Organic geochemical characteristics and oil generating potential of the Upper Jurassic Safer shale sediments in the Marib-Shabowah Basin,western Yemen

The organic rich Safer shales exposed in the north-central part of onshore Marib-Shabowah Basin are evaluated and their depositional environments are interpreted. Total organic carbon contents (TOC) of the shales range from 1.02–16.8 wt%, and yield hydrogen index (HI) values ranging from 130 to 820 mg HC/g TOC, consistent with mainly Type II with minor contributions from Type I and mixed Types II–III kerogens. The Safer shale samples have vitrinite reflectance values in the range of 0.5–1.0 R_o%, indicating early mature to peak mature stage for oil generation. T_max values range from 429–438 °C, which are in reasonably good agreement with vitrinite reflectance data. Kerogen microscopy shows that the Safer shales are characterized by high amounts of organic matter, consisting predominantly of yellow fluorescing amorphous organic matter and alginite of marine origin. This is supported by their high content of hydrogen rich Type II and I oil-prone kerogen.The biomarker distributions of the Upper Jurassic Safer extracts are characterized by dominant low to medium molecular weight compounds (n-C₁₄ to n-C₂₀), low Pr/Ph ratio (<1.0), high phytane/n-C₁₈ ratios (0.82–2.68), and predominant regular sterane C₂₇. All biomarker parameters clearly indicate that the organic matter was derived from marine algal inputs and deposited under anoxic (reducing) conditions. Hypersaline conditions also prevailed during deposition of these sediments, as indicated by the presence of gammacerane.     

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.     

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.     

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.     

Physical properties of selected block Argonne Premium bituminous coal related to CO2, CH4, and N2 adsorption

CO₂, CH₄, and N₂ adsorption and gas-induced swelling were quantified for block Blind Canyon, Pittsburgh #8 and Pocahontas Argonne Premium coals that were dried and structurally relaxed at 75 °C in vacuum. Strain measurements were made perpendicular and parallel to the bedding plane on ~ 7 × 7 × 7 mm³ coal blocks and gravimetric sorption measurements were obtained simultaneously on companion coal blocks exposed to the same gaseous environment. The adsorption amount and strain were determined after equilibration at P  ≤ 1.8 MPa. There is a strong non-linear correlation between strain and the quantity of gas adsorbed and the results for all gases and coals studied follow a common pattern. The dependence of the coal matrix shrinkage/swelling coefficient (C_gc) on the type and quantity of gas adsorbed is seen by plotting the ratio between the strain and the adsorbate concentration against the adsorbate concentration. In general, C_gc increases with increasing adsorbate concentration over the range of ~ 0.1 to 1.4 mmol/g. Results from the dried block coals are compared to CO₂ experiments using native coals with an inherent level of moisture as received. The amount of CO₂ adsorbed using native coals (assuming no displacement of H₂O by CO₂) is significantly less than the dried coals. The gas-induced strain (S) and adsorption amount (M) were measured as a function of time following step changes in CO₂, CH₄, and N₂ pressure from vacuum to 1.8 MPa. An empirical diffusion equation was applied to the kinetic data to obtain the exponent (n) for time dependence for each experiment. The data for all coals were pooled and the exponent (n) evaluated using an ANOVA statistical analysis method. Values for (n) near 0.5 were found to be independent on the coal, the gas or type of measurement (e.g., parallel strain, perpendicular strain, and gas uptake). These data support the use of a Fickian diffusion model framework for kinetic analysis. The kinetic constant k was determined using a unipore diffusion model for each experiment and the data were pooled for ANOVA analysis. For dry coal, statistically significant differences for k were found for the gases (CO₂ > N₂ > CH₄) and coals (Pocahontas >Blind Canyon > Pittsburgh #8) but not for the method of the kinetic measurement (e.g., strain or gas uptake). For Blind Canyon and Pittsburgh #8 coal, the rate of CO₂ adsorption and gas-induced strain for dry coal was significantly greater than that of the corresponding native coal. For Pocahontas coal the rates of CO₂ adsorption and gas-induced strain for dry and native coal were indistinguishable and may be related to its low native moisture and minimal amount of created porosity upon drying.     

Isotope geochemistry of Swan Lake Basin in the Nebraska Sandhills,USA: Large 13C enrichment in sediment-calcite records

This study presents isotope geochemical analyses conducted on water column samples and core sediments collected from the Swan Lake Basin. Water analyses include the dissolved methane (CH₄) content and the ratio of carbon-13 to carbon-12 (δ¹³C) in dissolved inorganic carbon (DIC). The core sediments – sandy muds containing inorganic calcite, organic matter, and opal phases ± ostracods – were examined by X-ray diffraction, dated by radiocarbon (¹⁴C), analyzed for wt% organic carbon, wt% organic nitrogen, wt% organic matter, wt% calcite, δ¹³C of bulk-sediment insoluble organic matter (kerogen), ¹⁸O:¹⁶O ratio (δ¹⁸O) and δ¹³C of bulk and ostracod calcite. Of particular significance is the large enrichment in carbon-13 (δ¹³C = +4.5 to +20.4‰ V-PDB) in the calcite of these sediments. The ¹³C-enriched calcite is primarily formed from DIC in the water column of the lake as a result of the following combined processes: (i) the incorporation of ¹³C enriched residual carbon dioxide (CO₂) after partial reduction to CH₄ in the sediments and its migration into the water column-DIC pool; (ii) the preferential assimilation of ¹²C by phytoplankton during photosynthesis; (iii) the removal of ¹³C-depleted CH₄ by ebullition and of organic matter by sedimentation and burial. The ¹³C enrichment was low between 3624 and 2470 yr BP; high between 2470 and 1299 yr BP; and moderate since 1299 yr BP. Low ¹³C enrichment was formed under low water-column carbon levels while higher ones were formed under elevated rates of biomass and calcite deposition. These associations seem to imply that biological productivity is the main reason for carbon-13 enrichments.     

Characterization of the CO2 fluid adsorption in coal as a function of pressure using neutron scattering techniques (SANS and USANS)

Small angle neutron scattering techniques have been applied to investigate the phase behavior of CO₂ injected into coal and possible changes in the coal pore structure that may result from this injection. Three coals were selected for this study: the Seelyville coal from the Illinois Basin (R_o = 0.53%), Baralaba coal from the Bowen Basin (R_o = 0.67%), and Bulli 4 coal from the Sydney Basin (R_o = 1.42%). The coals were selected from different depths to represent the range of the underground CO₂ conditions (from subcritical to supercritical) which may be realized in the deep subsurface environment. The experiments were conducted in a high pressure cell and CO₂ was injected under a range of pressure conditions, including those corresponding to in-situ hydrostatic subsurface conditions for each coal. Our experiments indicate that the porous matrix of all coals remains essentially unchanged after exposure to CO₂ at pressures up to 200 bar (1 bar = 10⁵ Pa). Each coal responds differently to the CO₂ exposure and this response appears to be different in pores of various sizes within the same coal. For the Seelyville coal at reservoir conditions (16 °C, 50 bar), CO₂ condenses from a gas into liquid, which leads to increased average fluid density in the pores (ρ_pore) with sizes (r) 1 × 10⁵ ≥ r ≥ 1 × 10⁴ Å (ρ_pore ≈ 0.489 g/cm³) as well as in small pores with size between 30 and 300 Å (ρ_pore ≈ 0.671 g/cm³). These values are by a factor of three to four higher than the density of bulk CO₂ (ρ_CO2) under similar thermodynamic conditions (ρ_CO2 ≈ 0.15 g/cm³). At the same time, in the intermediate size pores with r ≈ 1000 Å the average fluid density is similar to the density of bulk fluid, which indicates that adsorption does not occur in these pores. At in situ conditions for the Baralaba coal (35 ^OC, 100 bar), the average fluid density of CO₂ in all pores is lower than that of the bulk fluid (ρ_pore / ρ_CO2 ≈ 0.6). Neutron scattering from the Bulli 4 coal did not show any significant variation with pressure, a phenomenon which we assign to the extremely small amount of porosity of this coal in the pore size range between 35 and 100,000 Å.     

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

Three sets of pyrolysis experiments were performed on extracted coal (R_o% 0.39), coal (initial bitumen 13.5 mg/g coal) and bitumen enriched coal (total bitumen 80.9 mg/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 ΣC_2–5 at first increase and then decrease with increasing EASY%R_o and reach the highest values within the EASY%R_o ranges of 0.67–1.08, 1.07–1.19, 1.46–1.79 and 1.46–1.68, respectively. In contrast, C₁/ΣC_1–5 ratio at first decreases and then increases with EASY%R_o and reaches a minimum value in EASY%R_o 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%R_o. Nearly half of the maximum yield of methane from kerogen was generated at EASY%R_o > 2.2. The differences in methane yields among the three experiments at the same thermal stress are relatively minor at EASY%R_o < 2.2, but are greater with thermal stress at EASY%R_o > 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%R_o 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.     

Small angle X-ray scattering mapping and kinetics study of sub-critical CO2 sorption by two Australian coals

Time- and position-resolved synchrotron small angle X-ray scattering data were acquired from samples of two Australian coal seams: Bulli seam (Bulli 4, R_o = 1.42%, Sydney Basin), which naturally contains CO₂ and Baralaba seam (R_o = 0.67%, Bowen Basin), a potential candidate for sequestering CO₂. This experimental approach has provided unique, pore-size-specific insights into the kinetics of CO₂ sorption in the micro- and small mesopores (diameter 5 to 175 Å) and the density of the sorbed CO₂ at reservoir-like conditions of temperature and hydrostatic pressure.For both samples, at pressures above 5 bar, the density of CO₂ confined in pores was found to be uniform, with no densification in near-wall regions. In the Bulli 4 sample, CO₂ first flooded the slit pores between polyaromatic sheets. In the pore-size range analysed, the confined CO₂ density was close to that of the free CO₂. The kinetics data are too noisy for reliable quantitative analysis, but qualitatively indicate faster kinetics in mineral-matter-rich regions.In the Baralaba sample, CO₂ preferentially invaded the smallest micropores and the confined CO₂ density was up to five times that of the free CO₂. Faster CO₂ sorption kinetics was found to be correlated with higher mineral matter content but, the mineral-matter-rich regions had lower-density CO₂ confined in their pores. Remarkably, the kinetics was pore-size dependent, being faster for smaller pores.These results suggest that injection into the permeable section of an interbedded coal-clastic sequence could provide a viable combination of reasonable injectivity and high sorption capacity.     

Contact metamorphism of organic-rich mudstones and carbon release around a magmatic sill in the Basque-Cantabrian Basin,western Pyrenees

Recent studies have documented the expulsion of methane and oil to the Albian paleoseabed in the Basque-Cantabrian Basin. They interpret that hydrocarbon generation and expulsion were triggered by seismically recorded magmatic intrusions which metamorphosed organic-rich host sediments. An outcrop within the basin was selected to investigate organic matter evolution and sediment degassing due to an igneous body. This intrusion is a 5 m thick Late Albian basaltic sill that intruded mudstones of the Black Flysch Group, near Gorliz (north Iberia). Vitrinite and bitumen reflectance profiles and metamorphic mineral distribution in the overburden indicate that the sill produced a thermal effect that increases toward the intrusion, defining a 2 m thick (minimum) contact aureole.Geochemical profiles of TOC, S1, S2, HI and PC show a gradual decrease toward the sill indicating organic carbon loss and increase in the thermal maturity of the organic matter in the same direction. Concordantly, gas chromatograms show a loss of n-alkanes and a predominance of the shorter chain length homologues adjacent to the sill. Tmax and PI (S1/S1 + S2) values increase toward the sill which suggests an increase in the thermal stress and in the extent of kerogen pyrolysis, respectively.Organic carbon loss in the aureole was the result of carbon devolatilization and formation of CO₂ and CH₄ gases. The newly formed CO₂ reacted with pore waters to precipitate ¹³C depleted carbonate minerals in the aureole and in sill fractures. CH₄ escaped from the aureole via hydrofractures to the paleoseabed, where methane-derived authigenic carbonates were formed.     

Key factors controlling the gas adsorption capacity of shale: A study based on parallel experiments

This article performed a series of parallel experiments with numerical modeling to reveal key factors affecting the gas adsorption capacity of shale, including shale quality, gas composition and geological conditions. Adsorption experiments for shales with similar OM types and maturities indicate that the OM is the core carrier for natural gas in shale, while the clay mineral has limited effect. The N₂ and CO₂ adsorption results indicate pores less than 3 nm in diameter are the major contributors to the specific surface area for shale, accounting for 80% of the total. In addition, micropores less than 2 nm in diameter are generated in large numbers during the thermal evolution of organic matter, which substantially increases the specific surface area and adsorption capacity. Competitive adsorption experiments prove that shale absorbs more CO₂ than CH₄, which implies that injection CO₂ could enhance the CH₄ recovery, and further research into N₂ adsorption competitiveness is needed. The Langmuir model simulations indicate the shale gas adsorption occurs via monolayers. Geologically applying the adsorption potential model indicates that the adsorption capacity of shale initially increases before decreasing with increasing depth due to the combined temperature and pressure, which differs from the changing storage capacity pattern for free gases that gradually increase with increasing depth at a constant porosity. These two tendencies cause a mutual conversion between absorbed and free gas that favors shale gas preservation. During the thermal evolution of organic matter, hydrophilic NSO functional groups gradually degrade, reduce the shale humidity and increase the gas adsorption capacity. The shale quality, gas composition and geological conditions all affect the adsorption capacity. Of these factors, the clay minerals and humidity are less important and easily overshadowed by the other factors, such as organic matter abundance.     

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).     

FTIR microspectroscopy of Ediacaran phosphatized microfossils from the Doushantuo Formation,Weng'an,South China

Phosphatized microfossils from ca. 580 Ma from the Doushantuo Formation in the Weng'an region of South China were analyzed by Fourier transform infrared (FTIR) microspectroscopy for their chemical characterization. Two morpho-types of phosphatized embryo-like fossils (Megasphaera and Megaclonophycus) were analyzed, together with algal fossils. Transmission IR spectra of the microfossils have absorption bands of around 2960 cm^− 1 and 2925 cm^− 1, indicating the presence of aliphatic hydrocarbon (anti-symmetric aliphatic CH₃ and aliphatic CH₂), and have an additional band of around 1595 cm^− 1, probably derived from aromatic moieties (aromatic CC). In addition, IR microscopic mapping shows that aliphatic hydrocarbon and aromatics are distributed inside the embryo-like fossils. The embryo-like fossils appear to show three types of CH₃/CH₂ peak height ratios (R_3/2) and aromatic CC/CH₂ peak height ratios (R_CC/2 values): (1) high-R_3/2/low-R_CC/2 type (R_3/2 = ~ 0.2–1.0 and R_CC/2 ~ 0–2), (2) low-R_3/2/medium-R_CC/2 type (R_3/2 = ~ 0.2–0.6 and R_CC/2 = ~ 1–4); and (3) low-R_3/2/high-R_CC/2 type (R_3/2 = ~ 0.2–0.6 and R_CC/2 ~ 1–8). All three types are contained in both Megasphaera and Megaclonophycus. Raman spectra for the carbonaceous matter within the rock sample show a similar degree of thermal alteration, indicating that the organics were embedded in situ prior to thermal maturation. The IR spectroscopic differences might reflect differences in original organic compositions of microorganisms, and/or immediate post-mortem alteration. This suggests that the origins of phosphatized embryo-like fossils are more diverse than was previously recognized on the basis of their morphology. A comparison of R_3/2 and R_CC/2 values in the embryo-like fossils with those of the algal fossils and the extant microorganisms indicates the possible interpretation that some of the embryo-like fossils belong to animal embryo, others are algae, but none of them originate from bacteria.     

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.     

Interaction of U(VI) with Äspö diorite: A batch and in situ ATR FT-IR sorption study

Pristine diorite drill cores, obtained from the Äspö Hard Rock Laboratory (HRL, Sweden), were used to study the retention properties of fresh, anoxic crystalline rock material towards the redox-sensitive uranium. Batch sorption experiments and spectroscopic methods were applied for this study. The impact of various parameters, such as solid-to-liquid ratio (2–200 g/L), grain size (0.063–0.2 mm, 0.5–1 mm, 1–2 mm), temperature (room temperature and 10 °C), contact time (5–108 days), initial U(VI) concentration (3 × 10⁻⁹ to 6 × 10⁻⁵ M), and background electrolyte (synthetic Äspö groundwater and 0.1 M NaClO₄) on the U(VI) sorption onto anoxic diorite was studied under anoxic conditions (N₂). Comparatively, U(VI) sorption onto oxidized diorite material was studied under ambient atmosphere (pCO₂ = 10^−3.5 atm). Conventional distribution coefficients, K_d, and surface area normalized distribution coefficients, K_a, were determined. The K_d value for the U(VI) sorption onto anoxic diorite in synthetic Äspö groundwater under anoxic conditions by investigating the sorption isotherm amounts to 3.8 ± 0.6 L/kg which corresponds to K_a = 0.0030 ± 0.0005 cm (grain size 1–2 mm). This indicates a weak U sorption onto diorite which can be attributed to the occurrence of the neutral complex Ca₂UO₂(CO₃)₃(aq) in solution. This complex was verified as predominating U species in synthetic Äspö groundwater by time-resolved laser-induced fluorescence spectroscopy (TRLFS). Compared to U sorption at room temperature under anoxic conditions, U sorption is further reduced at decreased temperature (10 °C) and under ambient atmosphere. The U species in aqueous solution as well as sorbed on diorite were studied by in situ time-resolved attenuated total reflection Fourier-transform infrared (ATR FT-IR) spectroscopy. A predominant sorbing species containing a UO₂(CO₃)₃⁴⁻ moiety was identified. The extent of U sorption onto diorite was found to depend more on the low sorption affinity of the Ca₂UO₂(CO₃)₃(aq) complex than on reduction processes of uranium.     

Gas-generation potential of shales in small and medium-sized basins: a case study from the Xuanhua Basin,north China

Abstract

Small- and medium-sized basins are widely distributed, and some contain commercial gas reservoirs demonstrating their gas-generation potential. The Xuanhua Basin, which is a small-sized coal-bearing basin in north China, includes a promising target for shale-gas exploration in the Xiahuayuan Formation. In this study, we used this basin as a case study to assess the critical geochemical features for small or medium-sized basins to form commercial gas reservoirs. Total organic carbon (TOC) analysis, Rock-Eval pyrolysis, microscopic observation of macerals, vitrinite reflectance measurement and kerogen stable carbon isotope analysis were performed to characterise the organic geochemistry of the Xiahuayuan shales. The original total organic carbon (TOC_o) content and hydrocarbon-generative potential (S_2o) were reconstructed to further evaluate the gas-generation potential of these shales. In addition, geochemical data of shales from other similar-sized basins with gas discoveries were compared. The results showed that the kerogen from the Xiahuayuan Formation is Type III (gas-prone), and macerals are dominated by vitrinite. TOC values showed a strong heterogeneity in the vertical profiles, with most higher than 1.5?wt%. The measured R_o values ranged from 1.4 to 2.0%. However, thermal maturity was not correlated with the present-day burial depth with higher maturity in the wells closest to the diabase intrusion centre. The remaining generation potential (S₂) averaged 0.91?mg HC/g rock, equal to 1.4?cm³ CH₄/g rock, and the average amount of hydrocarbon generated was 4.33?cm³ CH₄/g rock. In small and medium-sized basins, the TOC content of commercially developed gas shales ranged from 0.5 to 2.5?wt%, organic matter was mainly humic (gas-prone), and the burial depth was generally shallow. Biogenic gas reservoirs for commercial exploitation tend to have larger shale thicknesses (120–800?m) than thermogenic gas reservoirs (60–90?m).

1. The Xiahuayuan Formation is a good gas-source rock with gas-prone kerogen type, relatively high TOC values and moderate thermal maturity.

2. The average amount of hydrocarbon generated from the Xiahuayuan shales is about 4.33?cm³ CH₄/g rock, indicating a potential to form a shale gas reservoir.

3. Owing to the influence of diabase intrusions, the Xiahuayuan shales have entered the dry gas window at relatively shallow-buried depths.

4. Small- and medium-sized basins have the potential to generate commercial gas reservoirs with the generated volume mainly a product of the thickness and maturity of black shales.

     

Assessing the solubility controls on vanadium in groundwater,northeastern San Joaquin Valley,CA

The solubility controls on vanadium (V) in groundwater were studied due to concerns over possible harmful health effects of ingesting V in drinking water. Vanadium concentrations in the northeastern San Joaquin Valley ranged from <3 μg/L to 70 μg/L with a median of 21 μg/L. Concentrations of V were highest in samples collected from oxic groundwater (49% > 25 μg/L) and lowest in samples collected from anoxic groundwater (70% < 0.8 μg/L). In oxic groundwater, speciation modeling (SM) using PHREEQC predicted that V exists primarily as the oxyanion H₂VO₄⁻. Adsorption/desorption reactions with mineral surfaces and associated oxide coatings were indicated as the primary solubility control of V⁵⁺ oxyanions in groundwater. Environmental data showed that V concentrations in oxic groundwater generally increased with increasing groundwater pH. However, data from adsorption isotherm experiments indicated that small variations in pH (7.4–8.2) were not likely as an important a factor as the inherent adsorption capacity of oxide assemblages coating the surface of mineral grains. In suboxic groundwater, accurate SM modeling was difficult since Eh measurements of source water were not measured in this study. Vanadium concentrations in suboxic groundwater decreased with increasing pH indicating that V may exist as an oxycationic species [e.g. V(OH)₃⁺]. Vanadium may complex with dissolved inorganic and organic ligands under suboxic conditions, which could alter the adsorption behavior of V in groundwater. Speciation modeling did not predict the existence of V-inorganic ligand complexes and organic ligands were not collected as part of this study. More work is needed to determine processes governing V solubility under suboxic groundwater conditions. Under anoxic groundwater conditions, SM predicts that aqueous V exists as the uncharged V(OH)₃ molecule. However, exceedingly low V concentrations show that V is sparingly soluble in anoxic conditions. Results indicated that V may be precipitating as V³⁺- or mixed V³⁺/Fe³⁺-oxides in anoxic groundwater, which is consistent with results of a previous study. The fact that V appears insoluble in anoxic (Fe reducing) redox conditions indicates that the behavior of V is different than arsenic (As) in aquifer systems where the reductive dissolution of Fe-oxides with As adsorbed to the surface is a well-documented mechanism for increasing As concentrations in groundwater. This hypothesis is supported by the relation of V to As concentrations in oxic versus anoxic redox conditions.Sequential extraction procedures (SEP) applied to aquifer material showed that the greatest amount of V was recovered by the nitric acid (HNO₃) extract (37–71%), followed by the oxalate-ascorbic acid extract (19–60%) and the oxalate extract (3–14%). These results indicate that V was not associated with the solid phase as an easily exchangeable fraction. Although the total amount of V recovered was greatest for the HNO₃ extract that targets V adsorbed to sorption sites of crystalline Al, Fe and Mn oxides, the greatest V saturation of sorption sites appeared to occur on the amorphous and poorly crystalline oxide solid phases targeted by the oxalate and oxalate-ascorbic acid extracts respectively. Adsorption isotherm experiments showed no correlation between V sorption and any of the fractions identified by the SEP. This lack of correlation indicates the application of an SEP alone is not adequate to estimate the sorption characteristics of V in an aquifer system.     

Organic geochemistry and depositional environment of the Aptian bituminous limestone in the Kale Gümüşhane area (NE-Turkey): An example of lacustrine deposits on the platform carbonate sequence

The Jurassic–Lower Cretaceous aged carbonate sequence is widely exposed in the southern zone of Eastern Pontides. Aptian black bituminous limestone is found in the upper part of this sequence in the Kale area (Gümüşhane). This limestone contains faunal remains (e.g., gastropod, ostracod, characean stems and miliolid type benthic foraminifera) that indicate a freshwater, lacustrine depositional environment.The total organic carbon (TOC) values of the bituminous limestone samples range from 0.11–1.30% with an average TOC value of 0.54%. The hydrogen index (HI) varies from 119–448 mg HC/g TOC (average HI 298 mg HC/g TOC) indicating that the limestone contains gas prone as well as oil prone organic matter. Pyrolysis data prove that the organic matter content in the bituminous limestone consists of Type II kerogen. The average T_max value for bituminous limestone samples is 438 °C (434–448 °C). Bitumen/TOC ratios for bituminous limestone are 0.05 and 0.04. The T_max values and the ratios indicate that the bituminous limestone samples contain early mature to mature organic matter.Analysis of solvent extracts from the two richest bituminous limestones show a predominance of high carbon number (C₂₆–C₃₀) n-alkanes. The Pr/Ph ratio and CPI value are 1.34 and 0.96, respectively. C₂₉ is the dominant sterane, with C₂₉ > C₂₇ > C₂₈. The bituminous limestone samples have low C₂₂/C₂₁ ratios, high C₂₄/C₂₃ tricyclic terpane ratios and very low C₃₁R/C₃₀ hopane ratios (<0.25). These data are consistent with the bituminous limestones being deposited in a lacustrine environment.     

Temperature and time effect on the concentrations of free radicals in coal: Evidence from laboratory pyrolysis experiments

The relationships between free radical concentration (N_g) and vitrinite reflectance (%R_o) of coal were tested through 36 laboratory anhydrous pyrolysis experiments. The experiments were carried out at isothermal reactor with pyrolysis temperatures ranging from 300 to 550 °C over 30–480 min. The effects of temperature and retention time on the N_g were investigated. The concentrations of free radicals in pyrolysis coal samples increase with increasing time and temperature of experiments and reach a maximum value at about 1.75 %R_o, and then decrease with further maturation. The Temperature Time Index (TTI) integral equation was applied to establish the relationship between the TTI and N_g in this paper. As the free radical concentration in organic matter is strongly maturity dependent, it may prove to be a valuable geothermometer for paleogeotemperature study in sedimentary basins.     

Reconstruction of paleo-redox conditions and early sulfur cycling during deposition of the Cryogenian Datangpo Formation in South China

In South China, the Datangpo black shales (663 Ma–654.5 Ma) were deposited during the Cryognian interglacial time between the Sturtian and Marinoan glaciations. Multi-geochemical proxies, including different iron speciation and relevant ratios (Fe_HR/Fe_T, Fe_P/Fe_HR and Fe_T/Al ratios) and molybdenum concentrations, were used to reconstruct the paleo-depositional environment of this black shale horizon. The ratios of different iron species (Fe_HR/Fe_T > 0.38 and Fe_P/Fe_HR < 0.80) suggest an overall anoxic conditions (ferruginous) over the deposition of the black shales, although intermittent euxinic (Fe_HR/Fe_T > 0.38 and Fe_P/Fe_HR ≈ 0.80) and oxic (Fe_HR/Fe_T < 0.38) intervals could have occurred. Furthermore, Fe_T/Al ratios (Fe_T/Al ≤ 0.51) confirm that water column may not be persistent euxinia during the deposition of the Datangpo black shales. Meanwhile, molybdenum concentrations show a decreasing trend towards the top of the black shales, reconciling the gradual oxygenating trend during this period as stated above. Compared to δ³⁴S_Py values in the Mesoproterozoic deep ocean, more positive δ³⁴S_Py values of this study may result from a small size of sulfate reservoir. The small-size sulfate reservoir and concurrent enrichment of molybdenum indicate that the ocean chemistry in the Cryogenian Period is similar to that in the Archean Eon.