 0.91 10-IV-4 [P.sub.3]1 517 1.66 0.53 0.60 10-IV-30 [P.sub.3]1 127 0.65 0.55 0.70 10-IV-40 [P.sub.3]1 139 0.57. 0.67 0.68 10-IV-56 [P.sub.3]1 71 0.16 0.59 0.48 10- IV-16 [P.sub.3]1 73 0.58 0.92 0.60 HYS-7-161 [P.sub.3]1 622 1.67 0.70 0.57 ZB-09-01 [P.sub.3]w 106 0.87 0.80 0.72 ZB14-1 [P.sub.3]d 181 0.25 0.93 0.75 ZB 17-3 [P.sub.3]d 394 1.09 1.17 0.53 LD7 [P.sub.3]d 68 0.14 0.68 0.99 CJ43 [P.sub.3]d -- -- 0.87 0.91 GZ17 [P.sub.3]d -- -- 0.59 0.66 GZ18-1 [P.sub.3]d -- -- 0.61 0.60 Sample Ph/n Gm/ [C.sub.27] [C.sub.28] number [C.sub.18] [C.sub.30]H 20R% 20R% TJ7-153 0.68 0.22 35.49 30.05 TJ7-58 0.79 0.22 32.96 30.87 ZB-19 0.7 0.19 32.39 23.58 HYS-3 0.90 0.21 32.72 30.94 HYS-6 0.89 0.19 37.10 28.00 HYS-8 0.85 0.18 36.93 29.48 HYS-11 0.94 0.20 36.72 29.22 TJ7-104 0.90 0.18 36.04 29.98 ZB-21 0.88 0.12 33.93 25.56 10-IV-4 0.80 0.35 30.36 29.08 10-IV-30 0.92 0.27 35.49 28.26 10-IV-40 0.91 0.29 33.60 31.17 10-IV-56 0.66 0.20 34.14 27.20 10- IV-16 0.53 0.26 36.58 29.04 HYS-7-161 0.66 0.20 31.45 28.85 ZB-09-01 0.60 0.30 29.42 28.41 ZB14-1 0.76 0.17 32.78 28.85 ZB 17-3 0.53 0.18 37.91 29.68 LD7 1.01 0.19 34.96 31.78 CJ43 0.71 0.37 28.09 29.87 GZ17 0.73 0.15 40.70 30.37 GZ18-1 0.75 0.12 41.29 29.62 Sample [C.sub.29] [C.sub.24]Te [C.sub.23]TT [C.sub.21]TT number 20R% /[C.sub.26]TT /[C.sub.30]H /[C.sub.23]TT TJ7-153 34.46 0.52 0.23 0.68 TJ7-58 36.17 0.69 0.67 0.95 ZB-19 44.03 2.14 0.10 0.90 HYS-3 36.34 0.63 0.85 1.65 HYS-6 34.89 0.57 0.27 0.63 HYS-8 33.59 0.57 0.28 0.71 HYS-11 34.06 0.54 0.26 0.67 TJ7-104 33.97 0.57 0.28 0.69 ZB-21 40.50 0.52 0.27 0.93 10-IV-4 40.57 0.38 0.18 0.94 10-IV-30 36.24 0.50 0.21 0.76 10-IV-40 35.23 0.47 0.21 0.72 10-IV-56 38.66 0.53 0.25 0.62 10- IV-16 34.39 0.57 0.31 0.63 HYS-7-161 38.37 0.62 0.55 1.64 ZB-09-01 42.17 0.54 0.12 1.09 ZB14-1 38.37 0.62 0.75 1.18 ZB 17-3 32.41 0.34 1.14 1.04 LD7 34.26 0.54 0.28 0.65 CJ43 42.02 0.41 0.18 0.87 GZ17 28.93 0.53 0.25 0.79 GZ18-1 29.09 0.54 0.26 0.75 Sample [C.sub.29]S [C.sub.29]H [C.sub.35] Ts number /(S + R) /[C.sub.30]H /[C.sub.34] /(Ts + Tm) TJ7-153 0.54 0.53 0.73 0.49 TJ7-58 0.52 0.50 0.84 0.50 ZB-19 0.50 1.11 1.01 0.30 HYS-3 0.51 0.50 0.00 0.52 HYS-6 0.52 0.54 0.69 0.50 HYS-8 0.52 0.54 0.69 0.49 HYS-11 0.54 0.54 0.63 0.49 TJ7-104 0.53 0.55 0.63 0.48 ZB-21 0.56 0.76 0.86 0.43 10-IV-4 0.55 0.52 1.04 0.52 10-IV-30 0.53 0.52 0.77 0.51 10-IV-40 0.52 0.55 0.85 0.51 10-IV-56 0.52 0.53 0.49 0.49 10- IV-16 0.53 0.55 0.48 0.48 HYS-7-161 0.51 0.49 0.49 0.49 ZB-09-01 0.49 0.42 0.84 0.45 ZB14-1 0.47 0.53 0.48 0.48 ZB 17-3 0.49 0.49 0.49 0.49 LD7 0.58 0.53 0.67 0.45 CJ43 0.51 0.53 0.71 0.53 GZ17 0.50 0.50 0.57 0.50 GZ18-1 0.51 0.53 0.59 0.51 Sample [C.sub.27-29]St [C.sub.23]Ts/([C.sub.29]Ts number /[C.sub.29-33]H +[C.sub.29]H) TJ7-153 0.66 0.27 TJ7-58 0.49 0.26 ZB-19 0.30 0.11 HYS-3 0.46 0.26 HYS-6 0.66 0.27 HYS-8 0.75 0.26 HYS-11 0.71 0.29 TJ7-104 0.81 0.26 ZB-21 0.39 0.22 10-IV-4 0.33 0.30 10-IV-30 0.48 0.30 10-IV-40 0.56 0.27 10-IV-56 0.63 0.28 10- IV-16 0.85 0.27 HYS-7-161 0.53 0.25 ZB-09-01 0.60 0.22 ZB14-1 0.56 0.29 ZB 17-3 0.70 0.22 LD7 0.81 0.27 CJ43 0.35 0.29 GZ17 0.80 0.25 GZ18-1 0.80 0.25 Note. Pr/Ph was from GC-MS trace; [E.sub.1], [O.sub.3w], [S.sub.1], [P.sub.3]1, [P.sub.3]d, [P.sub.3]ch, and [T.sub.1]f represent Lower Cambrian, Upper Ordovician Wufeng Fm, Lower Silurian, Upper Permian Longtan Fm, Upper Permian Dalong Fm, Upper Permian Changxing Fm, and Lower Triassic Feixianguan Fm, respectively. TT: tricyclic terpane; H: 17[alpha], 21[beta]-hopane; St: regular sterane; Ts: 18[alpha], 21[beta]-22, 29, 30-trisnorhopane; Tm: 17[alpha], 21[beta]-22, 29,30-trisnorhopane; 29 Ts: C29 18[alpha], 21[beta] 30-norhopane; Gm: gammacerane; M: moretane. TABLE 4: Biomarker parameters of solid bitumen from the NE Sichuan Basin. Sample Strata Pr/Ph Pr/n Ph/n number [C.sub.17] [C.sub.18] Bitumen-W YB101 [T.sub.1]f 0.55 0.52 0.81 Bitumen-W LG11-0921 P.sub.3]ch 0.88 0.48 0.65 Bitumen-W LG82-10-12 P.sub.3]ch 0.85 0.67 0.80 Bitumen-E YA1 P.sub.3]ch 0.41 0.49 0.76 Bitumen-E TS5 P.sub.3]ch 0.31 0.35 0.71 Bitumen-E TD10-1 P.sub.3]ch 0.42 0.34 0.62 Bitumen-E PG6-3 P.sub.3]ch 0.48 0.72 1.30 Bitumen-E PG5 4889.3 [T.sub.1]f 0.45 0.66 1.21 Bitumen-E Po2 [T.sub.1]f 0.65 0.44 0.68 Bitumen-E LJ2 [T.sub.1]f 0.64 0.37 0.62 Bitumen-E Du4 [T.sub.1]f 0.54 0.25 0.49 Bitumen-E HL5-4 P.sub.3]ch 0.96 0.73 1.08 Bitumen-E TD10-10 P.sub.3]ch 0.56 0.25 0.43 Bitumen-E PL-37 P.sub.3]ch 0.43 0.44 0.64 Bitumen-E PL-58 P.sub.3]ch 0.38 0.22 0.55 Bitumen-E MB2 P.sub.3]ch -- -- -- Bitumen-E MB2 P.sub.3]ch -- -- -- Bitumen-E PG3 [T.sub.1]f -- -- -- Bitumen-E PG2-1 [T.sub.1]f -- -- -- Bitumen-E PG2-3 [T.sub.1]f -- -- -- Sample Gm/ [C.sub.27] [C.sub.28] number [C.sub.30]H 20R% 20R% Bitumen-W YB101 0.22 34.35 29.83 Bitumen-W LG11-0921 0.11 34.05 31.97 Bitumen-W LG82-10-12 0.10 35.84 31.85 Bitumen-E YA1 0.30 33.32 31.24 Bitumen-E TS5 0.16 34.59 29.00 Bitumen-E TD10-1 0.22 30.54 31.75 Bitumen-E PG6-3 0.17 30.89 30.48 Bitumen-E PG5 4889.3 0.17 37.38 26.70 Bitumen-E Po2 0.17 34.65 26.54 Bitumen-E LJ2 0.19 28.71 29.28 Bitumen-E Du4 0.22 31.09 29.14 Bitumen-E HL5-4 0.22 30.72 34.01 Bitumen-E TD10-10 0.27 32.49 31.09 Bitumen-E PL-37 0.36 29.62 29.62 Bitumen-E PL-58 0.31 28.60 30.49 Bitumen-E MB2 0.30 28.54 23.52 Bitumen-E MB2 0.28 31.22 29.94 Bitumen-E PG3 0.29 35.46 30.41 Bitumen-E PG2-1 0.26 34.68 27.77 Bitumen-E PG2-3 0.30 34.75 27.47 Sample [C.sub.29] [C.sub.24]Te/ [C.sub.23]TT/ number 20R% [C.sub.26]TT [C.sub.30]H Bitumen-W YB101 35.43 0.57 0.23 Bitumen-W LG11-0921 33.99 0.32 0.27 Bitumen-W LG82-10-12 32.30 0.34 0.25 Bitumen-E YA1 35.43 0.57 0.14 Bitumen-E TS5 36.41 0.59 0.21 Bitumen-E TD10-1 37.71 0.55 0.14 Bitumen-E PG6-3 38.64 0.47 0.33 Bitumen-E PG5 4889.3 35.92 0.50 0.36 Bitumen-E Po2 38.80 0.48 0.43 Bitumen-E LJ2 42.01 0.53 0.22 Bitumen-E Du4 39.77 0.50 0.31 Bitumen-E HL5-4 35.27 0.79 1.29 Bitumen-E TD10-10 36.43 0.44 0.19 Bitumen-E PL-37 40.44 0.41 0.17 Bitumen-E PL-58 40.91 0.54 0.18 Bitumen-E MB2 47.95 0.79 0.23 Bitumen-E MB2 38.84 0.55 0.09 Bitumen-E PG3 34.13 0.49 0.16 Bitumen-E PG2-1 37.55 0.48 0.40 Bitumen-E PG2-3 37.77 0.50 0.21 Sample [C.sub.21]TT/ [C.sub.29]S/ [C.sub.29]H/ number [C.sub.23]TT (S+R) [C.sub.30]H Bitumen-W YB101 0.63 0.54 0.54 Bitumen-W LG11-0921 0.33 0.58 0.61 Bitumen-W LG82-10-12 0.78 0.54 0.56 Bitumen-E YA1 0.57 0.53 0.51 Bitumen-E TS5 0.59 0.52 0.52 Bitumen-E TD10-1 0.57 0.52 0.50 Bitumen-E PG6-3 0.80 0.58 0.48 Bitumen-E PG5 4889.3 0.72 0.58 0.52 Bitumen-E Po2 1.11 0.54 0.50 Bitumen-E LJ2 1.03 0.56 0.49 Bitumen-E Du4 0.98 0.59 0.51 Bitumen-E HL5-4 0.75 0.51 0.54 Bitumen-E TD10-10 0.39 0.50 0.38 Bitumen-E PL-37 0.87 0.51 0.51 Bitumen-E PL-58 0.79 0.53 0.72 Bitumen-E MB2 0.93 0.27 0.49 Bitumen-E MB2 0.55 0.46 0.48 Bitumen-E PG3 0.67 0.45 0.49 Bitumen-E PG2-1 0.76 0.52 0.57 Bitumen-E PG2-3 0.82 0.47 0.54 Sample [C.sub.35]H/ Ts/ [C.sub.27-29]St/ number [C.sub.34]H (Ts + Tm) [C.sub.29-33]H Bitumen-W YB101 0.63 0.48 0.75 Bitumen-W LG11-0921 1.69 0.54 0.64 Bitumen-W LG82-10-12 0.00 0.52 0.72 Bitumen-E YA1 0.57 0.47 0.80 Bitumen-E TS5 0.74 0.48 0.69 Bitumen-E TD10-1 0.59 0.47 0.79 Bitumen-E PG6-3 0.00 0.57 0.46 Bitumen-E PG5 4889.3 0.26 0.53 0.69 Bitumen-E Po2 0.37 0.58 0.49 Bitumen-E LJ2 1.70 0.59 0.48 Bitumen-E Du4 1.55 0.59 0.43 Bitumen-E HL5-4 1.77 0.49 0.82 Bitumen-E TD10-10 1.15 0.50 0.54 Bitumen-E PL-37 0.69 0.55 0.35 Bitumen-E PL-58 0.86 0.36 0.31 Bitumen-E MB2 0.87 0.27 1.21 Bitumen-E MB2 0.70 0.43 1.08 Bitumen-E PG3 0.78 0.40 0.56 Bitumen-E PG2-1 0.87 0.51 0.71 Bitumen-E PG2-3 1.62 0.51 0.66 Sample [C.sub.29]Ts/([C.sub.29]Ts number + [C.sub.29]H) Bitumen-W YB101 0.26 Bitumen-W LG11-0921 0.25 Bitumen-W LG82-10-12 0.27 Bitumen-E YA1 0.28 Bitumen-E TS5 0.26 Bitumen-E TD10-1 0.26 Bitumen-E PG6-3 0.32 Bitumen-E PG5 4889.3 0.29 Bitumen-E Po2 0.31 Bitumen-E LJ2 0.31 Bitumen-E Du4 0.30 Bitumen-E HL5-4 0.26 Bitumen-E TD10-10 0.27 Bitumen-E PL-37 0.29 Bitumen-E PL-58 0.21 Bitumen-E MB2 0.27 Bitumen-E MB2 0.27 Bitumen-E PG3 0.27 Bitumen-E PG2-1 0.26 Bitumen-E PG2-3 0.25 Note. Bitumen-E and Bitumen-W represent solid bitumen samples from the east and west to the PG gas field, respectively. 30.72 34.01 35.27. TABLE 5: Solid bitumen [delta][sup.13]C and [delta][sup.34]S values. Location Sample Age Depth [delta][sup.13]C /well number (m) ([per thousand]) TD10 TD10 [P.sub.3]ch -26.5 (#) YB101 YB101 [T.sub.1]f 6790 -273 (#) LG82 LG82-13 [P.sub.3]ch -- -26.7 LG11 LG11-921 [P.sub.3]ch -- -26.4 HB101 HB101 [T.sub.1]f -25.1 Location [delta][sup.34]S /well ([per thousand]) TD10 9.6 (#) YB101 5.8 (#) LG82 -- LG11 -- HB101 Note. See Table 1 note; (#) from Cai et al. (in press).
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|Title Annotation:||Research Article|
|Author:||Cai, Chunfang; Xu, Chenlu; He, Wenxiang; Zhang, Chunming; Li, Hongxia|
|Date:||Jan 1, 2017|
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