Source Rock Kerogen Research Articles

Evaluation of the molybdenum isotope system as a petroleum tracer: The Phosphoria petroleum system, western U.S.A.

The molybdenum (Mo) isotope composition of organic-rich mudrocks is used to infer paleo-ocean redox conditions but the potential of this isotope system as a petroleum tracer is uncertain. In this study, we measured the Mo isotope compositions of crude oils, asphaltene separates, and organic-rich source mudrocks (Meade Peak Member and Retort Member of the Permian Phosphoria Formation) for the Phosphoria petroleum system, western U.S.A. Crude oils from the Bighorn Basin have Mo concentrations of 0.01–0.39 μg/g that are significantly lower than Mo concentrations of 10–443 μg/g for the organic-rich mudrocks (2.4–16.6 wt% total organic carbon; TOC), suggesting inefficient transfer of Mo from source rock kerogen to oils. Asphaltene Mo concentrations are elevated (1.0–3.2 μg/g), indicating that asphaltene is an important host of Mo in the Phosphoria crude oils. However, statistically insignificant correlation between crude oil and asphaltene Mo concentrations as well as differences between the δ98Mo of some crude oils and their asphaltene separates (Δ98Moasphaltene–crude oil between −0.5‰ and +0.1‰) suggests other important hosts for Mo in the non-asphaltene fraction of the Phosphoria oils. The overall range of δ98Mo for fifteen Phosphoria crude oils and six asphaltene separates is 0.5–1.7‰ and 0.8–1.5‰, respectively. Crude oils unaltered by reservoir processes (biodegradation, water washing, thermochemical sulfate reduction) have δ98Mo of 1.1–1.4‰ whereas crude oils mildly affected by biodegradation and/or water washing span a wider range of δ98Mo (1.0–1.7‰). Five crude oils altered by thermochemical sulfate reduction (TSR), as indicated by higher δ34S, have lower δ98Mo (0.5–0.9‰), suggesting that TSR decreases the δ98Mo of crude oils via redox reactions and/or the introduction of external fluids containing isotopically light Mo into the oil reservoir. Biodegradation may cause variable δ98Mo in crude oils via kinetic isotope effects, microbial processes, or the recapture of isotopically distinctive Mo released from biodegraded oils elsewhere. A statistically significant inverse correlation between δ98Mo and δ34S for non-TSR altered oils may reflect a decrease in the δ98Mo of crude oils with increasing thermal maturity, perhaps associated with de-metalation reactions and/or formation of new organo-metal compounds. The δ98Mo of the unaltered crude oils falls within the range of δ98Mo for the Mo- and TOC-rich source rocks of the Retort and Meade Peake Members (1.0–2.0‰), suggesting the Mo isotope system has potential as an oil – source rock tracer. This application will have the most success in petroleum systems whose source rock(s) exhibit a narrow range of distinctive δ98Mo. Our study shows the Mo isotope system has promise as a petroleum tracer and potentially could be useful for studies on petroleum contamination in the environment.

Sulfate sources of thermochemical sulfate reduction and hydrogen sulfide distributions in the Permian Changxing and Triassic Feixianguan formations, Sichuan Basin, SW China

The sulfate sources of thermochemical sulfate reduction (TSR) and hydrogen sulfide (H2S) distributions in the Permian Changxing (P2c) and Triassic Feixianguan formations (T1f) in the Sichuan Basin were investigated using geochemical and carbon isotopic data for gases, and sulfur isotopic data for solid bitumen, H2S, and anhydrite. The concentration of H2S (>5.0%) is relatively high, and the δ34S values of the H2S are significantly higher than those of the Permian source rock kerogen, suggesting a TSR origin for the H2S. The δ13C values of the methane and ethane do not increase as the gas souring index (H2S/(H2S+∑Cn)) increases, and the δ34S values of the H2S are significantly lower than those of the solid bitumen, suggesting mainly liquid hydrocarbon dominated-TSR. The δ34S values of the solid bitumen and H2S in the Puguang gas field in the eastern platform are significantly lower than those in the Yuanba gas field in the western platform, and the sulfates for the TSR were most likely derived from the Early and Late T1f evaporative seawater, respectively. The sulfates required for TSR were most likely enriched during dolomitization based on the positive relationship between the H2S concentrations and the thickness of the dolostone reservoirs. The H2S distributions were mainly controlled by the sulfate distributions and the paleo-oil accumulations. The edges of the eastern and western platforms in the Kaijiang-Liangping trough, which were favorable for dolomitization and paleo-oil accumulations, are the most likely H2S-enriched areas in the Sichuan Basin.

Kerogen of the Upper Jurassic Source Rocks in the Western Part of the Yenisei–Khatanga Regional Trough

Kerogen of the Upper Jurassic Source Rocks in the Western Part of the Yenisei–Khatanga Regional Trough

Upper Jurassic to Lower Cretaceous source rocks in the Norwegian Barents Sea, part II: Insights from open- and closed-system pyrolysis experiments

The petroleum generation potential of Upper Jurassic to Lower Cretaceous organic rich shales from the southwestern Barents Sea was evaluated using bulk and quantitative pyrolysis analysis. Fifteen thermally-immature samples from the Hekkingen Formation with differing organic facies, as defined by maceral composition, were subjected to total organic carbon, Rock-Eval pyrolysis, pyrolysis gas chromatography, bulk kinetics, and micro-scale sealed vessel pyrolysis analyses. The results were employed to characterize differences in source rock kerogens, gross petroleum type, and the compositional evolution of the generated fluids as well as their physical properties (i.e. gas to oil ratio, saturation pressure, and formation volume factor) as a function of increasing maturity.The investigated samples contain varying proportions of kerogen type II and III. Heterogeneities in the kerogen composition result in different orders of thermal stability, with the onset of petroleum generation predicted to occur over a high and broad temperature range from 123 °C to 144 °C (at 3.3C⁰/Ma). Reduced kerogen stability associated with elevated sulfur contents is only documented in a few samples. Most of the analyzed samples have the potential to generate low GOR oils of an intermediate to aromatic, low wax paraffinic-naphthenic-aromatic (P–N-A) composition and variable amounts of wet gas. Petroleums of similar compositional and physical properties are predicted to have been generated from the natural maturation sequence of various organic facies in thermally mature areas of the Hammerfest Basin and the Ringvassøy-Loppa High and Bjørnøyrenna fault complexes. Vitrinite-rich sources in the Fingerdjupet Sub-basin and the Troms-Finnmark Fault Complex have potential for gas and condensate generation.

The geochemical characteristics, distribution of marine source rocks and gas exploration potential in the northwestern Sichuan Basin, China

In recent years, the northwestern part of the Sichuan Basin has become a popular location for natural gas exploration. However, up to this point, the geochemical characteristics and distribution of marine source rocks in this area have not been thoroughly investigated. In the northwestern Sichuan Basin, there are eight sets of marine source rock, including the Lower Sinian Doushantuo Formation, the third Member of Upper Sinian Dengying Formation, the Lower Cambrian Qiongzhusi Formation, the Lower Silurian Longmaxi Formation, the Middle Devonian, the Middle Permian Maokou Formation, the Upper Permian Longtan Formation/Wujiaping Formation, and the Upper Permian Dalong Formation, from which eight outcrop profiles were selected for systematic organic geochemical analysis. The Qiongzhusi Formation has the thickest high-quality source rocks, up to 80 m thick, followed by the Upper Permian Longtan/Wujiaping and Dalong formations, which have up to 20–30 m thick high-quality source rocks, whereas the thickness in other layers is relatively thin. By the abundance of organic matter, the Doushantuo, Qiongzhusi, Longmaxi, Longtan/Wujiaping, and Dalong formations developed high-quality source rocks with total organic carbon content (TOC) greater than 3%, while the third Member of Upper Sinian Dengying Formation, Middle Devonian and Maokou formations had low TOC. The kerogen of source rocks gradually enriched 13C from the type Ⅰ organic matter of the Lower Cambrian Qiongzhusi Formation to the Upper Permian Dalong Formation, and the δ13C values of Doushantuo Formation, the third Member of Dengying Formation, and Qiongzhusi Formation are less than −30.0‰. The δ13C values of Longtan Formation or Wujiaping Formation and Dalong Formation with type Ⅱ2 organic matter ranges from −28.0‰ and −26.0‰. Others lie somewhere in between type I and type II2. Except for Permian source rocks in Guangyuan and Chaotian areas, which are in the mature stage, source rocks in the northwestern Sichuan Basin are in the over-mature stage and largely in the thermal stage of dry gas. High abundance source rocks have provided rich marine natural gas resources. As a result, future gas exploration in the northwestern Sichuan Basin will focus on the gas-bearing system associated with the Qiongzhusi Formation and Upper Permian source rocks.

Effect of Kerogen Thermal Maturity on Methane Adsorption Capacity: A Molecular Modeling Approach.

The presence of kerogen in source rocks gives rise to a plethora of potential gas storage mechanisms. Proper estimation of the gas reserve requires knowledge of the quantities of free and adsorbed gas in rock pores and kerogen. Traditional methods of reserve estimation such as the volumetric and material balance approaches are insufficient because they do not consider both the free and adsorbed gas compartments present in kerogens. Modified versions of these equations are based on adding terms to account for hydrocarbons stored in kerogen. None of the existing models considered the effect of kerogen maturing on methane gas adsorption. In this work, a molecular modeling was employed to explore how thermal maturity impacts gas adsorption in kerogen. Four different macromolecules of kerogen were included to mimic kerogens of different maturity levels; these were folded to more closely resemble the nanoporous kerogen structures of source rocks. These structures form the basis of the modeling necessary to assess the adsorption capacity as a function of the structure. The number of double bonds plus the number and type of heteroatoms (O, S, and N) were found to influence the final configuration of the kerogen structures, and hence their capacity to host methane molecules. The degree of aromaticity increased with the maturity level within the same kerogen type. The fraction of aromaticity gives rise to the polarity. We present an empirical mathematical relationship that makes possible the estimation of the adsorption capacity of kerogen based on the degree of polarity. Variations in kerogen adsorption capacity have significant implications on the reservoir scale. The general trend obtained from the molecular modeling was found to be consistent with experimental measurements done on actual kerogen samples. Shale samples with different kerogen content and with different maturity showed that shales with immature kerogen have small methane adsorption capacity compared to shales with mature kerogen. In this study, it is shown for the first time that the key factor to control natural gas adsorption is the kerogen maturity not the kerogen content.

Potential of Light Oil and Condensates from Deep Source Rocks Revealed by the Pyrolysis of Type I/II Kerogens after Oil Generation and Expulsion

Light and condensable oils derived from mature kerogen and residual oil in deep source rocks have contributed strongly to a rapid increase in oil production. In this study, oil expulsion from kerog...

Geochemical characteristics of Middle-Upper Ordovician source rocks in the Kalpin outcrop profiles and marine oil-source correlation, Tarim Basin, NW China

The Middle-Upper Ordovician source rocks developed in six outcrop profiles in the Kalpin area, Tarim Basin, NW China were analyzed using an organic geochemical screening method. Most TOC values of source rocks of Salgan Formation of Middle-Upper Ordovician developed in the Dawangou, Kamatikan, and Tonggusibulong outcrop profiles are greater than 1.0%, whereas the TOC value of the source rocks of Yingan Formation of Upper Ordovician only developed in the Dawangou outcrop ranged from 0.14% to 1.29%, with an average value lower than that of the Salgan Formation source rocks. Combined with the analysis results of source rocks of Yuertusi Formation of Lower Cambrian developed in the Xiaoerbulake, Sugaite and West Yuti outcrop profiles, the source rocks of Yuertusi, Salgan and Yingan Formations showed similar molecular geochemical characteristics, with low Pr/Ph value, C23 greater than C21 tricyclic terpane, high gamacerane and C28 sterane content. The similarity in molecular compounds of Cambrian to Ordovician source rocks in the Kalpin area may be a result of the high maturity. In the relative distribution of C27–C29 regular steranes, the marine oils with C28 sterane lower than 25% showed great difference with that of the source rocks of Lower Cambrian Yuertusi Formation. In the distribution of carbon isotopic curves, the source rocks of Lower Cambrian Yuertusi Formation have lighter carbon isotopes, compared with that of the Middle-Upper source rocks, especially in kerogen carbon isotopes, Lower Cambrian Yuertusi Formation lighter 5‰ than that of Middle-Upper Ordovician source rocks. Overall, the carbon isotopes fractionation of saturate, bitumen, aromatic fraction, resin, asphaltene, and kerogen is small in source rocks from Middle-Upper Ordovician Salgan and Yingan Formations in the Kalpin area. It is suggested that the carbon isotope of kerogen of source rocks can be used as a parameter for oil-source correlation excluding the TSR of the oil reservoirs.

A geochemical investigation into the resource potential of the Lawn Hill Platform, northern Australia

The Lawn Hill Platform (LHP) is a sedimentary province in north-eastern Northern Territory and north-western Queensland that hosts a significant Paleoproterozoic–Mesoproterozoic sequence, often referred to as 'the ‘Isa Superbasin’, and includes the overlying South Nicholson Group. Shale gas resources and base-metals mineralisation are known in north-west Queensland, but the larger basin is underexplored. The Australian Government’s Exploring for the Future (EFTF) 2016−2020 program aims to boost resource exploration in northern Australia. New precompetitive geochemical data obtained in this program includes source rock geochemistry, kerogen kinetics, bitumen reflectance, biomarker and δ13C n-alkanes for understanding the petroleum potential, organic geochemistry of source rocks and fluids, stratigraphic correlations and mineralogy to determine the brittleness of shales. All data and derived reports are accessible on the EFTF portal (www.eftf.ga.gov.au), providing a central location for informed decision making. The results in this study demonstrate fair to excellent source rocks in multiple supersequences that are brittle and favourable to hydraulic stimulation. A comparison to the greater McArthur Basin demonstrates, that although there are many similarities in bulk geochemistry, LHP mudstones are largely heterogeneous, reflecting local variations that may be inherited from variations in contributing biomass, microbial reworking, depositional environment, sediment input and paleoredox conditions.

Molecular simulation of kerogen-water interaction: Theoretical insights into maturity

The ubiquity of water and kerogen in source rocks at reservoir conditions is a clear indication that the study of kerogen-water system plays a key role and relevant to the current state of knowledge for fundamental and applied shale research. From the early experimental studies, it is acknowledged that kerogen insolubility in a typical organic solvent is due in part to their complex molecular structure. From a theoretical perspective, we aim to understand the molecular interaction of kerogen-water system at the atomic level. The petrophysical implication of this study is to understand the impact of maturity level of kerogen on the water recognition relative to other inorganic components of shale. For this purpose, we have calculated the adsorption free energies of water molecule on multi-configurations of kerogen model in a high mature state using B3LYP/Def2TZVP level of theory. Different models were built to reflect the diversity of kerogen composition (related to the heteroatoms). Furthermore, we have calculated the electrostatic potential and frontiers molecular orbitals to interpret and explain the trend observed in the adsorption free energies. The main finding of our study supported that there are no tight interactions between the water molecules and kerogen. The water-recognition by kerogen surface depends mainly on its constituents of the heteroatoms (N, S, and O). Indeed, nitrogen atoms displayed the highest affinity to ward moisture, followed by oxygen and sulfur. Given that kerogen in its high mature state does not consists much of nitrogen atoms, in that context, the matured kerogen would be less likely to adsorb water molecules in absence of gas.

Stable isotope reversal and evolution of gas during the hydrous pyrolysis of continental kerogen in source rocks under supercritical conditions

Semi-closed hydrous pyrolysis experiments were conducted to investigate the isotopic evolution of shale gas produced from continental organic-rich shales with increasing thermal maturity and prospecting potential. The δ13C values of methane, ethane, propane and n-butane became heavier with increasing thermal maturity and showed good relationships with vitrinite reflectance (VR). Gases expelled from type-I, type-II, and type-III kerogens followed the normal carbon sequence (δ13CC1 < δ13CC2 < δ13CC3 < δ13CnC4) and the hydrogen isotopic sequence (δ2HC1 < δ2HC2 < δ2HC3 < δ2HnC4 < δ2HiC4) among the alkanes at VRs lower than 2.14% Ro, 2.42% Ro, and 1.87% Ro respectively. The isotopically reversed gases (δ13CC1 < δ13CC2 < δ13CnC4 < δ13CC3) were observed in type-I kerogen with a VRs above 2.14% Ro and in type-II kerogen with a VR above 2.42% Ro. In type-III kerogen, isotopically reversed gases (δ13CC1 < δ13CnC4 < δ13CC3 < δ13CC2) were observed with a VR above 2.94% Ro. These results suggest four stages in the stable carbon isotope reversal of ethane, propane, and n-butane with increasing maturity. The isotopically reversed gases (δ13CC1 < δ13CC2 < δ13CnC4 < δ13CC3) may represent lower maturity and higher productivity shale gas than the isotopically reversed gases (δ13CC1 < δ13CnC4 < δ13CC3 < δ13CC2), indicating that continental type-I kerogen has the highest potential productivity for shale gas, and continental type-III kerogen has the lowest. Stable hydrogen isotope composition did not respond to the stable carbon isotope reversal in isotopically reversed gases. We suggest that indigenous generation and mixing may be the dominant mechanisms responsible for the stable carbon isotope reversal, and adsorption/desorption during hydrocarbon expulsion may promote the stable isotope reversal under semi-closed conditions. Overall, these results suggest that this study is an important contribution to continental shale gas exploration.

Hydrocarbon generation potential of the C-P continental source rocks in the Qinshui Basin

The hydrocarbon generation potential of continental source rocks in the Carboniferous-Permian (C-P) coal-bearing stratum in the Qinshui Basin were systematically analyzed in this paper. Ro of the C-P source rocks is mainly distributed between 1.5% and 2.5%. The coal rock belongs to a typical type III organic matter, while the mudstone mainly contains type III organic matter and a small proportion of type II2 organic matter. Moreover, The geochemical characteristics of the source rock kerogen was analyzed in detail. Finally, an evaluation standard for hydrocarbon generation potential of the C-P continental source rocks was proposed.

Origin, source, mixing, and thermal maturity of natural gases in the Panyu lower uplift and the Baiyun depression, Pearl River Mouth Basin, northern South China Sea

Multiple natural gas fields have been discovered in the Baiyun depression and the adjoining Panyu lower uplift in the Pearl River Mouth Basin, northern South China Sea. The natural gases are associated with condensate and are characterized by relatively heavy carbon isotopes, with methane and ethane δ13C values ranging from –44.2‰ to –33.6‰ and –30.0‰ to –25.4‰, respectively. Nearly all methane and ethane are derived from oil-prone type II kerogen in the Wenchang Formation source rock, whereas the heavy hydrocarbon gases (propane, butanes, and pentanes) are derived from both the Wenchang and Enping (type III kerogen) Formations, based on an integrated comparison of carbon isotopic compositions of the natural gases, typical type I/II and type III kerogen-derived gases, and the Enping and Wenchang kerogens. The gases from the eastern parts of the Baiyun depression and the Panyu lower uplift mainly originate from secondary oil cracking and primary kerogen cracking, respectively. The gases from the northern slope of the Baiyun depression are a mixture of oil-cracking and kerogen-cracking gases. Both oil-cracking and kerogen-cracking gases were mainly generated from the Wenchang Formation source rock in the maturity range of 1.5%–2.5% vitrinite reflectance, with a corresponding present-day depth range of 5400–6500 m (17,700–21,300 ft). The apparent contribution of the Wenchang Formation to the discovered gas accumulations demonstrates that it is the most important source rock in the area, instead of the Enping Formation. The search for more gas derived from oil cracking will be the next natural gas exploration direction in the Baiyun depression.

The effect of pressure and hydrocarbon expulsion on hydrocarbon generation during pyrolyzing of continental type-III kerogen source rocks

In order to define the roles of water and lithostatic pressure in petroleum formation of continental type-III kerogen source rocks, semi-closed hydrous pyrolysis experiments were conducted under with 50–1200 bar water pressure and 125–2000 bar lithostatic pressure at 480 °C. Our results will be of great benefit to the exploration of shale gas and deep petroleum in China. Increasing water pressure from 50 to 325 bar did not affect the yields of gaseous hydrocarbons, oil and bitumen, but increasing water pressure leads the more oil and less gaseous hydrocarbons from continental type-III kerogen in the 325–1200 bar water pressure range under semi-closed conditions. The decreasing yields of gaseous hydrocarbons, dryness of gaseous hydrocarbons and primary hydrogen together confirm that increasing water pressure promotes the primary reaction but decreases the cracking rate of oil. The decreasing values of S2, HI and H/C in the pyrolysed samples confirm that high water pressure can increase the efficiency of hydrocarbon generation from continental type-III kerogen, while the maturation of kerogen correspondingly increases as shown by increasing values of VR and Tmax. In the 125–625 bar lithostatic pressure range, oil cracking and primary reaction of type-III kerogen may have contributed to the decreasing effect of hydrocarbon expulsion. The increasing hydrogen and gaseous hydrocarbon yields also confirm that the cracking of oil is enhanced within this pressure range. The decreasing trends of oil and gaseous hydrocarbon yields indicate that hydrocarbon generation rate was reduced by the high lithostatic pressure in the 625–2000 bar pressure range. The increasing values of S2, HI and H/C, and decreasing values of VR and Tmax of pyrolysed samples confirm the retardation effect of highlithostatic pressure on the efficiency of hydrocarbon generation and maturation. In addition, the results also indicate that expelling hydrocarbons strongly promotes further hydrocarbon generation and retards the cracking of oil from continental type-III kerogen in source rocks.

Hydrocarbon generation capability of Sinian–Lower Cambrian shale, mudstone, and carbonate rocks in the Sichuan Basin, southwestern China: Implications for contributions to the giant Sinian Dengying natural gas accumulation

The giant natural gas accumulation recently discovered within the (Neoproterozoic) Dengying Formation in the Sichuan Basin of southwestern China represents a new and important supplement to the ancient Neoproterozoic–Cambrian petroleum systems worldwide. However, the source of this gas is controversial because there are five possibilities based on geology, from bottom to top including the Lower Sinian Doushantuo mudstone, the Upper Sinian Dengying algal dolomite, the mudstone of the third member of the Dengying Formation, the Lower Cambrian Maidiping argillaceous dolomite, and the Lower Cambrian Qiongzhusi shale. To improve the understanding of this issue, 33 samples from the five possible source rock units in the study area were investigated for their character and maturity via petrology, total organic carbon (TOC), pyrobitumen reflectance, kerogen carbon isotope, and biomarker analyses. Based on the results, we address their hydrocarbon generation capabilities and contributions to the giant gas accumulation. Results show that present-day TOC values of the samples range from 0.03% to 2.36% and vary both regionally and stratigraphically, with the Qiongzhusi shales in the central basin and the Weiyuan–Ziyang area ranking the highest. In contrast, the organic matter source and maturity within these rocks are relatively homogenous with slight variation throughout the study area. The organic matter is predominantly derived from algae and bacteria with different compositions deposited in marine reducing environments. The rocks range in thermal maturity from postmature to overmature. These results imply that the generation capability of source rock had been high in the past, and the gas in the study area is most likely originated from oil cracking and the late generation directly from the kerogen of source rocks, with the Qiongzhusi shales being the dominant source rock. Thus, the hydrocarbon migration pattern in the study area is a lateral migration from deep-seated and younger Cambrian source rocks in sags to shallow-seated and older Sinian dolomite reservoirs in uplifts. The migration process occurred in the oil phase with the oil being later cracked. The differences in natural gas geochemistry may be controlled by complex factors, e.g., thermal maturity, the migration–accumulation process, and differing contributions from source rocks besides the dominant Qiongzhusi. Regionally, the central basin and the Weiyuan–Ziyang area have had high hydrocarbon generation capability and thus should be considered as favorable targets for natural gas exploration in the future. This study of China provides an additional example of Neoproterozoic–Cambrian petroleum systems worldwide and thus can help to synthesize the systematics of such systems and understand the sedimentary transition across the Precambrian–Cambrian boundary.

Petrography, fluid-inclusion, isotope, and trace-element constraints on the origin of quartz cementation and feldspar dissolution and the associated fluid evolution in arkosic sandstones

Feldspar dissolution, quartz cementation, and clay cementation are significant diagenetic processes in deep-water fan feldspar-rich sandstones in the Shengtuo area, Dongying sag (East China). The timing and origin of these water–rock interactions as well as the paleofluids in which relevant chemical reactions occurred were deduced using data from microscopy, fluid-inclusion microthermometry, oxygen-isotope microanalysis, and trace-element microanalysis. Three distinct, separate episodes of quartz overgrowths (referred to as Q1, Q2, and Q3) were distinguished by cathodoluminescence microscopy. The Q1 quartz, identified in all porous sandstones from 2500 to 3600 m (8200 to 11,800 ft), was formed at approximately 100°C–115°C (212°F–239°F) before oil filled the reservoirs. The Q2 quartz was mainly precipitated at 115°C–130°C (239°F–275°F), accompanying or slightly postdating the main phase of oil filling, and was identified in samples from 2800 to 3600 m (9200 to 11,800 ft). The Q3 quartz was only identified in sandstones buried deeper than 3500 m (11,400 ft) and was likely precipitated in the Quaternary when temperature exceeded 130°C–135°C (266°F–275°F). Secondary ion mass spectrometry oxygen-isotope microanalyses yielded δ18OVSMOW (Vienna standard mean ocean water) values ranging from 21.42‰ to 24.35‰ for Q1 quartz, from 22.03‰ to 24.99‰ for Q2 quartz, and from 21.72‰ to 22.91‰ for Q3 quartz. A mass-balance calculation and quantitative petrography data of the amount of leached feldspars and associated secondary minerals suggest that the internal feldspar dissolution is likely the primary source for the authigenic clays and quartz cements in these sandstones. Positive δ18O(water) values (+0.5‰ to +4.5‰ VSMOW) of quartz-forming waters indicate that quartz cementation and feldspar dissolution occurred in a geochemical system with a limited volume of diagenetically modified connate water. The variations of δ18O(cements) and trace-element compositions from Q1 quartz to Q2 quartz in individual overgrowth suggest that hydrocarbon filling changed the chemistry of the pore fluid significantly; further, δ18O(water) values of the pore water increased by approximately 2‰ VSMOW after oil filling. Meteoric freshwater did not contribute to quartz cementation and simultaneous feldspar dissolution. The detected CO2 and hydrocarbons in fluid inclusions in the quartz cements, the existence of CO2 in hydrocarbon-rich natural gas, and the pyrobitumen in the feldspar-hosted pores suggest that acids derived from organic matter (kerogen in source rocks and hydrocarbons in reservoirs) probably have promoted the extensive subsurface leaching reactions of feldspars in these sandstones. The ongoing development of Q2 and Q3 quartz suggests that quartz precipitation did not cease after oil filling. Further, diagenetic reactions likely have proceeded from water–rock interactions to hydrocarbon–water–rock interactions.

In situ geochemical characterization of pyrite crystals in burial dolomites of St. George Group carbonates

Secondary ion mass spectrometry (SIMS) was used to measure the δ34S of pyrite disseminated in burial dolomite matrix of Boat Harbour formation at Main Brook and Daniel’s Harbour (about 130 km apart). At Main Brook, δ34S values for the pyrite grains show wide variation (–15 to +20‰ (n = 20)), but are mostly negative. Combined with a paucity of two-phase fluid inclusions in the host burial dolomite, the depleted δ34S values suggest that the pyrite is a direct product of bacterial sulfate reduction (BSR). Predominantly negative δ34S values were also obtained for sampled pyrite at Daniel’s Harbour and Port au Choix; however, relatively high homogenization temperatures (&gt;100 °C) of two-phase fluid inclusions in the host dolomite is incompatible with a BSR process for pyrite formation. More so, Daniel’s Harbour is a site for main stage sulfide mineralization (Mississippi Valley-type (MVT) system), hosted in similarly burial dolomite and that has been previously constrained to be associated with thermochemical sulfate reduction (TSR). A relative proximity of the currently studied pyrite samples to this MVT system deposit is thus inconsistent with an in-situ BSR for these pyrites. The analyzed pyrite grains are commonly encased in bitumen, and they postdate their host burial dolomite and predate deep burial saddle dolomite. Taken together, the depleted δ34S signature in the pyrite was likely inherited from migrated hydrocarbons in the reservoir. Incursion of an initial pulse of hot sulfate-rich brine into the formation can cause thermal cracking of hydrocarbons, thereby releasing its low δ34S. Thus the inherited low δ34S signature was likely a product of an earlier BSR that occurred in the kerogen or source organic materials in source rock. Subsequently, the main stage sulfide mineralization (MVT deposit) occurred via in-situ TSR. These findings have an implication for the paragenetic history of sulfide minerals precipitated during MVT mineralization episode.

Sulfur and carbon isotopic compositions of the Permian to Triassic TSR and non-TSR altered solid bitumen and its parent source rock in NE Sichuan Basin

Reservoir solid bitumens from the Permian to Triassic and potential source rocks in the northeastern Sichuan Basin were measured for elemental and stable carbon (δ13C) and sulfur (δ34S) isotopic compositions to determine the chemical and isotopic composition of non-TSR and TSR-altered solid bitumen and to develop proxies to reflect the extent of bitumen alteration by TSR. Non-TSR altered reservoir bitumen samples showed S/C atomic ratios ⩽0.03 and had δ13C values closer to Longtan Formation (P3l) kerogen than to the Lower Silurian and Cambrian kerogens, and δ34S values slightly more enriched than P3l kerogens. The TSR-altered solid bitumens have incorporated significant amounts of TSR-derived H2S resulting in S/C atomic ratios (0.047–0.074) and δ34S values (13.4–24.0‰) being significantly higher than those of the solid bitumen not altered by TSR (S/C: 0.013–0.030; δ34S: 5.8–9.6‰) and the potential source rock kerogen. The incorporation has produced a decrease in N/C ratio and negative shift of −2.7‰ in δ13C values that resulted from increasing TSR-H2S back reactions with 12C-rich n-alkanes from the gas phase, soluble solid bitumen or paleo-oil to generate organic sulfur compounds such as ethanethiol that were incorporated into the solid bitumens, which is followed by further aromatization and polymerization. The solid bitumens show positive relationships of S/C ratios and δ34S values to the associated gas H2S/(H2S+ΣC1–6) or TSR extents, and thus the S/C ratios and δ34S values can be used as proxies to reflect TSR extents.

Sedimentary characterization of the carbonate source rock of Upper Kimmeridgian Parnac Formation of the Aquitaine Basin (Quercy area)

The main source rock (SR) of the Aquitaine Basin, the most important oil province in France, corresponds to organic-rich marine limestones of Upper Kimmeridgian age (Lons Formation in the Béarn area and Parnac Formation in the Quercy area). In order to better characterize their depositional environment, in particular the conditions of accumulation and preservation of organic-matter, a sedimentological, micropaleontological and geochemical study of the Crayssac section (Quercy) has been performed. Organic-rich sediments are argillaceous limestones (65 to 99% CaCO3) organized in repetitive beds of up to 1-m thickness. Their total organic matter content reaches up to 15 wt.%, and in this SR kerogen is type of II and immature. Microfauna content, the lack of barrier facies and the control of the wave action base over the depositional environments reflect deposition in an open marine type homoclinal ramp. Strong similarities with Kimmeridgian organic-rich limestones of the Middle East (Hanifa Formation) suggest that the Parnac Formation could act as an analogue of this prolific SR.

The effects of pressure and hydrocarbon expulsion on hydrocarbon generation during hydrous pyrolysis of type-I kerogen in source rock

Hydrous pyrolysis experiments were conducted on immature petroleum source rocks to define the roles of pressure and hydrocarbon expulsion in deep petroleum formation. This study can contribute to estimating the deep oil and natural gas prospects of lacustrine type-I kerogen and has important implications for deep petroleum exploration. The simulation temperature was 450 °C and the heating duration was 48 h. Water pressure ranged between 50 and 1200 bar, and lithostatic pressure ranged between 125 and 2000 bar. Under semi-closed conditions, increasing water pressure leads to more oil and less gaseous hydrocarbons being generated in the source rocks. The dryness of the hydrocarbon gas primarily confirms that increasing water pressure decreases the cracking magnitude of oil, which may indicate that high water pressures retard oil cracking. The decreasing contents of S2, HI and H/C in the solid residue confirm that high water pressure enhances the efficiency of hydrocarbon generation. Oil cracking is enhanced in the 125–625 bar lithostatic pressure range, probably because the pyrolysis conditions gradually approach those of a closed-system. The increasing gaseous hydrocarbon yields also confirm the accelerated cracking of oil within this pressure range. As lithostatic pressure increased from 625 to 2000 bar, the decreasing trends in oil and gaseous hydrocarbon yields indicate that hydrocarbon generation rate was retarded by high pressure within the closed system. The values of S2, HI, H/C, Ro and Tmax in solid pyrolysis residue confirm that high lithostatic pressure reduces the efficiency of hydrocarbon generation and maturation. Furthermore, hydrocarbon expulsion greatly impacts hydrocarbon generation within the source rocks. Increasing water pressure increases the effect of hydrocarbon expulsion and causes the pyrolysis conditions to gradually approach an open system; this phenomenon lowers the gas yields but increases oil yields. Increasing lithostatic pressure from 125 to 625 bar decreases the effect of hydrocarbon expulsion and causes the pyrolysis conditions to steadily approach a closed system, thereby lowering the oil yield but increasing gas yield. The results demonstrate that different pressures clearly have different effects on hydrocarbon generation in the source rock, and hydrocarbon expulsion also has a significant influence on hydrocarbon generation in source rock. More importantly, this study shows that the lacustrine type-I kerogen has a good potential to yield deep oil and natural gas.