Vitrinite Reflectance Measurements Research Articles

A petrological and organic geochemical study of Permian coal seams east of Maracajá, South Santa Catarina, Paraná Basin, Brazil

Coal samples from the Permian Rio Bonito Formation, collected from borehole MML-09 east of Maracajá, South Santa Catarina, Paraná Basin, Brazil, were characterized by petrological (vitrinite reflectance measurements, maceral analyses) and geochemical (Rock-Eval, Total Organic Carbon (TOC) and GC–MS) methods. The mean vitrinite reflectance values range from 0.73 to 0.87% Rrandom, indicating a rank level of high volatile B/A bituminous. The maceral composition showed predominance of vitrinite (49.4 to 61.2vol.%) and inertinite (9 to 24.5vol.%). The Rock-Eval analysis presented the following values: S1 and S2 ranging from 0.74 to 2.51mg HC/g coal and 34.1 to 108.87mg HC/g coal, respectively; Hydrogen Indices between 158 and 240mg HC/g TOC and Tmax (°C) between 440 and 448°C. The TOC contents of the coal samples present values ranging from 18.85 to 45.31wt.%. Vitrinite reflectance and Rock-Eval Tmax values indicate that the coals are in the beginning of the oil generation window. The potential for the formation of liquid hydrocarbons is rather low, due to the nature of the humic coal, whereas the rank level indicates that generation of gas from the coal has occurred. The biomarker analysis, using GC–MS and GC–MS–MS, allowed the interpretation of the depositional environment and provided another way of determining the degree of maturity of the coals, besides vitrinite reflectance and Tmax. The pristane/phytane (Pr/Ph) ratio is >1, mainly controlled by organic matter type, implied suboxic conditions during sedimentation. The vitrinite reflectance measurements, Tmax values and 20S/(20S+20R) and αββ/(αββ+ααα) ratios for C29 regular steranes revealed the marginally mature stage of the organic matter, although the distribution of hopanes indicated a mature stage of the organic matter, due to the absence of ββ hopanes and predominance of the 22S epimer over the 22R epimer for the hopanes from C-31 to C-35.

Standardization of reflectance measurements in dispersed organic matter: Results of an exercise to improve interlaboratory agreement

Vitrinite reflectance generally is considered the most robust thermal maturity parameter available for application to hydrocarbon exploration and petroleum system evaluation. However, until 2011 there was no standardized methodology available to provide guidelines for vitrinite reflectance measurements in shale. Efforts to correct this deficiency resulted in publication of ASTM D7708: Standard test method for microscopical determination of the reflectance of vitrinite dispersed in sedimentary rocks. In 2012–2013, an interlaboratory exercise was conducted to establish precision limits for the D7708 measurement technique. Six samples, representing a wide variety of shale, were tested in duplicate by 28 analysts in 22 laboratories from 14 countries. Samples ranged from immature to overmature (0.31–1.53% Ro), from organic-lean to organic-rich (1–22 wt.% total organic carbon), and contained Type I (lacustrine), Type II (marine), and Type III (terrestrial) kerogens. Repeatability limits (maximum difference between valid repetitive results from same operator, same conditions) ranged from 0.03 to 0.11% absolute reflectance, whereas reproducibility limits (maximum difference between valid results obtained on same test material by different operators, different laboratories) ranged from 0.12 to 0.54% absolute reflectance. Repeatability and reproducibility limits degraded consistently with increasing maturity and decreasing organic content. However, samples with terrestrial kerogens (Type III) fell off this trend, showing improved levels of reproducibility due to higher vitrinite content and improved ease of identification. Operators did not consistently meet the reporting requirements of the test method, indicating that a common reporting template is required to improve data quality. The most difficult problem encountered was the petrographic distinction of solid bitumens and low-reflecting inert macerals from vitrinite when vitrinite occurred with reflectance ranges overlapping the other components. Discussion among participants suggested this problem could not be easily corrected via kerogen concentration or solvent extraction and is related to operator training and background. No statistical difference in mean reflectance was identified between participants reporting bitumen reflectance vs. vitrinite reflectance vs. a mixture of bitumen and vitrinite reflectance values, suggesting empirical conversion schemes should be treated with caution. Analysis of reproducibility limits obtained during this exercise in comparison to reproducibility limits from historical interlaboratory exercises suggests use of a common methodology (D7708) improves interlaboratory precision. Future work will investigate opportunities to improve reproducibility in high maturity, organic-lean shale varieties.

Petrographic maturity parameters of a Devonian shale maturation series, Appalachian Basin, USA. ICCP Thermal Indices Working Group interlaboratory exercise

This paper presents results of an interlaboratory exercise on organic matter optical maturity parameters using a natural maturation series comprised by three Devonian shale samples (Huron Member, Ohio Shale) from the Appalachian Basin, USA. This work was conducted by the Thermal Indices Working Group of the International Committee for Coal and Organic Petrology (ICCP) Commission II (Geological Applications of Organic Petrology). This study aimed to compare: 1. maturation predicted by different types of petrographic parameters (vitrinite reflectance and spectral fluorescence of telalginite), 2. reproducibility of the results for these maturation parameters obtained by different laboratories, and 3. improvements in the spectral fluorescence measurement obtained using modern detection systems in comparison with the results from historical round robin exercises.Mean random vitrinite reflectance measurements presented the highest level of reproducibility (group standard deviation 0.05) for low maturity and reproducibility diminished with increasing maturation (group standard deviation 0.12).Corrected fluorescence spectra, provided by 14 participants, showed a fair to good correspondence. Standard deviation of the mean values for spectral parameters was lowest for the low maturity sample but was also fairly low for higher maturity samples.A significant improvement in the reproducibility of corrected spectral fluorescence curves was obtained in the current exercise compared to a previous investigation of Toarcian organic matter spectra in a maturation series from the Paris Basin. This improvement is demonstrated by lower values of standard deviation and is interpreted to reflect better performance of newer photo-optical measuring systems.Fluorescence parameters measured here are in good agreement with vitrinite reflectance values for the least mature shale but indicate higher maturity than shown by vitrinite reflectance for the two more mature shales. This red shift in λmax beyond 0.65% vitrinite reflectance was also observed in studies of Devonian shale in other basins, suggesting that the accepted correlation for these two petrographic thermal maturity parameters needs to be re-evaluated.A good linear correlation between λmax and Tmax for this maturation series was observed and λmax 600nm corresponds to Tmax of 440°C. Nevertheless if a larger set of Devonian samples is included, the correlation is polynomial with a jump in λmax ranging from 540 to 570nm. Up to 440°C of Tmax, the λmax, mostly, reaches up to 500nm; beyond a Tmax of 440°C, λmax is in the range of 580–600nm. This relationship places the “red shift” when the onset of the oil window is reached at Tmax of 440°C. Moreover, the correlation between HI and λmax (r2=0.70) shows a striking inflection and decrease in HI above a λmax of 600nm, coincident with the approximate onset of hydrocarbon generation in these rocks.

Depositional environment of oil shale within the Eocene Jijuntun Formation in the Fushun Basin (NE China)

The non-marine Fushun Basin in NE China is a fault-controlled basin filled with Eocene sediments. It hosts the largest opencast coal and oil shale mine in Asia. A single thick oil shale layer overlying sub-bituminous coal occurs within the Middle Eocene Jijuntun Formation. Based on mineralogy, inorganic and organic geochemistry, organic petrography, stable isotope geochemistry, and vitrinite reflectance measurements, the depositional environment and the oil shale potential of the oil shale-bearing succession were investigated. The Jijuntun Formation is subdivided into a lower and an upper unit characterized by a low and high quality oil shale, respectively. The thick oil shale layer of the Jijuntun Formation developed under long-lasting stable conditions in a deep freshwater lake, after drowning of a swamp. The organic matter in the lower unit is characterized by landplant-derived macerals. The sediments containing a type II kerogen (HI: ∼400 mgHC/gTOC) were deposited during warm and humid conditions. Lacustrine organisms predominant in the upper unit are forming kerogen type I (HI: ∼700 mgHC/gTOC). High bioproductivity and excellent preservation conditions resulted in high TOC contents up to 23.6 wt.% in the upper unit. The organic matter preservation was controlled by photic zone anoxia originating in a temperature stratified water column in the deep lake, without significant changes in bottom water salinity. Mid-Eocene cooling during deposition of the upper unit of the Jijuntun Formation is reflected by clay mineral composition. A hot and arid climate favoring brackish conditions in a shallow lake prevailed during accumulation of the overlying carbonate-rich Xilutian Formation. Individual geochemical parameters in the Fushun Basin have to be used with caution, e.g. the maturity proxy Tmax is affected by kerogen type, the redox proxy Pr/Ph ratio is probably biased by different sources of isoprenoids. This demonstrates the importance of multi-proxy studies.

Hydrocarbon Source Potential and Depositional Environment of the Surma Group Shales of Bengal Basin, Bangladesh

Abstract: Surma Group is the most important geological unit of Bengal basin, Bangladesh, because petroleum resources occur within this group. It is mainly composed of alternation of shale and sandstone and the shale fraction has long been considered as source rocks and the sandstone fraction as reservoir. These source and reservoir rocks have been studied by different authors by different approach but none of them adopted organic geochemistry and organic petrology as a means of study of source rock and their possible depositional environment. A total of thirty shale core samples have been collected from eight different gas fields to fulfill the short coming. The collected samples have been subjected to Source Rock Analysis (SRA) and/or Rock-Eval (RE) followed by pyrolysis gas chromatography (PyGC), gas chromatography mass spectrometry (GCMS), elemental analysis (EA) and organic petrological study such as vitrinite reflectance measurement and maceral analysis. The analyzed organic matter extracted from the shales of Surma Group consists mainly of Type III along with some Type II kerogen. The studied shales are mostly organically lean (TOC ±1%) and the extracted organic matter is fair to moderate. Based on these results, the analyzed shales have been ranked as poor (mostly) to fair quality source rock. The organic matter of the analyzed shale samples is thermally immature to early mature for hydrocarbon generation considering their Tmax and measured mean vitrinite reflectance values. The hopane 22S/(22S + 22R), moretane/hopane ratio and sterane parameters are also in good agreement with these thermal maturity assessments. The predominance of odd carbons over even carbons (most common) and/or even carbons over odd carbon numbered n-alkanes, moderate Pr/Ph ratio, low to high Tm/Ts ratio, comparative abundance of sterane C29 (i.e., C29 >C27>C28), Pr/nC17 - Ph/nC18 values, C/S ratio and dominance of vitrinite macerals group with the presence of liptinite macerals demonstrate that the organic matter has derived mainly from terrestrial inputs with an insignificant contribution from the marine sources. The condition of deposition alternates from oxic to anoxic.

Khatatba Formation as an active source rock for hydrocarbons in the northeast Abu Gharadig Basin, north Western Desert, Egypt

Rock samples and a suite of oil samples collected from wells drilled in the northeastern part of the Abu Gharadig Basin were studied to determine the petroleum potential of the Middle to Late Jurassic Khatatba Formation as a source rock for oil produced in the basin. Twenty-four cuttings and two cores in addition to three oil samples from the Riviera-1, Swag-2, and Spyglass-1 wells retrieved from the Upper Cretaceous reservoirs were analyzed. Analyses include total organic carbon (TOC), Rock-Eval pyrolysis, and vitrinite reflectance for rock samples and biomarker analyses for liquid hydrocarbons. Results reveal that the Khatatba Formation is an organic-rich source rock with TOC ranging from 1 to 5 wt%, locally exceeding 21 wt% due to the presence of coal interbeds in the depth interval 4,386–4,388 m. Rock-Eval pyrolysis data show that the Khatatba Formation is dominated by algal type II and mixed type II/III kerogens, but type III and type I kerogens also occur. The Khatatba shales and carbonaceous shales have entered the peak-mature stage of the oil generation window. Tmax for the samples ranges from 436 to 449 °C and vitrinite reflectance measurements between 0.76 and 0.92 %Ro. Geochemical analyses reveal that all analyzed oils were generated from thermally mature and organic-rich shale and carbonaceous shale belonging to Middle–Upper Jurassic and Lower Cretaceous source rocks during early and peak stages of the oil window. The correlation between oil samples from NE Abu Gharadig Basin shows that these oils are quite similar and were generated from mixed marine–terrigenous organic matter formed under suboxic–oxic depositional paleoenvironments. However, the differences in bulk and biomarker properties and light-end content of the oil samples can be attributed to thermal maturation, source rock facies variations, or secondary reservoir transformation, such as evaporative fractionation.

Geochemical Characterization of Potential Source Rock of the Central (Saltpond) Basin, Ghana

This research characterized the potential source rock of 3 exploratory wells from the Central (Saltpond) Basin, Ghana. Ten (10) samples each of the drilled cuttings from the three key exploratory wells were geochemically characterized for total organic carbon contents (TOC), rock-eval pyrolysis techniques and vitrinite reflectance measurements (Ro). The results revealed that they have fair to good total organic carbon (TOC) contents, suggesting that there might exist conditions in the Saltpond Basin that favour organic matter production and preservation. The rock-eval results showed that all the samples from the 3 exploratory wells contain predominantly types II and III kerogen with a capacity to generate gas-oil and gas respectively. They have good generation potential. Results of the vitrinite reflectance measurement also reveal that all the samples from the 3 exploratory wells have poor to low source-rock grade. The Saltpond Basin can be regarded as having fair petroleum source rocks and could be part of a petroleum system if sufficient burial and maturation have occurred.

Unconventional resource evaluation: Kockatea Shale, Perth Basin, Western Australia

Organic-rich shales occur in the Kockatea Shale Formation, Permo-Triassic of the Perth Basin (Western Australia) and have been investigated to characterise it as a potential shale gas unit. Classic sedimentological investigation methods, including core descriptions and thin section microscopy, were coupled with standardised organic geochemical analysis procedures, such as TOC determination and Rock-Eval pyrolysis, as well as maceral composition analysis and vitrinite reflectance (Ro) measurements. The Kockatea sediments show a trend of increasing maturity from north to south, with Ro values ranging from 0.6 to 2%, pointing to a thermal maturity between the wet and dry thermogenic gas window. The

Upper Eocene coal and coaly shale in the Central Myanmar Basin: Origin of organic matter and the effect of weathering

Extensive coals and coaly shales were deposited at the western margin of the Central Myanmar Basin (CMB) during the Late Eocene. Carbon, nitrogen and sulfur (CNS) elemental analyses, vitrinite reflectance, Rock-Eval pyrolysis, biomarker analyses and δ13C measurements were made of eight coal and coaly shale samples from the Pondaung and Yaw Formations. Moderate weathering was recognized in three coaly shales, as manifest by microscopic cracks, holes, and rim structures in vitrinite. A sample pair of fresh and weathered coaly shale collected from the same seam showed that HI, Pr/Ph ratio, and concentration of PAHs and long chain n-alkanes (>n-C20) bonded to kerogen in the coaly shales decreased drastically due to weathering, while OI increased. These results suggest that hydrocarbon generation potential of the coaly shale as an oil/gas source rock decreased to about one tenth by the weathering, whereas the free n-alkanes, biomarkers such as steranes and triterpanes, and δ13C ratios of kerogen were not affected. Facies change from the coaly shale layers (Phase-I) to the coal layers (Phase-II) was accompanied by variations in origin of the organic matter. The source of the organic matter was mainly terrestrial herbaceous vegetation and/or aquatic plants, deposited in oxic to oxygen-poor peat swamps associated with an estuarine/fluvial-deltaic setting. Phase-I is relatively rich in gymnosperm biomarkers such as retene and 1,7-dimethylphenanthrene (DMP), whereas Phase-II shows an increase in angiosperm proxies such as oleanane content and oleanane/C30 hopane ratio, with δ13C values ranging from -24.6‰ to -26.5‰. Based on HI values of unweathered samples, Phase-I is characterized by type II-III kerogen, while Phase-II contains type III kerogen. Higher values of HI, Pr/Ph ratios, n-C29/n-C19 alkane ratios (>1.5), and higher concentrations of conifer-derived 1,7-DMP in Phase-I suggest a significant contribution from material of resinous vascular plant origin. High Fluoranthene/(Fluoranthene+Pyrene) ratio in the uppermost coal suggests occurrence of wildfire, probably related to a dry climate experienced in Phase-II. Unweathered CMB samples show good source rock quality, with potential generation of liquid/gas hydrocarbons.

BURIAL AND THERMAL HISTORY MODELLING OF THE MURZUQ AND GHADAMES BASINS (LIBYA) USING THE GALO COMPUTER PROGRAMME

The GALO computer programme was used to model the thermal and burial histories of the Murzuq and Ghadames Basins, Libya. The model was based on recent drilling and seismic data from the basins, and used published deep temperature and vitrinite reflectance measurements. The model provides more accurate results than previous studies which were based on constant geothermal gradients during the basins' histories, and variations in heat flux at the base of the sedimentary cover were chosen so that calculated values of vitrinite reflectance coincide with those observed. The Murzuq Basin and Libyan part of the Ghadames Basin contain similar source rock units but have different burial histories. In the Murzuq Basin, maximum present‐day burial depths of Cambrian sediments range from 2200 to 2800 m and only locally reach 3000 – 3600 m; in the Ghadames Basin, however, burial depths can exceed 4–5 km. The burial history of the Murzuq Basin includes several periods of intense erosion and lithospheric heating which produced significant lateral variations in thermal maturity, leading in places to unexpected results. For example, relatively shallow‐buried Lower Silurian source rocks in the A‐76 area on the flank of the Murzuq Basin have a thermal maturity of Ro = 1.24% which is higher than the maturity of the same interval in more deeply buried areas (wells D1‐NC‐58 or J1‐NC101). In the central part of the Ghadames Basin, the modelling suggests a higher level of thermal maturity for organic matter in Silurian strata (Ro 0.8 to 1.3%), confirming the generation potential of Lower Silurian “hot shales”. Significant hydrocarbon generation began here in the Late Carboniferous and continues at the present day. Modelling of the Late Devonian (Frasnian) Aouinat Ouinine Formation “hot shales” suggests limited hydrocarbon generation depending strongly on burial depth, with the main phase of hydrocarbon generation taking place during the final episode of thermal activation in the Cenozoic. In the wells studied in the Ghadames Basin, the “oil window” extends over a considerable part of the present‐day sedimentary column.

Source rock characteristics and hydrocarbon generation modelling of Upper Cretaceous Mukalla Formation in the Jiza-Qamar Basin, Eastern Yemen

The Upper Cretaceous Mukalla coals and other organic-rich sediments which are widely exposed in the Jiza-Qamar Basin and believed to be a major source rocks, were analysed using organic geochemistry and petrology. The total organic carbon (TOC) contents of the Mukalla source rocks range from 0.72 to 79.90% with an average TOC value of 21.50%. The coals and coaly shale sediments are relatively higher in organic richness, consistent with source rocks generative potential. The samples analysed have vitrinite reflectance in the range of 0.84–1.10 %Ro and pyrolysis Tmax in the range of 432–454 °C indicate that the Mukalla source rocks contain mature to late mature organic matter. Good oil-generating potential is anticipated from the coals and coaly shale sediments with high hydrogen indices (250–449 mg HC/g TOC). This is supported by their significant amounts of oil-liptinite macerals are present in these coals and coaly shale sediments and Py-GC (S2) pyrograms with n-alkane/alkene doublets extending beyond nC30. The shales are dominated by Type III kerogen (HI < 200 mg HC/g TOC), and are thus considered to be gas-prone.One-dimensional basin modelling was performed to analysis the hydrocarbon generation and expulsion history of the Mukalla source rocks in the Jiza-Qamar Basin based on the reconstruction of the burial/thermal maturity histories in order to improve our understanding of the of hydrocarbon generation potential of the Mukalla source rocks. Calibration of the model with measured vitrinite reflectance (Ro) and borehole temperature data indicates that the present-day heat flow in the Jiza-Qamar Basin varies from 45.0 mW/m2 to 70.0 mW/m2 and the paleo-heat flow increased from 80 Ma to 25 Ma, reached a peak heat-flow values of approximately 70.0 mW/m2 at 25 Ma and then decreased exponentially from 25 Ma to present-day. The peak paleo-heat flow is explained by the Gulf of Aden and Red Sea Tertiary rifting during Oligocene-Middle Miocene, which has a considerable influence on the thermal maturity of the Mukalla source rocks. The source rocks of the Mukalla Formation are presently in a stage of oil and condensate generation with maturity from 0.50% to 1.10% Ro. Oil generation (0.5% Ro) in the Mukalla source rocks began from about 61 Ma to 54 Ma and the peak hydrocarbon generation (1.0% Ro) occurred approximately from 25 Ma to 20 Ma. The modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the Mukalla source rocks began from 15 Ma to present-day.

Organic geochemistry and petrography of Lower Cretaceous Wealden black shales of the Lower Saxony Basin: The transition from lacustrine oil shales to gas shales

Ninety-seven Wealden black shale samples from three wells in the Lower Saxony Basin have been studied by organic geochemical and organic petrographical methods to determine their maturity, organic facies and depositional environment. The maturities of the three wells range from early mature (Ex-A), late to postmature (Ex-C) to overmature (Ex-B) as determined by vitrinite reflectance measurements, diamondoid ratios and other geochemical maturity parameters. Ex-C and Ex-B show distinct petrographic features related to oil generation and migration. In particular, the occurrence of dispersed solid bitumen replacing initial type I kerogen suggests a formerly active petroleum system. Structural and textural differences between early mature alginites and solid bitumen in postmature to overmature samples show an alteration of the pore system with increasing maturity. A freshwater depositional environment is indicated by widespread occurrence of botryococcus algae and other small alginite particles predominating in the immature well. These alginites are absent in the more mature gas shales of wells Ex-C and Ex-B. Geochemical evidence of algae and phytoplankton in general is provided by numerous biomarker parameters, while the occurrence of β-carotane in some samples indicates events of increased salinity, although no hypersaline conditions are inferred due to very low gammacerane indices. Increased amounts of vitrinite and inertinite in samples of Ex-B suggest locally significant terrigenous input of organic matter for some periods during Wealden Shale deposition. High sulfur/organic carbon ratios provide evidence for sulfate rich waters and (partly) anoxic bottom water conditions. While the lower mature lacustrine source rocks generate paraffinic/waxy oils, gas and condensates are produced at post-mature stages. Furthermore, maturity distribution maps from 3D numerical petroleum systems modeling reveal substantial differences in respect to petroleum generation.

An Assessment of the Hydrocarbon Potential of the Gombe Formation, Upper Benue Trough, Northeastern Nigeria: Organic Geochemical Point of View

Gombe Formation is a heterogeneous sequence within the Upper Benue Trough consisting principally of shales with sands, clays and intercalations of coal. It is over 600 m thick maximally in some parts of the sub-basin and has been dated Maastritchtian. Fifteen (15) core samples from 3 boreholes (BA-7, BA-16 and BA-17) dug around the Maiganga Coal Mine have been studied geochemically using the Rock-Eval 6 method with the principal aim of evaluating their potential as possible source rocks for petroleum. The results of the Rock-Eval analysis for analyzed core samples from these boreholes within Gombe Formation shows that the samples in boreholes BA-7 and BA-16 contain Type II kerogen while those from borehole BA-17 contain Type III kerogen, and that the samples from boreholes BA-7 and BA-16 have very good generative potential while those from borehole BA-17 have good to very good potential. This study also reveals that the analyzed samples especially those from boreholes BA-7 and BA-16 may constitute good source rocks if the burial depth is sufficient. The Rock-Eval Tmax data available for thermal maturity assessment of the samples suggest that the analyzed samples from the three boreholes are thermally immature. This assessment is consistent with the immaturity status of their coeval Formations (Pindiga and Gongila Formations) in other part of the Benue Trough, suggesting that these contemporaneous Formations may be related in depth and/or have experienced similar geothermal gradient. It is therefore recommended that the thermal maturity of the analyzed samples from the three boreholes be re-evaluated by other thermal maturity indices such as vitrinite reflectance measurement and biomarker evaluation in order to further authenticate the maturity status of the Formation.

The Tectonic and Uplift History of the Kuruketage Area in the North-East Edge of the Tarim Basin, China: Constraints from Detrital Zircon and Apatite Fission Track Data

This study uses the application of zircon fission track (ZFT) and apatite fission track (AFT) thermochronometry technique to investigate the tectonic and uplift history of the Kuruketage area, north-east edge of the Tarim Basin. Based on measured ZFT, AFT and equivalent vitrinite reflectance measurements of samples in sedimentary rocks in Kuruketage area, the temperature time evolution history from early Paleozoic strata was modeled. The results show that the youngest peaks of ZFT at 371-392Ma and 328 - 305.7Ma record Hercynian tectonic and uplift event; the AFT peaks at 134.5 - 164Ma, 73 - 100Ma and 35.4Ma mainly represent the Late-Cretaceous tectonic and uplift event in Kuruketage area. The AFT thermal modeling results from the early Paleozoic strata indicate that the maximum paleo-temperature (at 140 215°C) experienced in late Silurian to early Devonian, and the strata temperature decreased to about 120°C before the Late-Cretaceous.

Reply to: “The mountains of North-East Greenland are not remnants of the Caledonian topography. A comment on Pedersen et al. (2012)”

In this reply, we comment on the issues raised by Japsen, Chalmers, and Green [Japsen et al. (2013). The mountains of North-East Greenland are not remnants of the Caledonian topography. A comment on Pedersen et al. (2012): Tectonophysics]. We find that new vitrinite reflectance measurements from one location in the region may suggest a more complicated post-Caledonian evolution than proposed by Pedersen et al. (2012) for the southernmost part of the studied area. Overall, however, we cannot reconcile our AFT data set with a complete obliteration of the topography in late Paleozoic times, followed by episodic post-Caledonian exhumation and re-burial, as suggested by Japsen et al. (2013).

Petrographic characteristics and palaeoenvironment of the Permian coal resources of the Barapukuria and Dighipara Basins, Bangladesh

Abstract Twenty-seven coal samples from the Barapukuria and Dighipara Coal Basins of Bangladesh were analysed for their maceral content, petrographic characteristics and vitrinite reflectance. The most predominant maceral was the inertinite group (mean 40%), followed by vitrinite (mean 31%) and liptinite (mean 22%), with considerable amounts of mineral matter (mean 7%). Semifusinite, fusinite and inertodetrinite were the most common macerals of the inertinite group. Collotelinite, collodetrinite and vitrodetrinite were the most frequently found macerals of the vitrinite group, while sporinite and cutinite were the most common in the liptinite group. Clay minerals occurred in higher concentrations than other minerals. The measured vitrinite reflectance values (%Ro) ranged from 0.71 to 0.80, indicating a high volatile bituminous B ranking. Facies modelling using maceral composition and maceral indices suggested an environment of forest swamps with alternating oxic–anoxic depositional conditions. Microlithotype-dependent depositional modelling indicated evolution in limno-telmatic zones under fluvio-lacustrine control, accompanied by the development of upper to lower deltaic plain conditions. A terrestrial origin with dry forest to piedmont plain conditions was suggested by the Gelification Index (GI) and Tissue Preservation Index (TPI). The lateral variation of the measured TPI values indicated an increase in the rate of basin subsidence. A cross-plot of the Ground Water Index (GWI) vs. the Vegetation Index (VI) suggested mires under ombotrophic to mesotrophic hydrogeological conditions containing herbaceous plants.

Organic Matter Characteristics of the Kiliran and Ombilin Oil Shales, Indonesia

Sixteen oil shale samples have been studied by means of organic petrology and pyrolysis. The samples were taken from Brown Shale and Sangkarewang Formations which were deposited in the Kiliran and Ombilin Basins, respectively, during Late Eocene syn-rift phase. The oil shale organic matter of Kiliran Basin is composed of mainly lamalginite and telalginite. The latter likely originate from Botryococcusbraunii. Sporinite, pollen grain and vitrinite are present in lower amounts. Vitrinite reflectance measurement of the oil shale results values averaging at 0.29%. The organic matter in the Sangkarewang oil shale is dominated by lamalginite. Telalginite occurs only in limited numbers. Sporinite, resinite, pollen grain and vitrinitemacerals are also present in lower amounts. The oil shale has vitrinite reflectance values about 0.37%. Rock-Evalpyrolysis data exhibit Tmax 430°C and 436°C for Kiliran and Ombilin oil shales, respectively. Vitrinite reflectance and Tmax data suggest that the oil shales are immature, where the maturity of Ombilin oil shale is slightly higher than that of Kiliran oil shale. Total organic carbon (TOC) measurement results values about 5.61% and 5.01%for Kiliran and Ombilin oil shales, respectively. The presence ofB. braunii-derived telalginite in the Kiliran oil shale confirms lacustrine deposition environments of most ofpaleogene source-rocks in Central Sumatra. This organism probably also indicates that the Kiliran lake was less nutrients or less productive than the Ombilin lake. With respect to beneficiation prospect, the presence ofB. braunii-derived organic matter might be one of contributors to the generally higher amounts of TOC as well as pyrolysis yield in the Kiliran oil shale.

Permian carbonaceous rocks from the Bonito Coalfield, Santa Catarina, Brazil: Organic facies approaches

Permian sedimentary rocks of the Rio Bonito Formation, Paraná Basin, in the Santa Catarina state, Brazil, contain three important coal seams, in a descending order: Barro Branco, Bonito Superior and Pre-Bonito Superior. Artinskian carbonaceous shale samples corresponding to the so called “Bonito coal” were sampled at the mine face of the coal bed of the Bonito I underground mine. These samples were analyzed in order to discuss their petrographical, geochemical, palynological, and paleobotanical characteristics. Palynological analyses demonstrated abundant and well-preserved palynomorphs showing a dominance of bisaccate pollen grains related to gymnospermic plants. Wood fragments preserved as coalified compression show the presence of lycophyta. Palynofacies on samples demonstrated good results for the recognition of preserved organic matter and changes in paleoenvironmental conditions along the sedimentary sequence. Palynofacies and palynological analyses indicate changes in paleoecological conditions that have favored the development of different plant communities during the depositional time span from a forested gymnosperm at the base to a lycophyte, arborescent plant dominated scenario at the top suggesting a shift to coastal environment. The microscopic maceral-group analyses reveal a predominance of liptinite and vitrinite over inertinite, while among microlithotypes, carbargilite is abundant. The joint occurrence of inertinite as a maceral in the carbonaceous rock and charcoal in associated shales suggests that the mire and near surroundings were regularly subject to wildfires. Mean random vitrinite reflectance (Rr) varies from 0.88 to 1.04%. The liptinite spectral fluorescence parameters obtained for samples show the λmax values varying from 610 to 650 indicating equivalent vitrinite reflectance (Rreq) values from 0.83 to 1.10%. These results show that the equivalent vitrinite reflectance (Rreq) correlates well with the measured vitrinite reflectance (Rr). The “Bonito Coal” is a high-volatile bituminous coal according to the ISO, 11760: 2005 standard. Total organic carbon varies from 2.4 to 44.0wt.% and sulfur is present in moderate to high contents. GC-MS analyses evidenced a predominance of even saturated hydrocarbons and the presence of αβ-hopanes and αββ-steranes.

The pioneer work of Bernard Kübler and Martin Frey in very low-grade metamorphic terranes: paleo-geothermal potential of variation in Kübler-Index/organic matter reflectance correlations. A review

Low-temperature metamorphic petrology occupies the P–T field between sedimentary and metamorphic petrology. Two important pillars of low-temperature metamorphism are coal petrology and clay mineralogy. When low temperature petrology was established bridging a hiatus between the two classical geological disciplines of sedimentary geology and metamorphic petrology, geologists faced a need for the usage of different terminology tenets. Martin Frey and Bernard Kubler were two pioneers in low-grade metamorphic petrology. They focused their research on clarifying the relationships of clay mineralogy and organic petrology to metamorphic pressure (P) and temperature (T) conditions. The ultimate aim of M. Frey and B. Kubler was to establish a correlation between clay indices and organic parameters for different geodynamic setting and therefore for various pressure–temperature (P–T) conditions occurring in low grade metamorphic terranes. For this purpose, a special attention was addressed to the correlation between the Kubler-Index (KI) and vitrinite reflectance (VR). All these efforts are dedicated to estimate the P–T conditions and thus to gain insight into the geodynamic evolution of low-grade metamorphic terranes. B. Kubler and M. Frey honored here concentrated their studies to the Helvetic Central Alps area. The very low-grade Helvetic domain is therefore of basic interest of this paper. Ensuing the extensive compilation of data from the Helvetic domain, a reinterpretation of Kubler and Frey’s research is presented in the light of last decade’s scientific progress. A comprehensive dataset available enables to discriminate many factors influencing the Kubler-Index and organic-matter reflectance alongside to time, temperature and pressure. The correlation is restricted to the KI and organic matter reflectance (mostly VR) because most of the studies used both methods. Organic matter reflectance (OMR) includes data from vitrinite reflectance and bituminite reflectance measurements. Geodynamics has important control on the KI/VR (OMR) correlation. Tectonic units having a similar geodynamic evolution are featured by the comparable KI/OMR trends, related to the particular paleo-geothermal conditions. Obviously the KI/OMR correlations provide a mean to characterise geothermal gradients and metamorphic very-low-grade pressure–temperature conditions. In terranes where high deformations rates are reported, exceeding the high anchizone conditions, strain promotes the kinetic effects of temperature and pressure on the KI versus OMR ratio.

The upper limit of maturity of natural gas generation and its implication for the Yacheng formation in the Qiongdongnan Basin, China

Vitrinite reflectance (VR, Ro%) measurements from residual kerogen of pyrolysis experiments were performed on immature Maoming Oil Shale substituted the samples for the gas-prone source rocks of Yacheng formation of the Qiongdongnan Basin in the South China Sea. The work was focused on determination an upper limit of maturity for gas generation (ULMGG) or “the deadline of natural gas generation”. Ro values at given temperatures increase with increasing temperature and prolonged heating time, but ΔRo-value, given a definition of the difference of all values for VR related to higher temperature and adjacent lower temperature in open-system non-isothermal experiment at the heating rate of 20°C/min, is better than VR. And representative examples are presented in this paper. It indicates that the range of natural gas generation for Ro in the main gas generation period is from 0.96% to 2.74%, in which ΔRo is in concordance with the stage for the onset and end of the main gas generation period corresponding to 0.02% up to 0.30% and from 0.30% up to 0.80%, respectively. After the main gas generation period of 0.96–2.74%, the evolution of VR approach to the ULMGG of the whole rock for type II kerogen. It is equal to 4.38% of VR, where the gas generation rates change little with the increase of maturation, ΔRo is the maximum of 0.83% corresponding to VR of 4.38%Ro, and the source rock does not nearly occur in the end process of hydrocarbon gas generation while Ro is over 4.38%. It shows that it is the same the ULMGG from the whole rock for type II kerogen as the method with both comparison and kinetics. By comparing to both the conclusions of pyrolysis experiments and the data of VR from the source rock of Yacheng formation on a series of selected eight wells in the shallow-water continental shelf area, it indicate that the most hydrocarbon source rock is still far from reaching ULMGG from the whole rock for type II kerogen. The source rock of Yacheng formation in the local areas of the deepwater continental slope basin have still preferable natural gas generative potential, especially in the local along the central depression belt (namely the Ledong, Lingshui, Songnan and Baodao sags from southwest to northeast) from the depocenter to both the margin and its adjacent areas. It help to evaluate the resource potential for oil and gas of the hydrocarbon source rock in the deepwater continental slope of the Qiongdongnan Basin or other basins with lower exploration in the northern of the South China Sea and to reduce the risk in exploration.