δ13C Values Of Methane Research Articles

Characteristics of Microbial Coalbed Gas during Production; Example from Pennsylvanian Coals in Indiana, USA

Coalbed gases from 11 wells producing from the Springfield and Seelyville Coal Members (Pennsylvanian) were analyzed for composition and carbon and hydrogen stable isotope ratios in four sampling events to investigate short-term variation trends. Nine wells in the Seelyville Coal Member produce coalbed gases from the virgin seam, whereas two wells in the Springfield Coal Member produce gas from mine voids. Methane dominates gas composition in all wells, and its content ranges from ~94% to almost 98%, with ethane typically accounting for less than 0.01%. Carbon dioxide content in most samples is below 1%, whereas N2 content ranges from less than 2% to 4.8%. Methane δ13C values range from −55.3‰ to −61.1‰, and δ2H values range from −201‰ to −219‰. Isotopic values of methane and C1/(C2 + C3) ratios indicate a biogenic origin along the CO2-reduction pathway, consistent with previous studies in this area. Our results demonstrate that gas properties may change significantly during a period of one year of production history. Compositional trends (e.g., C1/(C2 + C3), CH4/CO2 ratios) are specific for each well and often irregular. These changes result from a combined influence of numerous factors and, therefore, are difficult to predict.

The origin of N2-H2-CH4-rich natural gas seepages in ophiolitic context: A major and noble gases study of fluid seepages in New Caledonia

The study of natural gas seepages in New Caledonia has shown the occurrence of two gas families, one is N2-H2-CH4-rich, the other is N2-rich. The N2-H2-CH4-rich gases are bubbling in hyperalkaline springs (OH–-rich) known in the peridotite massif of the southern part of the island. This family of gas shows contents of N2 between 50 and 62%, H2 between 26 and 36%, and CH4 between 11 and 16%. δ13C values of methane are ranging from −39 to −32‰. We interpret the origin of H2 as a product of fluid-rock interaction between basic-ultrabasic rocks and water with oxidation of Fe2+ and reduction of underground water in the fracture system of the peridotites nappe. Methane is interpreted as the result of a reduction of dissolved inorganic and/or organic carbon in subsurface aquifers. The second family of gas emissions was found in thermal springs in the sedimentary units located structurally below the peridotites nappe. The gas is composed mostly of N2 (between 97 and 98%) associated with relatively high concentration of He. Both gas families show notably high N2 vs fossil noble gas contents (36Ar, 20Ne, 84Kr) suggesting that N2 is not directly issued from gas dissolved in aquifers equilibrated with atmosphere but most likely finds its origin in a deep source, probably within metamorphic sediments which are tectonically buried below the ophiolitic nappe. We interpret the N2-H2-CH4-rich family of gas as a result of a mixing between two end-members, (1) a H2-CH4-rich pole issued from the weathering of peridotite rocks and (2) a N2-rich pole which would be issued from the metamorphosed sediments buried below the ophiolitic units. An unusual inverse correlation between the atmospheric noble gas isotopes 20Ne and 36Ar is interpreted as the result of a degassing of a relatively shallow confined aquifer related to a bubble flow from depth.

Hydrocarbons from near-surface sediments of the Barents Sea north of Svalbard – Indication of subsurface hydrocarbon generation?

The Barents Sea is considered as an important target for oil and gas exploration, but the petroleum potential of its shelf and slope regions is unknown. Here we present results of a research cruise to the Northern Hinlopen Margin at the transition to the Southern Nansen Basin and the Eastern Yermak Plateau. Multichannel reflection seismic data acquisition, heat flow measurements, and geochemical analyses of near-surface sediments obtained by gravity coring were conducted to study the northern Barents Sea shelf and the early opening of the Nansen Basin and decipher their petroleum potential. Seismic data indicate high thicknesses of up to ∼2000 m of Cenozoic sediments. Heat flow density values in the study area range between 67 and 108 mW/m2. The sediment samples were analysed for bulk geochemistry and sorbed hydrocarbon gases and for two sites for extractable hydrocarbons. Data from extractable (n-alkanes > n-C25) and bulk (HI and OI from Rock Eval) organic matter demonstrate predominantly terrigenous organic material, most likely derived from ice-transported allochthonous sediments. None of the sediments revealed substantial amounts of methane in pore waters, arguing against active hydrocarbon seepage in the studied areas. However, thermogenic gases sorbed to the sediment matrix (clay minerals, organic matter and/or carbonates) were found in concentrations of up to 600 ppb (on sediment wet wt. basis). For the samples from the Northern Hinlopen Margin and particularly from the adjacent Nansen Basin, a paleo fluid flow of thermogenic gas is indicated and accompanied by higher n-alkanes with a modal, petroleum-like distribution. δ13C values of methane, ethane and propane and gas compositions point at a mainly marine source rock origin of all studied gases with early oil window maturities of the associated rocks (0.6–0.9%VR). From this data an admixture of Type III derived thermogenic gases is indicated for some of the Yermak Plateau sediments for which also the lowest abundances of sorbed gases (50–100 ppb) were observed. Gas geochemical characteristics in the samples with low gas abundances can partially be explained by an input of gases through ice-transport of allochthonous hydrocarbons, which were bound to mature organic matter. For a site on the Northern Hinlopen Margin NE of Svalbard, right at the southern termination of the Nansen Basin a different situation is indicated. In this area the highest concentrations of sorbed gases most likely derived from sediments with an early-oil window maturity and a marine kerogen Type II-typical isotopic distribution. At this location a pseudo well was constructed from 2D seismic data for reconstruction of thermal and maturity evolution. The simulation results indicate that an Early to Middle Eocene source rock would be in the early oil window since the Early Miocene. A possible source rock here and in the circum-Arctic region could have been formed by Azolla algae and other flourishing primary producers.

Origin and distribution of hydrogen sulfide in the Yuanba gas field, Sichuan Basin, Southwest China

The Yuanba gas field in the Permian Changxing Formation (P2c), which exhibits wide variations in its hydrogen sulfide (H2S) concentration (1.20–12.16%), is a typical sour gas field in the northern Sichuan Basin. The sulfur-rich reservoir's solid bitumen (atomic S/C ratios are 0.032–0.142), and late calcite cement δ13C values, which are smaller than the δ13C values of the host dolostone, indicate that the H2S originated from thermal sulfate reduction (TSR) and oil was involved in TSR. The gas souring index (GSI) of P2c's gases is generally lower than 0.1. The ethane δ13C values increase as the GSI increases, although no obvious increase was observed in the methane δ13C values. The calcite cements' δ13C values (−15.36 to +4.56‰) in dolostone are heavier than the typical reported values, which implies that only limited heavy hydrocarbon gases were involved in TSR. No anhydrites developed in P2c's reservoirs, and dissolved sulfate anions (SO42−) were mainly enriched during dolomitization. Insufficient dissolved SO42− most likely caused the lower H2S concentrations in the Permian to Triassic reservoirs in the northeastern Sichuan Basin compared to the Permian Khuff Formation in Saudi Arabia and the Jurassic Smackover Formation in Mississippi. Except for the SO42− in residual water in paleo-oil zones, SO42− from bottom water may also be involved in TSR; therefore, oil reservoirs with bottom water have more SO42− and can produce more H2S than pure oil reservoirs. This phenomenon may be the main cause of the great difference in the H2S concentrations between reservoirs, while gravitational differentiation during late uplift most likely creates differences in H2S concentrations in a single reservoir. Carbon dioxide (CO2), which has a relatively heavy δ13C value (−3.9 to −0.3‰), may be the combined result of TSR, the balance between CO2 and inorganic fluid systems, and carbonate decomposition.

Characteristics of stable carbon isotopic composition of shale gas

A type Ⅱ kerogen with low thermal maturity was adopted to perform hydrocarbon generation pyrolysis experiments in a vacuum (Micro-Scale Sealed Vessel) system at the heating rates of 2 °C/h and 20 °C/h. The stable carbon isotopic compositions of gas hydrocarbons were measured to investigate their evolving characteristics and the possible reasons for isotope reversal. The δ13C values of methane became more negative with the increasing pyrolysis temperatures until it reached the lightest point, after which they became more positive. Meanwhile, the δ13C values of ethane and propane showed a positive trend with elevating pyrolysis temperatures. The carbon isotopic compositions of shale gasses were mainly determined by the type of parent organic matter, thermal evolutionary extent, and gas migration in shale systems. Our experiments and study proved that the isotope reversal shouldn't occur in a pure thermogenic gas reservoir, it must be involved with some other geochemical process/es; although mechanisms responsible for the reversal are still vague. Carbon isotopic composition of the Fayetteville and Barnett shale gas demonstrated that the isotope reversal was likely involved with water–gas reaction and Fischer-Tropsch synthesis during its generation.

Distribution and origin of dissolved methane, ethane and propane in shallow groundwater of Lower Saxony, Germany

More than 90% of Germany's domestic natural gas production and reserves are located in Lower Saxony, North Germany. Recently, research has been intensified with respect to unconventional shale gas, revealing a large additional resource potential in northern Germany. However, many concerns arise within the general public and government/political institutions over potential groundwater contamination from additional gas wells through hydraulic fracturing operations.In order to determine the naturally occurring background methane concentrations, ∼1000 groundwater wells, covering ∼48 000 km2, have been sampled and subsequently analyzed for dissolved methane, ethane and propane and the isotopic composition of methane (δ13C).Dissolved methane concentrations cover a range of ∼7 orders of magnitude between the limit of quantification at ∼20 nl/l and 60 ml/l. The majority of groundwater wells exhibit low concentrations (<1 μl/l), a small number of samples (65) reveal concentration in the range >10 ml/l. In 27% of all samples ethane and in 8% ethane and propane was detected. The median concentration of both components is generally very low (ethane 50 nl/l, propane 23 nl/l).Concentrations reveal a bimodal distribution of the dissolved gas, which might mirror a regional trend due to different hydrogeological settings. The isotopic composition of methane is normally distributed (mean ∼ −70‰ vs PDB), but shows a large variation between −110‰ and +20‰. Samples with δ13C values lower than −55‰ vs PDB (66%) are indicative for methanogenic biogenic processes. 5% of the samples are unusually enriched in 13C (≥25‰ vs PDB) and can best be explained by microbial methane oxidation.According to a standard diagnostic diagram based on methane δ13C values and the ratio of methane over the sum over ethane plus propane (“Bernard”-diagram) less than 4% of the samples plot into the diagnostic field of typical thermogenic natural gases. However, in most cases only ethane has been detected and the remaining less than 15 samples demonstrate an uncommon ratio of ethane to propane compared to typical thermogenic hydrocarbons. These data do not suggest a migration of deeper sourced gases, but a thermogenic source cannot be excluded entirely for some samples. However, ethane and propane can also be generated by microbial processes and might therefore represent ubiquitous background groundwater abundances of these gases. Nevertheless, our data suggest that due to the exceedingly low concentration of ethane and propane, respective concentration changes might prove to be a more sensitive parameter than methane to detect possible migration of deeper sourced (thermally generated) hydrocarbons into a groundwater aquifer.

Thermal simulation study on the influence of coal-forming material on the isotopic composition of thermogenic coalbed gas

In order to understand the influence of coal-forming materials and slight differences in coal maceral composition on the isotopic composition of thermogenic coalbed gas, closed-system isothermal pyrolysis experiments were performed on forest and herbaceous swamp peats and on coals with slight differences in maceral compositions. The carbon and hydrogen isotopic compositions of the hydrocarbon gases (methane, ethane and propane) generated during the pyrolysis of the samples were determined. The results showed that the carbon and hydrogen isotopic compositions of the hydrocarbon gases generated from the herbaceous swamp peat were lighter than those generated from the forest swamp peat. At pyrolysis intervals from peat to vitrinite reflectance values (Ro) of 2.5%, 3.5% and 5.5%, this difference in the average δD value of the generated methane was 18‰, 11‰ and 9‰, and in the δ13C value of methane was 3.4‰, 3.8‰ and 1.8‰, respectively. The reason for the difference of trend can be explained as follows. The methane generated from the coal containing slightly higher exinite content had noticeably lighter carbon isotopic composition. However, the hydrogen isotopic composition of the generated methane was primarily related to coal-forming environmental factors, such as latitude, δD value of rainwater, and diagenetic fluid of freshwater or seawater. These results provide a basis for studying the isotopic geochemistry of coalbed gas.

An inter-regional assessment of concentrations and δ13C values of methane and dissolved inorganic carbon in small European lakes

Methane (CH4) and carbon dioxide emissions from lakes are relevant for assessing the greenhouse gas output of wetlands. However, only few standardized datasets describe concentrations of these gases in lakes across different geographical regions. We studied concentrations and stable carbon isotopic composition (δ13C) of CH4 and dissolved inorganic carbon (DIC) in 32 small lakes from Finland, Sweden, Germany, the Netherlands, and Switzerland in late summer. Higher concentrations and δ13C values of DIC were observed in calcareous lakes than in lakes on non-calcareous areas. In stratified lakes, δ13C values of DIC were generally lower in the hypolimnion due to the degradation of organic matter (OM). Unexpectedly, increased δ13C values of DIC were registered above the sediment in several lakes. This may reflect carbonate dissolution in calcareous lakes or methanogenesis in deepwater layers or in the sediments. Surface water CH4 concentrations were generally higher in western and central European lakes than in Fennoscandian lakes, possibly due to higher CH4 production in the littoral sediments and lateral transport, whereas CH4 concentrations in the hypolimnion did not differ significantly between the regions. The δ13C values of CH4 in the sediment suggest that δ13C values of biogenic CH4 are not necessarily linked to δ13C values of sedimentary OM but may be strongly influenced by OM quality and methanogenic pathway. Our study suggests that CH4 and DIC cycling in small lakes differ between geographical regions and that this should be taken into account when regional studies on greenhouse gas emissions are upscaled to inter-regional scales.

Geochemistry and origin of shallow gas in the Baise Basin, southern China

Abstract Many small and medium-sized Paleogene pull-apart basins in southern China contain an abundance of biogenic gas shows. Such shallow gas with biogenic characteristics has been thoroughly investigated only in Baise Basin. Hence, the research results from Baise Basin could serve as a model for the origin and characteristics of shallow gases in similar basins and areas in Southern China. There are ten gas fields with a total of proven reserves of 20 billion cubic meters discovered in Baise Basin. Three gas fields are located on the western and southern flank of the basin, and they are gas caps to heavy oil pools from depths between 600 m and 850 m. These accumulations contain dry biogenic gases, with C1/C1-5 exceeding 0.99, light δ13C1 (–76 to −54‰), and heavy δD1 (−218‰). Trace heavy gaseous hydrocarbons are strongly biodegraded (iC4/nC4>3). The other seven gas fields are located in the northern fault zone and the central Nakun uplift of the basin at depths between 300 m and 700 m. Gases are mainly unassociated and condensed gases. The condensed gases are depleted in 13C (δ13C1: −67 to −53.7‰, δ13C2: −52.3 to −36.1‰, δ13C3: −43.3 to −33.4‰), but wet with C1/C2+3 mostly less than 20, suggesting a mainly thermal origin at low maturity. The unassociated gases are dominated by methane, with C1/C2+3 ratio above 100, variable N2 (0 to 5.4%), and traces of CO2. The δ13C value of methane in the unassociated gases is between −76 to −60‰, and δD1 values from −248 to −213.7‰. These gases also contain isotopically light ethane with δ13C2 values of −64.5 to −42‰, which we infer to have originated from deeper horizons as a result of migration or diffusion from low-maturity thermal gases with light stable carbon isotopic compositions (C1/C2+3 <20, δ13C2 from −60‰ to −58‰). A similar thermal origin is inferred for the other heavy gaseous hydrocarbons. Formation water with the shallow gases of this basin is mainly NaHCO3-type with low TDS ranging from 1000 to 4500 ppm. The (HCO3+CO3)/Cl ratios range from 1.5 to 100, indicating a relative open hydrodynamic condition and the possible intrusion of meteoric water. These data indicate that early biogenic gas generated syndepositionally was probably not preserved, and that the current biogenic gas accumulation formed mainly as a result post-depositional of crude oil biodegradation in the western basin and coal biodegradation in the northern fault zone. Shallow gases in Baise Basin are mainly secondary biogenic gases, with an admixture of low maturity thermogenic gases from deeper horizons.

Trimethylamine and Organic Matter Additions Reverse Substrate Limitation Effects on the δ13C Values of Methane Produced in Hypersaline Microbial Mats.

Methane production has been observed in a number of hypersaline environments, and it is generally thought that this methane is produced through the use of noncompetitive substrates, such as the methylamines, dimethylsulfide and methanol. Stable isotope measurements of the produced methane have also suggested that the methanogens are operating under conditions of substrate limitation. Here, substrate limitation in gypsum-hosted endoevaporite and soft-mat hypersaline environments was investigated by the addition of trimethylamine, a noncompetitive substrate for methanogenesis, and dried microbial mat, a source of natural organic matter. The δ(13)C values of the methane produced after amendments were compared to those in unamended control vials. At all hypersaline sites investigated, the δ(13)C values of the methane produced in the amended vials were statistically lower (by 10 to 71‰) than the unamended controls, supporting the hypothesis of substrate limitation at these sites. When substrates were added to the incubation vials, the methanogens within the vials fractionated carbon isotopes to a greater degree, resulting in the production of more (13)C-depleted methane. Trimethylamine-amended samples produced lower methane δ(13)C values than the mat-amended samples. This difference in the δ(13)C values between the two types of amendments could be due to differences in isotope fractionation associated with the dominant methane production pathway (or substrate used) within the vials, with trimethylamine being the main substrate used in the trimethylamine-amended vials. It is hypothesized that increased natural organic matter in the mat-amended vials would increase fermentation rates, leading to higher H2 concentrations and increased CO2/H2 methanogenesis.

Processes involved in the origin and accumulation of hydrocarbon gases in the Yuanba gas field, Sichuan Basin, southwest China

Natural gases in the superimposed Sichuan Basin commonly experienced a history of remigration in marine carbonate reservoirs since the late Cretaceous. The reservoir in the Changxing Formation (P2c) in the Yuanba gas field in the Sichuan Basin is characterized by a great burial depth of 6200–7000 m and a high temperature about 165 °C. The gas dryness is 99.73–99.99%, and δ13C values of methane and ethane are −31.0 to −28.9‰ and −29.9 to −25.6‰, respectively. The chemical and isotopic compositions of natural gases, abundant reservoir solid bitumen, and high reservoir temperature (maximum to 240 °C) indicate that the P2c gases are of sapropelic origin and are derived from oil cracking. The paleo-oil layers, recognized by solid bitumen distribution, were mainly developed in high position traps when the paleo-oil accumulated during the early Jurassic. Reconstructed structural evolution shows the northwest was uplifted sharply and southern part dipped gently to the north in the gas field after oil cracking. Fluid potential analyses based on changes in the structural configuration imply that gas should re-migrate mainly to the northwest. The observations that paleo-oil-water contacts are mainly above the present day gas-water contacts in the northwest traps, and are below present day gas-water contacts in the middle and eastern traps also confirm the gas remigration trend. Currently, high gas production wells are mainly located in northwest traps and in high positions in the middle and eastern traps. Systematic analyses on early paleo-oil accumulation and late gas remigration processes can reduce the economic risks associated with natural gas exploration in the northeastern Sichuan Basin.

Temperature and injection water source influence microbial community structure in four Alaskan North Slope hydrocarbon reservoirs.

A fundamental knowledge of microbial community structure in petroleum reservoirs can improve predictive modeling of these environments. We used hydrocarbon profiles, stable isotopes, and high-density DNA microarray analysis to characterize microbial communities in produced water from four Alaskan North Slope hydrocarbon reservoirs. Produced fluids from Schrader Bluff (24–27°C), Kuparuk (47–70°C), Sag River (80°C), and Ivishak (80–83°C) reservoirs were collected, with paired soured/non-soured wells sampled from Kuparuk and Ivishak. Chemical and stable isotope data suggested Schrader Bluff had substantial biogenic methane, whereas methane was mostly thermogenic in deeper reservoirs. Acetoclastic methanogens (Methanosaeta) were most prominent in Schrader Bluff samples, and the combined δD and δ13C values of methane also indicated acetoclastic methanogenesis could be a primary route for biogenic methane. Conversely, hydrogenotrophic methanogens (e.g., Methanobacteriaceae) and sulfide-producing Archaeoglobus and Thermococcus were more prominent in Kuparuk samples. Sulfide-producing microbes were detected in all reservoirs, uncoupled from souring status (e.g., the non-soured Kuparuk samples had higher relative abundances of many sulfate-reducers compared to the soured sample, suggesting sulfate-reducers may be living fermentatively/syntrophically when sulfate is limited). Sulfate abundance via long-term seawater injection resulted in greater relative abundances of Desulfonauticus, Desulfomicrobium, and Desulfuromonas in the soured Ivishak well compared to the non-soured well. In the non-soured Ivishak sample, several taxa affiliated with Thermoanaerobacter and Halomonas predominated. Archaea were not detected in the deepest reservoirs. Functional group taxa differed in relative abundance among reservoirs, likely reflecting differing thermal and/or geochemical influences.

Gammaproteobacterial methanotrophs dominate cold methane seeps in floodplains of West Siberian rivers.

A complex system of muddy fluid-discharging and methane (CH4)-releasing seeps was discovered in a valley of the river Mukhrinskaya, one of the small rivers of the Irtysh Basin, West Siberia. CH4 flux from most (90%) of these gas ebullition sites did not exceed 1.45 g CH4 h(-1), while some seeps emitted up to 5.54 g CH4 h(-1). The δ(13)C value of methane released from these seeps varied between -71.1 and -71.3‰, suggesting its biogenic origin. Although the seeps were characterized by low in situ temperatures (3.5 to 5°C), relatively high rates of methane oxidation (15.5 to 15.9 nmol CH4 ml(-1) day(-1)) were measured in mud samples. Fluorescence in situ hybridization detected 10(7) methanotrophic bacteria (MB) per g of mud (dry weight), which accounted for up to 20.5% of total bacterial cell counts. Most (95.8 to 99.3%) methanotroph cells were type I (gammaproteobacterial) MB. The diversity of methanotrophs in this habitat was further assessed by pyrosequencing of pmoA genes, encoding particulate methane monooxygenase. A total of 53,828 pmoA gene sequences of seep-inhabiting methanotrophs were retrieved and analyzed. Nearly all of these sequences affiliated with type I MB, including the Methylobacter-Methylovulum-Methylosoma group, lake cluster 2, and several as-yet-uncharacterized methanotroph clades. Apparently, microbial communities attenuating methane fluxes from these local but strong CH4 sources in floodplains of high-latitude rivers have a large proportion of potentially novel, psychrotolerant methanotrophs, thereby providing a challenge for future isolation studies.

Mineral-forming and diagenetic processes related to Tertiary hydrocarbon seepage at the Bohemian Massif/Outer Western Carpathians interface: Evidence from the Hrabůvka quarry, Moravia, Czech Republic

Ancient hydrocarbon seepage occurred in the Hrabůvka quarry at the boundary between the basement of the Bohemian Massif (represented by folded Lower Carboniferous siliciclastics of the Culm facies) and Tertiary sedimentary cover of the Carpathian Foredeep (formed by Lower Badenian siliciclastics and calcareous clays). The unconsolidated Lower Badenian sediments contain lithified domains composed of limestone and breccias with limestone cement, whereas the basement rocks are cut by subvertical neptunic dykes filled up by limestone and calcite-marcasite-pyrite veinlets representing sealed fluid conduits. The deeply negative δ13C values of both vein calcite and limestone (down to −38.1‰ V-PDB) indicate that oxidation of hydrocarbons was the major source of carbon for authigenic mineralization. A fluid inclusion study suggests low fluid temperatures (<50 °C) and low and variable salinities of aqueous fluids associated with hydrocarbons (0.7–6.7 wt. % NaCl eq.). The variability of δ18O values of authigenic carbonates (−1.7 to −8.2‰ V-PDB) could reflect either slight changes in temperature of escaping fluids (mostly within 15 °C), and/or some mixing with meteoric waters. The low δ34S values of vein marcasite (∼–20‰ V-CDT) are consistent with bacterial reduction of sulfate in the hydrothermal system. Low C1/(C2+C3) ratios in hydrocarbon gas extracted from authigenic carbonates (9.9 and 5.8) as well as the high δ13C values of methane (−31.8 and −32.4‰ V-PDB) are compatible with a thermogenic source of hydrocarbons. REE data indicate sequestration of REE from finely dispersed detrital material in the apical part of the hydrothermal system. The available data are compatible with two possible scenarios of fluid origin. The hydrocarbons could have been leached from underlying Paleozoic sedimentary sequence by aqueous fluids that infiltrated into the basement after Tertiary tectonic reactivation. Alternatively, an external source of hydrocarbon-bearing fluids can be found in the adjacent Outer Western Carpathians flysch nappes containing petroleum-producing lithologies. Nevertheless, a regional flow of hydrocarbon-bearing fluids is evidenced by the occurrence of very similar hydrocarbon-bearing vein mineralizations in a wider area.

Hydrocarbon generation from coal, extracted coal and bitumen rich coal in confined pyrolysis experiments

Three sets of pyrolysis experiments were performed on extracted coal (Ro% 0.39), coal (initial bitumen 13.5mg/g coal) and bitumen enriched coal (total bitumen 80.9mg/g coal) at two heating rates of 2°C/h and 20°C/h in confined systems (gold capsules). For all three experiments, the yields of bitumen, Σn-C8+, aromatic components and ΣC2–5 at first increase and then decrease with increasing EASY%Ro and reach the highest values within the EASY%Ro ranges of 0.67–1.08, 1.07–1.19, 1.46–1.79 and 1.46–1.68, respectively. In contrast, C1/ΣC1–5 ratio at first decreases and then increases with EASY%Ro and reaches a minimum value in EASY%Ro range of 0.86–1.08, closely corresponding to the maximum values of the yields of bitumen and Σn-C8+. Methane yields increase consistently with EASY%Ro. Nearly half of the maximum yield of methane from kerogen was generated at EASY%Ro>2.2. The differences in methane yields among the three experiments at the same thermal stress are relatively minor at EASY%Ro<2.2, but are greater with thermal stress at EASY%Ro>2.2. This demonstrates that the kerogen always retained relatively more hydrogen and hydrocarbon generative potential at the postmature stage of bitumen rich coal than the extracted coal or coal.The maximum yield of ethane is 20–25% higher in the bitumen rich coal experiment than the extracted coal or coal, while the maximum yields of C3, C4 and C5 in the former are double to triple those in the latter. This result demonstrates that the added bitumen in bitumen rich coal substantially increased the generation of these wet gases. However, the averaged values of activation energies (with the same frequency factors) for both the generation and cracking of individual wet gases are similar and do not show consistent trends among the three experiments. For all three experiments, activation energies for the generation and cracking of wet gases are significantly lower than those in previously published oil pyrolysis experiments with same frequency factors (Pan et al., 2012; Organic Geochemistry 45, 29–47). Methane δ13C values at the maximum temperature or EASY%Ro are close to those of initial wet gases, especially C3, implying that the major part of methane shared a common initial precursor with wet gases, i.e., free and bound liquid alkanes.

Sources of natural gases in Middle Cambrian reservoirs in Polish and Lithuanian Baltic Basin as determined by stable isotopes and hydrous pyrolysis of Lower Palaeozoic source rocks

Origin of natural gases associated with oil and condensate accumulations within the Middle Cambrian sandstone reservoir of the Polish and Lithuanian Baltic Basin was characterised by means of molecular composition, stable carbon isotopes of methane, ethane, propane, butanes, pentanes and carbon dioxide, stable hydrogen isotopes of methane and stable nitrogen isotopes of gaseous nitrogen. Generated gas from potential Upper Cambrian, Tremadocian, and Llandovery source rocks by hydrous pyrolysis at 330°C and 355°C for 72h was used to characterise thermogenic gas to evaluate correlation parameters based on molecular composition and stable isotopes. The pyrolysis conditions represent gas generation during oil generation, which appears to be the conditions represented by the natural gas accumulations and their low GORs (gas:oil ratios). The dryness of the pyrolysis and natural hydrocarbon compositions compare well, but do not provide a means of distinguishing the contributions of each source rock to the natural gas accumulations. The average δ13C value of the natural methane is 6.9‰ depleted in 13C compared to methane generated in the hydrous pyrolysis experiments. This difference is less for ethane and essentially nonexistent for propane, butanes, and pentanes. Tentatively, this diminishing difference with increasing carbon number is attributed to kinetic effects resulting from higher experimental temperatures. Although the δ13C values of methane and ethane from the hydrous pyrolysis experiments are not useful in direct correlations with natural gas accumulations, δ13C of propane, butanes, and pentanes is useful, and indicates that the Upper Cambrian and Tremadocian source rocks are the main contributors and that the Llandovery source rocks are not significant contributors to the Polish and Lithuanian Baltic natural gases. Polish natural gases with relatively higher methane and ethane are attributed to the mixing of drier, more mature gases from deeper parts of the basin to the west. Carbon dioxide of natural gases was generated during thermogenic processes and gaseous nitrogen was generated from NH4-rich illites of the clayey facies and from thermal transformation of organic matter of the Lower Palaeozoic strata. Hydrous pyrolysis gases have higher concentrations of CO2, H2S and H2 than the natural gases. This difference is attributed to reduction or loss of these highly reactive and soluble gases during migration and entrapment of the natural gases. Although CO2 concentrations between pyrolysis and natural gases are different, the δ13C values of the former fall within the range of the latter.

Coseimic massive methane release from a submarine mud volcano

We report here the discovery of two methane-enriched plumes in a water column above the Kumano Knoll ♯5 submarine mud volcano (KK#5) in Nankai Trough during 2004; a slight methane enrichment was observed in this region in 2000 and 2010. The deeper of the two plumes spread horizontally at depths near the top of KK#5, whereas a shallow plume spread at a height of 300m from the top of KK#5. The end-member δ13C values of methane in both plumes, −46.1±4.8‰ and −51.4±5.8‰ in the deep and shallow plumes, respectively, and methane extracted from sediment in KK#5 (−52±2‰) are statistically indistinguishable. We conclude that the plumes were created by massive release of methane from KK#5 and that this event probably occurred in response to the large earthquakes (Mw 7.5) that occurred shortly before our observation in 2004. The discharge rates from submarine mud volcanoes (SMVs) in subduction zones may be highly variable in response to major earthquakes.

Diagenetic source of fluids causing the hydrothermal alteration of teschenites in the Silesian Unit, Outer Western Carpathians, Czech Republic: Petroleum-bearing vein mineralization from the Stříbrník site

Calcite-pyrite veinlets containing a small amount of quartz, chlorite, sphalerite and marcasite occur in teschenite which is situated within the Lower Cretaceous flysch siliciclastics of the Silesian Unit. Fluid inclusion study demonstrated the presence of a heterogeneous mixture of a low-salinity aqueous solution and mature methane-rich petroleum during precipitation of calcite and quartz. The δ13C values of methane and dissolved carbonate, δ34S values of pyrite, and δ18O values of parent hydrothermal solutions are all consistent with the external source of the fluid phase, derived from diagenetically modified flysch sediments. The vein formation occurred during an increase in both temperature (from <80 °C to 220 °C) and pressure (∼100–700 bar). The observed discrepancy between the maximum fluid temperature and the regional burial temperature, together with fluctuations in petroleum density and significant variations in chemical and isotopic compositions of fluids are interpreted in terms of episodic tectonically induced generation of the fluid phase related to deeper burial. The observed REE patterns of hydrothermal calcite and pyrite can be attributed to increased concentrations of organic ligands in the fluid phase and/or involvement of sorption/desorption processes.

Substrate Limitation for Methanogenesis in Hypersaline Environments

Motivated by the increasingly abundant evidence for hypersaline environments on Mars and reports of methane in its atmosphere, we examined methanogenesis in hypersaline ponds in Baja California Sur, Mexico, and in northern California, USA. Methane-rich bubbles trapped within or below gypsum/halite crusts have δ¹³C values near -40‰. Methane with these relatively high isotopic values would typically be considered thermogenic; however, incubations of crust samples resulted in the biological production of methane with similar isotopic composition. A series of measurements aimed at understanding the isotopic composition of methane in hypersaline systems was therefore undertaken. Methane production rates, as well as the concentrations and isotopic composition of the particulate organic carbon (POC), were measured. Methane production was highest from microbial communities living within gypsum crusts, whereas POC content at gypsum/halite sites was low, generally less than 1% of the total mass. The isotopic composition of the POC ranged from -26‰ to -10‰. To determine the substrates used by the methanogens, ¹³C-labeled methylamines, methanol, acetate, and bicarbonate were added to individual incubation vials, and the methane produced was monitored for ¹³C content. The main substrates used by the methanogens were the noncompetitive substrates, the methylamines, and methanol. When unlabeled trimethylamine (TMA) was added to incubating gypsum/halite crusts in increasing concentrations, the isotopic composition of the methane produced became progressively lower; the lowest methane δ¹³C values occurred when the most TMA was added (1000 μM final concentration). This decrease in the isotopic composition of the methane produced with increasing TMA concentrations, along with the high in situ methane δ¹³C values, suggests that the methanogens within the crusts are operating at low substrate concentrations. It appears that substrate limitation is decreasing isotopic fractionation during methanogenesis, which results in these abnormally high biogenic methane δ¹³C values.

Major ion and isotope geochemistry of fluids and gases from coalbed methane and shallow groundwater wells in Alberta, Canada

The production of coalbed methane (CBM) represents a vital new source of natural gas supply in Western Canada. There are, however, concerns over potential negative environmental impacts on shallow groundwater resources in the hypothetical case that leakage of fluids and gases from CBM operations occurs. This paper compares major ion and isotope geochemistry data for produced fluids or gases from two major coal deposits in Western Canada (Mannville Formation and the Horseshoe Canyon/Belly River Group) with similar data collected for shallow groundwater in south-central Alberta. The objective was to generate comprehensive baseline geochemical data to determine the key geochemical characteristics and differences of produced fluids and gases from two coal deposits and shallow groundwater in Alberta and to find parameters that are suitable for identifying potential leakage of fluids or gases into shallow groundwater. Shallow groundwater had average total dissolved solids (TDS) of 1037 mg/L. Most samples belonged to the Na–HCO3–SO4 water type and average SO42- concentrations were 185 mg/L. The Horseshoe Canyon/Belly River Group swabbing fluids had average TDS of 5427 mg/L, a Na–HCO3 water type, and average SO42- concentrations of 47.7 mg/L. The produced fluids from the Mannville Formation had average TDS contents of 74,500 mg/L, negligible SO42- and a Na–Cl water type. Shallow groundwater and produced fluids from the Horseshoe Canyon Formation and the Mannville group had distinct δ2H and δ18O values and plotting δ18O values versus total dissolved solids was found to be an effective approach to distinguish the waters. Sulfur isotope data revealed the occurrence of bacterial (dissimilatory) SO4 reduction in some shallow groundwater samples and in the produced fluids from the Horseshoe Canyon/Belly River Group. Methane was found in several shallow groundwater samples and its average δ13C (−72.1 ± 6.8‰) and δ2H values (−297 ± 17‰) indicated a biogenic origin predominantly from CO2 reduction. Dissolved gases from the Horseshoe Canyon Formation fluids with average δ13C values of methane of −54.0 ± 4.1‰ and ethane of −36.5 ± 2.4‰ and traces of higher alkanes suggest a mixture of predominantly biogenic and some thermogenic gas. Dissolved hydrocarbon gas from the Mannville Formation had the highest average δ13C values of −49.4 ± 3.6‰ for methane, −28.8 ± 2.1‰ for ethane and −26.9 ± 1.1‰ for propane. The presence of higher alkanes suggests that the Mannville produced fluids contain an appreciable thermogenic gas component. The biogenic gas component in the Horseshoe Canyon and the Mannville Formation was mainly formed via acetate fermentation according to αCO2–CH4 values between 1.02 and 1.07. It is concluded that δ18O values of the fluids in concert with total dissolved solids, and the isotopic compositions of methane and ethane are sufficiently distinct in shallow groundwater and produced fluids from the Horseshoe Canyon and the Mannville Formations that they may serve as tracers for evaluating potential contamination of shallow groundwater with produced fluids or gases.