Rock-Eval Parameters Research Articles

The impact of rapid heating by intrusion on the geochemistry and petrography of coals and organic-rich shales in the Illinois Basin

Igneous intrusion into organic-rich sedimentary rocks and coals has been suggested as a factor in the large-scale release of 13C–depleted thermogenic CH4, which may have led to global warming and mass extinction events in the geologic past. If a significant release of 13C–depleted thermogenic CH4 results from the intrusion of coal or organic-rich rocks, then it should produce 13C–enriched residual coal and dispersed organics in rocks adjacent to the intrusion due to the release of isotopically lighter CH4 gas. A review of the literature suggests only minor changes in the δ13Corg of coals adjacent to intrusions; however, a few studies have shown that changes in δ13Corg in intruded shales may be slightly more pronounced. The current study further evaluates the geochemical, isotopic, and petrographic changes that result from contact metamorphism and specifically compares the intrusion of coal to that of an organic-rich shale collected from the same general vicinity. Data for two different transects of intruded Pennsylvanian coal (Danville (No. 7) Coal) and an intruded organic-rich shale in the southern part of the Illinois Basin are presented.Both transects show similar increases in mean vitrinite reflectance (Rr); reflectance increases from background levels of 0.66% to 4.40% in the Danville (No. 7) Coal and 0.71% to 4.78% in the organic-rich shale. In addition, both transects show the formation of isotropic coke, and even development of fine circular mosaic anisotropic coke structure at and near the contact with the intrusion, along with the visual loss of liptinites at higher reflectances. In the Danville Coal transect, volatile matter, N, H, S, and O decrease whereas fixed carbon, C, and ash increase approaching the intrusion. The coal shows a marked decrease in remaining hydrocarbon potential (S2) and hydrogen index (HI) and an increase in Tmax (°C). Trends in most of the Rock-Eval parameters for the organic-rich shale are less clear due to variations in the amount of organic matter present, but a significant increase in thermal maturity (Tmax, 0C) is observed.No systematic changes in δ13C occur in the No. 7 Coal transect as the intrusion is approached, with δ13C varying between −25.4‰ and −24.8‰. The organic-rich shale transect shows a minor 1.2‰ enrichment in δ13C (from −25.2‰ to −24.0‰) within 2m of the intrusion. These isotopic shifts are not of a magnitude that would be expected if associated with a large-scale release of thermogenic CH4. In addition, no evidence exists in either transect for 13C–depleted condensed gas or pyrolytic carbon at the intrusion contact that could have moderated the isotopic signature. These data agree with those reported previously that indicate no clear isotopic evidence for large-scale CH4 generation due to rapid heating by igneous intrusion into coals or sedimentary rocks.

Stream and slope weathering effects on organic-rich mudstone geochemistry and implications for hydrocarbon source rock assessment: A Bowland Shale case study

This study contributes to the exploration and quantification of the weathering of organic-rich mudstones under temperate climatic conditions. Bowland Shales, exposed by a stream and slope, were sampled in order to develop a model for the effects of weathering on the mudstone geochemistry, including major and trace element geochemistry, Rock-Eval pyrolysis and δ13Corg. Four weathering grades (I – IV) are defined using a visual classification scheme; visually fresh and unaltered (I), chemically altered (II, III) and ‘paper shale’ that typifies weathered mudstone on slopes (IV). Bedload abrasion in the stream exposes of visually fresh and geochemically unaltered mudstone. Natural fractures are conduits for oxidising meteoric waters that promote leaching at the millimetre scale and/or precipitation of iron oxide coatings along fracture surfaces. On the slope, bedding-parallel fractures formed (and may continue to form) in response to chemical and/or physical weathering processes. These fractures develop along planes of weakness, typically along laminae comprising detrital grains, and exhibit millimetre- and centimetre-scale leached layers and iron oxide coatings. Fracture surfaces are progressively exposed to physical weathering processes towards the outcrop surface, and results in disintegration of the altered material along fracture surfaces. Grade IV, ‘paper shale’ mudstone is chemically unaltered but represents a biased record driven by initial heterogeneity in the sedimentary fabric. Chemically weathered outcrop samples exhibit lower concentrations of both ‘free’ (S1) (up to 0.6mgHC/g rock) and ‘bound’ (S2) (up to 3.2mgHC/g rock) hydrocarbon, reduced total organic carbon content (up to 0.34wt%), reduced hydrogen index (up to 58mgHC/gTOC), increased oxygen index (up to 19mgCO+CO2/gTOC) and increased Tmax (up to 11°C) compared with unaltered samples. If analysis of chemically weathered samples is unavoidable, back-extrapolation of Rock-Eval parameters can assist in the estimation of pre-weathering organic compositions. Combining Cs/Cu with oxygen index is a proxy for identifying the weathering progression from fresh material (I) to ‘paper shale’ (IV). This study demonstrates that outcrop samples in temperate climates can provide information for assessing hydrocarbon potential of organic-rich mudstones.

Geochemistry of organic matter and elements of black shale during weathering in Northern Guizhou, Southwestern China: Their mobilization and inter-connection

Different from previous studies on effect of weathering upon geochemical variation along a single weathered profile, this paper provides a new methodology validated by comparing a weathered outcrop samples and their stratigraphic counterpart un-weathered core samples in a nearby shallow borehole. This outcrop and borehole penetrated the Ordovician-Silurian Wufeng–Longmaxi shales, located in the same anticline structure in the northern part of Guizhou Province, Southern China. The mineral composition, major, trace and rare earth elements (REEs) composition and Rock-Eval parameters of outcrop and core samples were analyzed and compared. Organic matter (OM) was observed in the microscope and extracted for elements analysis. The results show that short-term weathering still has significant influence on OM, mineral and elemental composition of black shales. The elements composition shows the outcrop profile was moderately weathered. The REEs compositions do not alter much during weathering process and the REEs composition and their relative ratios still are valid for rock origin determination. The OM, mainly composed by graptolite and bitumen, even entering the highly-over thermal maturity, is still sensitive to the weathering with a systematic loss 30–50% of TOC along the outcrop profile, which suggests that the OM consumption is predominantly controlled by weathering duration and the distance from the weathering surface. In turn, OM has significant influence on the trace elements transportation behavior during weathering. Some trace elements associated with the OM such as V, Cr, Th, U, Ni and Co, change significantly in their absolute concentration during weathering, but their relative ratios do not necessarily change too much and might be still reliable proxies for paleo-environmental determination. The mobility of shale minerals during weathering is in the following order: plagioclase > potassium feldspar and dolomite >pyrite and OM. Short-term weathering can also result in considerable transportation of elements and significant variation of minerals content in black shale, which may pose potentially high environmental and engineering risk in the regions rich in black shale.

The influence of pyrolysis type on shale oil generation and its composition (upper layer of Aleksinac oil shale, Serbia)

The influence of pyrolysis type on the shale oil generation and its composition was studied. Different methods such as Rock-Eval pyrolysis, thermogravimetric analysis (TGA) and pyrolysis in the open and closed systems were applied. Samples from the Upper layer of Aleksinac oil shale (Serbia) were used as a substrate and first time characterized in detail. The impact of kerogen content and type on the shale oil generation in different pyrolysis systems was also estimated. Majority of the analysed samples have total organic carbon content > 5 wt. % and contain oil prone kerogen types I and/or II. Therefore, they can be of particular interest for the pyrolytic processing. The thermal behaviour of analysed samples obtained by TGA is in agreement with Rock-Eval parameters. The pyrolysis of oil shale in the open system gives higher yield of shale oil than the pyrolysis in the closed system. The yield of hydrocarbons (HCs) in shale oil produced by the open pyrolysis system corresponds to an excellent source rock potential, while HCs yield from the closed system indicates a very good source rock potential. The kerogen content has a greater impact on the shale oil generation than kerogen type in the open pyrolysis system, while kerogen type plays a more important role on the generation of shale oil than the kerogen content in the closed system. The composition of the obtained shale oil showed certain undesirable features, due to the relatively high contents of olefinic HCs (open system) and polar compounds (closed system), which may require further treatment to be used.

Petroleum Source-Rock Evaluation and Hydrocarbon Potential in Montney Formation Unconventional Reservoir, Northeastern British Columbia, Canada

Source-rock characteristics of Lower Triassic Montney Formation presented in this study shows the total organic carbon (TOC) richness, thermal maturity, hydrocarbon generation, geographical distribution of TOC and thermal maturity (Tmax) in Fort St. John study area (T86N, R23W and T74N, R13W) and its environs in northeastern British Columbia, Western Canada Sedimentary Basin (WCSB). TOC richness in Montney Formation within the study area is grouped into three categories: low TOC ( 3.5 wt%), and high TOC (>3.5 wt% %). Thermal maturity of the Montney Formation source-rock indicates that >90% of the analyzed samples are thermally mature, and mainly within gas generating window (wet gas, condensate gas, and dry gas), and comprises mixed Type II/III (oil/gas prone kerogen), and Type IV kerogen (gas prone). Analyses of Rock-Eval parameters (TOC, S2, Tmax, HI, OI and PI) obtained from 81 samples in 11 wells that penetrated the Montney Formation in the subsurface of northeastern British Columbia were used to map source rock quality across the study area. Based on total organic carbon (TOC) content mapping, geographical distribution of thermal maturity (Tmax) data mapping, including evaluation and interpretation of Rock-Eval parameters in the study area, the Montney Formation kerogen is indicative of a pervasively matured petroleum system in the study area.

Utilizing the Rock-eval pyrolysis and biomarkers parameters to characterize the organic matters of selected wells in the Central Gulf of Suez, Egypt

ABSTRACTOrganic matters from the KK 85-1and HH 83-1wells in the Central Gulf of Suez were analyzed by two well-proven organic geochemical methods: Rock-Eval pyrolysis and gas chromatography–mass spectrometry (GC–MS) analyses. These techniques were used to obtain independent parameters of organic matter composition, thermal maturity, and environment of deposition. The study reveals a close concordance between Rock-Eval pyrolysis data and biomarkers parameters such as steranes and triterpanes. Rock-Eval pyrolysis in conjunction with GC–MS analyses shows that the organic matters contain two types of kerogen (Type-II/III and Type III), which lie dominantly prior to the peak stage of the conventional oil window (end of diagensis–beginning of catagensis). The case study shows that these methods are suitable for a proper assessment of the petroleum potential of source rocks and the rapid geochemical characterization of sedimentary organic matter.

Geochemical characterization of the hydrous pyrolysis products from a recent cyanobacteria-dominated microbial mat

Hydrous pyrolysis experiments were performed on a recent microbial mat sample from Lagoa Vermelha, Brazil, to determine whether crude oil can be generated and expelled during artificial maturation of the Organic Matter (OM). The experiments were conducted at 280oC, 330oC and 350oC during 20h. Two types of liquid pyrolysis products, assigned as free oil and bitumen, were isolated and analyzed. Free oil represents free organic phase released by hydrous pyrolysis, whereas bitumen was obtained by extraction from the solid pyrolysis residue with dichloromethane. Changes in the OM maturity were determined using Rock-Eval parameters and biomarker maturity ratios of original sample and pyrolysis products. Biomarker compositions of original sample extract and liquid pyrolysates were used for determination of dominant bacterial source. The yields of free oil and bitumen showed that a microbial mat OM has a high liquid hydrocarbons generation potential. Rock-Eval maturity parameters, biopolymer and biomarker compositions indicate a significant increase of the OM maturity during hydrous pyrolysis. At 280oC the release of free, adsorbed and occluded compounds was observed; however, without a cracking of the OM. At 330oC the generation of bitumen and free oil is mostly related to the OM cracking. The highest yield of free oil was recorded at this temperature. Distribution of biomarkers in the extract of original sample and liquid pyrolysates confirms cyanobacteria-dominated microbial mats, whereas the identification of long chain n-alkane series, with maxi

Dynamics of soil organic matter based on new Rock-Eval indices

This paper aims to develop a new approach to interpret soil organic matter (SOM) dynamics from Rock-Eval pyrolysis. Rock-Eval standard parameters (TpS2, HI, OI) are limited when applied to SOM, as they were defined for tracking the origin of sedimentary organic matter (i.e. terrestrial vs aquatic and lacustrine vs marine). This study proposes new Rock Eval based indices, projected on a new diagram plotting >1300 samples, including litter and soil horizons, pure compounds and organic material. These new parameters reflect the thermal stability of SOM rather than its bulk chemistry. Their calculations are based on the contribution of four different areas (A1 to A4) integrated below the S2 pyrogram (amounts of released hydrocarbon compounds during the pyrolysis step). Results demonstrate that the relative values of A1 to A4 parameters can be used to survey the evolution of SOM during pedogenesis. These Rock-Eval parameters revealed a consistent thermal differentiation of SOM with depth, from thermally labile biogenic SOM in soil organic horizons to thermally stable mineral-associated SOM compounds in organo-mineral and mineral soil horizons, indicating a pedogenetic stabilization of SOM. Finally, newly defined I- and R-indices integrate the respective parts of A1 to A4 parameters into SOM dynamics, the I-index emphasizing the degree of transformation of the immature organic fraction (related to SOM stabilization), the R-index highlighting the contribution of the most refractory fraction or persistent SOM (related to pedogenic and inherited contributions). Analyses of a wide range of soils and reference samples (cellulose, lignin, humic substances, lignite, charcoal, coal, etc.) allow end-members as well as particular trends (humic, spodic, inherited) to be drawn. Specific examples are provided in order to illustrate some applications and uses for this new Rock-Eval based I/R diagram, from the study of grain size fractions to the evolution of SOM in soil chronosequences.

Model-assisted Rock-Eval data interpretation for source rock evaluation: Examples from producing and potential shale gas resource plays

Rock-Eval pyrolysis has been widely accepted by the petroleum industry as a useful technique for a quick, easy and cost effective source rock evaluation. However, there are misconceptions and misuse of some of the existing Rock-Eval parameters due to implicit underlying assumptions or poor understanding of the limitations, which could lead to erroneous conclusions. Data interpretation from a perspective of hydrocarbon generation kinetics may facilitate better interpretation of the hydrocarbon generation capacity of a source rock from its thermal stability and transformational behaviors. We present a model-assisted approach for data interpretation, from which data scatters can be viewed not only for the remaining petroleum generation potential of individual samples, but also for data specific thermal decomposition path as a whole to verify whether the data come from a single kerogen population with similar kinetics and associated generation potentials. Moreover, we propose a concept of dimensionless TOC and S2 variables that effectively removes the thermal maturity overprint in the traditional TOC vs. S2 plot used for the determination of the kerogen type. The dimensionless variables are defined by rescaling the parameters against their original values before thermal decomposition. On a dimensionless plot, data points from the same genetic population of source rocks align on a single line regardless of their thermal maturation levels. This article demonstrates the methods and the proposed approaches for studying oil generation kinetics and resource potential using traditional Rock-Eval data through examples from selected producing and potential shale gas plays in Canadian sedimentary basins and elsewhere.

Petrographic characteristics and paleomires of Mand-Raigarh coals, Mahanadi Gondwana Basin, Chhattisgarh, India

Mand-Raigarh coalfield is one of the largest coalfields in the Mahanadi basin. The Geological Survey of India carried out initial study primarily on exploration. However, detailed petrographic and geochemical characters of the coals have not been done so far. This investigation is an attempt for petrographic and geochemical appraisal of the coals. Moreover, effort is also made for possible interpretation on development of coal facies. The results drawn from 30 composite coal samples suggest coals are rich in vitrinite, with collotelinite as the dominant maceral while liptinite macerals register low concentration. Dominant mineral assemblages found were clay minerals, pyrite was recorded as disseminated, framboidal and euhedral forms, carbonates recorded were mainly siderites. The vitrinite reflectance random (VRo) mean values range from 0.44 % to 0.56 %, and the rank of coal is suggested as high volatile ‘B’ to ‘A’ sub-bituminous in rank. The rock–eval pyrolysis reveal TOC content varying from 37 % to 68.83 %, while low hydrocarbon generating potential is evident from low S2 and T max values. The Hydrogen Index (HI) versus Oxygen Index (OI) plot reveal that the samples belong to Kerogen type—II–III with input dominantly from terrestrial source, some samples also fall in Kerogen type—II domain indicating lacustrine input. Vitrinite reflectance result indicate that the samples are immature and approaching oil window, which is in agreement with data of the Rock–Eval parameters. The gelification index (GI) and tissue preservation index (TPI) indicate that the coal developed in a telematic set up with high tree density. The ground water index (GWI) and vegetation index (VI) demonstrate that the peat developed as an ombrogenous bog.

High-resolution organic carbon–isotope stratigraphy of the Middle Jurassic–Lower Cretaceous Agardhfjellet Formation of central Spitsbergen, Svalbard

We present the first complete organic carbon–isotope curve from the Agardhfjellet Formation, central Spitsbergen (Svalbard). Samples from two drill cores (DH2 and DH5R) were analysed for δ13Corg, total organic carbon (TOC) and Rock Eval. Rock Eval, litho- and biostratigraphy demonstrate a similar development in the two cores, allowing construction of a composite δ13Corg curve covering the Bathonian to lowermost Cretaceous. There are only weak correlations between Rock Eval parameters and δ13Corg, suggesting the isotopic signal is not mainly controlled by type of kerogen/maturation but rather reflects regional or global environmental changes. The carbon–isotope curves from the cores can be correlated with previously published curves from outcrops of the Slottsmøya Member and with more distant localities in the Barents Sea, Siberia, Great Britain and the Atlantic. Features in common with other published curves include a Callovian–Oxfordian positive excursion, a Kimmeridgian–Middle Volgian negative trend and a Middle Volgian negative excursion. These correlations allow refinement chronostratigraphy of the Jurassic of Svalbard.

Rapid geochemical and mineralogical characterization of shale by laser-induced breakdown spectroscopy

Detailed evaluation of shale geochemistry and mineralogy is important to assess petroleum reservoir quality, predict production potential and decide lateral placement and completion methods. Standard techniques for organic geochemical and mineralogical characterization are time consuming, can involve significant sample preparation and are prone to error. A new application for assessing shale samples is presented here: laser-induced breakdown spectroscopy (LIBS). A laser is used to rapidly pyrolyze shales and the changes in sample elemental composition during pyrolysis are monitored through optical emission spectroscopy. Unlike other common shale characterization methods, no specific sample preparation is required. Multivariate analysis is applied to the LIBS spectra to predict both organic geochemistry and mineralogy. The results show good correlation to TOC, Rock–Eval parameters and eleven minerals, including clay speciation. The technique also has the potential to directly measure organic hydrogen and oxygen and could provide an alternative to the indirect methods currently used.

High resolution geochemical analysis of organic matter accumulation in the Qingshankou Formation, Upper Cretaceous, Songliao Basin (NE China)

In the well-known continental Songliao Basin, the oil shale successions of the Cretaceous Qingshankou Formation are excellent source rocks for oil. The oil shale layers with high TOC (total organic carbon) contents developed at the bottom of the formation. They are divided into the lower oil shale (TOC up to 18.3%) and the upper oil shale layer (TOC up to 14.4%). The oil shale layers and accompanying mudstones are investigated by high resolution analyses of drill cores by pyrolysis, organic petrology, organic and inorganic geochemistry. The results demonstrate the predominance of type-I kerogen derived from algal-microbial mats (i.e. lamalginite). However, increased proportions of plant-derived organic matter are indicated by Rock-Eval parameters and the presence of vitrinite in the upper oil shale. As evidenced from lower concentrations of hopanes, higher sinking rates of organic matter (OM) are suggested to have been responsible for a lower extent of microbial degradation during accumulation of the lower oil shale unit. The environmental conditions are characterized by anoxic saline bottom water overlain by an extended zone of freshwater, favorable for OM production and preservation. Under these preconditions, oil shale thickness and quality are governed by primary productivity, related to accommodation space and nutrient supply. Redox conditions within the water column are the key factor controlling organic matter preservation.

Geologic Conditions of Shale Oil and Gas Accumulation in the Southeast Uplift Songliao Basin (Upper Cretaceous, NE China)

Thick dark source rocks were developed in the Qingshankou Formation (Late Cretaceous, Songliao Basin). According to sedimentary characteristics and systematical geochemical tests, the geological conditions of shale oil and gas accumulation are studied. The thick dark mudstone succession (TOC > 2%) is represented by deep lake environment and their thickness could reach 91 m in the center depression, Songliao Basin. Organic matter is mainly composed by type I and II1 kerogen. Vitrinite reflectance (0.5–0.7% Ro) and RockEval parameter Tmax (425–445°C) indicate that the source rock is marginal mature to mature. Abundant brittle minerals (average 51.1%) and the 4.1–14.0% porosity are developed in the mudstone. Based on the SEM and microscope observation, the micron level to nanometer level pores are the main reservoir for shale gas and oil. Through comprehensive analysis of these geological conditions, it is concluded that the lower part in the Qingshankou Formation has the potential to form shale oil and gas reservoirs, and the deep region of the Southeast Uplift near the basin center side is the best favorable zone of shale oil and gas accumulation.

Natural gas potential of Neoproterozoic and lower Palaeozoic marine shales in the Upper Yangtze Platform, South China: geological and organic geochemical characterization

In this article, we describe the geological features of the Ediacaran (upper Sinian), lower Cambrian and lower Silurian shale intervals in the Upper Yangtze Platform, South China, and report on the gas potential of 53 samples from these major marine shale formations. Reflected light microscopy, total organic carbon (TOC) measurement, Rock-Eval, carbon isotope ratio analysis, thermovaporization gas chromatography (Tvap-GC), and open pyrolysis gas chromatography (open py-GC) were used to characterize the organic matter. Measured TOC in this research is normally >2% and averages 5%. TOC contents are roughly positively correlated with increasing geological age, i.e. lower Silurian shales exhibit generally lower TOC contents than lower Cambrian shales, which in turn commonly have lower TOC contents than Ediacaran shales. Kerogen has evolved to the metagenesis stage, which was demonstrated by the abundant pyrobitumen on microphotographs, the high calculated vitrinite reflectance (Ro = 3%) via bitumen reflectance (Rb), as well as δ13 C of gas (methane) inclusions. Pyrolysates from Tvap-GC and open py-GC are quantitatively low and only light hydrocarbons were detected. The lower Silurian shale generally exhibits higher generation of hydrocarbon than the lower Cambrian and Ediacaran shale. Cooles’ method and Claypool’s equations were used to reconstruct the original TOC and Rock-Eval parameters of these overmature samples. Excellent original hydrocarbon generation was revealed in that the original TOC (TOCo) is between 5% and 23%, and original S1+S2 (S1o+S2o) is ranging from 29 to 215 mg HC/g rock.

Source rock characteristics of Albian Kazhdumi Formation in Zagros Region

During Albian time, a large but gentle depression was developed over Dezful Embayment extending to the northern part of Persian Gulf. Strong anoxic condition prevailed development of bituminous marls of Kazhdumi Formation in central part of the depression. Organic richness, quality, distribution, and maturity of Kazhdumi Formation in northeast margin of Arabian plate (Dezful Embayment, Persian Gulf, Abadan Plain and Fars Region) are evaluated in this study. Rock-Eval pyrolysis data, such as Tmax, S1, S2, oxygen index (OI), and total organic carbon (TOC), petrographic studies, and burial history information of 64 wells in 37 oil and gas fields and five outcrops are applied to achieve focused aims. Based on the interpretations of TOC and S2 data, Kazhdumi organic matter richness increases toward Dezful Embayment and the lowest values are recorded in central Persian Gulf (Qatar Arch). Using constructed burial and temperature histories, Tmax and vitrinite reflectance (VRr) values, the variation of maturity level are found similar to that of organic matter richness which highest and lowest maturities are observed in Dezful Embayment and Qatar Arch, respectively. Kerogen type studies were carried out based on Rock-Eval parameters and type II/III kerogen assessed for organic matter of Dezful Embayment and terrigenous or type III for those of Persian Gulf.

Gas potential of Proterozoic and Phanerozoic shales from the NW Himalaya, India: Inferences from pyrolysis

Organic richness and kerogen properties of sixty-seven shales, obtained from the outcrops and underground mines of Jammu, Kashmir and Ladakh regions of Northwest Himalaya, India, have been studied to evaluate their gas generation potential using Rock Eval pyrolysis. Ranging in age from the Proterozoic to Tertiary, organic matter content and characteristics of the carbonaceous and coaly shales vary widely, indicating that sedimentary and burial history significantly affected the preservation and maturation of organic components in rocks.The total organic carbon (TOC) content ranges from 0.01 to 1.2% in the Permian–Jurassic and Paleozoic–Tertiary shales of Ladakh to as high as 32.5% in the Eocene shales/coaly shales from Jammu. The thermo-labile hydrocarbons (S1) and those from cracking of kerogen (S2), released from the pyrolysis of Eocene Subathu shales, are observed to be high (from 0.1 to 2.6 and from 0.5 to 15.5mgHC/g rock, respectively). Rock Eval thermal maturity parameters, indicated by Tmax (temperature at highest yield of S2; >490°C) and calculated vitrinite reflectance (1.5 to 3.7 Ro %), suggest a post-mature, dry gas stage for the hydrocarbon generation. Based on hydrogen index (HI) and Tmax correlations, organic matter in the Subathu shales is characterized by a late metagenetic gas prone Type III kerogen and a fair to excellent gas potential is exhibited by these shales.The interbedded shale units in the Proterozoic Sirban Limestone Formation, occurring as an isolated inlier in Jammu, show TOC values from 0.1 to 1.4% with quite low S1, S2 and HI values. Thermal maturity of shales within the stromatolitic Sirban succession indicates a post-mature and/or already spent hydrocarbon stage. The Plio-Pleistocene carbonaceous clays, lignites and mudstones from the Lower Karewa Group of Kashmir basin are organically rich with TOC content ranging from 5.86 to 29.4%. A thermally immature, Type II/Type III kerogen is indicated by the HI (109 to 278mgHC/g TOC) and Tmax (399 to 427°C) plots of the Karewa samples. The exposed Lower Triassic Black shales from the Permian–Triassic boundary sections in Kashmir are comparatively lean in organic matter, with TOC values ranging from 0.18 to 0.93%, whereas the Permian–Jurassic and Paleozoic–Tertiary shales from Ladakh have a TOC content ranging from 0.01 to 1.22%. The pyrolyzable organic carbon is <0.1% and the residual organic carbon contributes significantly to the TOC content of these shales. The other Rock Eval parameters (S1, S2, HI) are quite low and indicate a poor source potential. The majority of shales from the Tethys and Trans Himalayan regions appear to have undergone metamorphism and exhumation of organic carbon associated with the Himalayan orogeny.

Characterization of sedimentary organic matter in recent marine sediments from Hudson Bay, Canada, by Rock-Eval pyrolysis

A combination of Rock-Eval pyrolysis and isotopic analyses is used to characterize the sources and distribution of organic matter in modern marine sediments from the subarctic Hudson Bay (including Hudson Strait and Foxe Basin), Canada. This approach reveals organic matter contributions from both marine and terrigenous sources, with spatial patterns and varying degrees of degradation that are consistent with inferences from traditional geochemical tracers for modern organic matter. Rock-Eval parameters characterize Hudson Bay organic matter with low hydrogen index, high oxygen index and a high degree of residual carbon that suggests heavily reworked materials. Locations of higher primary productivity in Hudson Strait, Foxe Basin, the northeast and far west of Hudson Bay, and the concentration of watershed runoff in the southern part of Hudson Bay can be delineated using the ratios between hydrogen and oxygen indices and from the distribution of labile organic carbon. Relatively high temperatures of peak hydrocarbon yield identify an advanced state of OM degradation or humic substances as important classes of organic carbon compounds in the majority of the sediment. Such highly degraded and oxygenated organic matter is unusual compared to that typically observed in other Arctic shelf seas and is consistent with a strong role for sediment and organic matter recycling in Hudson Bay. In the offshore region, the source of highly oxidized and labile organic matter identified by Rock-Eval parameters is resolved with δ13C and biomarker information that also permit examination of the sediment biogeochemical regime. This approach suggests that a distinct association with Mn enriched sediment contributes to the oxidization signal by abiotic or biological Mn related processes. These interpretations extend the limited information available on using Rock-Eval analyses to characterize organic matter in recently deposited marine sediments and describe an important consideration to using this method in Mn enriched environments.

Multivariate analysis of ATR-FTIR spectra for assessment of oil shale organic geochemical properties

In this study, attenuated total reflectance (ATR) Fourier transform infrared spectroscopy (FTIR) was coupled with partial least squares regression (PLSR) analysis to relate spectral data to parameters from total organic carbon (TOC) analysis and programmed pyrolysis to assess the feasibility of developing predictive models to estimate important organic geochemical parameters. The advantage of ATR-FTIR over traditional analytical methods is that source rocks can be analyzed in the laboratory or field in seconds, facilitating more rapid and thorough screening than would be possible using other tools. ATR-FTIR spectra, TOC concentrations and Rock–Eval parameters were measured for a set of oil shales from deposits around the world and several pyrolyzed oil shale samples. PLSR models were developed to predict the measured geochemical parameters from infrared spectra. Application of the resulting models to a set of test spectra excluded from the training set generated accurate predictions of TOC and most Rock–Eval parameters. The critical region of the infrared spectrum for assessing S1, S2, Hydrogen Index and TOC consisted of aliphatic organic moieties (2800–3000cm−1) and the models generated a better correlation with measured values of TOC and S2 than did integrated aliphatic peak areas. The results suggest that combining ATR-FTIR with PLSR is a reliable approach for estimating useful geochemical parameters of oil shales that is faster and requires less sample preparation than current screening methods.

Organic geochemistry and petrology of the Gomo Member, Recôncavo Basin, Brazil

The Recôncavo Basin is located in the northeast of Brazil, and is part of the Recôncavo–Tucano–Jatobá rift system. In this basin the first commercial oilfield was discovered in Brazil about 70 years ago, and the basin still remains until today a producer of hydrocarbons. The hydrocarbon generation within source rocks is controlled mainly by thermal maturation and by the type of organic matter. These parameters can be studied through petrological and organic geochemical analyses. The objective of the present study is to characterize the organic matter in the Gomo Member source rocks to obtain information on the type, content of the organic matter, and thermal maturity. The Gomo Member is considered the main hydrocarbon source rock of the Recôncavo Basin. The Gomo strata is predominantly comprised of pelitic sediments and black shales, intercalated with thin layers of carbonates and fine-grained sandstone. Results obtained from the analyses of 37 cutting samples collected from six petroleum exploration wells indicate that these rocks have organic carbon contents > 0.5 wt.%, however, the organic matter has a relatively low hydrocarbon generation potential as indicated by low S2 values. A plot of Hydrogen (HI) versus Oxygen Indices (OI) indicates kerogen type II, suggesting terrestrial and lacustrine contribution to the organic matter. The Rock Eval parameter Tmax and vitrinite reflectance show that the majority of the samples are in the marginal to low mature and moderately mature stages of the oil generation window. Considering the geochemical and petrological parameters, it appears that the southern compartment of the Recôncavo Basin had the highest rate of accumulation and preservation of the organic matter, and consequently the highest petroleum generation potential.