Diagenesis plays a crucial role in carbonate reservoir properties, for example through the dissolution or precipitation of carbonate minerals, with burial history and fluid migration thought to play an important role in the timing of these events. To better understand these relationships and the local manifestation of regional events, we study carbonate sedimentary rocks and associated diagenetic cements from the Loppa High and Finnmark Platform using in-situ U-Pb carbonate geochronology and C-O stable isotope ratios, combined with burial history modelling. The results indicate a complex history of diagenesis: analyzed dolomicrite samples from the Loppa High typically yield ages that are older than their biostratigraphic age, in contrast to dolomicrite samples from the Finnmark Platform that yielded younger ages; this regional offset may be reflective of different styles of early diagenesis, as well as heterogeneous and re-deposited origin of some studied materials. While many diagenetic calcite cements coincide with modelled burial or uplift events, other events have no cements associated with them, although the possibility that some diagenetic carbonate phases were unsampled cannot be ruled out. Some calcite cements are not associated with burial events at all and may instead be related to hydrocarbon ‘charging’, supported by strongly negative δ13C values recorded in these cements. Broadly, these results highlight the value of integrating petrographic observations, burial history modelling, carbonate U-Pb geochronology, and C-O isotope ratios, as well as the complexity of untangling diagenetic histories.

The Loppa High is a subsurface structural high located in SW Barents Sea flanked by regional fault complexes where many hydrocarbon discoveries have been made along its peripheries during recent years. Since the petroleum exploration started in the late 1970’s, extensive studies have been undertaken giving a good understanding of the subsurface stratigraphy and the presence and maturation of hydrocarbon sources, fluid migration processes into hydrocarbon traps and seabed seeps. Many shallow gas anomalies are observed in this region due to fluid migration from the deeper reservoirs. Taking advantage of modern echo sounder and sonar technology, a more precise mapping of shallow subsurface became possible as well as detection of seafloor seeps to be inspected and sampled by advanced ROV technology. Presence of thermogenic hydrocarbons in seeps would indicate remobilisation from reservoirs in the subsurface that remained after the Late Paleogene/Neogene tectonism and the Pleistocene glacial rebound. Results of multibeam echosounder mapping of selected areas have been used to select seep sites for detailed investigation using ROV’s, and HUGIN AUV equipped with synthetic aperture sonar (HISAS), methane sniffers and optical cameras. This has aided the selection of optimal sampling sites and the collection of a large amount of sample material including seeping fluids, carbonate crusts and sediments which has been used for geochemical characterization and geochronology. Here, we present the evidence of the hydrocarbon migration and seepage from reservoirs mainly of deep thermogenic origin and altered by shallow storage during and after glaciation. The thermogenic signature of the seeping fluids indicates the long term and large-scale supply of methane to the global methane budget also from similar areas of potential natural leakage from the subsurface to the water column.

Lower Paleozoic source rock (SR) characteristics and paleo-depositional environments are not well understood in the Barents Sea region. Organic and inorganic geochemical analyses of 17 carbonaceous samples from the Lower Cambrian Tokammane Formation, the Lower to Middle Ordovician Kirtonryggen and Valhallfonna formations in Ny Friesland, north-east Spitsbergen, show that there is a striking difference in petroleum generation potential and bulk geochemical properties between the Cambrian and Ordovician samples, and also within the Ordovician samples. TOC contents of <0.20 wt% for the Lower Cambrian Tokammane Formation samples indicate poor source rock richness. TOC contents in the range between 0.3 and 2.1 wt% and HI values between 123 and 424 mg HC/g TOC for the Valhallfonna and Kirtonryggen formation samples suggest significant variation in remaining petroleum generation potential with oil-prone (Type II) to mixed oil-and gas-prone (Type II/III) kerogen. Source rock maturity parameters such as Tmax (range 435-449 degrees C) and production indices for most Ordovician samples suggest relatively uniform maturity levels, ranging from the early-, to the peak-, of the oil generation window (i. e. ca. 0.70-0.85% Ro). This maturity level could have significant implication on the original petroleum potential assuming early generation from carbonate source rocks. Bulk carbon isotope data show that the Lower Cambrian Tokammane Formation samples are heavier (613C range from-28.4 to-28.8%o) than the Lower to Middle Ordovician Valhallfonna Formation samples (613C range from-29.7 to-30.9%o). The differences in the source rock richness and kerogen type within the Ordovician samples are attributed to organic facies variation. Tentatively, three categories of source rock organic facies (B, BC and C) are supported based on assumed-initial hydrogen index values for the Ordovician samples. The reliability of the indicated organic facies could be supported by addition of biomarker data from bitumen extracts. To our knowledge, this is the first study revealing the existence of a potential Lower Paleozoic source rocks in this part of the High Arctic, and this facies may also exist on the continental shelf to the north and NE.

A late Carboniferous to early Permian carbonate and evaporite succession from the Finnmark Platform (southern Barents Sea) contains nodules of anhydrite partially to fully replaced by calcite spar and native sulfur genetically linked to hydrocarbon migration and/ or oxidation, analogous to processes observed in salt diapir caprocks in the Gulf of Mexico. In situ U-Pb dating of this calcite spar therefore has the potential to directly date hydrocarbon migration and provide further insight into the geochemical and temperature conditions during this event when coupled with traditional stable and clumped isotope ratios (delta C-13, delta O-18, and Delta 47). Results indicate calcite formed ca. 50-15 Ma, postdating host-rock deposition by 250-285 m.y. Strongly negative delta C-13 values in the calcite spar (mean = -15 parts per thousand) are consistent with a major contribution of carbon from hydrocarbons, and.47 paleothermometry indicates a mean precipitation temperature of 46 +/- 11 degrees C. These geochemical results are consistent with the local burial history and suggest protracted hydrocarbon migration and/or oxidation and caprock formation spanning similar to 35 m.y.

Determining the thermal maturity and the charge history of crude oil to any reservoir, has key implications for understanding petroleum generation, accumulation history and hence identification of exploration potential. In this paper we combine studies of several source rock sequences and associated crude oils using quantitative component concentration data in addition to traditional molecular marker ratio parameter approaches. The case history studies include examination of organic-rich sapropelic marine source rocks from the Second White Speckled Shale Formation (2 WS Fm.), in the Western Canada Sedimentary Basin and the upper Jurassic Draupne Fm. in the North Sea and their related oils. Each molecular component in the petroleum has a unique concentration evolution curve during source rock maturation, in which n-alkanes, light aromatic hydrocarbons and diamondoid hydrocarbons increase in concentration with increasing maturity, while biomarkers decrease in concentration with maturity. This maturity dependent concentration variation plus the ubiquitous mixing of multiple oils in the reservoir is a key process that complicates the direct application of qualitative molecular marker ratio approaches to analysis of petroleum systems. We suggest an alternative maturity assessment approach using maturation calibrated curves of absolute concentrations of biomarkers and other alkanes in petroleum, coupled with selected aromatic hydrocarbon ratios to track the maturity/petroleum mass fraction relationships for a reservoired oil mixture in a more complex but realistic manner. Isoprenoid alkanes show less variation in concentration with maturity than other components and may be used as an internal reference point for mass fraction maturity and charge history assessment. Using component concentration data normalized to the concentration of the isoprenoid alkanes and calibrated using source rock analyses at different maturity levels from a single petroleum system (2WS), a simple mass balance model was constructed that allowed aggregate concentration data to be calculated for any mixture of oils produced in a prescribed oil charge history. In principle any charge history can be simulated using this approach and comparing the modelled and actual quantitative compositional profiles of crude oils allows differentiation of the more plausible and implausible oil charge histories for that particular reservoir. Clearly considerable refinement of this approach is needed but it appears that such a procedure has the potential, if developed further, to be a useful addition to the arsenal of petroleum geochemists and basin modelers. Knowing what a typical complete charge mass fraction maturity profile would look like for a given source rock type, enables the estimation of missing charge in the basin, allows the detection of complex multi-history charge scenarios, and provides a much more robust and complete data set for calibration of basin model charge history assessments. It also, with further development may be integrated into stochastic basin modelling approaches to study petroleum systems.

Abstract The Triassic Boreal Ocean was a shallow epicontinental basin and the sink of the World's largest delta plain known to date. Nutrient and freshwater supply from this delta have been regarded as important causes for high productivity and water mass stratification, forming Middle Triassic oil‐prone source rocks. Recent studies attribute upwelling and a productivity‐induced oxygen minimum zone as important factors. A multi‐elemental chemostratigraphic study of a Spathian–Carnian mudstone succession exposed in eastern Svalbard was performed to investigate their formation. This includes 89 samples from three localities, from which 34 elements were acquired using combustion and X‐ray fluorescence analyses. The goal is to provide a correlation framework and infer the role of productivity, redox and water mass restriction on organic matter accumulation and source rock formation. These processes had major impact on the source potential. The Spathian Vendomdalen Member suggests deposition during intermittent benthic euxinia and low productivity, corresponding with a reported deep thermocline that obstructed upwelling. The lower Anisian lower–middle Muen Member shows negligible enrichment in redox‐sensitive elements but in situ phosphate nodules, consistent with developing upwelling and moderate productivity. The middle Anisian upper Muen Member formed during high productivity and phosphogenesis and is linked with basin‐wide upwelling. Productivity, phosphate and redox proxies are all strongly enriched in the upper Anisian–Ladinian Blanknuten Member. In the south‐western Barents Sea, the pro‐deltaic environment of the emerging Triassic Boreal Ocean delta system had terminated these conditions. The upper Ladinian upper Blanknuten Member formed within intermittent euxinic bottom waters due to the shallowing sea level. The Carnian Tschermakfjellet Formation marks the dominance of the prograding delta system and the end of Triassic oil‐prone source rock formation in Svalbard.

A range of geochemical data has been used to navigate the complexity of systems that build critical energy resources. Society’s need for hydrocarbons and metals are among these resources. However, petroleum and ore deposits are traditionally studied as two completely different disciplines in geoscience. We argue that they share a common heritage, or at a minimum an intersection in that the source rocks for oil also present source rocks for metals in sedimentary basins. In this presentation, we demonstrate the value of merging the study and teaching of these two disciplines: petroleum geology and ore deposit geology associated with sedimentary basins. We present several possibilities, for example, (1) the hydrothermal fluid may be the hydrocarbon-carrying fluid, and (2) mixing of a hydrocarbon-bearing fluid with a metalliferous brine may precipitate sulfide intermingled with oil. The end locations for the two resulting resources, however, may be spatially displaced from one another. Using a petroleum discovery from the Barents Sea as an example, we will illustrate the intimacy between metal and hydrocarbon deposition, and we will show petrographically the episodic, locally catastrophic events that formed the two resources in the same space. We will show critical relationships between replacement textures and explosive overpressure textures, the latter leading to capture of chalcedony-oil and barite-oil emulsions. We will show sulfide veins with visible oil inclusions. Sphalerite-galena-fluorite are all critical players. Our results highlight poorly understood infusions of sphalerite, co-mingled with oil, residing in biogenic carbonate rocks. Further, from the perspective of ore geology, our interpretations challenge classic replacement textures in some ore-forming environments. Seemingly abrupt changes in sulfide mineralogy, or the switch to oxide minerals, may be violent rupture of earlier sulfides by catastrophic fluid ingress and infilling with a new mineralogy – rather than passive replacement as is the common interpretation. Designing strategic sampling in these complex environments often requires many analyses to build a forest of persuasive evidence to inform exploration models. Reliance on small or isolated data sets may lead to highly erroneous interpretations. Application of Re-Os geochronology and trace element geochemistry places fluid compositions in a time context, useful in both petroleum and sulfide settings. At the same time, this information distinguishes slow continuous deposition from small catastrophic events during construction of petroleum and ore systems. Long-term investment of industry in resource-related research rewards all parties, with the common goal of meeting the needs of society and expanding the technologies that will give humanity a more sustainable future. Cross-disciplinary approaches, marrying metals and hydrocarbons, will be essential for efficient exploration and advancement of resource knowledge. Funding – Partial funding for this project was provided by Lundin Energy Norway. Colorado State University-Geosciences provides no funding for the personnel and operation of the AIRIE Program and its Re-Os laboratories.

The Barents Sea basin is an oil and gas province containing more than 760 million tons of oil equivalents. The reservoir geology of the Barents Sea is complex due to multiple episodes of subsidence, uplift and erosion, which opened a network of extensional and wrench related faults allowing for fluid migration. The multifaceted geological history complicates efforts to describe the source and characteristics of natural gas in the subsurface Barents Sea. Here we apply stable isotopes, including methane clumped isotope measurements, to thirteen natural gases from five (Skrugard Appraisal, Havis, Alta, Filicudi, and Svanefjell) reservoirs in the Loppa High area in the southwestern Barents Sea to estimate the origins of methane. We compare estimates of methane formation temperature based on clumped isotopes to thermal evolution models for the region. We find that the methane has diverse origins including microbial and thermogenic sources forming and equilibrating at temperatures ranging from 34–238°C. Our clumped isotope temperature estimates are consistent with thermal evolution models for the area. These temperatures can be explained by gas generation and expulsion in the oil and gas window followed by isotopic re-equilibration in some reservoirs due to microbial methanogenesis and/or anaerobic oxidation of methane. Gases from the Skrugard Appraisal, Havis and Alta have methane equilibration temperatures consistent with maximum burial temperatures, while gases from Svanefjell have methane equilibration temperatures consistent with current reservoir temperature, suggesting isotope re-equilibration in the shallow reservoir. Gases from Filicudi on the other hand are consistent with generation over multiple points over its thermal history.

The organic-rich shales of the Middle Triassic Botneheia Formation in Svalbard and its correlative units offshore are considered important source rock intervals for oil and gas generation in the Norwegian Barents Shelf region. Detailed investigation of these intervals is essential to better understand the intra source rock variations and thus to improve exploration models. As source rocks are rarely cored during exploration campaigns, outcrop studies of analogue source rocks onshore Svalbard are of great importance for gaining a comprehensive understanding of the Triassic petroleum system offshore. This integrated sedimentological and geochemical study of the Botneheia Formation investigates the intricate relationship between mudstone facies, total sulfur, total organic/inorganic carbon, and the absolute and relative abundance of bulk bitumen content. Both the Muen Member (Anisian) and the overlying Blanknuten Member (mostly Ladinian) of the Botneheia Formation were densely sampled and analyzed from three outcrop localities on Edgeøya, eastern Svalbard. The results show that total sulfur, total organic carbon, bitumen richness, and relative and absolute aromatic hydrocarbon content increase from bioturbated, gray-colored shales in the lower to middle Muen Member upwards into non-bioturbated, phosphogenic black shales in the middle part of the Blanknuten Member. From here, organic carbon and bulk bitumen richness subsequently decrease upwards in concert with the occurrence of bioturbated, calcareous mudstones and impure limestones towards the top of the Blanknuten Member. Optical vitrinite reflectance variations do not suggest significant maturity variations with depth in the sample profiles, highlighting that the total organic carbon and bulk bitumen content are dominantly coupled with the developing source facies. These facies and chemostratigraphic trends mirror the implied marine vs. terrigenous organic matter sedimentation and benthic preservation potential, which were at a maximum in the middle Blanknuten Member. These processes appear to be closely related to the supply of nutritious upwelled waters that are further linked with an evolving pan-Arctic 2nd order Middle Triassic transgressive–regressive sequence. Facies and multivariate analyses of the geochemical data show that the lower to middle Muen Member are comparable to the pro-delta mudstones of the younger Tschermakfjellet Formation (Carnian), and that both units are clearly distinct from the increased source rock potential and richness in the upper part of the Muen Member and the entire Blanknuten Member. This provides evidence of genetically different paleo-depositional environments and source rock properties that are confined to the lower and upper parts of the Middle Triassic Botneheia Formation, and may have wide applications for Triassic source rock assessment in the offshore Norwegian Barents Sea.

The radiometric dating of geological events was a crucial achievement leading to the establishment of the geological time scale. The dating of the timing of petroleum charge into, and the determination of petroleum residence times in a geological trap would also be significant, as it would remove ubiquitous speculation concerning the history of reservoir charging in any basin setting. A thorough review of prior strategies to estimate the residence time of petroleum fluids in subsurface reservoirs revealed that few if any methods currently used provide useful estimates of the residence age of fluids. This paper is focused on the age dating of petroleum residence time in reservoirs based on the compositional alterations of reservoired fluids caused by natural radiation. This preliminary paper sets out the geochemical landscape and constraints on radiation-based age dating proxies. We report results on the propagation of radiation through reservoir rocks, which indicate that gamma radiolysis is a primary route to crude oil alteration. Gamma ray radiolysis experiments on crude oils at both natural and elevated radiation doses have been completed and the changing crude oil composition observed using LC, GC-MS and NMR. Reservoir fluids are naturally immersed in radioactive subsurface media that cause systematic alteration to crude oil composition with time, but the chemical changes are small in most natural settings. The degree of radiolysis of individual petroleum compounds was found to depend on chemical class, molecular size, initial compound concentration and the nature of the oil matrix, indicating that a proxy system for dating of petroleum charge times and oil residence times in petroleum traps will likely depend on case-specific calibrations. We define the apparent gamma ray radiolysis susceptibility (kGy−1) of different compounds. Large alkanes, such as high molecular weight normal alkanes (>C22) or hopanes, have high radiolysis susceptibility and show the most rapid decrease in component concentration with increasing radiation dose. In contrast, condensed aromatic hydrocarbons and diamondoid hydrocarbons are more resistant to decomposition through radiolysis. While assessing the decrease in concentration of a compound through radiolysis is a practical objective, it is more difficult to assess the production of new, unique radiolysis products given the great diversity and low concentrations of individual compounds produced. However, monitoring the production of specific functional groups during radiolysis of crude oils, using NMR spectroscopy, was found to be a feasible proxy analytical target. Analysis of newly generated carbon-carbon double bonds in bulk crude oils may represent an optimal approach for development as a radiolysis proxy. We propose a route to assessing in-reservoir crude oil radiation dose.

Investigating hydrocarbon generation and expulsion by pyrolysis is limited by methodologies incapable of simulating conditions close to those prevailing in natural systems. Destructive sample preparation, inappropriate pressure regimes and pyrolysis in closed mode and/or in the absence of water caused results not representative for natural processes. We here present a new approach for a laboratory scaled simulation of generation, primary migration and expulsion under near-natural conditions, using the “Expulsinator” device. Near-natural conditions are realized by application of lithostatic pressure onto a source-rock disc with intact pore network and by pyrolysis at the presence of water, conducted in open flow through mode. This study will give a detailed technical description of the apparatus and the methodology to implement an Expulsinator experiment. An Expulsinator experiment generates a combined generation and expulsion profile, resulting in a detailed source rock characterization, incorporating yields for oil and gas, as well as rock deformation data on mm- and μm-scale. Thus, information is provided about timing and amplitude of generation and expulsion events. The apparatus uses a novel way of continuous sampling during the pyrolysis, enabling product removal from the reactor during the generation and expulsion process. Sampling in open flow-through mode is technically demanding and requires stimulation by a modifier for quantitative removal of the expelled products from the reactor. Test experiments demonstrate that the modifier has no impact onto the expulsion behavior of the source rock. Following the technical description, the generation and expulsion profile of one Expulsinator experiment is discussed. Beside information about timing of product generation and expulsion, the experiment shows the connection between rock expansion/compression and expulsion events. The efficiency of this new methodology is compared with conventional closed hydrous pyrolysis. The results exhibit the advantages of the apparatus: Liquid yields are increased, and hydrocarbon (HC) -gas generation reduced, due to a suppression of secondary reaction by the open setup. Furthermore, conventional pyrolysis achieved lower expulsion rates, due to the absence of lithostatic pressure. The Expulsinator shows high potential for further applications, in particular for implementation of lab-simulation data into numeric models.

Is natural radioactivity a significant agent of hydrocarbon gas generation from sedimentary organic matter? Laboratory gamma radiation of dead crude oil (no solution gas) yields wet hydrocarbon gases depleted in C-13: delta C-13 CH4 (-75 parts per thousand to -65 parts per thousand), delta C-13 C2H6 (-52 parts per thousand to -45 parts per thousand), delta C-13 C3H8 (-42 parts per thousand to -37 parts per thousand) and delta C-13 n-C4H10 (-35 parts per thousand to -32 parts per thousand). Although laboratory irradiation dose rates are orders of magnitude higher than those in geological settings, radiolytic transformations occur at total radiation doses equivalent to those in natural geological settings over many millions of years. Radiolysis generates wet gases with isotopic signatures that might be interpreted as "biogenic" if only the methane carbon isotope ratio is considered. We examine situations where such gases may be quantitatively significant. (C) 2019 Elsevier Ltd. All rights reserved.

Petroleum systems are inherently complex, comprising multiple components and processes, which variably interact in space and time to form petroleum accumulations. Improved understanding of these complex systems requires a holistic approach of integrating diverse geological, geophysical and organic and inorganic geochemical data. Here, we present an applied and comprehensive Re-Os geochronological and geochemical study on the Brynhild petroleum system from the Norwegian North Sea. Essential components of this system include shale source rocks of the Mandal and Farsund Formations, reservoir sandstones of the Ula Formation and their bitumen extracts, and produced Brynhild crude oil. Rock-Eval, trace metal and Re-Os data reveal the excellent oil-generation potential of the shaley source rocks (high contents of organic matter containing large amounts of type I kerogens) and constrain their depositional conditions (anoxic bottom waters in a high-productivity regime driven by enhanced supply of land-derived nutrients). Seven Re-Os shale ages between similar to 146 and similar to 134 Ma are consistent with existing Volgian-Ryazanian age estimates and constrain the initial Os-187/Os-188 of the shales to similar to 0.52 in the lowermost Farsund Formation and similar to 0.75 in the uppermost Mandal Formation. Solvent-extracted reservoir rocks of the Ula Formation contain insoluble organic matter with type III-type IV kerogens likely supplied by erosion of older (a precise 179 Ma Re-Os age with unrealistically low initial Os-187/Os-188) coal-bearing sediments or organic-rich shales. The Brynhild crude oil has relatively low Os-187/Os-188 and a generation age of similar to 44 Ma based on an asphaltene-only Re-Os isochron. Maltenes from the Brynhild crude oil are isotopically affected by interaction with organic-rich source rocks that represent the seal for the Brynhild oil field. Compared with the crude oil, bitumen from Ula Formation sandstones have contrasting Re-Os properties: high Os-187/Os-188 ratios and young generation ages between 8 and 0 Ma based on asphaltene-bitumen-maltene Re-Os triplets, asphaltene-only Re-Os regressions, and Re-Os model ages for components with extremely high (187)Rs/Os-188. The 44 Ma and 8-0 Ma Re-Os ages agree well with regional burial models that indicate oil generation from -44 Ma to present day. A genetic link between crude oil and bitumen is indicated by their similar alkane patterns, V and Ni contents, and V/Ni and pristane/phytane ratios. Modeling of Os-187/Os-188 for individual organic components through time shows that shales of the Mandal Formation developed Os-187/Os-188 ratios that match those of the crude oil and bitumen at similar to 44 Ma and similar to 8 Ma, respectively, and therefore confirm the source for both hydrocarbon phases. We suggest that bitumen formed during in-reservoir mixing of a similar to 44 Ma old early mature, asphaltene-poor oil (Brynhild crude oil) with an similar to 8 Ma old asphaltene-rich oil.

The radiometric dating of geological events was a crucial achievement leading to the establishment of the geological time scale. The dating of the timing of petroleum charge into, and oil residence times in a petroleum trap would also be as significant, eliminating much speculation concerning reservoir charging times and migration routes and providing direct assessment of play concepts in conventional targets and storage phenomena in unconventional reservoirs. The examination of the residence age spatial profiles in a fluid column, coupled to numerical models of fluid flux, might allow estimates of the charge, spillage and leakage fluid fluxes into and out of the trap both for petroleum and CO2 storage reservoirs. However, current strategies to assess the residence time of fluids in subsurface reservoirs methods fail to provide useful estimates, and arguably the most important constraining information in a petroleum system is currently inaccessible. Based on several years of research, we have defined the geochemical landscape and constraints on fluid radiolysis-based age dating proxies. In theory, the chemical alterations in petroleum reservoir fluids, caused by in-reservoir radioactivity could be used as a chronometer, although there are great analytical challenges associated with such strategy. In this study, we scrutinize the requirements, potential benefits and practical feasibility of such potential technologies, showing preliminary results for a case history data set where residence age is a key determinant of exploration strategy.

The Harstad Basin is a structural block on the continental shelf of SW Barents Sea where gas hydrates likely occurred below the grounded ice-sheet during the last glaciation and it hosts active gas seepage at numerous seafloor sites. We present an integrated study of fluid flow systems in the Harstad Basin by combining seismic profile interpretations and gas flare mapping data with the geochemical results obtained on seafloor seeping gas and methane-derived carbonate crusts. More than 190 acoustic gas flares were registered in water column, many of them in association with pockmarks and carbonate crust fields. However, weak or absent seepage observed during remotely operated underwater vehicle transects across many pockmarks and crust fields suggests that seepage activity may have decreased since the last deglaciation. In the western Harstad Basin, seeps of microbial methane occur mainly above Tertiary formations that are pinching out below the glacial sediments. High amplitude seismic anomalies suggest the presence of gas pockets at the base of the glacial sediments and within Tertiary deposits. In contrast, gas seeping in the eastern Harstad Basin originates from a biodegraded thermogenic source tentatively connected to the deeply faulted Mesozoic rocks occurring below glacial sediments. This spatial variability in fluid sources is also recorded in the carbon isotope data of seafloor carbonate crusts, with delta C-13 values typically between -55 and -42 parts per thousand and -40 and -20 parts per thousand VPDB for carbonate crusts associated with microbial and thermogenic fluids, respectively. U-Th chronology combined with the stable isotope data suggests that this discrepancy in fluid sources over a distance of about 20 km has been stable since the last glaciation and highlights the significance of regional underlying geology in mediating fluid supply to the seafloor.

Rock-Eval and total organic carbon (TOC) analyses of 144 samples representing Triassic-Lower Cretaceous intervals from the SW Barents Sea (the Svalis Dome, the Nordkapp and Hammerfest basins, and the Bjarmeland Platform) and Svalbard demonstrate lateral variations in source rock properties. Good to excellent source rocks are present in the Lower-Middle Triassic Botneheia and Steinkobbe, and Upper Jurassic Hekkingen formations, 1 - 7 wt% and 6 -19 wt% TOC, respectively. Hydrogen indices of 298 - 609 mg HC/g TOC in the Botneheia Formation from Svalbard, and 197 - 540 mg HC/g TOC in the Steinkobbe Formation of Svalis Dome suggest Type II (oil-prone) and Type II/III (oil/gas-prone) kerogens, respectively. The Kobbe Formation (Botneheia/Steinkobbe-equivalent) is organic-lean and generally gas-prone (Type III kerogen) on the Bjarmeland Platform and in the Nordkapp Basin, and is a good source rock with Type III/II kerogen in the Hammerfest Basin. In the investigated wells, the Hekkingen Formation is more oil-prone on the Bjarmeland Platform than in the Nordkapp Basin, while Lower Cretaceous samples have poor potential for oil. Upper Triassic samples show potential mainly for gas; however, coal/coaly-shale samples in well 7430/07-U-01 (Bjarmeland Platform) are oil/gas-prone. Most samples analysed are immature to early mature; thus, the variation in petroleum potential and kerogen type is a function of organic facies rather than maturity levels.

The Svalbard Archipelago, located in the Arctic region, holds source rocks of great importance to the understanding of the Petroleum systems in the Barents Sea and the Circum-Arctic Region. Vast Mesozoic sedimentary successions are exposed on the major islands. The key targets of this study were to identify the source rock potential and describe the organic matter (OM) in terms of total organic carbon contents (TOC), hydrocarbon potential, organic facies, and level of maturity in more detail and from more varied localities than previously accomplished. Fortynine outcrop samples, mostly shales and mudstones, representing Triassic and Jurassic formations from four different locations at Svalbard have been analysed geochemically. The results indicate that both Jurassic and Triassic sediments have potential for oil and gas generation, and the best source rocks at Svalbard lie within the Triassic Botneheia Formation. Most samples from the Botneheia Formation at the Blanknuten locality are characterized by high TOC (5-10%) and high hydrogen index (HI) (445-609 mg HC/g TOC) values, suggesting excellent source rocks with Type II kerogen. Most samples from the Botneheia Formation at the Muen locality have also very good TOC values (2.4-6.2%), but significantly lower HI values (124-184 mg HC/g TOC), indicative of gas prone Type III kerogen. These results suggest that the organic rich Botneheia Formation at Muen has currently lower generating capability than its analogue at the Blanknuten locality, and this difference is mainly attributed to maturation. The Muen samples are also defined by higher production index (PI) values than the Blanknuten samples, and typical values range from 0.1-0.3 at a Tmax of 448-457°C for the Muen samples, and this compares to PI values of 0.04-0.06 at a Tmax of 439-446 °C for the Blanknuten samples. This suggests that the Muen samples are presently at a “late-oil-window-maturities” and therefore have already generated and expelled significant proportions of oil, due to their elevated PI values. Still they are capable of generating gas, while the Blanknuten samples are today only at an early “oil-window-maturity-stage”. The samples from the Upper Jurassic Agardhfjellet Formation at the Myklegardfjellet/Agardhbukta locality are characterized by 2.2-5.9% TOC, 77-121 mg HC/g TOC HI, and 452-465 °C Tmax values, implying gas prone Type III kerogen which are presently within the “late oil window maturity”. Isotope and biomarker data suggest that the source rock facies is marine for most samples with additional organic matter input from terrestrial flora for some of the Jurassic samples. The poster presentation includes a comparison between these Triassic and Jurassic formations at Svalbard, with time equivalent offshore Barents Sea Steinkobbe (1.5-9% TOC) and Hekkingen (3-16% TOC) formations.

Petroleum occurring in lower Paleozoic rocks is known to be present in southern Scandinavia, northern Poland, and the Baltic states. Oil has been produced from lower Paleozoic reservoirs in Sweden, northern Poland; and the Baltic countries Lithuania, Latvia, and the Russian exclave area of Kaliningrad. The sources for this petroleum are marine, organic-rich muds deposited in the Cambrian Ordovician, and Silurian. This article concerns geochemical analysis of oils extracted from sandstones and carbonates from the Norwegian Oslo Graben rift and locations in Sweden and describes, in addition, insoluble bitumens collected from lower Paleozoic rocks in the Oslo Graben, locations in Sweden, and from upper Paleozoic rocks in a Norwegian North Sea well. The oils in this study have several geochemical characteristics shared with oils from the Baltic states and northern Poland, and the maturities of the oils are, in general, low. The occurrences of bitumen and migrated petroleum in the Oslo Graben lead us to believe that petroleum also has been generated and expelled in the related offshore Skagerrak Graben, indicating that a Paleozoic petroleum system operated in the Skagerrak Graben. This potential petroleum system has not suffered the degree of uplift, erosion, and destruction of reservoirs experienced by the onshore Oslo Graben, making preservation of any petroleum accumulations in the Skagerrak Graben more plausible. Although speculative, these considerations should interest anyone involved in petroleum exploration in the Skagerrak and the Norwegian-Danish Basin, not the least because of the proximity of Skagerrak and major energy markets in Europe.