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Marinoan cap carbonates are the first sedimentary rocks deposited after the Marinoan Snowball Earth glaciation and likely record the marine geochemical signals across the Cryogenian-Ediacaran boundary. The nature of the parent fluids, the possible precursor mineralogies and the dolomitisation models of these carbonates are debated to the present day. Cap carbonates and their fibrous dolomite cement samples from the Jiulongwan and Huajipo sections in South China were analysed for their petrography and geochemistry. Data obtained shed light on the deposition and alteration history of cap carbonates. Two types of fibrous dolomite cement precipitated penecontemporaneously with platform carbonate sediment deposition: (i) isopachous fascicular-optic dolomite fabrics with a characteristic botryoidal habit and mottled cathodoluminescence colour; they likely formed via an aragonitic precursor; and (ii) radial-slow dolomite cement, representing a direct marine precipitate. Growth zones are recognised under the SEM and visible in alternating dull- and bright-red zones under the cathodoluminescence microscope. Basal cap carbonates (Ce anomalies: 0.85 ± 0.11; Mn: 3324.3 ± 558.2 ppm) and the base (Ce anomalies: 0.83 ± 0.22; Mn: 2349.2 ± 1276.4 ppm) of fascicular-optic dolomite cement from platform facies indicate anoxic marine seawater with high Mn concentrations. Based on the geochemical data of fibrous dolomite and blocky calcite cement, the marine porewater evolved from the Mn reduction zone (Ce anomalies: 1.04 ± 0.26) to the sulphate reduction zone (Ce anomalies: 1.00 ± 0.48) and the Fe reduction zone (Ce anomaly: 1.40). In situ trace and rare earth elemental contents and the transition from a dull to bright fluorescence colour along the fibrous dolomite transects point to the former activity of microbial sulphate reduction and the degradation of organic matter. These two factors likely facilitated the formation of cap dolostone and multiphase dolomite cement crusts in a marine seawater (porewater) environment. Data shown here are significant for those concerned with the palaeoenvironmental archive and the dolomitisation process of Marinoan cap dolostones. Cartoon and a summary of petrographic and geochemical properties from cap carbonate substratum to fibrous dolomite cement and blocky calcite cement. Red rectangle shown in stratigraphic context is enlarged as the phase section. [Display omitted] • Fascicular-optic dolomite has an aragonitic precursor, radial-slow dolomite represents marine precipitate. • Depositional seawater is anoxic with high Mn contents. • Microbial sulphate reduction and the degradation of organic matter facilitated dolomitisation. [ABSTRACT FROM AUTHOR]

Deeply buried (4500–7000 m) Ordovician carbonate reservoirs in the Tazhong area, Tarim Basin, NW China show obvious heterogeneity with porosity from null in limestones and sweet dolostones to 27.8% in sour dolostones, from which economically important oils, sour gas and condensates are currently being produced. Petrographic features, C, O, Sr isotopes were determined, and fluid inclusions were analyzed on diagenetic calcite, dolomite and barite from Ordovician reservoirs to understand controls on the porosity distribution. Ordovician carbonate reservoirs in the Tazhong area are controlled mainly by initial sedimentary environments and eo-genetic and near-surface diagenetic processes. However, vugs and pores generated from eogenetic and telogenetic meteoric dissolution were observed to have partially been destroyed due to subsequent compaction, filling and cementation. In some locations or wells (especially ZG5-ZG7 Oilfield nearby ZG5 Fault), burial diagenesis (e.g. thermochemical sulfate reduction, TSR) probably played an important role in quality improvement towards high-quality reservoirs. C2 calcite and dolomite cements and barite have fluid inclusions homogenization temperatures (Ths) from 86 to 113 °C, from 96 to 128 °C and from 128 to 151 °C, respectively. We observed petrographically corroded edges of these high-temperature minerals with oil inclusions, indicating the dissolution must have occurred under deep-burial conditions. The occurrence of TSR within Ordovician carbonate reservoirs is supported by C3 calcite replacement of barite, and the association of sulfur species including pyrite, anhydrite or barite and elemental sulfur with hydrocarbon and 12 C-rich (as low as −7.2‰ V-PDB) C3 calcite with elevated Ths (135–153 °C). The TSR may have induced burial dissolution of dolomite and thus probably improved porosity of the sour dolostones reservoirs at least in some locations. In contrast, no significant burial dissolution occurred in limestone reservoirs and non-TSR dolostone reservoirs. The deeply buried sour dolostone reservoirs may therefore be potential exploration targets in Tarim Basin or elsewhere in the world. [ABSTRACT FROM AUTHOR]

Petroleum stability varies greatly among different basins with light oil recently being produced from reservoirs at depths up to 8260 m and present bottom hole temperatures up to 171 °C in the Tarim Basin. Determining the extent of oil-gas conversion (EOGC) and its controls are crucial to the "exploration deadline" of temperature or depth for liquid hydrocarbons. For this purpose, about 90 oils from the Cambrian and Ordovician in the Tarim Basin have been analyzed for biomarkers, diamondoids and thiadiamondoids, and their gas/oil ratios were collated. These oils have EOGC from 45.4 to 98.3% for TSR-altered oils in the Tazhong and Shunbei areas, and only 0–49.2% for all other non-TSR oils. Among non-TSR-altered oils, Tazhong oils show higher EOGC values (28.0–49.2%) than those in Tabei (0–9.7%) and Shunbei (0–32.7%) oils, respectively. We propose that higher heating rates (7 °C/Ma) and shorter durations (<5 Ma) at high temperatures (>150 °C) may account for the lower EOGC values of oils in the Tabei and Shunbei areas than those in the Tazhong with values of 0.1 °C/Ma and 250 Ma (>120 °C), respectively. The oil may be completely converted to methane-dominated gas if it was exposed to high temperatures for a longer duration as exampled from gas pools from the Lower Cambrian in the Sichuan Basin. In this case, the oil was heated at a rate of 1 °C/Ma since the oil charge and experienced >200 °C for about 50 Ma. Thermochemical sulfate reduction may have enhanced the conversion of oil to gas, leading to an increase in EOGC values from 30% for non-TSR-altered oils to 98% for the strongly TSR-altered oil in the eastern Tazhong area with similar burial-heating history. A similar case for elevated EOGC due to TSR can be found in the Smackover Formation, Gulf of Mexico. Thus, two global models related to heating rate and duration at high temperatures and TSR are developed to illustrate oil stability with temperature and are expected to be instructive for deep petroleum exploration. • The extents of oil-gas conversion in the Tarim Basin vary widely in different areas. • Higher heating rates and shorter durations at high temperatures may favor the preservation of oil. • TSR could lower oil and gas stability and accelerate the conversion of oil to wet gas and of wet gas to dry gas. • Two global models are developed to illustrate oil stability with temperature. [ABSTRACT FROM AUTHOR]

Gases, oils, solid bitumen samples and fluid inclusions were analyzed for chemical composition and δ 13 C and δ 34 S values, and production data were collated, to elucidate the origin and fates of the H 2 S in the Tazhong area. The H 2 S in the Ordovician was measured to have δ 34 S values from 12.1‰ to 23.4‰, which are significantly lighter than the counterpart in the Cambrian (33.0‰), indicating that the H 2 S did not migrate from the Cambrian, but may have been derived from thermochemical sulfate reduction in situ , as partially supported by 12 C-rich CO 2 in fluid inclusions and TSR calcites with δ 13 C values from −3.6‰ to −17.7‰ in the Ordovician. The H 2 S rich gas subsequently mixed with H 2 S-poor, 13 C rich methane-dominated gas as indicated by the roughly negative correlations of H 2 S content to dryness and gas/oil ratio, and CH 4 from fluid inclusions having δ 13 C values 1.2–3.6‰ lighter than the associated free gas. The H 2 S has been dissolved in formation water, precipitated as pyrite and incorporated into oils and solid bitumens, resulting in the generation of alkylthiolanes, alkylthiols and alkyl 2-thiaadamantanes, and increase in δ 34 S values and S/C ratios of the solid bitumen. The content of H 2 S produced from the water intervals or petroleum–water transition zones is significantly contributed from exsolved gas and thus higher than that of the gas-cap gas in the reservoirs. Thus, H 2 S contents cannot be used to indicate TSR extents in the Ordovician. However, in the Cambrian, whole oil and saturates show positive shifts in δ 13 C values with increasing H 2 S contents, indicating that the H 2 S in the Cambrian was derived from TSR by liquid hydrocarbons. [ABSTRACT FROM AUTHOR]

Intense thermochemical sulfate reduction (TSR) and up to 18% H 2 S are found in the Upper Permian Changxing Formation (P 3 ch) in the northeast (NE) Sichuan Basin, China, despite that rare gypsum or anhydrite was found in this formation. Here, we present new concentration data of carbonate-associated sulfate (CAS) from carbonate host rocks, C, O, and Sr isotope data for TSR-related calcites, and S isotope data for sulfur compounds obtained during this study. These data along with spatial-temporal changes in palaeogeopressure conditions, hydraulic conductivity and the physical capacity indicate that the H 2 S was generated locally from TSR within the P 3 ch reservoirs. We propose that the reactive sulfates were derived from CAS released during dolomitization and recrystallization of earlier dolomite within the P 3 ch Fm. and from the cross-formational migration of evaporative brines from the Lower Triassic Feixianguan Formation (T 1 f) to P 3 ch Fm. Our calculation shows that the two sources could provide enough SO 4 2− for the generation of H 2 S within the P 3 ch reservoirs. Early downward migration of sulfate-rich evaporative brines from the T 1 f formation occurred in near-surface and shallow burial diagenetic settings (mainly <1000 m). The evaporative brines seeped into porous grainstones and displaced preexisting seawater, causing pervasive dolomitization within the P 3 ch Fm. Subsequently, TSR calcites precipitated from the pore water have high Sr concentrations (up to 7767 ppm), close to the T 1 f TSR calcites, and 87 Sr/ 86 Sr ratios mainly from 0.7074 to 0.7078, which are significantly higher than those of Late Permian seawater but within the range of early Triassic seawater. [ABSTRACT FROM AUTHOR]

Deep burial carbonate reservoirs (>4000 m) have great potential of reserves for oil and gas exploration, although the matrix reservoirs generally become extremely heterogeneous and tight due to various diagenesis. Hydrothermal dissolution is supposed to be important for formation of high-quality deep burial carbonate reservoirs. However, few studies have focused on influence of minor fluorine-bearing fluid on carbonate reservoir quality. This study integrates petrography, geochemistry and fluid inclusion data to understand impact of fluorine-bearing fluid on deep burial carbonate reservoirs. Mineralogy and mineral distribution suggest that fluorite and concomitant calcite are found in the Ordovician and Cambrian strata of the whole Tazhong area, especially in the vicinity of faults. Calcite associated with fluorite is probably derived from progressive mixture between formation water and fluorine-bearing hydrothermal fluid, which is supported by REY pattern of concomitant calcite, surrounding limestone and fluorite, and fluid inclusion microthermometric data of concomitant calcite and fluorite. Fluorine-bearing hydrothermal fluid was responsible for the concomitant C2 calcite of high Y/Ho ratio. Therefore, the superchondritic Y/Ho ratio of concomitant calcite can be probably used as proxy for identifying distribution of minor fluorine-bearing hydrothermal fluid. For thick fluorite bed, influx of fluorite-rich fluid resulted in surrounding limestone dissolution and altered zones between fluorite and limestone. This process simultaneously improves porosity and permeability of high-energy sedimentary facies reservoirs. In contrast, the fluorine-rich hydrothermal fluid through the low-energy sedimentary facies mainly enhanced permeability of the tight carbonate reservoirs rather than porosity. For widespread tight reservoir of high-energy and low-energy sedimentary facies, even minor fluorite-bearing fluids still enhance permeability. The fluorine-bearing hydrothermal fluid may influence carbonate reservoirs away from hydrothermal-altered zones. Significance of minor fluorine-bearing hydrothermal fluid for widespread tight carbonates has probably been underestimated for deep burial carbonate reservoir. • Calcite associated with fluorite is derived from mixture between formation water and fluorine-bearing hydrothermal fluid. • Superchondritic Y/Ho ratio of calcite can be probably used as proxy for distribution of fluorine-bearing hydrothermal fluid. • The ability of fluorine-rich fluid to improve carbonate reservoir quality is influenced by lithology and sedimentary facies. • Minor fluorine-bearing hydrothermal fluid can still improve permeability of deep burial tight carbonate reservoir. [ABSTRACT FROM AUTHOR]

Abstract: Petrographic features, carbon and oxygen isotopes, and trace elements were determined, and fluid inclusions were analyzed on late diagenetic cements and vug-fillings from the Lower Triassic carbonates to account for much higher porosities in the sour dolomite reservoirs than in the sweet limestones in northeastern Sichuan Basin. In the NE side to the Kaijiang-Liangping Trough, dolostone reservoirs have porosities mainly from 6 to 12%, up to 28% and contain 9–20% H2S. The dolomite includes pre-bitumen re-crystallized silt-sized crystals without occurrence of fluid inclusions, and late burial dolomite. The late burial dolomite has been measured to have fluid inclusions homogenization temperatures (HTs) from 72 to 128 °C. Part of the dolomites with HTs up to 121 °C show corroded edges or replacement by TSR calcites. TSR calcites show δ 13C values from −2.3 to −18.9‰, FeO from null to 810 μg/g and SO3 from 50 to 18,700 μg/g. Vug-filling TSR calcites have much lower FeO and SO3 than the replacement calcites of anhydrite, suggesting that dissolved Fe2+ released from the dissolution of dolomite and anhydrite as a result of TSR may have reacted with TSR-H2S and precipitated as pyrite. The dissolution may have released 13C-rich CO2 resulting in the present-day CO2 having δ 13C values significantly heavier than those of the TSR calcites as light as −18.9‰. The dolomite and anhydrite dissolution during late stage of TSR may have enlarged or redistributed porosity in the NE side dolostones. In contrast, oolitic limestone reservoirs in the SW side contain significantly lower sulfates and thus no significant late-diagenetic dissolution and TSR. The porosity difference in the two sides resulted from original physical property due to early dolomitization and subsequent improvement from anhydrite and dolomite dissolution as a result of TSR. [Copyright &y& Elsevier]

Abstract: Thermochemical sulfate reduction is considered to result in H2S >10% and high dryness coefficient values in the Lower Triassic and Upper Permian carbonate reservoirs in the NE Sichuan Basin. The gases produced from gas–water transition and water intervals were measured to have H2S higher than 30%, and are calculated to have significantly higher H2S and CO2 contents than a gas produced from a gas interval, and thus are not used to reflect TSR extents. Methane and ethane were shown to shift positively in carbon isotopes as a result of TSR. However, the fractionation has not quantitatively described. A logarithmic relationship is found to give the best fit for methane δ13C1 and [1 − H2S/(∑C1–6+H2S)] for all the gases with an equation of δ13C1, t = −16.6lnx − 33.0, indicating a closed system Rayleigh distillation with a kinetic fractionation factor αC of 1.0166. Ethane shows similar δ13C2 shift to methane (6.1‰ vs 5.5‰) for H2S/[H2S + ∑C1–6] = 0.2 in the NE Sichuan Basin. The δ13C2 deviation is significantly less than that of Mobile Bay Jurassic Norphlet Fm TSR-altered ethane (+16‰) for H2S/[H2S + ∑C1–6] = 0.1 (Mankiewicz et al., 2009). The ethane in association with high H2S (>10%) in NE Sichuan Basin shows slightly lighter δ13C values than those of the potential source rocks. Thus, it is possible for small amounts of gas derived from cracking of the source rocks to have mixed with TSR-altered gas in the high H2S pools. [Copyright &y& Elsevier]

Abstract: New sour pools have recently found in the Lower Triassic Feixianguan Fm carbonate reservoirs in the East Sichuan Basin in China with H2S up to 17.4% by volume. A recent blowout from a well drilled into this formation killed hundreds of people as a result of the percentage concentrations of H2S. In order to assess the origin of fatal H2S as well as the cause of petroleum alteration, H2S concentrations and the isotopes, δ34S and δ13C have been collected and measured in gas samples from reservoirs. Anhydrite, pyrite and elemental sulphur δ34S values have been measured for comparison. The high concentrations of H2S gas are found to occur at depths >3000m (temperature now at ∼100°C) in evaporated platform facies oolitic dolomite or limestone that contains anhydrite nodule occurrence within the reservoirs. Where H2S concentrations are greater than 10% its δ34S values lie between +12.0 and +13.2‰ CDT. This is within the range of anhydrite δ34S values found within the Feixianguan Fm (+11.0 to +21.7‰; average 15.5±3.5‰ CDT). Thus H2S must have been generated by thermochemical sulphate reduction (TSR) locally within the reservoirs. Burial history analysis and fluid inclusion data reveal that the temperature at which TSR occurred was greater than about 130–140°C, suggesting that the present depth-temperature minimum is an artifact of post-TSR uplift. Both methane and ethane were actively involved in TSR since the petroleum became almost totally dry (no alkanes except methane) and methane δ13C values become significantly heavier as TSR proceeded. Methane δ13C difference thus reflects the extent of TSR. While it is tempting to use a present-day depth control (>3000m) to predict the distribution of H2S in the Feixianguan Fm, this is an invalid approach since TSR occurred when the formation was buried some 1000–2000m deeper than it is at present. The likelihood of differential uplift across the basin means that it is important to develop a basinal understanding of the thermal history of the Feixianguan Fm so that it is possible to determine which parts of the basin have been hotter than 130–140°C. [Copyright &y& Elsevier]

The deep-burial Cambrian Xiaoerbulake Formation microbialites reservoir hosts significant hydrocarbon in the Tarim Basin. However, limited understandings of fluid-rock interactions from deposition to deep-burial regimes hamper petroleum exploration. Here, petrological observations, in-situ elemental contents and porosity-permeability analyses were performed to understand the complex interactions and the microbialites performance. Dolo-mudstone, crystalline dolostone, and four kinds of microbialites are distinguished as dolostones types. In the depositional stage, microbialites are characterized by (evaporated) seawater dolomitization with the mediation of microbial activity. The dolostone matrix shows seawater-like δ13C, δ18O and REY patterns. Thrombolitic and foam spongy dolostones from high-energy subtidal to intertidal zones show large framework pores compared to stratiform stromatolitic dolostones from low-energy intertidal zones. In near-surface settings, meteoric diagenesis generates secondary pores, while fine-crystalline dolomite cements partially fill pores. During the shallow to intermediate burial regimes, medium-to coarse-crystalline dolomite cements yield negative δ18O values and slightly flat REY patterns. The precipitation of this dolomite phase further decreases reservoir porosity. In deep burial settings, one type of saddle dolomite is likely to be formed by replacement from carbonate precursors, while the second type might be directly precipitated from hydrothermal fluids. These two types of saddle dolomites show different cathodoluminescent characteristics and geochemical data. Subsequently, two types of calcite cements are formed by the calcification of dolomite and yield significant negative δ13C values due to thermochemical sulfate reduction. Finally, the third calcite phase is likely to be a direct precipitate from burial brines. Hydrothermal activity and thermochemical sulfate reduction generate and/or re-distribute secondary pores. Based on the plethora of depositional environments and fluid-rock interactions, thrombolitic dolostone generally yields higher porosity-permeability than other types of microbialites. Thrombolite reservoir has high potential for petroleum exploration and is significant for those concerned with microbialite hydrocarbon fields. The variation of microbialite reservoir porosity along time. [Display omitted] • Microbialites are characterized by seawater dolomitization with mediation of microbial activity. • Two types of saddle dolomite and three types of calcite cements are identified based on high-resolution geochemical analyses. • Hydrothermal activity and thermochemical sulfate reduction generate secondary pores. • Thrombolite yields better reservoir performance than other types of microbialites. [ABSTRACT FROM AUTHOR]

The deeply buried dolostones in the Lower Cambrian Longwangmiao Formation at Central Sichuan Basin of China are a crucial hydrocarbon exploration target. However, the origin of various types of dolomite for these carbonate reservoirs has not been well understood. In this study, petrological studies, geochemical analyses including C, O and Sr isotopes, in-situ trace elements and rare earth elements, and fluid inclusions analyses are performed in order to uncover the dolomitization mechanisms. The results show that an initial pervasive replacive dolomitization phase (Md, D1 and D2) was followed by volumetrically less important cement phases (D3, D4, D5, D6 and calcite). The δ18O values and element concentrations (e.g., Na and Sr) appear to suggest that this early dolomitization was caused by reflux of slightly modified seawater. In the shallow burial realm, influx of meteoric water led to a decrease in Fe content (from 1000 ppm down to 70 ppm) and ∑REE content (from 34.22 ppm down to 9.56 ppm) in early diagenetic D3 dolomite with more negative δ18O SMOW values. This early meteoric water flux may have created considerable dissolution porosities. The D3 and D6 dolomite cements were interpreted as the result of dolomite dissolution and reprecipitation due to burial compaction. The D4, D5 dolomites and late calcite cements display markedly positive Eu anomalies suggesting the presence of hydrothermal fluid. Some late diagenetic calcites with negative δ13C values as low as −5‰ V-PDB and relatively higher Y/Ho ratio of ca. 36.9 were interpreted to be derived from thermochemical sulfate reduction (TSR). The effects of hydrothermal fluid and TSR on reservoir qualities seem to be minor in this case. Hence, this study emphasizes the role of late diagenetic preservation of primary and early diagenetic porosity in the formation of economically important, ultra-deep dolostone reservoirs in sedimentary basins. • Dolomitization of the reservoirs occurred via reflux of penesaline seawater. • Current porosity was inherited from early diagenetic meteoric water dissolution. • TSR and hydrothermal alteration had little impact on current porosity. • Ultra-deep reservoirs occur along an embayment in a carbonate platform with pervasive dolomitization. [ABSTRACT FROM AUTHOR]

Deep (4000–6000 m) and ultra-deep burial (>6000 m) carbonate reservoirs are becoming important petroleum exploration targets of China and worldwide basin. Thermochemical sulfate reduction (TSR) may be pervasive in the deep and ultra-deep burial petroliferous carbonate strata associated with evaporite. However, there is still considerable confusion on the effect of TSR on reservoir quality. Petrography, geochemistry and fluid inclusion data from carbonate reservoirs of Tarim Basin were integrated to resolve the disagreement. Based on distribution of sulfur-bearing mineral, SO 4 2− concentrations and SO 4 2−/Cl− ratios in both formation water and fluid trapped in fluid inclusion, we propose that SO 4 2− in formation water is likely major reactant involved in TSR reaction of North Slope, whereas coarsely diagenetic anhydride is likely major sulfate reactant involved in TSR reaction of East Burial Hill Belt. Silurian fracture-filling pyrite has δ34S values similar to those of Ordovician fracture-filling pyrite, H 2 S and sulfur, suggesting that TSR dissolved sulfate involved in (North Slope) may occur in a partly open system for H 2 S and CO 2. However, TSR diagenetic anhydride involved in (East Burial Hill Belt) may occur in a closed diagenetic system. TSR in a partly open-system, associated with gas charge and flow of cross formational fluids, probably increased fluid pressure, and further transported H 2 S, CO 2 and solute from dissolution through fracture. A closed system of anhydrite-bearing strata seems to hinder transports of TSR-derived CO 2 or bicarbonate, and result in precipitation of TSR calcite, pyrite and bitumen close to the TSR sites. In combination with petrographic observations, intense dissolution in North Slope have released more inorganic CO 2 leading to TSR calcite and CO 2 in the natural gas showing δ13C values much heavier relative to δ13C values of TSR calcites in East Burial Hill Belt as light as −13.4‰. TSR-induced dissolution of carbonate minerals during oil-dominated TSR may be related to the reaction of dolomite with anhydride and release of H+ due to pyrite precipitation, rather than new formed water during TSR. Similar to geological settings of Ordovician TSR, anhydrite-poor Lower Cambrian dolostones underlying evaporites seals may thus be the most promising target for future exploration success in ultra-deep Cambrian reservoirs of Tarim Basin. The controversy about the effects of TSR on reservoir quality can partly be ascribed to differently geological settings where TSR occurred. • Sulfate reactants can be speculated by mineralogy, and geochemistry of formation water and fluid trapped in fluid inclusion. • Comparison of δ34S value of pyrite and H 2 S from Silurian and Ordovician imply partly open diagenetic systems during TSR. • Petrology, 13C-rich TSR calcite and present-day CO 2 suggest H 2 S, CO 2 and solute were transported from dissolution sites. [ABSTRACT FROM AUTHOR]

Volatile organic sulfur compounds (VOSC) are trace components of natural gas that can provide substantial information regarding gas origins, migration, and key processes such as H 2 S generation and its occurrence in natural gas reservoirs. In the current study we demonstrate the applicability of VOSC as a proxy for gas-source rock correlations and identification of interactions between H 2 S and other natural gas components. We studied the molecular and isotopic compositions of VOSC formed during low-level thermal maturation (%Ro equivalent = 0.60–0.71) of six different immature source rocks covering a variety of kerogens (types I, II, II-S and III). Anhydrous pyrolysis experiments (300 °C, 72h) were performed on all the source rocks studied, and the produced gases were analyzed for their molecular compositions and compound specific sulfur isotopes of the various VOSC formed. The formed gases were either dominated by CH 4 (32.2–49.9%) or CO 2 (31.9–46.2%) and contained a variety of alkanes in the C 2 –C 5 range. H 2 S formed in 6 out of 8 experiments at concentrations ranging from 0.6 to 4.3%. The results demonstrated formation of VOSC in all experiments, regardless of kerogen types or source rock lithologies. The formation of thiols (16–121.2 ppm) in the produced gas was restricted to those experiments that contained H 2 S. This indicates that thiols formation is limited to gas-phase interactions between H 2 S and hydrocarbons. In contrast, thiophenes formed in all experiments (14.9–1778.8 ppm) regardless of H 2 S presence. Thiols preserved the δ34S signal of their associated H 2 S due to gas-phase interactions between the two, while thiophenes showed no interaction with the associated H 2 S and instead preserved the δ34S signature of the bulk kerogen (within 3.5‰ on average) of each source rock. This work demonstrates the applicability of thiophenes to act as a gas-source rock proxy for natural gas and thiols as a proxy for identification of present or paleo-interactions between natural gas and H 2 S. • Volatile organic sulfur compounds are formed during thermal maturation of different kerogens (type I, II, IIS and III). • Thiols are formed by gas-phase reactions of H 2 S with hydrocarbons, their δ34S depends on that of parent H 2 S. • Thiophenes are formed by thermal cracking of the parent kerogen, their δ34S follows that of the parent kerogen. • The presence of thiophenes in natural gas indicates a self-sourced system or an input from oil to the reservoir. [ABSTRACT FROM AUTHOR]

Molecular and compound specific isotope analysis of volatile organic sulfur compounds (VOSC), alkanes and CO 2 in natural gases from the Ordovician Majiagou Formation of the Daniudi field (Ordos basin, China) was performed. The analysis of VOSC demonstrated abundant thiols, sulfides and thiophenes in several samples while others had low concentrations of sulfides only. Molecular analysis of main alkanes and non-hydrocarbons showed the samples vary by the nitrogen and H 2 S concentrations. Thiols in the gas were at isotopic equilibrium with H 2 S bearing isotopic signature similar to that of Ordovician anhydrites within the reservoirs, hence the source of H 2 S was likely thermochemical sulfate reduction (TSR) of these anhydrites. In contrast, gas samples that lacked thiols also lacked H 2 S. Since all gases came from the same formation and similar thermal regime, the lack of thiols and H 2 S indicates that the occurrence of TSR in the field was limited, likely by contact between hydrocarbons to the anhydrites. The isotopic signature (δ34S) of thiophenes in the gas samples suggests the source of the gas is unlikely to be Carboniferous or Permian coals which were previously suggested as the source rocks for the gas. The δ13C and δ2H of alkanes further supports this suggestion as it demonstrates Carboniferous and Permian gases are unlikely to undergo TSR and generate the gas present in the Ordovician reservoirs. Instead, the δ13C and δ2H of alkanes hint that the gas source is shale rather than coal. This study demonstrates the applicability of compound specific sulfur isotope analysis of VOSC in identification of H 2 S sources, performing gas-source rock correlation and acting as a complementary proxy in case where routine analysis of hydrocarbons (δ13C and δ2H) is insufficient for identification of the gas source. • Volatile organic sulfur compounds were measured in natural gas from the Ordovician Majiagou Formation in the Daniudi field. • Molecular and sulfur isotopic distribution of thiols indicate that the origin of H 2 S is TSR from Ordovician anhydrites. • The natural gas of the Majiagou Formation was likely generated in-situ from an Ordovician source rock. • Distribution of VOSC isotopes indicates TSR in Ordovician gas reservoirs was likely localized due to limited sulfate presence. [ABSTRACT FROM AUTHOR]

Large volumes of black and volatile oils have been recently discovered from 7000 m to 8400 m below surface in the Tarim Basin. Diamondoids, compounds recalcitrant to thermal stress, have been applied to estimate the extent of oil-cracking, but uncertainties remain concerning additional influences, such as evaporative fractionation and biodegradation. To investigate controls on diamondoid abundance in oil reservoirs, we performed detailed geochemical characterizations of biomarkers and diamondoids of twenty-eight oils from the Halahatang sub-Depression in the Tabei area of the Tarim Basin. Based on the results, the oils belong to one population. Three oils in the northeastern Halahatang area show the coexistence of n -alkanes and 25-norhopanes, indicating that early-expelled oils were severely biodegraded and then mixed with later, fresh charges of oil. Multiple molecular maturity indices suggest that oil maturities increase with depth. Interestingly, 3- + 4-methyldiamantanes, which should be enriched in highly mature oils, are found to be more abundant in less mature oils from shallower reservoirs, with exceptions of only four samples in the northeast. Published data for the eastern Lunnan area display a similar pattern that diamondoids are progressively enriched in shallower oils. The special pattern is interpreted to be the result of phase fractionation induced by a gas-dominated late charge. The late charge of gas firstly extracted diamondoids from deep-buried, highly-cracked oils through evaporative fractionation. As the vapor migrated towards the up-dip direction, decrease of pressure and temperature led to condensation of the diamondoids in the vapor. Briefly, the diamondoids were transferred to relatively shallow reservoirs through a combination of evaporative fractionation and subsequent phase separation. Alternatively, the abnormal enrichment of diamondoids in the northern part may be because of locally vertical charges of highly mature, diamondoid-rich gases through large faults. • The thermal maturity of oils in the Halahatang area increases with depth. • The diamondoid concentrations in the Halahatang area mostly decline with depth. • Inverse distribution of diamondoids resulted from phase fractionation induced by a late gas-dominated charge. • The phase fractionation includes evaporative fractionation and subsequent phase separation. [ABSTRACT FROM AUTHOR]

Currently, there are very limited methods for direct gas-source rock correlation studies. Herein, we applied sulfur isotope analyses of individual volatile organic sulfur compounds (VOSC) in natural gases and dibenzothiophenes (DBTs) in the associated oils from Ordovician reservoirs in Shunbei and Tahe areas of the Tarim Basin, and coupled them with characteristics of gaseous hydrocarbons to elucidate gas-source correlation and secondary alterations in the reservoirs. The results show that the VOSCs in some of the gas samples have reached isotopic equilibrium with the associated H 2 S but with distinct sulfur isotope compositions, suggesting that they may be related to the thermal cracking of kerogen and/or oil, or altered by thermochemical sulfate reduction (TSR). The δ34S values of VOSCs in the gases unaffected by TSR range from +14.9 to +21.3‰, which are correlated well with the Cambrian source rock kerogen and DBTs from its derived oils, indicating the gases may have a Cambrian source. Few gas samples from the Tahe area exhibit higher δ34S values of VOSCs (from +22.9 to +31.6‰) but with no evidence for TSR alteration in the associated oils. This suggests that exogenous TSR-H 2 S was charged into the reservoirs, and altered the δ34S values of the VOSCs. The sulfur isotopes of VOSCs in a gas sample range from +27.3 to +34.8‰ which are close to the Cambrian anhydrite but are not in isotopic equilibrium with the associated H 2 S. This suggests that the VOSCs have interacted with recently migrated H 2 S produced by TSR and the increasing concentrations of H 2 S might have prevented the system from reaching isotopic equilibrium with the VOSC. Thus, VOSC can provide an additional layer of information when interpreting gas generation and migration processes within a complex basin such as the Tarim Basin. • Large variations in δ34S values of VOSCs suggest multiple sources of sulfur, including TSR, for the gases. • The results show that the gases analyzed in the Tarim Basin may be derived from the Cambrian source rock. • VOSCs can be used as a complementary tool to identify natural gas origin and alterations. [ABSTRACT FROM AUTHOR]

Two oolites of the Lower Triassic Feixianguan Formation on the margins of the Kaijiang-Liangping (K-L) Trough in the NE Sichuan Basin were deposited in the upper parts of similar shallowing-upward sequences, and are capped by a subaerial exposure surface. However, they have contrasting diagenetic histories and reservoir qualities: the sour oolitic dolostone reservoirs on the eastern side of the K-L Trough have significantly higher porosities than the sweet oolitic limestone reservoirs on the western side. A petrologic and geochemical comparison of the two oolites was carried out so as to investigate the role of diagenetic processes on the co-evolution of oolite structure and pore network. On both sides of the K-L Trough, eogenetic meteoric digenesis led to an inversion of texture with ooid dissolution and interparticle cementation in the oolite layers close to the exposure surface. The layers relatively far from the exposure surface mostly underwent recrystallization in association with connate seawater, resulting in neomorphic fabrics in the ooid cortices and less interparticle calcite cement. During the subsequent dolomitization, the early-formed oolite structure were mostly inherited by the dolostones on the eastern side, with fabric-retentive textures in the layers close to the exposure surface and fabric-destructive textures in the layers far from the exposure surface. During deeper burial the oolitic limestones were subjected to extensive calcite cementation and porosity loss, whereas the dolostones generally retained more porosity and have better connectivity of the micropore network. The higher porosity of the dolostones is ascribed to lesser chemical compaction and associated cement precipitation, rather than the creation of new pores. Porosity enhancement is closely dependent on the absence of the calcite cement related to pressure solution. The heterogeneity of the dolostone fabrics and the porosity was further enhanced by the subsequent recrystallization and the dissolution-reprecipitation process induced by thermochemical sulfate reduction, during which small amounts of net porosity are calculated to have been created. The oolitic limestones are the best reservoirs close to the exposure surface, whereas the most porous dolostones with the highest degree of fabric destruction are commonly some distance from the exposure surface. These results provide some insights into the diagenetic controls on oolite structure and porosity, and have implications for predicting the porosity of deeply-buried oolitic reservoirs, so have global theoretical and practical significance. • A clear process is reported for the co-evolution of oolite structure and porosity. • The deep extension of the effects of early diagenesis is crucial for late diagenesis. • Meteoric diagenesis has a major control on the final framework of oolitic dolostone. • Recrystallization and TSR enhance the heterogeneity of oolite fabric and porosity. • Dolomitization of oolite results in porosity preservation rather than creation. [ABSTRACT FROM AUTHOR]

Hydrothermal dolomitization is an important diagenetic process that affects the quality of carbonate reservoirs. While geochemical modeling is a useful tool to improve our understanding of this process, comparatively little research has been focused on producing reservoir intervals. This study examines deeply buried (over 4500 m deep), Lower Ordovician dolomitized limestones (more than 50 m revealed by the borehole) in an exploration well in the Tazhong Uplift, Tarim Basin. The well penetrated a fault zone that was affected by extensive hydrothermal activity during the Permian. Batch geochemical modeling and reactive transport modeling (RTM) were used to evaluate the potential sources of hydrothermal fluid and the associated mechanisms that resulted in a relatively restricted distribution of dolomitization in the study area. Simulation results show that the RTM, which can include geological heterogeneity, provides more reliable constraints for the volume of hydrothermal fluids required for the observed scale of dolomitization, compared to batch geochemical modeling. According to the simulation results, the interstitial fluids released from underlying Cambrian formations due to high pressure and high temperature are not the only source of hydrothermal dolomitization. Other mechanism like long-lasting recharge of seawater-derived basement brines may be took place. Scenario simulations also indicate that the patterns of hydrothermal dolomitization and porosity distributions are strongly related to permeability heterogeneity in the formation. This study shows the ability and feasibility of geochemical modeling as a tool to quantitatively evaluate and further understand hydrothermal dolomitization processes, which are also helpful for other similar geological process research. However, reliable and detailed geological information, geological constrains, especially geological heterogeneity distributions, are crucial to achieve beneficial conclusions. • Numerical models were used to evaluate potential hydrothermal fluid sources. • Quantitative evaluations compared available and required dolomitizing fluid volumes. • Reactive transport models provided more reliable constraints for fluid volumes. • Dolomitization patterns correlated with porosity and permeability heterogeneities. [ABSTRACT FROM AUTHOR]