Rock-Eval Analysis Research Articles

Thermal history of the Northwestern Argentina, Central Andean Basin, based on first-ever reported graptolite reflectance data

The thermal maturity from the Early Paleozoic strata in Northwestern Argentina was studied using reflected light microscopy and Rock-Eval analyses. The graptolites were collected from the Acoite and Lipeón formations, at the Los Colorados section, Cordillera Oriental, and the Huaytiquina, and Muñayoc sections, Puna highland, corresponding to the "Coquena" Formation and the Cochinoca-Escaya Magmatic-Sedimentary Complex. Rock-Eval parameters were unreliable due to the low TOC, S1, and S2 values. The Cordillera Oriental region sediments have low maturity based on low reflectance (%GRo= 0.63%–1.11%) and anisotropy of graptolites. In contrast, the higher graptolite reflectance of samples from the Muñayoc and Huaytiquina sections (%GRo= 5.57%–6.62%), in the Puna region, indicates considerably higher maturity. This could result from the combination of hydrothermal fluids with a temperature range from 336 °C to 358 °C, associated volcanism, and deformation related to tectonics events, which produced a higher geothermal gradient in the Puna. The Los Colorados section's thermal maturity modeling shows a better fit considering erosion episodes at the Late Paleozoic and Early Cenozoic. However, more studies about geothermal parameters and stratigraphy are necessary to corroborate these preliminary models and propose new approaches for the Puna region.

Long-term bare-fallow soil fractions reveal thermo-chemical properties controlling soil organic carbon dynamics

Abstract. Evolution of organic carbon content in soils has the potential to be a major driver of atmospheric greenhouse gas concentrations over the next century. Understanding soil carbon dynamics is a challenge due to a wide range of residence times of soil organic matter and limited constraints on the mechanisms influencing its persistence. In particular, large uncertainties exist regarding the persistence of pyrogenic organic carbon in soils. In order to characterize organic matter with varying degrees of persistence and to distinguish pyrogenic organic carbon, we combined Rock-Eval analysis, a thermo-chemical method, with the benzene polycarboxylic acid molecular marker method and Raman spectroscopy to characterize samples from long-term bare-fallow experiments, progressively depleted in the most labile organic carbon over time. Considering the heterogeneity of soil samples, size fractions have been separated to distinguish pools of organic carbon with distinct properties. We observe that organic carbon dynamics is dependent on granulometry. A pool of organic carbon with intermediate residence times, from years to a few decades, representing ca. 65 % of the bulk soil organic carbon stock, is mainly associated with fine fractions (< 20 µm). With time under bare fallow, this organic carbon is progressively transferred towards finer fractions through the breakdown of organic matter. Coarse fractions (> 20 µm) are rich in centennially persistent organic carbon, representing ca. 20 % of the initial organic carbon stock, due to the chemical recalcitrance of organic matter in these fractions, dominated by pyrogenic organic carbon. A second pool of persistent organic carbon, representing ca. 15 % of the initial organic carbon stock, is associated with the clay fraction, indicating mechanisms of protection occurring at the submicron scale (< 2 µm). This persistent organic carbon only represents 30 % of the organic carbon initially present in the clay fraction. Persistent organic carbon exhibits heterogeneous chemical signatures depending on the considered pool but a consistent thermal signature demonstrating the relationship between thermal stability and biogeochemical stability of soil organic carbon. This gives the possibility of assessing the size of the persistent organic carbon pool in soils using thermal parameters. The persistence of pyrogenic organic carbon in the clay fraction is similar to the one of total organic carbon. The different persistence of coarse and fine pyrogenic organic carbon resides in the highly condensed nature of sand-sized pyrogenic carbon, which may result from burning temperatures over 700 ∘C. Pyrogenic organic carbon is not inert but exhibits a consistent increase in the level of condensation with time in all size fractions, showing the role of chemical quality in pyrogenic organic carbon persistence. Overall, this study helps improve the separation, evaluation and characterization of carbon pools with distinct residence times in soils and gives insight into the mechanistic origin of soil organic carbon dynamics.

Critical insights from Rock-Eval analysis of vitrains

Rock-Eval S2 and S4 curves are commonly used to interpret active source rocks. In this work we report the formation of unusual, uneven, spiky S2 pyrograms from Rock-Eval of manually isolated vitrain bands from Mvb and Lvb coals. The spikes and unevenness in the S2 curves for coking-vitrains are interpreted to form from the release of gases or bubbles bursting from the melt during the pyrolysis stage. Crucible swelling numbers measured for these vitrains were observed to be 3 to 4 times higher than the parent coal from which they were separated. Field Emission Scanning Electron Microscope (FE-SEM) images also document formation of three dimensional bubbles due to bursting of gaseous bubbles, in the pyrolysis-residue (using Rock-Eval) of coking-vitrains. For bulk coal samples and vitrains isolated from HvbA coals, the S2 pyrograms were observed to be smooth. At higher sample weights, the formation of spikes for the vitrains from Mvb and Lvb was observed to increase, irrespective of the heating-rates used, owing to the release of greater amounts of gases or bubbles bursting from the melt. The results indicate the importance of cross-examining S2 pyrograms as it offers clues towards the behavior of coals during pyrolysis, and for better interpretation of results.

Determination of hydrocarbon generation potential of a non-isothermal pyrolysis of Faraghun and Sarchahan Formations in Coastal Fars and the Persian Gulf, Iran

Source rock assessment is a key step in any petroleum exploration activity. The results of Rock-Eval analysis showed that Sarchahan Formation was in the late oil window, while the Faraghun and Zakeen Formations were just in the early stages of the oil window. Furthermore, Sarchahan, Zakeen and Faraghun Formations exhibited different kerogen types (types-Ⅱ, types-Ⅲ and type-Ⅲ, respectively). Refining the kinetic parameters using the OPTKIN software, the error function returned error values below 0.1, indicating accurate optimization of the kinetic parameters. Based on the obtained values of activation energy, it was clear that Sarchahan Formation contained type-Ⅱ kerogen with an activation energy of 48–52 kcal/mol, while Zakeen and Faraghun Formations contained type-III kerogen with activation energies of 70–80 kcal/mol and 44–56 kcal/mol, respectively. The geographical distribution of the samples studied in this work, it was found that the organic matter (OM) quantity and quality increased as one moved toward the Coastal Fars in Sarchahan Formation. The same trend was observed as one moved from the southern coasts of Iran toward the shaly and coaly portions of Faraghun Formation in the center of the Persian Gulf.©2021 China Geology Editorial Office.

Comparative Study on Hydrocarbon Generation in Different Tectonic Zones: A Case Study from the Upper Jurassic Naokelekan Formation at the Imbricated and High Folded Zones, Kurdistan Region, Iraq

The impact of tectonic activities from different tectonic zones on hydrocarbon generation in the Upper Jurassic Naokelekan Formation was addressed in this study. The Upper Jurassic Naokelekan Formation is an important potential of source rocks for hydrocarbon generation that charges most of the Cretaceous and younger reservoirs in the Kurdistan Region, Iraq. A total of 5 rock specimens from the Warte outcrop and 7 cutting samples from Well Bina Bawi-1 were collected for Rock-Eval pyrolysis to investigate the relationship between the ability of the formation to generate hydrocarbons and tectonic activities. The results of Rock-Eval analysis on the analyzed samples showed an average of 2.65 wt% and 0.9 wt% total organic carbon (TOC) for Warte and Well Bina Bawi-1, respectively. Based on the TOC data, the Naokelekan Formation, in general, has a good to very good source rock potential. The qualitative properties of the organic matter (OM) of the formation were inferred from the kerogen types. The Warte section mostly contains type III kerogen that is gas prone, whereas the Well Bina Bawi-1 section contains mixed type I-II kerogen that is oil prone. It should be taken into consideration that the values for the hydrogen index (HI) of the Warte section are unreliable for interpretation of the organic type, because the HI is considerably reduced owing to the high level of thermal maturity. The Tmax values showed that the Warte section is thermally more mature than the Well Bina Bawi-1 section. The difference in the thermal maturity can likely be attributed to the differential effects of the tectonic activities on the studied areas. Depending on the proximity or distance of the area in relation to the subduction zone, the sediments in the Imbricated Zone were more affected by the tectonic activities than the sediments in the High Folded Zone. Accordingly, the main factors that might have caused a higher thermal maturity in the Imbricated Zone include a high paleo heat flow, overthrusting, and hydrothermal activities.

Organic geochemistry of source rocks in the Baiyun Sag of the Pearl River Mouth Basin, South China Sea

Source rock samples (i.e., drill cuttings) of the Wenchang, Enping, and Zhuhai formations from the Baiyun sag in the deep-water area of the Pearl River Mouth Basin (PRMB) in the South China Sea were collected and subjected to organic geochemical analysis. The three sets of potential source rocks were further divided into six types, based on biomarkers and carbon isotopic compositions: shallow lacustrine and semideep–deep lacustrine source rocks of Wenchang Formation, shallow lacustrine and marine transgression-related source rocks of Enping Formation, and littoral and neritic source rocks of Zhuhai Formation. The Wenchang Formation semideep–deep lacustrine source rocks developed in the Baiyun Sag are characterized by low ratio of C30 4-methylsteranes to C29 steranes (4-Me/C29 < 0.25) and relatively 13C-depleted isotopic compositions (δ13Ckerogen < −27.5‰), which are obviously different from those from shallow-water area in the PRMB. Rock–Eval analysis shows the Wenchang Formation develops good source rocks, which are better than those in the Enping Formation. The Zhuhai Formation does not contain effective source rocks because of its low maturity. According to the distribution of bicadinanes and oleanane, it is speculated that shallow lacustrine source rocks of Wenchang Formation in the northern Baiyun Sag have similar high bicadinanes to C30 hopane ((W + T)/C30H) and low oleanane to C30 hopane (OL/C30H) ratios to those of the Enping Formation, indicating their possible contribution to the discovered hydrocarbon accumulations. In summary, hydrocarbons generated by the Wenchang Formation source rocks should become the next key exploration target in the Baiyun Sag.

Organic petrological and geochemical appraisal of the Upper Jurassic Naokelekan Formation, Kurdistan, Iraq

Upper Jurassic Naokelekan Formation, being part of the intercepted strata of the well-known Miran oilfield in Kurdistan region of Northern Iraq, has been previously extensively evaluated as a potential/effective source rock, mainly by means of organic geochemistry. In the present study, a total of 60 samples were collected from four Naokelekan Fm. outcrops, those of Banik, Galy-Derash, Barsarin and Dwawa, in order to conduct organic petrographical study and organic geochemical assessment, including both biomarker and Rock-Eval analyses. The average recorded TOC content for Banik, Galy-Derash, Barsarin and Dwawa section is considerable to very high, corresponding to values of 27.5, 9.0, 3.5 and 5.2 wt%, respectively, with the highest values representing the notably organic-rich bottom part of the Formation, known as “coal layer”. According to the petrographical analysis, solid migrabitumens comprise the predominant component for all the analysed samples, whereas the maceral groups of vitrinite, liptinite and/or inertinite showcase a minor to trace occurrence. In terms of organic geochemistry, each of the four sections of interest shows a different biomarker profile. Nevertheless, a number of calculated parameters related to kerogen type and depositional conditions, including the isoprenoids/n-alkanes ratios, suggest a mixed terrestrial-marine organic matter. Furthermore, as indicated by the Ro (%) measurements along with Rock-Eval parameters and the vitrinite reflectance equivalent based on aromatic compounds, the maturity level is marginally mature in the cases of Banik and Galy-Derash, whereas in the cases of Dwawa and Barsarin sections it is mature to post-mature. A synthesis of the organic petrography and geochemical appraisal applied in the present study, suggests that the reported solid hydrocarbons in Naokelekan Fm., particularly at its basal layers are non-indigenous/migrated and the precursor organic matter was deposited in a marine environment, under oscillating conditions ranging from euxinic to well‑oxygenated. Accordingly, the organic features of the notably bitumen-rich “coal-bed” fit the profile of a reservoir and/or migration path.

P.354 Bloomed again: seasonality and clinical correlates in bipolar disorder

Important depositional characteristics indicative of climate change has been discovered in 50-m sedimentary succession consisting of oil shales with a marlstone and carbonate matrix of the Viséan shales from the Lower Carboniferous Emma Fiord Formation on Devon Island, Canada's Arctic Archipelago. Older Carboniferous (Tournaisian) shales, are however absent from Devon Island, but elsewhere such as Big Marsh, Nova Scotia, Tournaisian shales show no comparable evidence for climate change.The techniques used include reflected light microscopy, RockEval analyses, instrumental neutron activation analysis (INAA) for elemental concentration.Indeed, Viséan shales from the Lower part the Emma Fiord Formation from Devon Island have a marlstone matrix with abundant algal matter. The matrix also has low carbonate (32%) and total organic carbon (TOC) content between 33.3%and 55.6%. Moreover, the TOC show a positive correlation with authigenic uranium, and Mo, which suggests a high productivity due to the high rain, deeper water lacustrine depositional environment. Other Viséan oil shales from the Emma Fiord Formation on Devon Island have somewhat different characteristics from those with marlstone matrix. Indeed, they have a high (75%) carbonate content with calcified algal matter and low TOC (1.14–17.4%). A very low correlation between TOC and authigenic U, and Mo. Most importantly very high oil generation (98–413 L/t) potential of marlstones as compared to low yield of carbonate mudstones (4.1–17.0 L/t) shows a dramatic climatic shift to low precipitation and much dryer conditions. Such a drastic climatic condition has not been detected for the Tournaisian oil shales.

Comparing natural and artificial thermal maturation of a Type II-S source rock, Late Cretaceous, Israel

Marine source rocks that are sulfur-rich (i.e., Type II-S kerogen) start to mature earlier than their sulfur-lean equivalents (Type II). This affects the amount of petroleum generated with the increase in thermal maturation. However, the evolution of HI with Tmax upon thermal maturation is not described quantitatively (or semi-quantitatively) for Type II-S kerogen. Here we explore the natural thermal maturation of the Ein Zeitim/Ghareb Formation (Late Cretaceous) type II-S source rock in the Golan Basin, north Israel. This is done by comparing geochemical data on cuttings from the section in the Golan Basin with an artificial maturation experiment conducted on an immature analog core taken from the Shfela Basin, central Israel. Using bulk Rock-Eval analyses of unextracted and extracted samples, the natural and artificial maturation paths are found to be comparable and show sub-parallel trends for the relative decrease in hydrogen index (HI) and the increase in the normalized bitumen content (mgBitumen/gTOC) with increasing thermal maturation (measured as Tmax). This comparison suggests that maturation in the Golan Basin increases with depth across the ~350 m thick section from an early maturation state to the peak of bitumen generation. While the original HI (HIo) is estimated from the field data, the original S2 prior to maturation (S2o) is estimated based on the empirical relationship derived from the artificial maturation data trend in order to estimate hydrocarbon generation. Second-order differences between the artificial and natural maturation trends may be due to small differences in the sulfur content of the immature kerogens from the two basins (0.5–1 wt% from the kerogen), leading to an offset in the Tmax maturation scale. Thus, a lower-case scenario is considered to estimate lower values for S2o and the hydrocarbons generated across the source rock section. As sulfur in the immature kerogen has a substantial effect on the onset of maturation, we postulate that the maturation path presented here is more representative for sulfur-rich kerogens then that of the sulfur-lean Type II kerogens. However, variability in the sulfur content within sulfur-rich kerogens, will probably change the specific maturation path of a given kerogen.

Impact of Paleosalinity, Paleoredox, Paleoproductivity/Preservation on the Organic Matter Enrichment in Black Shales from Triassic Turbidites of Semanggol Basin, Peninsular Malaysia

Turbidite-associated black shale of the Semanggol Formation is extensively distributed in the northwestern part of the Western Belt, Peninsular Malaysia. The black shale occurs as a dark grey to black and thick to medium-bedded deposit. It represents the distal part of submarine fan system (outer-fan) overlying interbedded sandstone to shale facies of the mid-fan and conglomeratic pebbly sandstone facies of the inner-fan. Field observations and its widespread occurrence have resulted in the black shale being considered as a potential analog for a source rock in offshore Peninsular Malaysia. The present study includes detailed mineralogical (XRD, SEM, and EDX analysis), inorganic geochemical (major oxides, trace elements TEs, and rare earth elements REEs), and Rock-Eval pyrolysis analyses of the black shale samples, collected from the Gunung Semanggol, Bukit Merah, and Nami areas in northwestern Peninsular Malaysia. The primary focus of this study is to investigate the provenance, paleoredox conditions, paleoclimate, sedimentary rate, paleoproductivity, and upwelling system that would be helpful to understanding the role of these parameters in the enrichment of organic matter (OM) in the black shale. The Rock-Eval analysis shows that the black shale of the Semanggol Formation comprises type-III kerogens, which suggests organic input from a terrestrial source. The black shale also contains mature to postmature organic matter. Based on the mineralogical analysis, the mineral composition of the black shale comprises illite and kaolinite, with abundant traces of quartz and feldspar as well as few traces of titanium and zircon. Inorganic geochemical data designate black shale deposition in a passive margin setting that has experienced moderate to strong weathering, semi-arid to hot arid climate, and moderate sedimentation rate. Ratios of Ni/Co, U/Th, and V/(V+Ni) along with slightly negative to positive Ce* anomalies and UEF-MoEF cross-plot unanimously indicate anoxic/dysoxic water conditions that are suitable for organic matter preservation. Geochemical proxies related to modern upwelling settings (i.e., Cd/Mo, Co vs. Mn) show that the deep marine black shale was strongly influenced by persistent upwelling, a first-order controlling factor for organic matter enrichment in the distal part (outer fan of the submarine fan system) of the Semanggol Basin. However, productivity-controlled upwelling and a high sedimentary rate, as well as high-productivity in oxygen-depleted settings without strong anoxic conditions, has played an essential role in the accumulation of organic matter.

Clumped isotope geothermometry of an Ordovician carbonate mound, Hudson Bay Basin

The Hudson Bay sedimentary basin was overlooked geologically until two decades ago. Recent efforts to understand the palaeogeothermal history of this basin have led to the evaluation of fluid inclusion microthermometry, apatite fission track, organic matter reflectance and Rock–Eval analyses. Although apatite fission track and organic maturity indicators tend to show relatively low maximum burial temperatures (60–80°C), evidence of potential oil slicks on the sea surface and oil and gas shows in offshore wells have been reported across Hudson Bay. Fluid inclusion microthermometry in a carbonate mound sequence suggests homogenization temperatures of 118 ± 25 and 93 ± 10°C for recrystallized synsedimentary marine calcite and late pore-filling burial calcite, respectively. This sequence provides an interesting geological framework to test the application of clumped isotope thermometry against independent geothermometers. Here, we present clumped isotope data acquired on the late calcite cements and diagenetically altered early marine phases. The integration of clumped isotopic data with other thermal indicators allows the reconstruction and refinement of the thermal–diagenetic history of these carbonates by confirming an episode of heating, probably of hydrothermal origin and prior to normal burial diagenesis, that reset both fluid inclusions and the clumped isotope indicators without recrystallization.

Regional hydrocarbon potential and thermal reconstruction of the Lower Jurassic to lowermost Cretaceous source rocks in the Danish Central Graben

The Danish part of the Central Graben (DCG) is one of the petroliferous basins in the offshore region of north-western Europe. The source rock quality and maturity is here reviewed, based on 5556 Rock-Eval analyses and total organic carbon (TOC) measurements from 78 wells and 1175 vitrinite reflectance (VR) measurement from 55 wells, which makes this study the most comprehensive to date. The thermal maturity is evaluated through 1-D basin modelling of 46 wells. Statistical parameters describ-ing the distribution of TOC, hydrocarbon index (HI) and Tmax are presented for the Lower Jurassic marine Fjerritslev Formation, the Middle Jurassic terrestrial-paralic Bryne, Lulu, and Middle Graben Formations and the Upper Jurassic to lowermost Cretaceous marine Lola and Farsund Formations in six areas in the DCG. For the Farsund Formation the source-rock richness is presented for selected stratigraphic sequences. The upper part of the Farsund Formation is immature in the southern part of the Salt Dome Province, and late oil mature in and near the Tail End Graben and in the Søgne Basin. The lower part of the Farsund Formation is immature in local areas, yet post-mature in the Tail End Graben and in the Salt Dome Province. The Lower and Middle Jurassic shales are gas-prone in most of the DCG. The depth of the oil window, as defined by a VR of 0.6% Ro, ranges between 2200 and 4500 m. The variations are ascribed to heat flow differences in the DCG and can be modelled by a simple depth model, which includes the thickness of the Cretaceous to Palaeo-gene Chalk and Cromer Knoll Groups. According to the model, a thick Chalk Group offsets the oil window to deeper levels, which likely can be attributed to the thermal properties of the highly thermally conductive chalk compared to the underlying less thermally conductive clays. The DCG is an overpressured basin, and high-pressure, high-temperature conditions are expected to occur deeper than 3.8 km except for the Feda and Gertrud Grabens where such conditions, due to generally lower tem-peratures, are expected to occur deeper than around 4.7 km.

Mineralogical and geochemical imprints to determine the provenance, depositional history and tectonic settings of Triassic turbidites in the Semanggol and Semantan Basins, Peninsular Malaysia

• Semanggol and Semantan formations are part of Triassic successions in SE Asia. • Triassic turbidites exemplify inner to outer fan in a deep-marine fan system. • Semanggol turbidites were sourced from felsic rocks and represent passive margin. • Semantan rocks have felsic-intermediate origin and show active-continental margin. • Based on redox-sensitive metals, depositional conditions fluctuate from anoxic-oxic. • Type-III kerogen, mature-overmature proposing terrestrial input of organic matter. The present study provides systematic mineralogical, inorganic geochemical and Rock-Eval analyses of turbidite deposits of the Semanggol and Semantan formations to investigate their provenance, depositional environment and tectonic setting as well as type, origin and maturation of organic matter in black shale. These deposits are extensively distributed in Peninsular Malaysia and are observed in the field as conglomerate, pebbly sandstone, thick-bedded sandstone, interbedded sandstone and shale, laminated black shale, and tuffaceous sandstone. These sedimentary sequences are predominantly deep-marine and occasional shallow-marine deposits characterizing a deep-marine fan system. Based on Al 2 O 3 /TiO 2 ratios, more felsic rocks for the Semanggol Formation and felsic-intermediate rocks for the Semantan Formation are proposed as sources for their detrital fractions and this interpretation is also substantiated by the binary plot of Zr vs Ti. V/(V + Ni), V/Ni and Ni/Co analyses indicate anoxic/oxic conditions. Ternary diagram of immobile- trace-elements inferred passive margin for Semanggol turbidites and an active-continental margin for Semantan turbidites. The dissimilarity between geochemically and geologically derived tectonic settings, mainly for the Semanggol turbidites, is because of changing tectonic setting and recycled nature of sediment sources that were deposited in diverse tectonic settings. The black shale clay fractions from both formations dominantly contain illite and kaolininte with abundant traces of quartz. The illite content varies from 43 to 56% and illite crystallinity index (IC) from 0.2° to 0.4° Δ2θ (average: 0.28° Δ2θ), showing studied black shale fall in anchizone. Rock-Eval pyrolysis reveals Type-III kerogens, suggesting a terrestrial source of organic matter in black shale of both formations.

Organic geochemical characterization of crude oils and source rocks from Concession 6, central Sirt Basin, Libya

The Sirt Basin contains most of Libya’s producing oil fields and is in northern Libya, south of the Gulf of Sirt in the Mediterranean Sea. The main aims of this study were to characterize the type of organic matter and depositional conditions of the source rocks and thermal maturity of the crude oils in this region using a variety of geochemical techniques including gas chromatography (GC), gas chromatography/mass spectrometry (GCMS), stable carbon and hydrogen isotopes, total organic carbon (TOC), and Rock Eval analysis. Twelve crude oil samples from Cambrian–Ordovician Gargaf, Upper Paleocene Zaltan, and Middle Eocene Gialo reservoirs and seventy-nine source rock samples representing Sirt Shale samples from nine wells were collected from the Zaltan Platform and surrounding troughs in the central Sirt Basin. Organic geochemical parameters indicate that these oils were sourced from marine organic matter deposited under oxic to suboxic conditions. The oils were divided into three groups based on their whole oil carbon and hydrogen isotopic composition and thermal maturity as manifested by several saturate and aromatic hydrocarbon maturity parameters. Based on the geochemical data, it is proposed that there are at least two sources for the crude oils in the Zaltan Platform area of the central Sirt Basin. The study also indicates that the Sirt Shale source rocks from Maradah Trough are dominated by marine organic matter and have reached the main phase of oil generation.

Assessment of oil potentials for humic coals on the basis of flash Py-GC, Rock-Eval and confined pyrolysis experiments

Confined pyrolysis experiments (gold capsules), quantitative flash pyrolysis-gas chromatography (Py-GC) and Rock-Eval analysis were performed on ten coals from the Junggar Basin and seven coals from the Kuqa Depression, Tarim Basin, northwestern China. The maximum yields of liquid components in confined pyrolysis experimnets (MCPΣC8+), which reflect oil potentials, have close correlations with the yields of n-alkanes + n-alkenes (FPΣn-C7+) in flash Py-GC, but have poor correlations with Rock-Eval QI ((S1 + S2)/TOC) values. Thus, oil potentials of coals can be better predicted on the basis of FPΣn-C7+ yields from flash Py-GC analysis. Coals with FPΣn-C7+ yield >10.4 mg/g TOC can generate MCPΣC8+ yield >∼22.5 mg/g TOC or oil yield >∼40 mg/g TOC in confined pyrolysis or in natural systems and are effective oil source rocks. Although both Py-GC and Rock-Eval are open systems, the yields of total liquid components (FPΣC7+) obtained from flash Py-GC have poor correlations with, and are substantially lower than, Rock-Eval QI. In contrast, FPΣC7+ values have much better correlations with oil potentials (MCPΣC8+). Coals with higher oil potentials (MCPΣC8+) generate higher amounts of liquid components detected in flash Py-GC (FPΣC7+) than those with lower oil potentials but similar Rock-Eval QI. The correlations for parameters with gas to oil ratios (GOR) in confined pyrolysis are increasingly better in the sequence of Rock-Eval QI, H/C atomic ratios, MCPΣC8+, FPΣn-C7+ and FPΣn-C7+/ΣC7+ ratios. GOR of petroleum generated from coals within oil generative window can be reasonably predicted on the basis of FPΣn-C7+/ΣC7+ ratio from flash Py-GC analysis.

Rock-Eval analysis and organic petrographical characterization of the Upper Jurassic Naokelekan Formation, northern Mesopotamian basin, Kurdistan Region-Iraq

The aim of this study is to assess the type, thermal maturity and the petroleum generation potential of the Upper Jurassic Naokelekan Formation, occurring across the Kurdistan Region of Iraq, by applying organic petrographical methods and Rock-Eval analysis. The Rock-Eval data would indicate the presence of kerogen types III, IV and II as the main constituents. However, the qualitative petrographical evaluation revealed that the main organic constituents are solid hydrocarbons, in the form of microgranular migrabitumens, with minor amounts of pyrobitumens. These secondary particles have affected the results of the Rock-Eval analysis and would have led to misinterpretation of organic matter typification based on pyrolysis results only. The combined results of petrography and pyrolysis indicate an active petroleum system within the Upper Jurassic sequence, where hydrocarbons are generated and reservoired within suitable lithologies.

Basin modeling of Late Cretaceous / Mio-Pliocene (.) petroleum system of the deep-water eastern Colombian Basin and South Caribbean Deformed Belt

Previous interpretation of 2D and 3D seismic reflection data have shown widespread, direct hydrocarbon indicators from deep-water successions of the eastern Colombian Basin (ECB) and adjacent South Caribbean Deformed Belt (SCDB) that suggest the presence of an extensive - but poorly defined - petroleum system. We integrate Rock-Eval analysis, seismic interpretation, and 1D/2D thermal and basin modeling to better understand the origin of gas chimneys and bright spots identified in the ECB. Our dataset consists of 36 Rock-Eval samples of Coniacian to Santonian source rocks from the DSDP well sites 153, 151, and 146 located in the Beata Ridge tied to a 270 km-long composite 2D seismic line covering the ECB. Rock-Eval analyses reveal intervals of immature source rocks containing 1) kerogen types II and III; 2) an average TOC of 3.70% with a maximum TOC of 11.4%; 3) an average HI of 241; and 4) an average OI of 124. Seismic interpretation reveals: 1) wedging of post-Coniacian, organic-rich successions from the Beata Ridge (35–73 m thick) towards the ECB (500–1700 m thick); 2) Late Cretaceous to Eocene slow sedimentation rate of 38 m/my, followed by faster Oligocene to Recent sedimentation rate of 149 m/my from the Magdalena River; and 3) Late Oligocene to Recent thrusting and propagation of the SCDB. Thermal and basin modeling show: 1) mature Cretaceous source rocks in the SCDB and ECB; 2) Miocene to Pliocene, Magdalena Fan-derived deltaic and turbiditic reservoir and seal rocks, and Plio-Pleistocene sealing mass transport deposits.; 3) Late Oligocene to present-day trap formation related to thrust front structures, compaction folds, and stratigraphic traps; 4) hydrocarbon expulsion since Pliocene times; 5) vertical and lateral up-dip seaward migration occurs in the ECB while a secondary landward migration takes place toward the SCDB; and 6) hydrocarbon accumulation and preservation may be affected by remobilization due to biodegradation in the ECB and trap breaching in the SCDB.

1D and 2D basin modeling, in evaluating the hydrocarbon generation-migration-accumulation potential, at coastal Fars Area, Southern Iran

One of the giant hydrocarbon generation zones in Iran has been developed in the south of the Zagros Mountain Range (i.e., South Zagros), located between the South Zagros and the Persian Gulf in a foreland basin known for high levels of exploration uncertainties (due to the presence of complex structures, multiple source layers, and migration pathways). In this basin, the Permotriassic formations provide for the main reservoir strata, while the hydrocarbon content is deemed to be derived from the “hot shales” of the Silurian-Ordovician Sarchahan Formation, serving as source rock. As the focus of the present research, the Coastal Fars region is developed along the shores of southern Iran and hosts a number of gas reservoirs that have been increasingly discovered since 1970. Developed in the Permotriassic siliciclastics and carbonates of the Faraghan, Dalan, and Kangan Formations, gas reservoirs have made the Coastal Fars a hot zone for exploration and production activities. In this research, one 2D and five 1D models of the basin (at five exploration wells) were constructed to evaluate the maturity of the main Silurian-Ordovician source rock and further investigate the hydrocarbon charge, timing, migration pathways, and accumulation sites. The models were then utilized to investigate the relationship between the presence of multiple shale layers and hydrocarbon content of the reservoir at one of the studied wells using Rock-Eval analysis. This study showed that an uplift that happened after the hydrocarbon generation has led to a dry hole in the study area. The results indicated that the Sarchahan Formation is probably the main source rock across the region, according to previous researches in this area its organic contents were dated back to the late Ordovician rather than the Silurian. The shale intercalations across the reservoirs (Kangan and Upper Dalan), especially in the Khayam Field, were found to produce more than 90% of their hydrocarbon generation potential. No non-indigenous hydrocarbon was identified across the study area, implying that the entire hydrocarbon content was generated by the identified source rocks. Laboratory analysis indicated the presence of type II and type III kerogen at a local heat flow rate of about 65 mW/m2 since the Cretaceous. In total, the Sarchahan Formation was found to reach a maximum burial depth of 6 km, making it matured to overmatured all over the study area.

A climate change event, detected in Viséan oil shales from Devon Island, Arctic Canada

Important depositional characteristics indicative of climate change has been discovered in 50-m sedimentary succession consisting of oil shales with a marlstone and carbonate matrix of the Viséan shales from the Lower Carboniferous Emma Fiord Formation on Devon Island, Canada's Arctic Archipelago. Older Carboniferous (Tournaisian) shales, are however absent from Devon Island, but elsewhere such as Big Marsh, Nova Scotia, Tournaisian shales show no comparable evidence for climate change.The techniques used include reflected light microscopy, RockEval analyses, instrumental neutron activation analysis (INAA) for elemental concentration.Indeed, Viséan shales from the Lower part the Emma Fiord Formation from Devon Island have a marlstone matrix with abundant algal matter. The matrix also has low carbonate (32%) and total organic carbon (TOC) content between 33.3%and 55.6%. Moreover, the TOC show a positive correlation with authigenic uranium, and Mo, which suggests a high productivity due to the high rain, deeper water lacustrine depositional environment. Other Viséan oil shales from the Emma Fiord Formation on Devon Island have somewhat different characteristics from those with marlstone matrix. Indeed, they have a high (75%) carbonate content with calcified algal matter and low TOC (1.14–17.4%). A very low correlation between TOC and authigenic U, and Mo. Most importantly very high oil generation (98–413 L/t) potential of marlstones as compared to low yield of carbonate mudstones (4.1–17.0 L/t) shows a dramatic climatic shift to low precipitation and much dryer conditions. Such a drastic climatic condition has not been detected for the Tournaisian oil shales.

Organic geochemistry of a lacustrine shale across the Toarcian Oceanic Anoxic Event (Early Jurassic) from NE China

Thirty-nine shale samples of the Lower Jurassic Beipiao Formation from drill core ZK01 in the Jinyang Basin, NE China were investigated by comprehensive organic geochemical methods in this study. A prominent negative excursion in δ 13 C org values (~ 2‰) was observed in the Beipiao Formation, which is most likely associated with Toarcian Oceanic Anoxic Event (T-OAE) negative carbon isotope excursion (CIE) that is recorded globally in marine and terrestrial sediments constrained by previous studies. Elemental and Rock-Eval analyses of Beipiao shales demonstrate that the total organic carbon (TOC) ranges from 0.56 to 4.33 wt% (average of 1.40 wt%) and S 2 values range from 0.12 to 6.91 mg/g (average of 1.3 mg/g) and implicate fair to good source rock potential. A majority of the T max values of the Beipiao shales range from 456 to 465 °C, indicating that the organic matter is within the mature oil window apart from few overmature samples with extreme high T max values that might have been affected by local magmatic intrusions. Elemental analysis suggests that the kerogens are mainly Type II-III. Unlike many marine organic-rich sediments deposited during OAEs, redox proxies indicate no significant upper water column oxygen-depletion during the formation of Beipiao lacustrine shale. The decreasing upward trend of organic source indicators such as tricyclic terpanes/C 30 hopane values, relative distributions of regular C 27 steranes to C 29 steranes, and steranes/hopanes in the Beipiao Formation consistently suggest a shift to a lower abundance of eukaryotic organisms relative to bacterial community abundance during the onset of the T-OAE. Meanwhile, gradually decreasing values of gammacerane/C 30 hopane in the Beipiao Formation during the negative CIE suggest decreasing salinity and increased mixing of the Jinyang paleo-lake system, potentially corresponding with the shift toward an accelerated hydrological cycle with enhanced fresh water input to this lacustrine system. Moreover, increasing C 30 moretane/C 30 hopane values contemporaneous with the negative CIE also suggest enhanced land erosion during putative Toarcian climatic warming, which could have increased delivery of riverine nutrients and elevated regional primary productivity, eventually resulting in massive organic matter accumulation in the Beipiao shales. • A prominent negative excursion in δ 13 C org values (~ 2‰) was observed in the Toarcian Beipiao lacustrine shale. • A shift to lower abundance of eukaryote relative to bacterial community in lacustrine system during the onset of the T-OAE. • Progressive accelerated hydrological cycle enhanced fresh water input and increased mixing of NE China lacustrine system. • The organic enrichment and good hydrocarbon generation potential resulted from enhanced delivery of riverine nutrients.