Modelling the petroleum generation and migration of the third member of the Shahejie Formation (Es3) in the Banqiao Depression of Bohai Bay Basin,Eastern China

The mudstones in the third member of the Shahejie Formation (Es3) are the primary source rocks in the Banqiao Depression of Bohai Bay Basin. They are rich in organic matter with Total Organic Carbon (TOC) content up to 3.5%. The sandstones in the Es3 member are the deepest proven hydrocarbon reservoir rocks with measured porosity and permeability values ranging from 3.6% to 32.4% and from 0.01 md to 3283.7 md, respectively. One, two and three-dimensional basin modelling studies were performed to analyse the petroleum generation and migration history of the Es3 member in the Banqiao Depression based on the reconstruction of the burial, thermal and maturity history in order to evaluate the remaining potential of this petroleum province. The modelling results are calibrated with measured vitrinite reflectance (R_o), borehole temperatures and some drilling results of 63 wells in the study area. Calibration of the model with thermal maturity and borehole temperature data indicates that the present-day heat flow in the Banqiao Depression varies from 59.8 mW/m² to 61.7 mW/m² and the paleo-heat flow increased from 65 Ma to 50.4 Ma, reached a peak heat-flow values of approximately 75 mW/m² at 50.4 Ma and then decreased exponentially from 50.4 Ma to present-day. The source rocks of the Es3 member are presently in a stage of oil and condensate generation with maturity from 0.5% to 1.8% R_o and had maturity from 0.5% to 1.25% R_o at the end of the Dongying Formation (Ed) deposition (26 Ma). Oil generation (0.5% R_o) in the Es3 member began from about 37 Ma to 34 Ma and the peak hydrocarbon generation (1.0% R_o) occurred approximately from 30 Ma to 15 Ma. The modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the Es3 member source rocks began from 31 Ma to 10 Ma with the peak hydrocarbon expulsion shortly after 26 Ma. Secondary petroleum migration pathways in the Es3 member of the Banqiao Depression are modelled based on the structure surfaces at 26 Ma and present-day, respectively. The migration history modelling results have accurately predicted the petroleum occurrences within the Es3 member of the Banqiao Depression based on the calibration with drilling results of 10 oil-producing wells, one well with oil shows and 52 dry holes. Six favorable zones of oil accumulations in the Es3 member of the Banqiao Depression are identified especially oil accumulation zones I and II due to their proximity to the generative kitchens, short oil migration distances and the presence of a powerful drive force.     

Distribution and significance of novel low molecular weight sterenes in an immature evaporitic sediment from the Jinxian Sag,North China

An unusual series of C₂₂–C₂₇ monounsaturated sterenes and C₂₄–C₃₀ tetracyclic terpanes (17,21-secohopanes) were detected in relatively high concentrations in an immature evaporitic marl sediment of the Jinxian Sag, Bohai Bay Basin, North China. The site of unsaturation in these novel sterenes is assigned tentatively to the D ring on the basis of mass spectral interpretation, which also distinguishes them from reported unsaturated sterenes. Other hydrocarbon biomarker or stable isotope characteristics are indicative of microbial (e.g. methyl hopanes), phytoplankton or higher plant (depleted δ¹³C values of isoprenoids and hopanes) inputs and an anoxic carbonate depositional environment (hexacyclic hopanes; tetracyclic terpanes). The hydrocarbon composition showed no obvious biodegradation and the relatively high concentration of unsaturated terpenoids (e.g. gammacerene) and low values of other established maturity parameters (T_s/T_m = 0.23; R_o = 0.44%; T_max = 417 °C), are consistent with sediments of low maturity. The novel, low molecular weight sterenes and the tetracyclic terpanes may be early diagenetic products of microbial sources in a carbonate environment.     

Stable carbon isotope geochemistry of adsorbed alkane gases in near-surface soils of the Saurashtra Basin,India

The stable carbon isotopic compositions of light hydrocarbon gases adsorbed in near-surface soil and sediments from the Saurashtra basin were characterized for their origin and maturity. Saurashtra is considered geologically prospective for oil and gas reserves; however, a major part of the basin is covered by the Deccan Traps, hindering the exploration of Mesozoic hydrocarbon targets. Surface geochemical prospecting, based on micro-seepage of hydrocarbons from subsurface accumulations, could be advantageous in such areas. In light of this, 150 soil samples were collected from the northwestern part of Saurashtra, around the Jamnagar area, where a thick sedimentary sequence of about 2–3 km exists under 1–1.5 km of Deccan basalt. The concentration of acid desorbed alkane gases from soil samples was found to vary (in ppb) as: methane (C₁) = 3–518; ethane (C₂) = 0–430; propane (C₃) = 0–331; i-butane (iC₄) = 0–297; n-butane (nC₄) = 2–116; i-pentane (iC₅) = 0–31 and n-pentane (nC₅) = 0–23, respectively.Fifteen samples with high concentrations of alkane gases were measured for their δ¹³C₁; δ¹³C₂ and δ¹³C₃ compositions using gas chromatography–combustion-isotope ratio mass spectrometry (GC–C-IRMS). The values for methane varied from ? 27 to ? 45.4‰, ethane from ? 20.9 to ? 27.6‰, and propane from ? 20.4 to ? 29.1‰ versus the Vienna PeeDee Belemnite (VPDB). The carbon isotope ratio distribution pattern represents isotopic characteristics pertaining to hydrocarbon gases derived from thermogenic sources. Comparisons of carbon isotopic signatures and compositional variations with the standard carbon isotopic models suggest that hydrocarbon gases found in the shallow depths of the study area are not of bacterial origin but are formed thermally from deeply buried organic matter, likely to be mainly a terrestrial source rock with a partial contribution from a marine source. These gases may have migrated to the near-surface environment, where they represent an admixture of thermally generated hydrocarbon gases from mixed sources and maturity. The maturity scale (δ¹³C versus Log Ro %) applied to the surface sediment samples of the Jamnagar area indicated the source material to be capable of generating oil and gas. The detection of thermogenic alkane gases in near-surface sediments offers the possibility of hydrocarbons at depth in Saurashtra.     

Geochemical comparison between gas in fluid inclusions and gas produced from the Upper Triassic Xujiahe Formation,Sichuan Basin,SW China

Natural gas in the Xujiahe Formation of the Sichuan Basin is dominated by hydrocarbon (HC) gas, with 78–79% methane and 2–19% C₂₊ HC. Its dryness coefficient (C₁/C_1–5) is mostly < 0.95. The gas in fluid inclusions, which has low contents of CH₄ and heavy hydrocarbons (C₂₊) and higher contents of non-hydrocarbons (e.g. CO₂), is a typical wet gas produced by thermal degradation of kerogen. Gas produced from the Upper Triassic Xujiahe Formation (here denoted field gas) has light carbon isotope values for methane (δ¹³C₁: −45‰ to −36‰) and heavier values for ethane (δ¹³C₂: −30‰ to −25‰). The case is similar for gas in fluid inclusions, but δ¹³C₁ = −36‰ to −45‰ and δ¹³C₂ = −24.8‰ to −28.1‰, suggesting that the gas experienced weak isotopic fractionation due to migration and water washing. The field gas has δ¹³C_CO2 values of −15.6‰ to −5.6‰, while the gas in fluid inclusions has δ¹³C_CO2 values of −16.6‰ to −9‰, indicating its organic origin. Geochemical comparison shows that CO₂ captured in fluid inclusions mainly originated from source rock organic matter, with little contribution from abiogenic CO₂. Fluid inclusions originate in a relatively closed system without fluid exchange with the outside following the gas capture process, so that there is no isotopic fractionation. They thus present the original state of gas generated from the source rocks. These research results can provide a theoretical basis for gas generation, evolution, migration and accumulation in the basin.     

Organic geochemistry of the Vindhyan sediments: Implications for hydrocarbons

The organic geochemical methods of hydrocarbon prospecting involve the characterization of sedimentary organic matter in terms of its abundance, source and thermal maturity, which are essential prerequisites for a hydrocarbon source rock. In the present study, evaluation of organic matter in the outcrop shale samples from the Semri and Kaimur Groups of Vindhyan basin was carried out using Rock Eval pyrolysis. Also, the adsorbed low molecular weight hydrocarbons, methane, ethane, propane and butane, were investigated in the near surface soils to infer the generation of hydrocarbons in the Vindhyan basin. The Total Organic Carbon (TOC) content in shales ranges between 0.04% and 1.43%. The S₁ (thermally liberated free hydrocarbons) values range between 0.01–0.09 mgHC/gRock (milligram hydrocarbon per gram of rock sample), whereas the S₂ (hydrocarbons from cracking of kerogen) show the values between 0.01 and 0.14 mgHC/gRock. Based on the T_max (temperature at highest yield of S₂) and the hydrogen index (HI) correlations, the organic matter is characterized by Type III kerogen. The adsorbed soil gas, CH₄ (C₁), C₂H₆ (C₂), C₃H₈ (C₃) and nC₄H₁₀, (nC4), concentrations measured in the soil samples from the eastern part of Vindhyan basin (Son Valley) vary from 0 to 186 ppb, 0 to 4 ppb, 0 to 5 ppb, and 0 to 1 ppb, respectively. The stable carbon isotope values for the desorbed methane (δ¹³C₁) and ethane (δ¹³C₂) range between −45.7‰ to −25.2‰ and −35.3‰ to −20.19‰ (VPDB), respectively suggesting a thermogenic source for these hydrocarbons. High concentrations of thermogenic hydrocarbons are characteristic of areas around Sagar, Narsinghpur, Katni and Satna in the Son Valley. The light hydrocarbon concentrations (C₁–C₄) in near surface soils of the western Vindhyan basin around Chambal Valley have been reported to vary between 1–2547 ppb, 1–558 ppb, 1–181 ppb, 1–37 ppb and 1–32 ppb, respectively with high concentrations around Baran-Jhalawar-Bhanpur-Garot regions (Kumar et al., 2006). The light gaseous hydrocarbon anomalies are coincident with the wrench faults (Kota – Dholpur, Ratlam – Shivpuri, Kannod – Damoh, Son Banspur – Rewa wrench) in the Vindhyan basin, which may provide conducive pathways for the migration of the hydrocarbons towards the near surface soils.     

The composition,origin and fate of complex mixtures in the maltene fractions of hydrothermal petroleum assessed by comprehensive two-dimensional gas chromatography

Sedimentary organic matter in hydrothermal systems can be altered by high temperature fluids to generate petroleum. The saturated and aromatic fractions of these hydrothermal oils are compositionally similar to conventional oil with the exception that they often contain higher concentrations of polycyclic aromatic hydrocarbons (PAH) as well as substantial mixtures of coeluting organic compounds that produce dramatically rising signal on the baseline of gas chromatograms termed unresolved complex mixtures (UCMs). Little is known about the compounds that compose UCMs and why or how they form. This is in part due to an inability to discriminate between in situ and migrated components that characterize the petroleum generated in hydrothermal systems. However, UCMs are also a product of the limitations imbedded in analytical separation techniques. With the advent of comprehensive two-dimensional gas chromatography (GC × GC), a revision of what should constitute molecular complexity needs to be considered. We address these problems by comparing the molecular compositions of the maltene fractions of three previously published hydrothermal petroleum samples using time of flight-mass spectrometry (GC × GC–ToF-MS) and 12 hydrothermal petroleum samples in cores from three locales using comprehensive two-dimensional gas chromatography with flame ionization detection (GC × GC–FID). The sediment cores were collected from Middle Valley, located off the axis of the Juan de Fuca Ridge, and the Escanaba Trough, along the Gorda Ridge, both in the NE Pacific Ocean, as well as from the Guaymas Basin in the Gulf of California. We define a UCM in GC × GC data to be a condition in which ⩾25% of the detected peaks within a chromatographic area coelute in either the first or second dimension. In turn, complex (CM) and simple mixtures (SM) are defined as having 5–24% and <5% coelution, respectively. All CM and UCMs were dominated by an array of configurational isomers, which becomes increasingly aromatic with higher molecular weight. We relate this to a multi-molecular complexity metric (MCM) by quantitatively comparing the difference in total peak variance and peak density for a GC × GC chromatogram. MCM values correlate with biomarker thermal maturity ratios for the Escanaba Trough and Guaymas Basin samples indicating that molecular complexity in these hydrothermal environments is in part a function of burial temperatures. Partial Least Squares (PLS) linear regression was applied to the total number of peak retention times as a proxy for the bulk molecular differences between each hydrothermal oil sample. Differences in the sample regressions correlate with the thermal maturity and the degree of PAH alkylation, indicating that this technique can be used to assess the degree of oxidative weathering due to dehydrogenation and hydrocarbon cracking. Subtracted chromatograms were then used to quantitatively track all of the individual molecular changes within the pyrolytic regime at Escanaba Trough. These subtracted chromatograms indicate that high molecular weight PAHs are highly mobile in hydrothermal fluids and may represent a phase partitioning that is occurring at greater depths. This phase condenses just below the seafloor to form an UCM in the near surface sediments. Saturated hydrocarbon biomarkers, such as hopanes, steranes and biphytanes are less mobile and more prone to being cracked and/or aromatized prior to migration toward the ocean floor. Together these techniques suggest that the molecular complexity of hydrothermal petroleum maximizes during the early stages of thermal maturation. The diversity of compounds forming these UCMs then decreases with increasing dehydrogenation, dealkylation and condensation reactions associated with elevated thermal stress and exposure to oxidants within the hydrothermal fluids.     

Origin and Source of Deep Natural Gas in Nanpu sag,Bohai Bay Basin,China

Natural gas exploration in Nanpu sag, Bohai Bay Basin, has achieved breakthroughs in recent years, and a number of natural gas and condensate wells with high yield have been found in several structures in the beach area. Daily gas production of single wells is up to 170,000 m3, and high-yield wells are mainly distributed in?the Nanpu No. 1 structural belt.?Studies have shown that these natural gases are mainly hydrocarbon gases, with methane content about 80% to 90% and ethane 6%-9%, so they are mainly wet gas; and non-hydrocarbons are at a low level.?Carbon isotopes of methane range from -42‰ to -36‰, and ethane from -28‰ to -26‰. Calculated maturity based on the relationship between δ13C and Ro of natural gas, the gases are equivalent to those generated from organic matter when Ro is 1.0%-1.7% (mainly 1.25%-1.32%). The natural gas is oil-type gas generated from the source rocks at mature to high mature stage, associated with condensate, so carbon isotopes of the gases are heavier. Natural gas in the Nanpu No.1 structural belt is mainly associated gas with condensate. The analysis of the origin and source of natural gas and condensate, combined with the monomer hydrocarbon carbon isotopes and biomarker, indicated that the main source rocks in the Nanpu No.1 structural belt were Es3 (the lower member of the Shahejie Formation), followed by Es1 (the upper member of the Shahejie Formation).?The high-mature hydrocarbons from source rocks in the deep sag mainly migrated through deep inherited faults into shallow traps and accumulated to form oil and gas pools. Therefore, there is a great potential for exploring gas in deep layers.     

Laboratory methods for evaluating migrated high molecular weight hydrocarbons in marine sediments at naturally occurring oil seeps

A laboratory study has been conducted to determine the best methods for the detection of C₁₀–C₄₀ hydrocarbons at naturally occurring oil seeps in marine sediments. The results indicate that a commercially available method using n-C₆ to extract sediments and gas chromatography–flame ionization detection (GC–FID) to screen the resulting extract is effective at recognizing the presence of migrated hydrocarbons at concentrations from 50 to 5000 ppm. When non-biodegraded, the amount of oil charge is effectively tracked by the sum of n-alkanes in the gas chromatogram. However, once the charge oil becomes biodegraded, with the loss of n-alkanes and isoprenoids, the amount of oil is tracked by the quantification of the unresolved complex mixture (UCM). Gas chromatography–mass spectrometry (GC–MS) was also found to be very effective for the recognition of petroleum related hydrocarbons and results indicate that GC–MS would be a very effective tool for screening samples at concentrations below 50 ppm oil charge.     

Geochemical and isotopic approach to maturity/source/mixing estimations for natural gas and associated condensates in the Thrace Basin,NW Turkey

The Tertiary Thrace Basin located in NW Turkey comprises 9 km of clastic-sedimentary column ranging in age from Early Eocene to Recent in age. Fifteen natural gas and 10 associated condensate samples collected from the 11 different gas fields along the NW–SE extending zone of the northern portion of the basin were evaluated on the basis of their chemical and individual C isotopic compositions. For the purpose of the study, the genesis of CH₄, thermogenic C₂₊ gases, and associated condensates were evaluated separately.Methane appears to have 3 origins: Group-1 CH₄ is bacteriogenic (Calculated δ¹³C_C1–C = −61.48‰; Silivri Field) and found in Oligocene reservoirs and mixed with the thermogenic Group-2 CH₄. They probably formed in the Upper Oligocene coal and shales deposited in a marshy-swamp environment of fluvio-deltaic settings. Group-2 (δ¹³C_C1–C = −35.80‰; Hamitabat Field) and Group-3 (δ¹³C_1–C = −49.10‰; Değirmenköy Field) methanes are thermogenic and share the same origin with the Group-2 and Group-3 C₂₊ gases. The Group-2 C₂₊ gases include 63% of the gas fields. They are produced from both Eocene (overwhelmingly) and Oligocene reservoirs. These gases were almost certainly generated from isotopically heavy terrestrial kerogen (δ¹³C = −21‰) present in the Eocene deltaic Hamitabat shales. The Group-3 C₂₊ gases, produced from one field, were generated from isotopically light marine kerogen (δ¹³C = −29‰). Lower Oligoce ne Mezardere shales deposited in pro-deltaic settings are believed to be the source of these gases.The bulk and individual n-alkane isotopic relationships between the rock extracts, gases, condensates and oils from the basin differentiated two Groups of condensates, which can be genetically linked to the Group-2 and -3 thermogenic C₂₊ gases. However, it is crucial to note that condensates do not necessarily correlate to their associated gases.Maturity assessments on the Group-1 and -2 thermogenic gases based on their estimated initial kerogen isotope values (δ¹³C = −21‰; −29‰) and on the biomarkers present in the associated condensates reveal that all the hydrocarbons including gases, condensates and oils are the products of primary cracking at the early mature st age (R_eq = 0.55–0.81%). It is demonstrated that the open-system source conditions required for such an early-mature hydrocarbon expulsion exist and are supported by fault systems of the basin.     

Molecular and isotopic partitioning of low-molecular-weight hydrocarbons during migration and gas hydrate precipitation in deposits of a high-flux seepage site

Detailed knowledge of the extent of post-genetic modifications affecting shallow submarine hydrocarbons fueled from the deep subsurface is fundamental for evaluating source and reservoir properties. We investigated gases from a submarine high-flux seepage site in the anoxic Eastern Black Sea in order to elucidate molecular and isotopic alterations of low-molecular-weight hydrocarbons (LMWHC) associated with upward migration through the sediment and precipitation of shallow gas hydrates. For this, near-surface sediment pressure cores and free gas venting from the seafloor were collected using autoclave technology at the Batumi seep area at 845 m water depth within the gas hydrate stability zone.Vent gas, gas from pressure core degassing, and from hydrate dissociation were strongly dominated by methane (> 99.85 mol.% of ∑[C₁–C₄, CO₂]). Molecular ratios of LMWHC (C₁/[C₂ + C₃] > 1000) and stable isotopic compositions of methane (δ¹³C = ? 53.5‰ V-PDB; D/H around ? 175‰ SMOW) indicated predominant microbial methane formation. C₁/C₂₊ ratios and stable isotopic compositions of LMWHC distinguished three gas types prevailing in the seepage area. Vent gas discharged into bottom waters was depleted in methane by > 0.03 mol.% (∑[C₁–C₄, CO₂]) relative to the other gas types and the virtual lack of ¹⁴C–CH₄ indicated a negligible input of methane from degradation of fresh organic matter. Of all gas types analyzed, vent gas was least affected by molecular fractionation, thus, its origin from the deep subsurface rather than from decomposing hydrates in near-surface sediments is likely.As a result of the anaerobic oxidation of methane, LMWHC in pressure cores in top sediments included smaller methane fractions [0.03 mol.% ∑(C₁–C₄, CO₂)] than gas released from pressure cores of more deeply buried sediments, where the fraction of methane was maximal due to its preferential incorporation in hydrate lattices. No indications for stable carbon isotopic fractionations of methane during hydrate crystallization from vent gas were found. Enrichments of ¹⁴C–CH₄ (1.4 pMC) in short cores relative to lower abundances (max. 0.6 pMC) in gas from long cores and gas hydrates substantiates recent methanogenesis utilizing modern organic matter deposited in top sediments of this high-flux hydrocarbon seep area.     

Quantifying pyrogenic carbon from thermosequences of wood and grass using hydrogen pyrolysis

Previously studied thermosequences of wood (chestnut) and grass (rice straw) biochar were subjected to hydrogen pyrolysis (hypy) to evaluate the efficacy of the technique for determining pyrogenic carbon (C_P) abundance. As expected, biochar from both wood and grass produced at higher temperature had higher C_P amount. However, the trend was not linear, but more sigmoidal. C_P/C_T ratio values (C_T = total organic carbon) for the wood thermosequence were ⩽0.03 at biochar production temperature (T_CHAR) ⩽ 300 °C. They increased dramatically until 600 °C and remained relatively constant and near unity at higher biochar production temperature. Grass biochar was similar in profile, but C_P/C_T values rose dramatically after 400 °C. The findings are consistent with the hypothesis that hypy residues contain polycyclic aromatic hydrocarbons (PAHs) with a degree of condensation above at least 7–14 fused rings, with labile organic matter and pyrogenic PAHs below this degree of condensation removed by hypy.Both wood and grass thermosequences displayed δ¹³C_P values that decreased with increased T_CHAR, indicating that recalcitrant carbon compounds (pyrogenic aromatic PAHs with a relatively high degree of condensation) were first formed from structural components with relatively high δ¹³C values (e.g. cellulose). Relatively constant δ¹³C values at T_CHAR ⩾ 500 °C suggested the dominant pyrolysis reaction was condensation of PAHs with no additional fractionation. Comparison of hypy with benzene polycarboxylic acid (BPCA), ‘ring current’ NMR and pyrolysis gas chromatography–mass spectrometry (GC–MS) results from the same suite of samples indicated a consistent overview of the structure of C_P, but provided unique and complimentary information.     

A first step towards identification of tannin-derived black carbon: Conventional pyrolysis (Py–GC–MS) and thermally assisted hydrolysis and methylation (THM–GC–MS) of charred condensed tannins

Tannins account for a significant proportion of plant biomass and are likely to contribute to the residues formed by incomplete biomass combustion (black carbon, BC). Nonetheless, the molecular properties of thermally modified tannins have not been investigated in laboratory charring experiments. We applied conventional analytical pyrolysis–gas chromatography–mass spectrometry (Py–GC–MS) and thermally assisted hydrolysis and methylation (THM–GC–MS) to investigate the effects of heat treatment with a muffle furnace on the properties of condensed tannins (CT) from Corsican pine (Pinus nigra) needles. Py–GC–MS showed a decrease in the relative abundance of the 1,2,3-trihydroxybenzenes (pyrogallols) at ⩾300 °C and of the dihydroxybenzenes (mainly catechols) at ⩾350 °C due to dehydroxylation of the CT B ring. Further dehydroxylation led to formation of monohydroxybenzenes (phenols), which showed a strong enrichment between 350 and 400 °C and, at higher temperatures, to a series of monocyclic and polycyclic aromatics [benzene, alkyl benzenes and polycondensed aromatic hydrocarbons (PAHs)]. Degradation of the A ring could not be recognized via Py–GC–MS, probably because of the poor chromatographic behavior of 1,3,5-trihydroxybenzenes (phloroglucinols). The progressive dehydroxylation and eventual polycondensation of the CT B ring was corroborated using THM–GC–MS. In addition, with THM–GC–MS the thermal rearrangement of CT A rings at 300 °C and higher was inferred from the relative abundance of 1,3,5-trimethoxybenzenes (methylated phloroglucinol derivatives). These compounds were observed at moderate/high temperature (up to 450 °C) and can not be produced from THM of lignin, suggesting that they may be markers of CT in natural BC samples.     

Early Carboniferous paleomagnetic results from the northeastern margin of the Qinghai–Tibetan plateau and their implications

We conducted paleomagnetic investigations on limestone from the Lower Carboniferous Huaitoutala Formation in the Qaidam Basin near Delingha City, Qinghai Province, China. The characteristic remanent magnetization (D = 5.8°, I = − 25.7°, k = 114.3, α₉₅ = 4.8°) passes a fold test and indicates a paleopole position of − 39.2°N, 90.4°E and a paleolatitude of 13.5°N for the Qaidam Block for the early Carboniferous. Based on global tectonic reconstructions and paleontological evidence, we suggest that the Qaidam Block was adjacent to, but independent from, the North China, South China, Alashan–Hexi and Tarim blocks at this time. This result suggests that Pre-Carboniferous sutures reported around the Qaidam Basin represent collisional events within Gondwana, rather than the final sutures that gave rise to the present tectonic configuration.     

A review of the geological characteristics and mineralization history of iron deposits in the Altay orogenic belt of the Xinjiang,Northwest China

In this review, we describe the geological characteristics and metallogenic–tectonic origin of Fe deposits in the Altay orogenic belt within the Xinjiang region of northwestern China. The Fe deposits are found mainly within three regions (ordered from northwest to southeast): the Ashele, Kelan, and Maizi basins. The principal host rocks for the Fe deposits of the Altay orogenic belt are the Early Devonian Kangbutiebao Formation, the Middle to Late Devonian Altay Formation, with minor occurrences of Lower Carboniferous and Early Paleozoic metamorphosed volcano-sedimentary rocks. The principal mineral-forming element groups of the deposits are Fe, Fe–Cu, Fe–Mn, Fe–P, Fe–Pb–Zn, Fe–Au, and Fe–V–Ti. The Fe deposits are associated with distinct formations, such as volcanic rocks, skarn deposits, pegmatites, granite-related hydrothermal vein mineralization, and mafic pluton-related V–Ti-magnetite deposits. The Fe deposits are most commonly associated with volcanic rocks in the upper Kangbutiebao Formation, in the volcano-sedimentary Kelan Basin, and in skarn deposits at several localities, including the lower Kangbutiebao Formation in the volcano-sedimentary Maizi Basin, and the Altay Formation at Jiaerbasidao–Kekebulake region. Homogenization temperatures of fluid inclusions in the prograde, retrograde and sulfide stages of the skarn type deposit are mainly medium- to high-temperature (cluster between 200 and 500 °C), medium-temperature (cluster between 200 and 340 °C) and low- to medium temperature (cluster between 160 and 300 °C), respectively. Ore fluids in the sedimentation period in the volcano-sedimentary type deposit are characterized by low- to medium temperature (with a peak around 190 °C), low to moderate salinity (3.23 to 22.71 wt.% NaCl equiv). Ore fluids in the pegmatite type deposit are characterized by low- to medium temperature (with a peak at 240 °C), low salinity (with a peak around 9 wt.% NaCl equiv). An analysis of the isotopic data for Fe deposits from the Altay orogenic belt indicates that the sulfur was derived from several sources, including volcanic rocks and granite, as well as bacterial reduction of sulfate from seawater. The present results indicate that different deposit types were derived from various sources. The REE geochemistry of rocks and ores from the Fe deposits in the Altay orogenic belt suggests that the ore-forming materials were derived from mafic volcanic rocks. Based on isotopic age data, the timing of the mineralization can be divided into four broad intervals: Early Devonian (410–384 Ma), Middle Devonian (377 Ma), Early Permian (287–274 Ma), and Early Triassic (c. 244 Ma). The ore-forming processes of the Fe deposits are closely related to volcanic activity and the emplacement of intermediate and felsic intrusions. We conclude that Fe deposits within the Altay orogenic belt developed in a range of tectonic settings, including continental arc, post-collisional extensional settings, and intracontinental settings.     

Thermal degradation of rye and maize straw: Lipid pattern changes as a function of temperature

Future climatic conditions may coincide with an increased potential for wildfires in grassland and forest ecosystems, whereby charred biomass would be incorporated into soils. Molecular changes in biomass upon charring have been frequently analysed with a focus on black carbon. Aliphatic and aromatic hydrocarbons, known to be liberated during incomplete combustion of biomass have been preferentially analysed in soot particles, whereas determinations of these compounds in charred biomass residues are scarce. We discuss the influence of increasing charring temperature on the aliphatic and aromatic hydrocarbon composition of crop grass combustion residues. Straw from rye, representing C₃ grasses and maize, representing C₄ grasses, was charred in the presence of limited oxygen at 300, 400 and 500 °C. Typical n-alkane distribution patterns with a strong predominance of long chain odd-numbered n-alkanes maximising at C₃₁ were observed in raw straw. Upon combustion at 300 °C aliphatic hydrocarbons in char were dominated by sterenes, whereas at 400 °C sterenes disappeared and medium chain length n-alkanes, maximising around n-C₂₀, with a balanced odd/even distribution were present. At a charring temperature of 500 °C n-alkane chain length shifted to short chain homologues, maximising at C₁₈ with a pronounced predominance of even homologues. Even numbered, short chain n-alkanes in soils may thus serve as a marker for residues of charred biomass. Aromatic hydrocarbons indicate an onset of aromatization of biomass already at 300 °C, followed by severe aromatization upon incomplete combustion at 400–500 °C. The diagnostic composition of aliphatic and aromatic hydrocarbons from charred biomass affords potential for identifying residues from burned vegetation in recent and fossil soils and sediments.     

Origin,distribution and hydrogeochemical controls on methane occurrences in shallow aquifers,southwestern Ontario,Canada

Natural gas reservoirs in organic-rich shales in the Appalachian and Michigan basins in the United States are currently being produced via hydraulic fracturing. Stratigraphically-equivalent shales occur in the Canadian portion of the basins in southwestern Ontario with anecdotal evidence of gas shows, yet there has been no commercial shale gas production to date. To provide baseline data in the case of future environmental issues related to hydraulic fracturing and shale gas production, such as leakage of natural gas, saline water, and/or hydraulic fracturing fluids, and to evaluate hydrogeochemical controls on natural gas accumulations in shallow groundwater in general, this study investigates the origin and distribution of natural gas and brine in shallow aquifers across southwestern Ontario. An extensive geochemical database of major ion and trace metal chemistry and methane concentrations of 1010 groundwater samples from shallow, domestic wells in bedrock and overburden aquifers throughout southwestern Ontario was utilized. In addition, select wells (n = 36) were resampled for detailed dissolved gas composition, δ¹³C of CH₄, C₂, C₃, and CO₂, and δD of CH₄. Dissolved gases in groundwater from bedrock and overburden wells were composed primarily of CH₄ (29.7–98.6 mol% of total gas volume), N₂ (0.8–66.2 mol%), Ar + O₂ (0.2–3.4 mol%), and CO₂ (0–1.2 mol%). Ethane was detected, but only in low concentrations (<0.041 mol%), and no other higher chain hydrocarbons were present, except for one well in overburden overlying the Dundee Formation, which contained 0.81 mol% ethane and 0.21 mol% propane. The highest methane concentrations (30 to >100 in situ % saturation) were found in bedrock wells completed in the Upper Devonian Kettle Point Formation, Middle Devonian Hamilton Group and Dundee Formation, and in surficial aquifers overlying these organic-rich shale-bearing formations, indicating that bedrock geology is the primary control on methane occurrences. A few (n = 40) samples showed Na–Cl–Br evidence of brine mixing with dilute groundwater, however only one of these samples contained high (>60 in situ % saturation) CH₄. The relatively low δ¹³C values of CH₄ (−89.9‰ to −57.3‰), covariance of δD values of CH₄ and H₂O, positive correlation between δ¹³C values of CH₄ and CO₂, and lack of higher chain hydrocarbons (C₃₊) in all but one dissolved gas sample indicates that the methane in groundwater throughout the study area is primarily microbial in origin. The presence or absence of alternative electron acceptors (e.g. dissolved oxygen, Fe, NO₃, SO₄), in addition to organic substrates, controls the occurrence of microbial CH₄ in shallow aquifers. Microbial methane has likely been accumulating in the study area, since at least the Late Pleistocene to the present, as indicated by the co-variance and range of δD values of CH₄ (−314‰ to −263‰) and associated groundwater (−19‰ to −6‰ δD-H₂O).     

An improved cubic model for the mutual solubilities of CO2–CH4–H2S–brine systems to high temperature,pressure and salinity

The phase behavior of CO₂–CH₄–H₂S–brine systems is of importance for geological storage of greenhouse gases, sour gas disposal and enhanced oil recovery (EOR). In such projects, reservoir simulations play a major role in assisting decision makings, while modeling the phase behavior of the relevant CO₂–CH₄–H₂S–brine system is a key part of the simulation. There is a need for an equation of state (EOS) for such system which is accurate, with wide application range (pressure, temperature and aqueous salinity), computationally efficient and easy for implementation in a reservoir simulator.In this study, an improved cubic EOS model of the system CO₂–CH₄–H₂S–brine is developed based on the modifications of the binary interaction parameters in Peng–Robinson EOS, which is widely implemented in reservoir simulators. Thus the new model is suited for numerical implementation in reservoir simulators.The available experimental data of pure gas brine equilibrium and gas mixture solubility in water/brine are carefully reviewed and compared with the new model. From the comparison, the new model can accurately reproduce (1) the CO₂–brine mutual solubility data at temperature from 0 °C to 250 °C, pressure from 1 bar to 1000 bar and NaCl molality (mole number in 1 kg water, molal is used for short) from 0 to 6 molal, (2) CH₄–brine mutual solubility data at temperature from 0 °C to 250 °C, pressure from 1 bar to 2000 bar and NaCl molality from 0 to 6 molal, (3) H₂S–brine mutual solubility data at temperature from 0 °C to 250 °C, pressure from 1 bar to 200 bar and NaCl molality from 0 to 6 molal, and (4) has good accuracy for gas mixture solubility in brine.     

30 million years of Permian volcanism recorded in the Choiyoi igneous province (W Argentina) and their source for younger ash fall deposits in the Paraná Basin: SHRIMP U–Pb zircon geochronology evidence

We present four SHRIMP U–Pb zircon ages for the Choiyoi igneous province from the San Rafael Block, central–western Argentina. Dated samples come from the Yacimiento Los Reyunos Formation (281.4 ± 2.5 Ma) of the Cochicó Group (Lower Choiyoi section: andesitic breccias, dacitic to rhyolitic ignimbrites and continental conglomerates), Agua de los Burros Formation (264.8 ± 2.3 Ma and 264.5 ± 3.0 Ma) and Cerro Carrizalito Formation (251.9 ± 2.7 Ma Upper Choiyoi section: rhyolitic ignimbrites and pyroclastic flows) spanning the entire Permian succession of the Choiyoi igneous province. A single zircon from the El Imperial Formation, that is overlain unconformably by the Choiyoi succession, yielded an early Permian age (297.2 ± 5.3 Ma), while the main detrital zircon population indicated an Ordovician age (453.7 ± 8.1 Ma). The new data establishes a more precise Permian age (Artinskian–Lopingian) for the section studied spanning 30 Ma of volcanic activity. Volcanological observations for the Choiyoi succession support the occurrence of explosive eruptions of plinian to ultraplinian magnitudes, capable of injecting enormous volumes of tephra in the troposphere–stratosphere. The new SHRIMP ages indicate contemporaneity between the Choyoi succession and the upper part of the Paraná Basin late Paleozoic section, from the Irati up to the Rio do Rasto formations, encompassing about 24 Ma. Geochemical data show a general congruence in compositional and tectonic settings between the volcanics and Paraná Basin Permian ash fall derived layers of bentonites. Thickness and granulometry of ash fall layers broadly fit into the depletion curve versus distance from the remote source vent of ultraplinian eruptions. Thus, we consider that the Choiyoi igneous province was the source of ash fall deposits in the upper Permian section of the Paraná Basin. Data presented here allow a more consistent correlation between tectono-volcanic Permian events along the paleo-Pacific margin of southwestern Gondwana and the geological evolution of neighboring Paleozoic foreland basins in South America and Africa.     

An experimental comparison of gas generation from three oil fractions: Implications for the chemical and stable carbon isotopic signatures of oil cracking gas

Although oil cracking has been documented as one of the important sources of gas in many overmature marine sedimentary basins, the chemical and carbon isotopic signatures of gases of this origin are still open to question. In this study a Cambrian crude oil from the central Tarim basin, along with its main separated fractions (saturates, aromatics and asphaltenes), were pyrolyzed in sealed gold tubes to investigate how generated gases vary in chemical and carbon isotopic composition and how this variation would influence the genetic interpretation of oil cracking gas. The results indicate that the gases from cracking of aromatics and asphaltenes are much drier and more enriched in ¹³C than the gases from the cracking of saturates and crude oil at the same level of thermal maturity. In the experimental run of 20 °C/h, the dryness index of the gases (defined as the volume percentage of C₁ in C_1–5) from the cracking of saturates ranges from 26.2–90.6% with the methane carbon isotope change ranging from −54.8‰ to −35.5‰, whereas the dryness index is never lower than 60.6% for the gases from the cracking of aromatics with methane carbon isotope ranging from −39.9‰ to −32.2‰. Correspondingly, experimental data for the four samples plot in different areas in diagrams designed to distinguish oil cracking gas from kerogen cracking gas, such as ln(C₂/C₃) vs. δ¹³C₂–δ¹³C₃ and δ¹³C₁ vs. δ¹³C₂–δ¹³C₃, indicating compositional variability of crude oil could assert an important influence in these diagrams. Therefore it is prudent to bring other geological constraints into consideration to avoid misinterpretation.The kinetic parameters for the bulk generation of C_1–5 gas and the methane carbon isotope fractionation extrapolated to geological conditions of 2 °C/Ma and an initial temperature of 50 °C show that the temperatures of C_1–5 gas generation from the aromatics and asphaltenes are lower than those from the saturates and crude oil due to their lower activation energies and frequency factors. Generation of C_1–5 gases from the aromatics is modeled to be initiated about 122 °C whereas the initiation temperature for the saturates sample is 176 °C. Below 189 °C (EasyRo = 1.8%), the yields of C_1–5 gases follow the order: aromatics > asphaltenes > crude oil > saturates. At similar thermal maturity levels, the methane carbon isotopic compositions are significantly different for the four samples, with an order of ¹³C enrichment: aromatics > asphaltenes > crude oil > saturates, however the difference in methane carbon isotopes becomes smaller with increasing temperature. This indicates that methane carbon isotopic values can be significantly different for gases cracked from oils that are compositionally diverse, especially in the early stage of methane generation.     

Geochemical assessment of hydrocarbon migration phenomena: Case studies from the south-western margin of the Dead Sea Basin

Calcite veins with fluid and solid bitumen inclusions have been discovered in the south-western shoulder of the Dead Sea rift within the Masada-Zohar block, where hydrocarbons exist in small commercial gas fields and non-commercial fields of heavy and light oils. The gas–liquid inclusions in calcite are dominated either by methane or CO₂, and aqueous inclusions sometimes bear minor dissolved hydrocarbons. The enclosed flake-like solid bitumen matter is a residue of degraded oil, which may be interpreted as “dead carbon”. About 2/3 of this matter is soot-like amorphous carbon and 1/3 consists of n-C₈C₁₈ carboxylic acids and traces of n-alkanes, light dicarboxylic acids, and higher molecular weight (>C₂₀) branched and/or cyclic carboxylic acids. Both bitumen and the host calcites show genetic relationship with mature Maastrichtian chalky source rocks (MCSRs) evident in isotopic compositions (δ¹³C, δ³⁴S, and δ¹⁸O) and in REE + Y patterns. The bitumen precursor may have been heavy sulfur-rich oil which was generated during the burial compaction of the MCSR strata within the subsided blocks of the Dead Sea graben. The δ¹⁸O and δ¹³C values and REE + Y signatures in calcites indicate mixing of deep buried fluids equilibrated with post-mature sediments and meteoric waters. The temperatures of fluid generation according to Mg–Li-geothermometer data range from 55 °С to 90 °С corresponding to the 2.5–4.0 km depths, and largely overlap with the oil window range (60–90 °С) in the Dead Sea rift (Hunt, 1996; Gvirtzman and Stanislavsky, 2000; Buryakovsky et al., 2005). The bitumen-rich vein calcites originated in the course of Late Cenozoic rifting and related deformation, when tectonic stress triggers damaged small hydrocarbon reservoirs in the area, produced pathways, and caused hydrocarbon-bearing fluids to rise to the subsurface; the fluids filled open fractures and crystallized to calcite with entrapped bitumen. The reported results are in good agreement with the existing views of maturation, migration, and accumulation of hydrocarbons, as well as basin fluid transport processes in the Dead Sea area.