Source Rock Facies Research Articles

Linking source rock to expelled hydrocarbons using diamondoids: An integrated approach from the Northern Gulf of Mexico

Nanodiamonds (diamondoids) are the ideal geochemical tool for hydrocarbon-source correlation in high-maturity fields since they are thermally stable and outlast biomarkers (molecular fossils), which deteriorate with thermal maturity. Diamondoids form in the shallow subsurface as organic material reacts with clay minerals in source rock, thereby preserving information about the precursor organic compounds and parent minerals. The unique suites of diamondoids generated by these combinations allow direct linkage between expelled hydrocarbons and source rock facies. We compared diamondoid distributions obtained from oils produced from both Eagle Ford Fm. and Austin Chalk Fm. in South-Central Texas, to rock extracts taken from equivalent intervals in a cored pilot hole. The targeted well is in the gas window where biomarkers are of limited use. Diamondoid distributions from oils produced from laterals in the Eagle Ford Fm. and the Austin Chalk Fm. matched extracts from those formations, proving that local sourcing is recognizable in expelled hydrocarbons.A second phase of this project included a direct comparison of results from pilot hole extracts to diamondoids analyzed from 15 oils selected from producing Eagle Ford wells. We showed a close match between the diamondoid chemistry of produced oils regionally and source samples from the Eagle Ford Formation in the cored pilot well. However, samples from immediately adjacent formations (Buda and Upson) were discordant, containing higher concentrations and different distributions of diamondoids when compared to the Austin and Eagle Ford systems.These results spurred a third phase of investigation that included generating diamondoid data from extracts of known Mesozoic Northern Gulf of Mexico (NGoM) source rocks stratigraphically beneath the Austin and Eagle Ford system. These included the Aptian-Albian Pearsall group and several Jurassic formations (Oxfordian Smackover Fm., Kimmeridgian Haynesville Fm., and Tithonian Bossier Fm.). The outlier samples from phases 1 and 2 are matched with deeper source rocks when comparing their diamondoid geochemistry to those of extracts from cored Jurassic source samples. These Jurassic intervals and migration pathways were then vetted with seismic data and integrated attribute analysis.The results of this work show: 1.expelled hydrocarbons can be linked to parent source rock using diamondoid composition; 2. diamondoids can be used to discriminate co-sourcing in intervals where routine biomarker analyses would fail; 3. Samples of well-known Mesozoic source rocks in the northern Gulf of Mexico (Cenomanian-Turonian Eagle Ford Fm., Tithonian Bossier Fm., Kimmeridgian Haynesville Fm., and Oxfordian Smackover Fm.) can be independently recognized using diamondoids, and 4. seismic anisotropy and fluid escape attributes helped delineate both deep-seated, through-going faults and intervals of high fracture density, allowing for connectivity and migration from the deeper source rocks illuminated by diamondoid analyses.

Classical Biomarker and Quantitative Extended Diamondoid Analysis Fingerprints for Crude Oils from Deepwater Developments in Block 17, Lower Congo Basin, Angola.

The organic geochemistry of six oil samples from the offshore Block 17 (Lower Congo Basin, northwestern Angola) was studied by a combination of classical biomarker and extended diamondoid analyses to elucidate source rock facies, the extent of biodegradation, and thermal maturity. Based on molecular data, oils are interpreted as depicting a mixture of two pulses of hydrocarbon generation probably from the Bucomazi and Malembo formations. Geochemical results also gave evidence of mixing of a lacustrine siliciclastic-sourced oil charge and a second more terrestrially derived oil type in the samples analyzed. A single genetic oil family was identified through hierarchical cluster analysis; however, two groups of oils were identified on the basis of their biodegradation levels using the Peters/Moldowan scale. Lower and upper Malembo oils have a slight depletion and a notable absence of n-alkanes, suggesting PM levels of 1 and 2, respectively. Most molecular maturity parameters of the oil samples suggest a maturity level equivalent to the onset of the peak of the oil generative window.

Characterization of Late Cretaceous to Miocene source rocks in the Eastern Mediterranean Sea: An integrated numerical approach of stratigraphic forward modelling and petroleum system modelling

AbstractStratigraphic forward modelling was used to simulate the deposition of Upper Cretaceous, Eocene and Oligo‐Miocene source rocks in the Eastern Mediterranean Sea and, thus, obtain a process‐based 3D prediction of the quantity and quality distribution of organic matter (OM) in the respective intervals.Upper Cretaceous and Eocene models support the idea of an upwelling‐related source rock formation along the Levant Margin and the Eratosthenes Seamount (ESM). Along the margin, source rock facies form a narrow band of 50 km parallel to the palaeo shelf break, with high total organic carbon (TOC) contents of about 1% to 11%, and HI values of 300–500 mg HC/g TOC. On top of the ESM, TOC contents are mainly between 0.5% and 3% and HI values between 150 and 250 mg HC/g TOC. At both locations, TOC and HI values decrease rapidly towards the deeper parts of the basin. In the Oligo‐Miocene intervals, terrestrial OM makes up the highest contribution to the TOC content, as marine organic matter (OM) is diluted by high‐sedimentation rates. In general, TOC contents are low (<1%), but are distributed relatively homogenously throughout the whole basin, creating poor quality, but very thick source rock intervals of 1–2 km of cumulative thickness.The incorporation of these source rock models into a classic petroleum system model could identify several zones of thermal maturation in the respective source rock intervals. Upper Cretaceous source rocks started petroleum generation in the late Palaeocene/early Eocene with peak generation between 20 and 15 Ma ca. 50 km offshore northern Lebanon. Southeast of the ESM, generation started in the early Eocene with peak generation between 18 and 15 Ma. Eocene source rocks started HC generation ca. 25 Ma ago between 50 and 100 km southeast of the ESM and reached the oil to wet gas window at present day. However, until today they have converted less than 20% of their initial kerogen. Although the Miocene source rocks are mostly immature, Oligocene source rocks lie within the oil window in the southern Levant Basin and reached the onset of the wet gas window in the northern Levant Basin. However, only 10%–20% of their initial kerogen have been transformed to date.

Degradation-resistant biomarkers in the Pirambóia Formation tar sands (Triassic) and their correlation with organic facies of the Irati Formation source rocks (Permian), Paraná Basin (Brazil)

The Pirambóia Formation tar sands constitute one remarkable occurrence of heavy oil in the eastern border of the Paraná Basin, São Paulo State, Brazil, being characterized as highly degraded oils related to the Irati-Pirambóia oil system. In this context, the aim of the present work was to investigate biomarkers that are more resistant to degradation and use them to establish a more reliable geochemical correlation between the tar sand oils of the Pirambóia Formation (collected from the Fazenda Betumita and Guareí I outcrops) and the organic extracts of black shales of the Irati Formation (facies Irati A and B, collected in the Amaral Machado Quarry, São Paulo State). For this purpose, analysis of stable carbon isotopes and diagnostic ratios of saturated and aromatic biomarkers were investigated, and the most reliable diagnostic ratios were selected based on the principal component statistical analysis. The results pointed to different degradation extent between the tar sand outcrops, being higher for the Guareí I samples. In this scenario, it was verified that most of the diagnostic ratios commonly used in oil-source rock correlation studies were susceptible to degradation processes. It was also observed that samples from Pirambóia and Irati formations are at the beginning of the oil generation window, with the C29 ββ/(αα + ββ) ratio as the most suitable to assess thermal maturity of extremely degraded oils. The multivariate statistical analysis of the results, based on ten more resistant diagnostic ratios, allowed to select six main variables responsible for the similarity between the samples from the Irati and Pirambóia formations: δ13C (‰), TPP ratio (C30 tetracyclic polyprenoids over diasteranes), %C28 and %C29 monoaromatic steranes, (C20 + C21)/(C23 + C24) tricyclic terpanes, and C23 tricyclic terpane/(C23 tricyclic terpane + C29 hopane). These geochemical parameters showed greater reliability in the correlation between the Pirambóia Formation tar sand oils and the Irati samples of the facies A, deposited in a restricted marine environment under anoxic-euxinic conditions.

The use of heavy mineral chemistry in reconstructing provenance: A case study from Mesozoic sandstones of Kutch Basin, India

Petrography and geochemistry of the Mesozoic sedimentary rocks of the Kutch Basin in western India reveal the predominance of felsic source rocks. Single‐grain chemistry of the detrital heavy minerals in these sediments refines the existing provenance interpretations by incorporating additional data related to source lithology. The study presents information on type, composition, and metamorphic grade of the source rocks for the Mesozoics of the Kutch Basin, which comprises Jhurio, Jhumara, Jhuran, and Bhuj formations. Chemistry of rutile, garnet, and tourmaline supports multiple sources of sediments. The ratio between Cr and Nb in rutile suggests the dominance of sediment input from metapelites. The relationship between (Fe + Mn)–Mg–Ca in garnets and Ca–Fetotal–Mg in tourmalines indicates the dominance of Ca‐poor felsic metamorphic source along with intermediate‐acidic plutonic rocks. The multivariate discrimination of the detrital garnets reveals the dominance of granulite and amphibolite facies source rocks. Rutile compositions indicate subordinate inputs from mafic sources across the investigated sedimentary succession. The single‐grain analysis of heavy minerals, therefore, infers a wide variation in source rock types.

Hydrocarbon Uncertainty Based on Facies Analysis: Middle Jurassic Sequence (Jaisalmer Formation), Jaisalmer Basin, Rajasthan

Abstract The middle Jurassic transgressive limestone with intermitted fresh water clastic facies of Jaisalmer Formation contains reservoirseal assemblage with fair source rock potential, provide a target for exploration. Till date, very few exploration ventures have been made to explore this formation. The frontier exploration team need to address this sequence with possible accumulation pattern and migration pathways. The objective of current study is to focus on the prospectivity of Jaisalmer Formation that has been established from minor discovery of liquid and gaseous hydrocarbon. In the present study, an attempt has been made to establish the facies model that includes litho-micro-facies, bio-facies, source rock facies and depositional facies. This formation has been tested for hydrocarbon in several wells and in some of the well gas/oil has been flown with water. With exploration background in mind, a detailed examination of Jaisalmer Formation has been attempted in terms of its contribution to the exploration efforts in the basin.

Organofacies composition of Upper Jurassic – lowermost Cretaceous source rocks, Danish Central Graben, and insight into the correlation to oils in the Valdemar Field

Abstract The organic-rich marine shales of the Upper Jurassic - lowermost Cretaceous Farsund Formation are the main hydrocarbon source rocks for the Cretaceous chalk reservoir of the Valdemar Field (Danish North Sea). Geochemical analyses of oil extracts from core samples across the greater Valdemar Field show substantial heterogeneity of the reservoir oils, suggesting contribution from kitchen areas with source rocks of variable organofacies and thermal maturity. In order to better understand the source rock facies that charged the field, a refined organofacies characterization of the Upper Jurassic - lowermost Cretaceous marine shale source rock succession (Farsund Formation) in the Danish Central Graben was established. This organofacies characterization is based on integration of petrographic and geochemical data and demonstrates large variations in both the regional and local distribution of the organofacies at the sequence level in the shales within the Danish Central Graben. In addition, the organofacies characterization shows that the respective sequences in the succession may be represented by several organofacies at the same time. Part of the explanation to the heterogeneity in the oil types accumulated within the Valdemar Field may lie in the presence of different organofacies within the uppermost sequences (Vol-3 to Ryaz-1) in the three kitchen areas. Each organofacies presumable generates different types of oils and the variation in the relative proportions of the different organofacies likely determines the composition of the generated oils. One dimensional (1-D) maturity modelling at three pseudo-well locations, each representing a potential Farsund Formation kitchen, shows that all kitchens are in the main oil window and that mainly oil was expelled from the Volg-3 to Ryaz-1 sequences. Modelling indicates that (i) average values of TOC, HI, thickness and the kinetic model are the main controls on generation and expulsion of hydrocarbons; and (ii) by increasing these parameters, expulsion could also occur from the lower part of the succession.

Chapter 5 Interpretation of the origin and evolution of the Arabian Intrashelf Basin and the development of the Dhruma Atash, Tuwaiq and Hanifa sequences

Abstract This is the first of two chapters in which the data presented in the first four chapters of this Memoir are reviewed and interpreted. A summary cross-section across the basin from the Saudi outcrop to Abu Dhabi and the Tethyan margin is used to summarize the regional setting and sequences as interpreted in this Memoir. The key points illustrated by the summary cross-section are stated and discussed in the first part of this chapter. Two different interpretations for the eastern margin of the intrashelf basin are reviewed. In the first of these interpretations, the margin with the deeper waters of the Tethys Ocean shelf is adjacent to the intrashelf basin rim in Abu Dhabi, whereas in the second, preferred in this Memoir, a broad, shallow Tethyan shelf platform (200–300 km wide) extends from the intrashelf basin rim to the Tethys continental shelf edge. The implications of Late Jurassic exposure and erosion on the adjacent Tethyan shelf are discussed. The development of the Arabian Intrashelf Basin during the Callovian–late Oxfordian (the Tuwaiq Mountain Formation, the source rock and the Hanifa intervals and associated sequences) is interpreted and discussed with illustrations, including step-by-step facies maps. The interpretation integrates depositional, eustatic and tectonic factors in the evolution of the intrashelf basin. The interpretation in this Memoir is that the Arabian Intrashelf Basin began with isostatic and extensional subsidence on top of a broad Dhruma Atash Member platform, which had largely filled the accommodation space up to the wave base and to near sea-level. It developed fully into an intrashelf basin during the deposition of the Callovian Tuwaiq sequence, with rising sea-levels coincident with a productive shallow water carbonate factory resulting in a rim of shallow water carbonate. An end-Callovian to early Oxfordian lowstand terminated the Tuwaiq sequence on the basin rim. During the lowstand, restricted conditions in the basin deposited the rich Lower Hanifa source rock as a lowstand systems tract. As more normal conditions returned in a subsequent sequence, the source rock facies graded upwards into Hanifa reservoir facies, which partially filled the basin. Hanifa progradation was terminated by another lowstand during which a subaqueous gypsum/anhydrite marker bed was deposited in at least part of the remnant basin. Earlier interpretations of these sequences are also discussed.

About this title - The Middle and Late Jurassic Intrashelf Basin of the Eastern Arabian Peninsula

This Memoir provides a thorough regional synthesis of the geology of the rimmed Arabian Intrashelf Basin, reconciling differing interpretations of lithostratigraphy, sequence stratigraphy and biostratigraphy. Variation of energy levels and facies due to its setting in the SE palaeotradewind belt are described. The intrashelf basin formed during rising sea level as a single rimmed carbonate intrashelf basin. A possible global cooling phase resulted in a lowstand which restricted the basin, resulting in petrographically unique carbonate source rock facies dominated by cyanobacterial deposition. Two subsequent third-order carbonate sequences largely filled the basin. Eustatic change concomitant with uplift of the Tethys shelf resulted in alternation of carbonates and evaporites (gypsum-anhydrite) across the region. The end result was a sealed intrashelf basin which preserved early formed porosity and confined generated hydrocarbons within the intrashelf basin facies.

Sedimentology and hydrocarbon potential of the Late Ordovician glacial deposits on the Arabian Platform and Southeastern Turkey

The Late Ordovician glacial deposits are widespread and constitute a significant portion of the Early Paleozoic stratigraphic sequence of the cover rocks of the Arabian and African platforms. The glaciation lasted less than one million years between the Late Ashgillian (445 Ma) and Early Silurian (444 Ma) but it had a strong impact on the whole area. It has been proven that the glaciofluvial sandstones form important oil and gas reservoirs in Saudi Arabia and in North African and other Middle Eastern countries, including SE Turkey, but their heterogeneity and internal lithofacies characteristics have not been fully understood yet. In Saudi Arabia the hydrocarbon-producing glacial paleovalley systems forming the Sarah Formation extend 70 km in the W-E direction. In southern Turkey, similar glacial paleovalleys, defined as the Yurteri Formation, extend in a NW-SE direction. It consists of massive, well-sorted, porous reservoir sandstones of good quality and produces significant amounts of oil and sweet gas in SE Turkey. When the glaciation ceased in the Early Silurian time, the ice mass melted and released large volumes of water into the oceans. Returning waters resulted in rapid sea-level rise and onlap relations across the platforms. This widespread marine transgression deposited organic-rich, potential source-rock hot shale facies directly on the good-quality glaciofluvial reservoir sandstones. This publication is based on intensive outcrop and subsurface studies on the core samples of the reservoir sandstones and the source-rock shale facies in every part of Saudi Arabia and SE Turkey. These studies clearly indicated the hydrocarbon potentials of the Late Ordovician glaciation formed on the Gondwana plate. The aim of this paper is to demonstrate the presence of a close genetic relationship between the glaciofluvial reservoir sandstones and overlying hot shale source-rock facies and downward migration of oil and gas into the underlying porous sandstones mainly due to hydrostatic pressure.

Petroleum geochemical aspects of the Mandawa Basin, coastal Tanzania: the origin of migrated oil occurring today as partly biodegraded bitumen

The shallow-marine Upper Jurassic–Lower Cretaceous sedimentary successions of the Mandawa Basin, coastal Tanzania, are located about 80 km away from the offshore gas discoveries of Block 2, Tanzania. In this paper we present petroleum geochemical data, including bitumen extracted from outcrop samples which are relevant to the understanding of the onshore ‘Petroleum System’ and possibly also to the offshore basin. Despite some biodegradation and weathering, common to all outcrop samples, most bitumen samples analysed contain mature migrated oil. The maturity span of geomarkers (C 13 –C 15 range) covers the entire oil and condensate/wet gas window ( R c = 0.7–2% R c , where R c is the calculated vitrinite reflectance), with the biomarkers generally indicating the oil window ( R c = 0.7–1.3% R c ). This suggests that the bitumen extracts represent several phases of migrated oil and condensate, which shows that the samples are part of an active or recently active migration regime or ‘Petroleum System’. The source-rock facies inferred for the bitumen is Type II/III kerogen of siliciclastic to carbonate facies. This is oil-prone kerogen, typical for a marine depositional system with an influx of proximal-derived terrigenous material blended in with in situ marine algal organic matter (OM). Application of age-specific biomarkers such as the C 28 /C 29 -steranes, extended tricyclic terpane ratio (ETR), nordiacholestanes and the aromatic steroids suggest that more than one source rock have contributed to the bitumen. Possible ages are limited to the Mesozoic (i.e. excluding the Late Paleozoic), with the most likely source rock belonging to the Early Jurassic. More geochemical and geological studies should be undertaken to further develop the general understanding of the petroleum system of the Mandawa Basin and its implications to the ‘Petroleum Systems’ both offshore and onshore. This paper also presents a reinterpretation of published gas composition and isotope data on the Pande, Temane and Inhassoro gas fields (Mozambique) with implications for possible oil discoveries in the gas-dominated region.

Oil-Source Rock Correlation Of Oil Seepage And Rock Samples Collected From The Cibulakan Formation At Palimanan Area, West Java

This paper presents the results and discussion of a petroleum geochemistry study performed on two oil seepage and seven outcrop samples collected from the Cibulakan Formation at Palimanan area, West Java. The presence of two oil seepages in Palimanan area indicates that there is an effective source rock which has produces hydrocarbon. The objectives of the study were to determine the hydrocarbon source potential of outcrops, and to characterise selected rock extracts and oil seepage samples, and determine the progenitor source facies at time generation/expulsion. The method used in this research is field study and laboratory analysis. Field studies were conducted on oil and rock sampling, while the geochemical laboratory analysis includes Total Organic Carbon, Rock-Eval Pyrolysis, Vitrinite Reflectance, Kerogen Typing, Bitumen Extraction, Liquid Chromatography, Gas Chromatography fingerprint and GC-MS biomarker. The oil-source rock correlation to its oil based on GC fingerprint (n-alkane distributions) and GC-MS biomarker (triterpanes and sterane distributions) has been done. The oil seepage is correlated with possible source rocks from the Cibulakan Formation. Based on the n-alkane distribution the oil seepage showed biodegradation, but based on the biomarker distributions, it is interpreted that the oil seepage have been generated from a source rock facies containing mainly non-marine algal debris (Type II Kerogen) mixed with some input from terrestrial higher plant organic matter (Type III Kerogen). The oil seepage shows a moderately good correlation with the rock extracts based on GC-MS biomarker data. These biomarker parameters has been successfully used to determine the origin of oil with its precursor source rock by correlating the rock extracts to possible source rocks in the oil and gas exploration.

Genetic type and source of natural gas in the southern margin of Junggar Basin, NW China

Abstract Natural gas has been discovered in many anticlines in the southern margin of the Junggar Basin. However, the geochemical characteristics of natural gas in different anticlines haven't been compared systematically, particularly, the type and source of natural gas discovered recently in Well Gaotan-1 at the Gaoquan anticline remain unclear. The gas composition characteristics and carbon and hydrogen isotope compositions in different anticlines were compared and sorted systematically to identify genetic types and source of the natural gas. The results show that most of the gas samples are wet gas, and a few are dry gas; the gas samples from the western and middle parts have relatively heavier carbon isotope composition and lighter hydrogen isotope composition, while the gas samples from the eastern part of southern basin have lighter carbon and hydrogen isotope compositions. The natural gas in the southern margin is thermogenic gas generated by freshwater-brackish water sedimentary organic matter, which can be divided into three types, coal-derived gas, mixed gas and oil-associated gas, in which coal-derived gas and mixed gas take dominance. The Jurassic coal measures is the main natural gas source rock in the southern margin, and the Permian lacustrine and the Upper Triassic lacustrine-limnetic facies source rocks are also important natural gas source rocks. The natural gas in the western part of the southern margin is derived from the Jurassic coal measures and the Permian lacustrine source rock, while the natural gas in the middle part of the southern margin is mainly derived from the Jurassic coal measures, partly from the Permian and/or the Upper Triassic source rocks, and the natural gas in the eastern part of the southern margin is originated from the Permian lacustrine source rock. The natural gas in the Qingshuihe oil and gas reservoir of Well Gaotan-1 is a mixture of coal-derived gas and oil-associated gas, of which the Jurassic and Permian source rocks contribute about half each.

The characteristics and hydrocarbon-generation model of Paleogene\u2013Neogene System saline lacustrine facies source rocks in the Western Qaidam Basin, China

To further understand the characteristics and hydrocarbon-generation model of Paleogene–Neogene System salt-lake facies source rocks in the Western Qaidam Basin, selecting argillaceous source rock samples from the Lower Ganchaigou Formation, the Upper Ganchaigou Formation, and the Upper Youshashan Formation in the Western Qaidam Basin, relevant experimental studies have been carried out, including pyrolysis of rocks, analysis of soluble components, and simulation of hydrocarbon generation and expulsion. According to the analysis of the experimental results, the selected sample thermal evolution degree stays in the low-mature–immature stage and shows good hydrocarbon-generation ability. There was a positive correlation between chloroform bitumen “A,” moderate salt content and carbonate content, and cumulative liquid hydrocarbon production. The hydrocarbon-generation peaks of the Paleogene–Neogene salt-lake facies source rocks in the Western Qaidam Basin are significantly advanced compared to the traditional model. The result clearly defines the hydrocarbon-generation model of Paleogene–Neogene salt-lake facies source rocks in the study area, which is important to direct the oil and gas exploration in the Western Qaidam Basin.

Evaluation of hydrocarbon potential, quality of source rock facies, and delineating of their depositional environment in Mamu Formation of Anambra Basin, Nigeria

This investigation was carried out by collecting a total of six shale samples from two exposures of Mamu formation in Enugu and Igarra for geochemical analysis for investigation of source rock potential and environment of deposition. The values of TOC (1.79-3.16wt %) and SOM (1450 – 1625ppm) reveals that the shale of Mamu at the two locations are good – very good source rocks. The plot of hydrogen index against oxygen index and TOC against petroleum genetic potential shows both type III and IV kerogen indicating a gas prone and inert kerogen content. The values of Tmax ranges from (390 O c – 437 O C) suggesting that the source rock is immature to early thermally mature. Finally, the cross plot of TSC against TOC confirms a normal marine depositional environment for the samples collected at both locations. Keywords: Hydrocarbon Potential, Environment of Deposition, Mamu Formation, Cross Plot

Integrated Cretaceous stratigraphy of the Cauvery Basin, South India

Cretaceous sequences of the Cauvery Basin, South India, can serve as an analogue to understand the subsurface successions with proven potential for commercial hydrocarbon exploration. In this area, the distribution of hydrocarbon reservoir and source rock facies was profoundly influenced by relative sea level changes amplified by rifting and related tectonic activities. Of particular interest are the sedimentary strata exposed in mines, quarries and outcrops around the Ariyalur area of Tamil Nadu, that mirror subsurface strata. This study reviews and integrates the stratigraphic studies based on this area and published over the past three decades. In particular, we concentrate on lithological features, macrofossils, microfossils, ichnofossils, magnetic polarity and sequence stratigraphy to reveal the geologic history of the Cauvery Basin. Age control, paleoenvironmental interpretations, paleobathymetry, paleoecology and paleotemperature are based on ammonites, belemnites, brachiopods, mollusks, nannofossils, and foraminifera. Key results include an integrated stratigraphic framework, paleobathymetry and sea level history that shows seven second/third-order depositional sequences, and major sea level falls during the late Turonian and late Maastrichtian linked to the Marion and Reunion mantle plumes, respectively.

PARATETHYAN PETROLEUM SOURCE ROCKS: AN OVERVIEW

The Paratethys area extends from Central Europe to the borders of the Caspian Sea in Central Asia and hosts a significant number of petroleum provinces, many of which have been charged by Eocene to Miocene source rocks of supra‐regional significance. These include highly oil‐prone Middle Eocene marls and limestones in the Eastern Paratethys (Kuma Formation and equivalents) which are several tens of metres thick. Estimates of the source potential index (SPI) indicate that the Kuma Formation in the northern Caucasus and the Rioni Basin (Georgia) may generate 1 to 2 tons of hydrocarbons per square metre (tHC/m2). This implies that the Kuma Formation may also be an important and additional source rock in the eastern Black Sea.Oligocene and Lower Miocene pelitic rocks (Maikop Group and equivalents) are considered to be the most important source rocks in the Paratethys. Vertical variations in source potential record different stages of basin isolation that reached a maximum during the Early Oligocene (NP23) Solenovian Event. However major variations exist between different sub‐basins in the Central and the Eastern Paratethys. In the Central Paratethys, the highest quality source rocks occur in the Carpathian Basin where the Menilite Formation, several hundreds of metres thick, can generate up to 10 tHC/m2. Locally the Menilite Formation is about 1500 m thick and continues into the Lower Miocene. In these settings, the Menilite Formation can generate approximately 70 tHC/m2. In the Alpine Foreland Basin (Schöneck and Eggerding Formations) and the Pannonian Basin (Tard Clay Formation), oil‐prone source rocks are restricted to the Lower Oligocene. In the Eastern Paratethys, the best source rock intervals of the Maikop Group are typically associated with the Early Oligocene Solenovian Event. By contrast, with the exception of the Kura Basin in Azerbaijan, the potential of Upper Oligocene and Lower Miocene rocks is often limited. In total, the Maikop Group may generate up to 2 tHC/m2 in the North Caucasus area and 4 tHC/m2 in the Rioni Basin.A particular source rock facies is found in the Western Black Sea where diatomaceous rocks with good oil potential accumulated in the Kaliakra Canyon during Early Miocene time. This facies may generate up to 8 tHC/m2, but is probably limited to shelf‐break canyons.Middle and Upper Miocene rocks are the main source for oil and thermogenic gas in the Pannonian Basin System, and also contributed to thermogenic hydrocarbons in the Moesian Platform and the South Caspian Basin. In addition, Upper Oligocene and Miocene rocks are the source for microbial gas in several basins including the Alpine and Carpathian foredeeps.

PETROLEUM SYSTEMS IN THE AUSTRIAN SECTOR OF THE NORTH ALPINE FORELAND BASIN: AN OVERVIEW

Two separate petroleum systems have been identified in the Austrian sector of the North Alpine Foreland Basin: a lower Oligocene – Cenomanian/Eocene oil and thermogenic gas system; and an Oligocene‐Miocene microbial gas system. Recent studies by both academic and industry‐based research groups have resulted in an improved understanding of these petroleum systems, which are reviewed in this paper.Lower Oligocene organic‐rich intervals (up to 12 %TOC; HI: 400–600 mgHC/gTOC), capable of generating slightly more than 1 t of hydrocarbons/m2, are the source rocks for the thermogenic petroleum system in the Austrian sector of the North Alpine Foreland Basin. The present‐day distribution of this source rock is controlled by submarine mass movements which removed a large part of the organic‐rich interval from its depositional location during the late early Oligocene. The transported material was redeposited in locations to the south which are at the present day buried beneath Alpine thrust sheets. In addition, source rock units were incorporated into Molasse imbricates during Alpine deformation. Hydrocarbon generation began during the Miocene, and the oil kitchen was located to the south of the Alpine thrust front. Hence, lateral migration over distances of up to 50 km was required to charge the mainly Eocene and Cenomanian non‐ and shallow‐marine sandstone reservoir units. Hydrocarbons are in general trapped in structures related to east‐west trending normal faults, and differences in source rock facies resulted in the development of separate western and eastern oil families. Surprisingly, with the exception of some fields in the eastern part of the study area, associated gas contains varying (and sometimes very high) percentages of primary and secondary microbial methane. The composition of oil in some fields is influenced by both biodegradation and water washing. Post‐Miocene uplift in the Austrian sector of the basin had further effects on biodegradation and the consequent formation of secondary microbial gas, and also resulted in re‐migration.The upper Oligocene to lower Miocene succession (Puchkirchen Group, Hall Formation) provides both source and reservoir rocks for the microbial petroleum system in the Austrian sector of the North Alpine Foreland Basin. TOC contents (<1.0 %) and HI values (<140 mgHC/gTOC) of pelitic source rocks are typically low. Microbial gas was generated shortly after deposition during early diagenesis and was subsequently fixed in gas hydrates. Basin subsidence and high sedimentation rates resulted in decomposition of the hydrates below their stability zone, and reservoirs were filled during the early Miocene. Subsequent mixing of microbial gas with thermogenic gas and condensates is widespread. However, biodegradation has prevented precise determination of the fraction of thermogenic hydrocarbons present in gas samples. Reservoir sandstones were deposited within a deep‐marine channel belt along the axis of the North Alpine Foreland Basin, and reservoir quality depends on the precise position within this belt. In the study area, gas is trapped in compaction anticlines or at channel margin pinch‐outs and additional traps are formed by imbrication structures.

Gas generation and its isotope composition during coal pyrolysis: Potential mechanism of isotope rollover

Recent studies on both conventional (thermogenic gas) and unconventional (shale gas) gases show comparable carbon/hydrogen isotope rollover, i.e., before the rollover point, carbon/hydrogen isotope increases with increasing thermal maturity (or decreasing gas wetness), while after the rollover point, the gas component (i.e., ethane, propane, etc.) becomes more depleted in 13C or 2H with increasing thermal maturity. In order to further investigate potential mechanism of the isotope rollover, combined with previous researches on isotope rollover, this study carried out two batches of pyrolysis experiments on a low mature coal sample from the Songliao Basin, China at constant temperatures for about 72 h under the condition with added water and without added water. The results demonstrate that carbon and hydrogen isotope rollover of ethane and propane started at 500 °C, no matter with added water or without added water. Combined with previous studies on gases of various origins, it is found that such isotopic anomalies were a common phenomenon at high thermal mature stage, despite of what kind of the source rocks and whether adding water or not under the laboratory condition. This is likely caused by the mixing of gases directly from the decomposition of macromolecule of kerogen and those from the tightly entrapped straight-chain species in kerogen at relatively high thermal mature stage. These straight-chain species are normally entrapped in the kerogen, and will probably be released at high thermal maturation stage. Marine facies source rocks from southern China also demonstrate the existence of such tightly entrapped hydrocarbons at very high thermal maturity. The results may have important significance on the gas exploration at relatively high mature stage and have a guidance on the gas production changes during the exploration.

Paleofacies of Eocene Lower Ngimbang Source Rocks in Cepu Area, East Java Basin based on Biomarkers and Carbon-13 Isotopes

The Eocene Lower Ngimbang carbonaceous shales are geochemically proven hydrocarbon source rocks in the East Java Basin. Sedimentary facies of source rock is important for the source evaluation that can be examined by using biomarkers and carbon-13 isotopes data. Furthermore, paleogeography of the source sedimentation can be reconstructed. The case study was conducted on rock samples of Lower Ngimbang from two exploration wells drilled in Cepu area, East Java Basin, Kujung-1 and Ngimbang-1 wells. The biomarker data include GC and GC-MS data of normal alkanes, isoprenoids, triterpanes, and steranes. Carbon-13 isotope data include saturate and aromatic fractions. Various crossplots of biomarker and carbon-13 isotope data of the Lower Ngimbang source samples from the two wells show that the source facies of Lower Ngimbang shales changed from transitional/deltaic setting at Kujung-1 well location to marginal marine setting at Ngimbang-1 well location. This reveals that the Eocene paleogeography of the Cepu area was composed of land area in the north and marine setting to the south. Biomarkers and carbon-13 isotopes are powerful data for reconstructing paleogeography and paleofacies. In the absence of fossils in some sedimentary facies, these geochemical data are good alternatives.