Thermal Maturity Parameters Research Articles

Impact of anaerobic biodegradation on alkylphenanthrenes in crude oil

The biodegradation of crude oil by microorganisms from well Luo-801, China, was examined in cultures grown under conditions that promoted either methanogenesis or sulfate reduction, at 35°C and 55°C. Headspace gas and oil compositions were characterized at 180d and 540d. Alkylphenanthrenes are relatively recalcitrant to bacterial attack and the biodegradation of these compounds appeared to be insignificant after 180d under both conditions, but is evident after 540d. The depletion of alkylphenanthrenes was monitored through evaluation of the ratio of alkylphenanthrenes to the most bioresistant, analyzed component (C28 20R triaromatic steroid hydrocarbon) and isomer susceptibility also was evaluated by relative abundance comparison within the compound class. The influence of growth temperature varied. Only slight differences in alkylphenanthrene concentrations were observed after 180d whereas the greater degrees of biodegradation were observed at 35°C in the methanogenic culture and at 55°C in the sulfate reducing culture. Overall, higher biodegradation rates occur under sulfate reducing condition, which is consistent with the conclusion that methanogens are generally less able to compete for substrates than sulfate reducers. The biodegradation susceptibility of alkylphenanthrenes decreases with increasing degree of alkylation, i.e., phenanthrene (P) and methylphenanthrenes (MPs) were more easily biodegradable than C2-alkylphenanthrenes (C2-Ps) and C3-alkylphenanthrenes (C3-Ps). Biodegradation selectivity for specific homologues is not striking for the limited time duration of the experiments. However, 3-MP seems slightly more vulnerable than other methylphenanthrene isomers and 1,7-DMP has slightly higher ability to resist biodegradation than the other C2-P isomers. The commonly used thermal maturity parameters derived from methylphenanthrene isomer ratios are altered insignificantly by biodegradation and remain valid for geochemical assessment. This information should be useful for assessing the limits of in situ crude oil biodegradation.

The Geochemical Characterization of Sediments from Early Cretaceous Sembar Formation

The soluble organic matter (SOM) and kerogen of sediments contain organic molecules, and can be interpreted in terms of source, generative potential, thermal maturity, and depositional environment of the organic matter. Early Cretaceous sedimentary sequence of Sembar Formation comprising five sediments samples was analyzed. Both SOM and hydrocarbons bound to the kerogen terms as pyrolyzed organic matter (POM) were characterized geochemically. Hydrous pyrolysis was carried out to release hydrocarbons from extracted sediments and fractionated by liquid chromatography. Saturated fractions from both SOM and POM were further analyzed by gas chromatography-flame ionization detector. The study suggested that Cretaceous sequence of Sembar Formation has fair to good hydrocarbon source potential. Thermal maturity parameters indicate onset of oil genesis zone. The presence of even carbon numbered n-alkenes, Pr/Ph and Pr/n-C17 versus Ph/n-C18 plots reveal marine algal source and anoxic depositional environment of organic matter from Sembar Formation.

Biomarker Molecular Indicators Predict Biodegraded Heavy Oil Physical Properties: A Case from Dongying Depression, Eastern China

To determine reliable molecular thermal maturity parameters for prediction of the physical properties of biodegraded oils, a suite of oils including 11 biodegraded oils from Caoqiao oilfield and 5 non-biodegraded oils from Wangjiagang oilfield in Dongying depression in Bohai-bay basin, eastern of China were analyzed. The oils were selected in a wide range of viscosity in order to investigate the relation between the parameters and oil properties. The data show the effects of biodegradation on some molecular thermal maturity parameters: C29 sterane parameters C2920S/(20S+20R) and C29ββ/(ββ+αα) increased apparently under heavy biodegradation (rank 6~7); parameters C3122S/(22S+22R), C3222S/(22S+22R), C293-methyl/C29 4-methyl, (C28+C29Tricyclics)/Ts and (C28+C29Tricyclics)/ (C28+C29Tricyclics +Ts) showed effects from heavy biodegradation (rank 6~7), and terpanes parameters Ts/(Ts+Tm), C29Ts/(C29Ts+C29Tm) and aromatic C20/(C28+C20), (C20+C21)/(C20+C21+C26+C27+C28) and D(3-6)/(D3-6+ C29 4-methylstigmastane 20R showed no effect from heavy biodegradation. Based on the comparison, the molecular maturity parameters C26 to C28 triaromatic parameters C26S/ (C26S+C28S), C27R/(C27R+C28R), C28/(C26+C27+C28) and tricyclic terpanes parameters C19/(C19+C23) were recommended to predict the physical properties of biodegraded oil for these parameters showed no effects from biodegradation(rank 6~7) and better relations with oil physical properties compared to other parameters. Some quantificational equations between these molecular thermal maturity parameters and the physical properties of biodegraded oils were inferred, which may assist in predicting the viscosity and API gravity of reservoired oils before production.

Organic geochemistry and petrology of subsurface Paleocene–Eocene Wilcox and Claiborne Group coal beds, Zavala County, Maverick Basin, Texas, USA

Coal samples from a coalbed methane exploration well in northern Zavala County, Maverick Basin, Texas, were characterized through an integrated analytical program. The well was drilled in February, 2006 and shut in after coal core desorption indicated negligible gas content. Cuttings samples from two levels in the Eocene Claiborne Group were evaluated by way of petrographic techniques and Rock–Eval pyrolysis. Core samples from the Paleocene–Eocene Indio Formation (Wilcox Group) were characterized via proximate–ultimate analysis in addition to petrography and pyrolysis. Two Indio Formation coal samples were selected for detailed evaluation via gas chromatography, and Fourier transform infrared (FTIR) and 13C CPMAS NMR spectroscopy. Samples are subbituminous rank as determined from multiple thermal maturity parameters. Elevated rank (relative to similar age coal beds elsewhere in the Gulf Coast Basin) in the study area is interpreted to be a result of stratigraphic and/or structural thickening related to Laramide compression and construction of the Sierra Madre Oriental to the southwest. Vitrinite reflectance data, along with extant data, suggest the presence of an erosional unconformity or change in regional heat flow between the Cretaceous and Tertiary sections and erosion of up to >5km over the Cretaceous. The presence of liptinite-rich coals in the Claiborne at the well site may indicate moderately persistent or recurring coal-forming paleoenvironments, interpreted as perennially submerged peat in shallow ephemeral lakes with herbaceous and/or flotant vegetation. However, significant continuity of individual Eocene coal beds in the subsurface is not suggested. Indio Formation coal samples contain abundant telovitrinite interpreted to be preserved from arborescent, above-ground woody vegetation that developed during the middle portion of mire development in forested swamps. Other petrographic criteria suggest enhanced biological, chemical and physical degradation at the beginning and end of Indio mire development. Fluorescence spectra of sporinite and resinite are consistent and distinctly different from each other, attributed to the presence of a greater proportion of complex asphaltene and polar molecules in resinite. Gas chromatography of resinite-rich coal shows sesquiterpenoid and diterpenoid peaks in the C14–17 range, which are not present in resinite-poor coal. Quantities of extracts suggest bitumen concentration below the threshold for effective source rocks [30–50mg hydrocarbon/g total organic carbon (HC/g TOC)]. Saturate/aromatic and pristane/phytane (Pr/Ph) ratios are different from values for nearby Tertiary-reservoired crude oil, suggesting that the Indio coals are too immature to source liquid hydrocarbons in the area. However, moderately high HI values (200–400mg HC/g rock) may suggest some potential for naphthenic–paraffinic oil generation where buried more deeply down stratigraphic/structural dip. Extractable phenols and C20+ alkanes are suggested as possible intermediates for acetate fermentation in microbial methanogenesis which may, however, be limited by poor nutrient supply related to low rainfall and meteoric recharge rate or high local sulfate concentration.

Geological and geochemical characterization of the Lower Cretaceous Pearsall Formation, Maverick Basin, south Texas: A future shale gas resource?

As part of an assessment of undiscovered hydrocarbon resources in the northern Gulf of Mexico onshore Mesozoic section, the U.S. Geological Survey (USGS) evaluated the Lower Cretaceous Pearsall Formation of the Maverick Basin, south Texas, as a potential shale gas resource. Wireline logs were used to determine the stratigraphic distribution of the Pearsall Formation and to select available core and cuttings samples for analytical investigation. Samples used for this study spanned updip to downdip environments in the Maverick Basin, including several from the current shale gas-producing area of the Pearsall Formation. The term shale does not adequately describe any of the Pearsall samples evaluated for this study, which included argillaceous lime wackestones from more proximal marine depositional environments in Maverick County and argillaceous lime mudstones from the distal Lower Cretaceous shelf edge in western Bee County. Most facies in the Pearsall Formation were deposited in oxygenated environments as evidenced by the presence of biota preserved as shell fragments and the near absence of sediment laminae, which is probably caused by bioturbation. Organic material is poorly preserved and primarily consists of type III kerogen (terrestrial) and type IV kerogen (inert solid bitumen), with a minor contribution from type II kerogen (marine) based on petrographic analysis and pyrolysis. Carbonate dominates the mineralogy followed by clays and quartz. The low abundance and broad size distribution of pyrite are consistent with the presence of oxic conditions during sediment deposition. The Pearsall Formation is in the dry gas window of hydrocarbon generation (mean random vitrinite reflectance values, Ro = 1.2–2.2%) and contains moderate levels of total organic carbon (average 0.86 wt. %), which primarily resides in the inert solid bitumen. Solid bitumen is interpreted to result from in-situ thermal cracking of liquid hydrocarbon generated from original type II kerogen that was prevented from expulsion and migration by low permeability. The temperature of maximum pyrolysis output (Tmax) is a poor predictor of thermal maturity because the pyrolysis (S2) peaks from Rock-Eval analysis are ill defined. Vitrinite reflectance values are consistent with the dry gas window and are the preferred thermal maturity parameter. A Maverick Basin Pearsall shale gas assessment unit was defined using political and geologic boundaries to denote its spatial extent and was evaluated following established USGS hydrocarbon assessment methodology. The assessment estimated a mean undiscovered technically recoverable natural gas resource of 8.8 tcf of gas and 3.4 and 17.8 tcf of gas at the F95 and F5 fractile confidence levels, respectively. Significant engineering challenges will likely need to be met in determining the correct stimulation and completion combination for the successful future development of undiscovered natural gas resources in the Pearsall Formation.

Petroleum geochemistry of the Potwar Basin, Pakistan: 1. Oil–oil correlation using biomarkers, δ 13C and δD

Geochemical characterisation of 18 crude oils from the Potwar Basin (Upper Indus), Pakistan is carried out in this study. Their relative thermal maturities, environment of deposition, source of organic matter (OM) and the extent of biodegradation based on the hydrocarbon (HC) distributions are investigated. A detailed oil–oil correlation of the area is established. Gas chromatography–mass spectrometry (GC–MS) analyses and bulk stable carbon and hydrogen isotopic compositions of saturated and aromatic HC fractions reveals three compositional groups of oils. Most of the oils from the basin are typically generated from shallow marine source rocks. However, group A contains terrigenous OM deposited under highly oxic/fluvio-deltaic conditions reflected by high pristane/phytane (Pr/Ph), C 30 diahopane/C 29Ts, diahopane/hopane and diasterane/sterane ratios and low dibenzothiophene (DBT)/phenanthrene (P) ratios. The abundance of C 19-tricyclic and C 24-tetracyclic terpanes are consistent with a predominant terrigenous OM source for group A. Saturated HC biomarker parameters from the rest of the oils show a predominant marine origin, however groups B and C are clearly separated by bulk δ 13C and δD and the distributions of the saturated HC fractions supporting variations in source and environment of deposition of their respective source rocks. Moreover, various saturated HC biomarker ratios such as steranes/hopanes, diasteranes/steranes, C 23-tricyclic/C 30 hopane, C 28-tricyclic/C 30 hopane, total tricyclic terpanes/hopanes and C 31( R + S)/C 30 hopane show that two different groups are present. These biomarker ratios show that group B oils are generated from clastic-rich source rocks deposited under more suboxic depositional environments compared to group C oils. Group C oils show a relatively higher input of algal mixed with terrigenous OM, supported by the abundance of extended tricyclic terpanes (up to C 41+) and steranes. Biomarker thermal maturity parameters mostly reached to their equilibrium values indicating that the source rocks for Potwar Basin oils must have reached the early to peak oil generation window, while aromatic HC parameters suggest up to late oil window thermal maturity. The extent of biodegradation of the Potwar Basin oils is determined using various saturated HC parameters and variations in bulk properties such as API gravity. Groups A and C oils are not biodegraded and show mature HC profiles, while some of the oils from group B show minor levels of biodegradation consistent with high Pr/ n-C 17, Ph/ n-C 18 and low API gravities.

Separation of 18α(H)-, 18β(H)-oleanane and lupane by comprehensive two-dimensional gas chromatography

18α(H)-, 18β(H)-oleanane and lupane are angiosperm-derived biomarkers that are used as age indicators for the Late Cretaceous onwards when the first proliferation of angiosperms occurred. In addition, the 18α(H)-/18β(H)-oleanane ratio is employed as a thermal maturity parameter of crude oil. However, evidence has shown that accurate quantification of these compounds has been impeded by inadequate chromatographic separation by traditional one-dimensional gas chromatography. In this study, we present the separation of 18α(H)-, 18β(H)-oleanane and lupane with comprehensive two-dimensional gas chromatography (GC × GC). Furthermore, it was observed that 18β(H)-oleanane elutes earlier than 18α(H)-oleanane in second dimension (polarity) which we attribute to steric hindrance effects. Two GC conditions have been developed in order to achieve baseline separation of the triterpenoids of interest in complex mixtures such as sediment extracts and crude oils.

Comprehensive two-dimensional gas chromatography with time of flight mass spectrometry applied to biomarker analysis of oils from Colombia

In order to become GC×GC–TOFMS a useful tool in geochemical oil prospecting, it is mandatory to be able to calculate quantitative geochemical parameters. A suite of Colombian oils from Upper Magdalena Valley Basin was chosen to obtaining several thermal maturity and source parameters based on biomarker ratios showing that GC×GC–TOFMS is able to be used to provide relevant geochemical information.

Oil–oil and oil-source rock correlations in the Alpine Foreland Basin of Austria: Insights from biomarker and stable carbon isotope studies

The Alpine Foreland Basin is a minor oil and moderate gas province in central Europe. In the Austrian part of the Alpine Foreland Basin, oil and minor thermal gas are thought to be predominantly sourced from Lower Oligocene horizons (Schöneck and Eggerding formations). The source rocks are immature where the oil fields are located and enter the oil window at ca. 4 km depth beneath the Alpine nappes indicating long-distance lateral migration. Most important reservoirs are Upper Cretaceous and Eocene basal sandstones. Stable carbon isotope and biomarker ratios of oils from different reservoirs indicate compositional trends in W–E direction which reflect differences in source, depositional environment (facies), and maturity of potential source rocks. Thermal maturity parameters from oils of different fields are only in the western part consistent with northward displacement of immature oils by subsequently generated oils. In the eastern part of the basin different migration pathways must be assumed. The trend in S/(S + R) isomerisation of ααα-C 29 steranes versus the αββ (20R)/ααα (20R) C 29 steranes ratio from oil samples can be explained by differences in thermal maturation without involving long-distance migration. The results argue for hydrocarbon migration through highly permeable carrier beds or open faults rather than relatively short migration distances from the source. The lateral distance of oil fields to the position of mature source rocks beneath the Alpine nappes in the south suggests minimum migration distances between less than 20 km and more than 50 km. Biomarker compositions of the oils suggest Oligocene shaly to marly successions (i.e. Schoeneck, Dynow, and Eggerding formations) as potential source rocks, taking into account their immature character. Best matches are obtained between the oils and units a/b (marly shale) and c (black shale) of the “normal” Schöneck Formation, as well as with the so-called “Oberhofen Facies”. Results from open system pyrolysis-gas chromatography of potential source rocks indicate slightly higher sulphur content of the resulting pyrolysate from unit b. The enhanced dibenzothiophene/phenanthrene ratios of oils from the western part of the basin would be consistent with a higher contribution of unit b to hydrocarbon expulsion in this area. Differences in the relative contribution of sedimentary units to oil generation are inherited from thickness variations of respective units in the overthrusted sediments. The observed trend towards lighter δ 13C values of hydrocarbon fractions from oil fields in a W–E direction are consistent with lower δ 13C values of organic matter in unit c.

Molecular composition and organic petrographic characterization of Madbi source rocks from the Kharir Oilfield of the Masila Basin (Yemen): palaeoenvironmental and maturity interpretation

The upper part of Madbi Formation organic-rich shale is considered an important regional source rock in the Masila Basin, Yemen. Ten cutting samples from this Upper Jurassic organic-rich shale were collected from wells drilled in the Kharir Oilfield, Masila Basin in order to geochemically assess the type of organic matter, thermal maturity and depositional environment conditions. Results reveal that Upper Jurassic organic-rich shale samples contain high organic matter more than 2.0 wt.% TOC and have very good to excellent hydrocarbon potential. Marine algae organic matter is the main source input for the Upper Jurassic shale sequence studied. This has been identified from organic petrographic characteristics and from the n-alkane distributions, which dominated by n-C14-n-C20 alkanes. This is supported by the high value of the biomarker sterane/hopane ratio that approaches unity, as well as the relatively high C27 sterane concentrations. A mainly suboxic depositional environment is inferred from pr/ph ratios (1.75–2.38). This is further supported by relatively high homohopane value, which is dominated by low carbon numbers and decrease towards the C35 homohopane. The concentrations of C35 homohopane are very low. The depositional environment conditions are confirmed by some petrographic characteristics (e.g. palynofacies). Detailed palynofacies analysis of Madbi shales shows that the Madbi shale formation is characterised by a mix of amorphous organic matter, dinoflagellates cysts and phytoclasts, representing a suboxic, open marine setting. The Upper Jurassic marine shale sequence in the Masila Basin is thermally mature for hydrocarbon generation as indicated by biomarker thermal maturity parameters. The 22 S/22 S + 22R C32 homohopane has reached equilibrium, with values range from 0.58 to 0.62 which suggest that the Upper Jurassic shales are thermally mature and that the oil window has been reached. 20 S/(20 S + 20R) and ββ/(ββ + αα) C29 sterane ratios suggest a similar interpretation, as do the moretane/hopane ratio. This is supported by vitrinite reflectance data ranging from 0.74% to 0.90%Ro and thermal alteration of pollen and spore. The thermal alteration index value is around 2.6–3.0, corresponding to a palaeotemperature range of 60–120°C. These are the optimum oil-generating strata. On the basis of this study, the Madbi source rock was deposited under suboxic conditions in an open marine environment and this source rock is still within the oil window maturity range.

Assessment of the oil source-rock potential of the Pedregoso Formation (Early Miocene) in the Falcón Basin of northwestern Venezuela

The early Miocene Pedregoso Formation is one of the numerous formations rich in organic matter within the stratigraphic record of the Urumaco Trough, in the central area of the Falcón Basin. Due to its lithological characteristics and stratigraphic position, this formation is of great interest regarding the basin's petroliferous systems. The evaluation of various inorganic and organic geochemical parameters indicates that the organic matter is primarily of marine origin, deposited in a marine carbonate environment typical of reefal systems, under oxic-to-dysoxic conditions. The low variability in the TOC concentrations and in the distributions of the biomarkers extracted from the samples suggests that the paleoenvironmental conditions and the organic-matter supply remained approximately constant throughout the sedimentation of this unit. The Pedregoso type-II organic matter (marine origin) and initial organic richness value (∼1.8%) suggest that this unit has probably generated hydrocarbons within the Urumaco Trough. However, present-day thermal maturity parameters reveal that the Pedregoso organic matter is overmature (dry gas window), indicating that this unit is only capable to generate gas. In addition, the geothermal gradient, maturity parameters, and the maximum paleotemperature estimated in this study suggest that the Pedregoso Formation reached a maximum burial depth the ∼6.5 km, consistent with the value obtained from data of stratigraphic thickness in the Urumaco Trough. This implies that the thermal anomaly that affected the basin during the Late Eocene–Early Miocene did not reach the central part of the basin, and therefore, the organic matter maturation in this unit is due to the sedimentary burial.

A comparison of thermal maturity parameters between freely extracted hydrocarbons (Bitumen I) and a second extract (Bitumen II) from within the kerogen matrix of Permian and Triassic sedimentary rocks

In this study we compared various maturity dependent aromatic, steroid and triterpenoid hydrocarbon ratios in bitumens that are freely extractable from sedimentary rocks (Bitumen I) with those in second extracts that comprised hydrocarbons closely associated with the kerogen/mineral matrix (Bitumen II). Bitumen II was released through kerogen isolation and demineralisation using HCl and HF/H 3BO 3. The samples studied, although of similar age, come from different localities. They represent a range of facies and two kerogen types (II and III), and all were deposited under marine conditions. The results show that the more stable β isomers of methylnaphthalene (MN) and methylphenanthrene (MP) are relatively more abundant in Bitumen II. The difference between the methylnaphthalene ratio (MNR) of Bitumens I and II, when plotted against the ratio of clay to total organic carbon (clay/TOC), gives an excellent correlation ( R 2 = 0.88). The highest clay/TOC ratio corresponds with the biggest difference in MNR for the respective bitumens, consistent with the more stable β isomers being preferentially retained within the clay/kerogen matrix. Since the β MP isomers are higher in Bitumen II than in Bitumen I, it was anticipated that their methylphenanthrene index (MPI-1) values, a commonly used measure of thermal maturity, would also be different. For most samples, the measured MPI-1 in Bitumen I is generally higher than that in Bitumen II (except for three samples), thus showing a bias towards a lower thermal maturity for the second extract. The opposite is true of the β/α MP ratio and MNR. This may be attributed to the fact that phenanthrene (P), which is part of the denominator in MPI-1, is more stable than its methylated counterparts. Steroid and triterpenoid maturity parameters also showed differences between the two extracts, with C 27 diasterane/sterane and Ts/(Ts + Tm) being higher in Bitumen I. Only the former parameter is positively correlated with the clay/TOC ratio, suggesting that clay content probably influences the diagenetic transformation of steroid precursors to diasteranes. The observed differences between the maturity parameters of Bitumen I and Bitumen II may be especially important in sedimentary rocks that contain high percentages of clay minerals.

Early Hydrocarbon Generation of Algae and Influences of Inorganic Environments during Low Temperature Simulation

Algae were simulated for 5 years at low temperature (80°C) in order to study their early hydrocarbon generation processes. The samples were analyzed by gas chromatography-mass spectrometry. The results show that the range of carbon numbers and relative concentrations of alkanes are different under different simulated conditions. Hypersaline condition favors the formation and maturity of saturates. Iron ion probably delays the evolutionary pathways from phytol to phytene to phyane, while may catalyse the release of high concentrations of squalene and bicyclic terpanes. Meanwhile, common aromatic compounds have been formed during this low temperature simulation, and high abundant methyldibenzothiophenes were found in the hypersaline sample. The formation pathways of methylnaphthalenes in the early evolution of algae were proposed tentatively. By mathematical cluster and factor analyses on some classical thermal maturity parameters, the converted relations between phenanthrene and methylphenanthrenes and their inorganic environmental effects were discussed.

Geochemical features of re-deposited organic matter occurring in fluvioglacial sediments in the Racibórz region (Poland): A case study

The erosion of rocks rich in organic matter typically leads to the complete mineralization of the organic material. However, in some cases, it is re-deposited to become a part of sediments once more. This process should be considered to be a part of global carbon cycle, possibly much more significant than assumed to-date. The research presented here aims to characterize re-worked organic matter occurring in post-glacial sediments of southern part of Poland, in the Oder river valley (the Racibórz town region, Miocene, Pleistocene and Holocene age). Organic substances extracted from the sediments originated from organic matter that had resided in rocks eroded by glaciers. Sediments were sampled in two boreholes which sediments were correlated. Sediments were extracted and extracts analyzed with gas chromatography-mass spectrometry (GC-MS) to assess distributions of biomarker groups. Organic matter of selected samples was pre-concentrated and analyzed with Py/GC-MS. In the extracts several biomarker parameters of source/environment and thermal maturity were calculated. Organic substances in the investigated sediments come from variable re-deposited organic matter occurring in rocks eroded by glaciers. Three main parent types of re-deposited organic material are identified showing variable geochemical features: 1) organic matter of recent or almost recent age being the source of polar labile compounds; probably formed in situ, 2) re-deposited organic matter of the middle diagenesis showing features similar to lignites (huminite reflectance Rf ~ 0.25–0.35%) deriving from angiosperm remains, mainly monocotyledons and to the lower extend also deciduous trees, 3) re-deposited organic matter at the middle catagenesis (Rf ~ 0.65–0.75%) being the source of most of aromatic hydrocarbons and biomarkers such as steranes, hopanes of the more thermally advanced distribution type. Its geochemical properties and assumed directions of sediment transport indicate bituminous coals of Upper Silesian Coal Basin together with coaly shales as a possible source of this organic matter. Such mixed origin of organic matter caused large discrepancies in values of thermal maturity parameters depending on input from the particular sources and occurrence both geochemical biomarkers and their biochemical precursors in the same samples.

CH 4/N 2 Ratio as a Potential Alternative Geochemical Tool for Prediction of Thermal Maturity of Natural Gas in Tarim Basin

In this context, the bulk ratio of CH 4/N 2 is examined as a potential alternative geochemical parameter for the assessment of thermal maturity of natural gas and compared to other previously published data. Open-system non-isothermal pyrolysis of low-mature coal from the Manjiaer sag, Tarim basin, yielded generation curves for methane and nitrogen. Analysis of the change of vitrinite reflectance indicates a two-stage process of thermal maturation with increasing temperatures. The relationship between R o and pyrolysis temperature could be expressed by the following equations: Stage I: R o = 0.0014 T + 0.109, r = 0.9931( R o < 0.6%); Stage II: R o = 0.0067 T −1.5855, r = 0.9996 ( R o > 0.6%). A kinetic interpretation of the characteristics of nitrogen and methane generation in humic coal during laboratory pyrolysis indicates that the bulk ratios of methane and nitrogen as thermal maturity parameters may be applied to assess the maturity of gas-sources. Thus, the maturity of the source rocks of natural gases in the Tarim basin was expressed in terms of CH 4/N 2 ratios and compared with other geochemical natural gas parameters, such as stable isotopes. The predicted results were found to be consistent with the published data.

Accumulation and Mixing of Oils in Jinghu Sag of Subei Basin: Constraints from Thermal Maturity Parameters

Abstract Oils in Jinghu sag are abundant with high content of polar compounds and have a low ratio of saturate to aro-matic hydrocarbons and a high ratio of resin to asphaltene. The gross composition of oils in the Jinghu sag suggests typical immature to low mature characteristics. Some compounds with low thermal stability were identified. Light hy-drocarbons, a carbon preference index, an odd even index, n-alkane and hopane maturity parameters show mature fea-tures and little differences in the maturity level among oils. Sterane isomerization parameters indicate an immature to low mature status of oil. Transfer of the sedimentary center during sedimentation has led to different thermal histories among subsags and thus generated oils with different maturities. On the basis of source analyses, four migration and accumulation patterns with different maturity can be classified. Combined with available information on mergers of source, reservoir and long distance oil lateral migration, mixing conditions were present in the Jinghu sag. Experimental results indicate that maturity variations are caused by mixtures of hydrocarbons with different maturity.

Organic geochemistry and petrology of coals and carbonaceous shales from western Venezuela

The aim of this study is to provide geochemical and petrological data to characterize coals and carbonaceous shales from western Venezuela in terms of both compositional and thermal maturity parameters. The samples, collected in outcrop, belong to the Paleocene Marcelina Formation, the Eocene–Oligocene Carbonera Formation, the Paleocene Orocué Group, and the Lower Miocene Cerro Pelado Formation. Geochemical results are based on total organic carbon (TOC) content, Rock-Eval pyrolysis and proximate analyses, whereas petrographic data include vitrinite reflectance ( R r), and maceral composition. Thermal evolution of all samples is low, varying from immature to early mature. Coals and carbonaceous shales from the Marcelina and Cerro Pelado Formations are humic, the former having larger amounts of inertinite. Nevertheless, both groups of samples are compositionally homogeneous. Samples from the Carbonera Formation and Orocué Group show a great compositional scatter, varying from humic to sapropelic. Our geochemical profile for Marcelina Formation coals allowed the detection of the first coalification jump, whereas the Cerro Pelado Formation profile shows an abrupt decrease of organic matter content toward the top of the studied interval. Results shown here confirm data from previous studies relative to the high oil-source rock potential of Carbonera Formation and Orocué Group coals and carbonaceous shales.

Geochemical and petrographic properties of some Spitsbergen coals and dispersed organic matter

This paper presents the characteristics of selected parameters of organic matter of the Tertiary coal samples and organic matter of Carboniferous rock samples from the Spitsbergen. The coal samples were taken from Central Coal Basin (the Longyearbyen region) and from the Forlandsundet Basin (Oscar II Land, the Kaffioyra region). Samples of dispersed organic matter were collected from Suffolk Pynten and Sergeijevfjellet area in Sorkapp Land. The optical properties of coal samples are different from properties of dispersed organic matter. Macerals of vitrinite group dominate in all of the samples. The average content of vitrinite group macerals is much lower in dipersed organic matter samples than it is in coals. The average content of liptinite group macerals is a little lower, and inertinite group macerals is much higher. The average content of mineral matter is higher in organic matter samples than in coal samples. The average value of vitrinite reflectance and standard deviation of organic matter is higher in comparison with coals. The coal samples are generally classified as orthobituminous, medium rank type C. There are samples from very low- to middle-grade coal. The values of vitrinite reflectance and standard deviation of coals investigated are similar and are lower than they are in dispersed organic matter. Gas chromatography–mass spectrometry (GC-MS) was applied to assess organic matter source and rank with use of several biomarker parameters. Primary organic matter of the Tertiary coals contained predominantly material from conifers, among them, Cupressaceae and/or Taxodiaceae and Podocarpaceae families were identified by their characteristic biomarkers. Dispersed organic matter of rocks does not show features indicating input of vascular plants into its primary material, and its origin is assumed to be algal/bacterial. Samples with Calamites fossils contained organic matter with only low terrestrial input. Results of rank assessment by thermal maturity parameters based on biomarkers agree with vitrinite reflectance data: the Kaffioyra and the Longyearbyen coals are in the range of high volatile bituminous coals. The dispersed organic matter samples seems to be more mature than that of both coals and can be assessed as late catagenetic. The organic matter of the Sergeijevfjellet Formation was formed in basins with higher fluctuation of water level; lower amount of water caused oxidation of organic matter in a basin. The mire plants contained less of resins and essential oils than Hornsundneset Formation mire plants. The deposits of organic matter in a Tertiary basin were formed with faster subsidence and higher water level. The plants of Oligocene age (Kaffioyra region) contain more resins and essential oils than plants of Paleocene age (Longyearbyen region), while coalification degree is similar. However, technological parameters of Paleocene coals are better. The organic matter of Kaffioyra region was formed in basins with higher fluctuation of water level than from the Longyearbyen region.

Relationship between petrographic and geochemical characterisation of selected South African coals

Fifteen samples of South African coals from the Waterberg, Soutpansberg (Northern Province) and Main Karoo (Mpulanga and KwaZulu-Natal) provinces were investigated by petrographic and geochemical methods. The aim of this work was to establish the relationship between these two methods for evaluation of coal maturity in the case of South African coals. The petrographic analyses included maceral and microlithotype evaluation by routine quantitative methods as well as random reflectance measurements. Maceral analysis included identification of vitrinite, liptinite and inertinite groups. The same samples were used for microlithotype analysis. Vitrite, liptite, inertite, clarite, durite,vitroinertite, duroclarite, clarodurite and carbominerite were identified. To assess the facies trends, liptinite-poor and liptinite-rich durite and clarodurite were counted separately. Sporoclarite and cutinodetrite were also treated independently. Both maceral and microlithotype analyses were performed to confirm the geochemical and petrographic compatibility in interpretation of the primary organic material which was deposited in the biochemical stage of coal formation. The reflectance measurements were carried out in incident light using a Zeiss Universal microscope. The 546 nm interference filter was applied. Distributions of aliphatic and aromatic hydrocarbons present in coal extracts were analysed by gas chromatography-mass spectrometry (GC-MS) for assessment of both source/environment of deposition and coal thermal maturity. Normal alkane distribution shows odd-over-even carbon number predominance in the case of coals in the range of 0.63–0.80% vitrinite reflectance. Several groups of compounds related to conifer resin were identified indicating predominant source of organic matter of the coals, for example tetracyclic diterpanes, retene and simonellite. The coal rank was assessed by 13 thermal maturity parameters based on isomerisation reactions of sterane and triterpane diastereomers together with ratios and indices of aromatic hydrocarbons and methyldibenzothiophenes based on different thermal resistance of their α- and β-alkyl isomers. The correlation of reflectance ( R rv%) with two sterane diasteromer parameters: C 29αββ/(ααα+αββ), C 29ααα20S/(20S+20R) and aromatic hydrocarbon parameters of thermal maturity such as: MDR (Methydibenzothiophene ratio), MPI-1 (MethylPhenanthrene Index-1) revealed good agreement. Lower correlation coefficients were obtained for TMR-2 (Trimethylnaphthalene ratio), TeNR (Tetramethylnaphthalene ratio) and DMPR (Dimethylphenenthrene ratio) with respect to R rv%. Other correlations of biomarker and aromatic hydrocarbon parameters with R rv% were poor.

Gas Chromatography-Mass Spectrometry in Geochemical Investigation of Organic Matter of the Grodziec Beds (Upper Carboniferous), Upper Silesian Coal Basin, Poland

Abstract Organic matter of five lithologically different rocks, belonging to the Grodziec Beds (Upper Namurian A strata), was geochemically characterised by various instrumental methods. Mineral composition of rocks, known from previous experiments, was investigated by X-ray diffraction (Bzowska et al., 2000) and organic matter as a whole was characterised by infra-red spectroscopy. Next, extracts of organic matter were analysed by chromatographic methods, especially by gas chromatography-mass spectrometry (GC-MS) analysis applied to investigate aliphatic and aromatic hydrocarbon fractions. It was found that sedimentary organic matter of the Grodziec Beds predominantly comes from terrestrial sources, i.e. higher vascular plants, deposited in aerobic (oxic) environment. It shows features of type III kerogen or type II kerogen of bacterial/terrestrial origin of primary biogenic matter. Thermal maturity was estimated by means of various geochemical parameters based on distribution of biomarkers and alkyl-substituted aromatic hydrocarbons. It was found that the thermal maturity of organic matter of investigated rocks is at the end of diagenesis or beginning of catagenesis. Input of older migrating bitumen was suggested as an explanation for increased values of some thermal maturity parameters in the case of one of sandstones. Water-washing and/or biodegradation has partially changed the composition of organic matter, especially in the case of porous sandstones, where such interactions are possible. Mineral composition of the host rock seems to be important here, protecting organic matter of mudstones against such post-depositional alterations.