Black carbon and polycyclic aromatic hydrocarbons (PAHs) in surface sediments of China's marginal seas

This study investigates the distribution of black carbon (BC) and its correlation with total polycyclic aromatic hydrocarbons (I PAH) pound in the surface sediments of China's marginal seas. BC content ranges from < 0.10 to 2.45 mg/g dw (grams dry weight) in the sediments studied, and varied among the different coastal regions. The Bohai Bay sediments had the highest BC contents (average 2.18 mg/g dw), which comprises a significant fraction (27%-41%) of the total organic carbon (TOC) preserved in the sediments. In comparison, BC in the surface sediments of the North Yellow Sea, Jiaozhou Bay, East China Sea and the South China Sea is less abundant and accounted for an average of 6%, 8%, 14% and 5%, respectively, of the sedimentary organic carbon pool. The concentration of I PAH pound in the surface sediments ranges from 41 to 3 667 ng/g dw and showed large spatial variations among the sampling sites of different costal regions. The Bohai Bay has the highest I PAH pound values, ranging from 79 to 3 667 ng/g dw. This reflects the high anthropogenically contaminated nature of the sediments in the bay. BC is positively correlated to TOC but a strong correlation is not found between BC and I PAH pound in the surface sediments studied, suggesting that BC and PAHs preserved in the sediments are derived from different sources and controlled by different biogeochemical processes. Our study suggests that the abundance of BC preserved in the sediments could represent a significant sink pool of carbon cycling in China's marginal seas.

Petroleum System in Deepwater Basins of the Northern South China Sea

The northern South China Sea margin has experienced a rifting stage and a post-rifting stage during the Cenozoic. In the rifting stage, the margin received lacustrine and shallow marine facies sediments. In the post-rifting thermal subsidence, the margin accumulated shallow marine facies and hemipelagic deposits, and the deepwater basins formed. Petroleum systems of deepwater setting have been imaged from seismic data and drill wells. Two kinds of source rocks including Paleogene lacustrine black shale and Oligocene-Early Miocene mudstone were developed in the deepwater basin of the South China Sea. The deepwater reservoirs are characterized by the deep sea channel rill, mass flow complexes and drowned reef carbonate platform. Profitable capping rocks on the top are mudstones with huge thickness in the post-rifting stage. Meanwhile, the faults developed during the rifting stage provide a migration path favourable for the formation of reservoirs. The analysis of seismic and drilling data suggests that the joint structural and stratigraphic traps could form giant hydrocarbon fields and hydrocarbon reservoirs including syn-rifting graben subaqueous delta, deepwater submarine fan sandstone and reef carbonate reservoirs.

Seismic characteristics of a reef carbonate reservoir and implications for hydrocarbon exploration in deepwater of the Qiongdongnan Basin, northern South China Sea

Our analysis of approximately 40,000 km of multichannel 2-D seismic data, reef oil-field seismic data, and data from several boreholes led to the identification of two areas of reef carbonate reservoirs in deepwater areas (water depth >= 500 in) of the Qiongdongnan Basin (QDNB), northern South China Sea. High-resolution sequence stratigraphic analysis revealed that the transgressive and highstand system tracts of the mid-Miocene Meishan Formation in the Beijiao and Ledong-Lingshui Depressions developed reef carbonates. The seismic features of the reef carbonates in these two areas include chaotic bedding, intermittent internal reflections, chaotic or blank reflections, mounded reflections, and apparent amplitude anomalies, similar to the seismic characteristics of the LH11-1 reef reservoir in the Dongsha Uplift and Island Reef of the Salawati Basin, Indonesia, which house large oil fields. The impedance values of reefs in the Beijiao and Ledong-Lingshui Depressions are 8000-9000 g/cc x m/s. Impedance sections reveal that the impedance of the LH11-1 reef reservoir in the northern South China Sea is 800010000 g/cc x m/s, whereas that of pure limestone in BD23-1-1 is > 10000 g/cc x m/s. The mid-Miocene paleogeography of the Beijiao Depression was dominated by offshore and neritic environments, with only part of the southern Beijiao uplift emergent at that time. The input of terrigenous sediments was relatively minor in this area, meaning that terrigenous source areas were insignificant in terms of the Beijiao Depression: reef carbonates were probably widely distributed throughout the depression, as with the Ledong-Lingshui Depression. The combined geological and geophysical data indicate that shelf margin atolls were well developed in the Beijiao Depression, as in the Ledong-Lingshui Depression where small-scale patch or pinnacle reefs developed. These reef carbonates are promising reservoirs, representing important targets for deepwater hydrocarbon exploration. (C) 2008 Elsevier Ltd. All rights reserved.

Petroleum geological framework and hydrocarbon potential in the Yellow Sea

Sedimentary basins in the Yellow Sea can be grouped tectonically into the North Yellow Sea Basin (NYSB), the northern basin of the South Yellow Sea (SYSNB) and the southern basin of the South Yellow Sea (SYSSB). The NYSB is connected to Anju Basin to the east. The SYSSB extends to Subei Basin to the west. The acoustic basement of basins in the North Yellow Sea and South Yellow Sea is disparate, having different stratigraphic evolution and oil accumulation features, even though they have been under the same stress regime since the Late Triassic. The acoustic basement of the NYSB features China-Korea Platform crystalline rocks, whereas those in the SYSNB and SYSSB are of the Paleozoic Yangtze Platform sedimentary layers or metamorphic rocks. Since the Late Mesozoic terrestrial strata in the eastern of the NYSB (West Korea Bay Basin) were discovered having industrial hydrocarbon accumulation, the oil potential in the Mesozoic strata in the west depression of the basin could be promising, although the petroleum exploration in the South Yellow Sea has made no break-through yet. New deep reflection data and several drilling wells have indicated the source rock of the Mesozoic in the basins of South Yellow Sea, and the Paleozoic platform marine facies in the SYSSB and Central Rise could be the other hosts of oil or natural gas. The Mesozoic hydrocarbon could be found in the Mesozoic of the foredeep basin in the SYSNB that bears potential hydrocarbon in thick Cretaceous strata, and so does the SYSSB where the same petroleum system exists to that of oil-bearing Subei Basin.

One century record of contamination by polycyclic aromatic hydrocarbons and polychlorinated biphenyls in core sediments from the southern Yellow Sea

Sixteen polycyclic aromatic hydrocarbons (PAHs) and 28 polychlorinated biphenyls (PCBs) were measured at a 2-cm interval in a core sample from the middle of the southern Yellow Sea for elucidating their historical variations in inflow and sources. The chronology was obtained using the Pb-210 method. PAHs concentrations decreased generally with depth and two climax values occurred in 14-16 cm and 20-22 cm layers, demonstrating that the production and usage of PAHs might reach peaks in the periods of 1956-1962 and 1938-1944. The booming economy and the navy battles of the Second World War might explain why the higher levels were detected in the two layers. The result of principal component analysis (PCA) revealed that PAHs were primarily owing to the combustion product. Down-cored variation of PCB concentrations was complex. Higher concentrations besides the two peaks being the same as PAHs were detected from 4 to 8 cm, depositing from 1980 to 1992, which probably resulted from the disposal of the out-dated PCB-containing equipment. The average Cl percentage of PCBs detected was similar to that of the mixture of Aroclor 1254 and 1242, suggesting they might origin from the dielectrical and heat-transfer fluid. The total organic carbon (TOC) content played a prevalent role in the adsorption of high molecular weight PAHs (>= 4-ring), while no obvious relationship among total PCBs, the concentration of congeners, and TOC was found.

油气、微生物与砂岩型铀矿形成关系研究——以东胜铀矿床和钱家店铀矿床为例

Sandstone-type uranium deposits are frequently found close to oil fields or uraniferous sandstones contain bitumen or petroleum. However, few evidence has been presented to indicate the association of uranium mineralization with petroleum oxidation. Thus, Dongsheng uranium deposit in Ordos Basin and Qianjiadian deposit in Kailu Basin are taken for examples to solve the puzzle. Integration data from sedimentary petrology, mineralogy, race elements geochemistry, isotope geochemistry and organic geochemistry, the uranium and petroleum sources, and diagenetic paragenesis of the host sandstone are analyzed, and then the genetic relationship between microbes, petroleum and uranium deposits are discussed. The observation under microscope shows that the host sandstone samples from Middle Jurassic Zhiluo Formation in the Dongsheng deposit contained different kinds of metamorphic rock fragments, which should have been derived form outcrops north to this basin. The LREE/HREE ratios of gneiss and amphibolite sampled from outcrops were close to the highest and the lowest LREE/HREE ratios of the sandstones with well-compared chondrite-normalized REE patterns, respectively. So these results consistently indicated that parent rocks of sandstones were mainly contributed from these two kinds of metamorphic rocks. There was very high Th/U ratio for granite gneiss, which was a mainly potential U resource. Hydrocarbon inclusions and adsorbed hydrocarbons are observed under fluorescence microscope in the host sandstone of Dongsheng uranium deposit, suggesting that the sandstones may have been utilized as oil migration pathways. Based on biomarker parameters, it is indicated that the inclusion oils and adsorbed hydrocarbons were marginally mature to mature, and were derived from humic-sapropel type organic matter under poor reducing freshwater to semi-saline environment. The features are similar to those of organic matter extracted from Triassic sandstone and source rock, but are different from that of cretaceous sandstone. Thus, it can be concluded that the inclusion oils and adsorbed hydrocarbons were mainly derived from Triassic lacustrine facies source rock. Observation results under Scanning Electron Microscopy and Electron Microprobe with Energy Spectrum Analysis show that, in Dongsheng area, the main uranium ore mineral is coffinite. The coffinite is intimately intergrown or coexists with pyrite and calcite, thus, the solution during mineralization stage is inferred to be alkaline. The alkaline environment is not favored for uranium to be pre-concentrated by absorption, and then be reduced abiogenetically. δ34S of pyrite and δ13C of calcite indicate that pyrite was formed by bacterial sulfate reduction (BSR) and part of the carbon of calcite has been dirived from oxidation of petroleum, respectively. Additionally, petroleum is found biodegraded. All the lines of evidence consistently indicate that petroleum was involved in uranium mineralization. Coffinite with microbe-like structures is found in the high U sandstone samples and is composed of nanoparticles, indicating the coffinite is biogenic. The conclusion are also supportted by laboratory experiment studies, which have shown that SRB are capable of utilizing U(VI) as the preferred electron acceptor for respiration and reduce U(VI) to U(IV) directly, coupled the oxidaton of organic matter and sulfate reduction. Based on the research results mentioned above, in the Dongsheng area, coffinite is likely to have formed by mixing of brine containing petroleum derived from Triassic with uranium-bearing meteoric water from outcrops north to Ordos Basin. SRB utilize hydrocarbon as carbon source, and directly reduce U(VI) resulting in precipitation of coffinite. The product of metabolism, H2S and CO2, was precipitated as pyrite and calcite during mineralization stage. Petroleum in fluid inclusions and adsorbed type in host sandstone from Lower Cretaceous Yaojia Formation in Qianjiadian uranium deposit, Kailu Basin, are derived from Jurassic Jiufotang Formation in this basin and the uranium mineral consists mainly of pitchblende. The δ34S and δ13C values of pyrite and calcite during mineralization stage indicate SRB have likely degraded petroleum, which is similar to that of Dongsheng deposit. The alkaline environment as indicated by the diagenetic mineral assemblage calcite, Fe dolomite, pyrite and pitchblende deposit suggests that U ore in the Qiangjiajiadian has a similar origin, i.e., direct reduction by SRB. However, less part of pitchblende is intergrown with kaolinite, suggesting the solution during mineralization stage is acidic. The environment is favorable for U(VI) to be adsorded on quartz or other mineral, and then reduced by H2S produced by SRB. Thus, it can be concluded that U(VI) reduction with petroleum oxidation by SRB and other microbes is an important ore-forming mechanism in petroleum-related sandstone-type uranium deposits. The finding is significant in that it provides a theoretical basis for exploration of both uranium and petroleumr.

流体地球化学：成因、流动和流体-岩石相互作用及塔里木盆地实例研究

Geofluid in sedimentary basins is related to petroleum generation, migration, accumulation and preservation, and is a topic of geological frontier. By integrating the multi-discipline methods of petroleum geochemistry, sedimentology, hydrogeology, petroleum geology and experimental geochemistry, the thesis has carried out experiments of microcline dissolution in solutions with organic acids, crude oil, brines with high total dissolved solids (TDS), and has dealt with Al distribution between the crude oil and the brines after the experiments. Cases for study includes Central Tarim, Hetianhe Gas Field and Kucha forland basin with data containing fluid chemistry and isotopic compositions, thin sections of sandstones and carbonates, homogenization temperatures and salinities of fluid inclusions, isotopic compositions of bulk rock and autigenic minerals. The aims are to elucidate fluid origin and flow in the three areas, effect of hydrocarbon emplacement on diagenesis, and to show occurrence of microbe-mediated, and thermochemical sulfate reduction in the Tarim Basin. Microcline dissolution experiments show that after 100 hour, part of the dissolved Al distributes in the crude oil, and the Al concentrations in the crude oil rise when organic acids are added. The result can be used to explain that most oilfield waters in the Tarim Basin are characterized by less than 3mg/L Al. Crude oil added to the solutions can enhance microcline dissolution, which is also observed in the case - Silurian sandstones with early crude oil emplacement in the Central Tarim. Al and Si have higher concentrations in the experiments of oxalic acid than of acetic acid under the same pH conditions, suggesting that there exist Al-oxalate and Si-oxalate complexes. Presence of acetate can enhance the activity of Ca and Al, but Al concentrations have not been increased significantly due to formation of small Al-acetate complex during the experiments. Relationships between δD and δ~(18)O in conjunction with chemistry of oilfield waters show that the waters are evaporated connate waters, which subsequently mixed with meteoric water, and were influenced by water-rock interactions such as salt dissolution, dolomitization of calcite, albitization of feldspar. In the Hetianhe Gas Field where salt dissolution took place, δD and δ~(18)O values can be used to trace nicely meteoric water recharge area and flow direction, but TDS can not. Part of the waters have high TDS but very light δD and δ~(18)O. When combined with paleo-topography, or fluid potentials, meteoric water is suggested to flow eastward in the Hetianhe Gas Field, which is the same with the Central Tarim. Whist in the Kuche forland basin, meteoric water may have permeated Cambrian-Ordovician strata. Relationship between ~(87)Sr/~(86)Sr and 1/Sr can be used to indicate migration and mixing of brines from carbonate strata (low ~(87)Sr/~(86)Sr ratio but high Sr content), clastic strata (high ~(87)Sr/~(86)Sr ratio but low Sr content) and crystalline basement (high ~(87)Sr/~(86)Sr ratio and heavy δ~(18)O value). Using this approach, it can be found that ~(87)Sr-depleted brine from Ordovician carbonates have migrated up to and mixed with ~(87)Sr-enriched waters from Silurian and Carboniferous sandstones, and that Silurian brines have mixed with meteoric water. In the Kuche forland basin, brines from the Cambrian and Ordovician carbonates have higher ~(87)Sr/~(86)Sr ratios than those from the overlying sandstones, when combined with chemistry, δ~(15)N and ~3He/~4He ratios of the coexisting natural gases, suggesting that the brines were derived from the basement. There exists some debate on the effect of hydrocarbon emplacement on mineral diagenesis. Case-study from Silurian sandstones in the Central Tarim show that quartz has kept overgrowing secondarily when oil saturation was decreased by meteoric water flushing subsequently to hydrocarbon emplacement. Silicon precipitates on the water-wet quartz surface, leading to decreased Si concentration close to the surface. A Si grads can result in Si diffusion, which supplies Si for quartz overgrowth. Hydrocarbon oxidation-sulfate reduction is an important type of organic-inorganic interaction. Not only can it make secondary alteration of hydrocarbons, but generate H_2S and CO_2 gases which can improve reservoir property. Thermochemical sulfate reduction took place at the temperatures more than 125 ℃ to 140 ℃ in the Cambrian-Ordovician carbonates, the products - H_2S and CO_2 gases migrated up to the Silurian, and precipitated as pyrite and calcite, respectively. The pyrite has an average δ~(34)S value close to those of Ordovician seawater and anhydrite, and calcite has δ~(13)C value as low as -21.5‰. In the Hetianhe Gas Field, sulfate reduction bacteria carried by meteoric water flowing eastward may have preferentially depleted ~(12)C of light hydrocarbon gases, and results in heavier δ~(13)C values of the residual hydrocarbon gases and higher molar CO_2 in the natural gases in the west than in the east. Coexisting pyrite has δ~(34)S values as low as -24.9‰.

吐合盆地鲁克沁构造带断块油藏形成机制及油藏预测

Lukeqin arc belt is a compound structure generated by multi-movements and composed of 6 sub-structural zones, which are connected by Huoyanshan Mountain. General characteristics of the arc belt are multi-patterns of structure, multi-phases for petroleum, multi-types of trap and multi-layers for reservoirs. As a part of the eastern Lukeqin arc belt located on the south of Taibei depression, Lukeqin structural zone behaves as a complex faulted-fold zone, in which the formation and distribution of hydrocarbons are controlled by structures. As the dominant source of dynamics for the second migration of hydrocarbon, structure stress field is closely related with the potentials of hydrodynamics. Results derived from the simulations of stress field by finite element method indicate that the northwest tending faults prefer seal to the northeast tending ones. The reason is that the northwest tending faults were squeezed more strongly than the northeast tending ones. Therefor, the northeast tending faults become always the paths for oil to migrate southeastward. Lukeqin structural zone is the main site for oil to concentration because it is surrounded by high stress. Situated on the front of the foreland basin of Turpan-Hami, Lukeqing arc belt is a dam to hold back the southward migrating oil from Shengbei depression. The axis line of Shenquan-Shengnan-Yanmuxi, Lukeqin and Yubei controls the migrating paths and concentrating process of oil and gas. Results derived from stress simulation and structure analyses indicate consistently that both Yubei and Lukeqin structural zones are the favorite areas for oil to migrate. The generally southward paths for oil to migrate out of Taibei depression can be two ways. One of them is from Taibei depression to Yubei structural zone and the other is from Taibei depression to Lukeqin structural zone. By the both ways, oil migrated upward along the faults and southeastward along the structural axis to concentrate in either Permian or Triassic system. The newly ascertained path for oil migration, which is accurately southeastward instead of coarsely southward, indicates the directions for further explorations on the compound Lukeqin block zone. Five kinds of seal models of fault are all found in Lukeqin block zone by studying the seal features of faults occurred in the zone. Having studied the fault seal and their controlling factors by fuzzy set method, the paper deems that the northwest tended faults are better than the northeast tended ones for oil to concentrate. The most important factors to decide the seal extent of faults in this zone are the characteristics of main stress and fluids instead of capillary pressure differences between the two sides of fault and smear mud factors. There exist seal differences not only between the faults of different time but also between the sections within a fault due to the variation of depths, strata and positions. The general distribution rules of reservoirs were dominated by the seal characteristics of a fault during the time reservoirs formed. While the current features of fault seal decide the conservation of reservoirs and heights of oil accumulations. Seal or not of a fault is not absolute because the essential for fault to seal is the distribution of permeability of fault zone. Therefor, the multi cyclical activities of faults create the space-time variation of seal features of the fault. Totally, the seal extent of the faults within the area is not as perfect as to accumulate ordinary crude. Crude oil can only be sealed when it becomes viscous. Process for crude oil to become viscous and viscous happened strongly because of the fault-fold movements. Shallowly burying and even revealing of the objective layers of the reservoirs made the crude oil to be thickened by water washing biologically degradation and oxidation degradation. The northwestward deepening during or after the reservoir formation of the structural zone provided the power for oil to migrate one or more times. The main reason for oil accumulation is the formation of Lukeqin block zone during Xishanyao stage, middle Jurassic Period, Early Yanshanian Movement. While the main reason for reservoir conservation is the placidity of Triassic blocks after the formation of reservoirs. Contrasting to former opinions, it is concluded that the reservoirs in Lukeqin zone, including viscous reservoirs, were formed by one time but not more times. So the author proposes the opinion that the reservoirs of viscous oil were formed by viscous oil migration under the conditions of aptitude sets of fault seals controlled by fluid and other factors. To grope the distribution rules outside Taibei depression and discuss the formation mechanism of Anjurassic reservoirs, it is necessary to study the dominate factors for the formation of reservoirs in Lukeqin structural zone such as structural stress, fault seals and thickening mechanism of crude oil. Also, the necessary studies are the key to break through the Taibei depression and Anjurassic systems. Therefor, they are significant for the future exploration and reserve increasing of hydrocarbon within the Turpan-Hami basin. The paper studied the distribution rules of block reservoirs and forecasted the favorable zones for further exploration in Turpan-Hami basin. Conclusions can be useful for not only the exploration in the area but also the theory consult in the adjacent areas.

富硫流体的成因与硫酸盐还原作用研究

Origins of H_2S, thiols, thiophenes in natural gases and sulphur-enriched oils are complicated and thus some debates exist on them. The post-doctoral research is based upon oil- and gas-field data. Cases for study include Triassic Jianglingjiang Formation natural gases, Wolonghe Field, Sichuan Basin, Paleozoic oils and bitumen, Central Tarim, gases reserviored nearby Carboniferious - Ordovician unconformity, Hetianhe Field, Tarim Basin and sulphur-enriched oils in Tertiary reserviors in Jinxian Sag, Bohai Bay Basin. We have carried out analyses on the oils and gases for chemistry, δ~(13)C, δ~(34)S, and molecular composition of biomarkers, analyzed authigenetic pyrite forδ~(34)S, formation water for chemistry and δD and δ~(18)O along with petroleum system and burial history analyses, The aims are to assess the origins of the H2S and authigenetic pyrite, to discuss the possibility of reduced sulphur incorporation into hydrocarbons and to determine the mechanisms of hydrocarbon secondary alteration in the above four cases by comparison. The research shows that the reduced sulphur in the four cases is the result of thermochemical and biological sulphate reduction., TSR and BSR, respectively. No evidence indicates an origin of decomposition of organic matter or mantle - derived H2S in the cases. Elevated H_2S contents (up to 32%) in the Triassic Jialingjiang Formation are considered to result from TSR while relatively low H_2S (up to 2000ppm) in the Hetianhe Field resulted from BSR. However, it is not the case for the Central Tarim where relatively low H2S but abundant authigenetic pyrite occurr. Part of the H_2S in the Central Tarim reservoirs has reacted with iron released from clay minerals to precipitate pyrite. Thus, reduced sulphur δ~(34)S and reservoir temperatures rather than the H2S amount are reliable parameters to distinguish between TSR and BSR. TSR in Sichuan Basin Triassic Jialingjiang Formation and Central Tarim Paleozoic reservoirs are showed to take place at more than 125℃. the H2S and authigenetic pyrite have δ~(34)S close to parent anhydrite. In contrast, BSR in the reservoirs near the Carboniferous - Ordovician unconformity in the Hetianhe Field and in the Tertiary in the Jinxian Sag took place at temperatures less than 80℃with sulphide δ~(34)S as light as -24.9‰ and -12.5‰, anhydrite δ~(34)S as heavy as +26‰and +3 5-+40‰, respectively. Chemistry and isotopic composition of the natural gases change as the result of sulphate reduction. It has been observed that relative composition of light hydrocarbon gases is changed along with a rise in H_2S and CO_2. TSR in the Triassic Jialingjiang Formation and BSR in the Hetianhe Field result in a greater degree of preferential depletion of methane than larger molecular hydrocarbon gases. As TSR or BSR proceeds, hydrocarbon gases evolved to heavier carbon isotope as the result of kinetic isotopic fractionation, i.e., selective anaerobic oxidation of ~(12)C. Using the model of residual methane (Whiticar, 1999) to describe the relationship among the proportion of methane oxidation, isotopic shift and fraction factor, about 30% methane is calculated to have been oxidized during BSR in the western part of the Hetianhe Field. From the above, it can be concluded that in the area where H_2S is abundant, empiricalδ~(13)C -Ro relationships do not work. Sulphate reduction results in a rise in sulphur content, gravity and viscosity of an oil as well as changes in δ~(13)C and δ~(34)S. On special conditions, the reduced sulphur from sulphates might be incorporated into oils, i.e., the increasing sulphur is derived from secondarily reduced sulphur. A positive correlative relationship exists between sulphur content and δ~(34)S in the oils in Paleozoic reservoirs in Central Tarim, indicating that enhanced sulphur is ~(34)S-enriched, originated from TSR. The Jinxian oil with the highest sulphur content has the lightest δ~(34)S, suggesting part of the sulphur in the oil is ~(34)S-depleted, originated from BSR. In the Jinxian oil with increasing sulphur content, asphaltenes shows higher content and more negative δ~(13)C, and saturates shows evidence of biodegradetion and a decreasing content and a positive δ~(13)C shift. Thus, asphaltenes have δ~(13)C values closer to saturates. All the above indicate that the reduced sulphur has been incorporated into biodegradated saturates to generate new asphaltenes with relatively light δ~(13)C of saturates. Thiols and thiophenes in natural gases in the Triassic Jialingjiang Formation may result from reaction of H_2S with hydrocarbon. In the Jialingjiang Formation hydrocarbon gases are dominated by methane thus have a high dryness coefficient and thiols are showed to be positively related to H_2S content, suggesting that the thiols may result from H_2S reaction with short chain hydrocarbons. In contrast, high thiophenes occur in wet gases in Jurassic reservoirs with their source rock from sulphur - depleted type I kerogen, indicating that thiophenes may be a product of reaction of H2S with longer chain hydrocarbons.