the existence of oil or gas in both present-day and palaeo-accumulations of petroleum.Trapped petroleum represents an excellent source of information about hydrocarbon generation, expulsion, migration and accumulation, and the analysis of reservoired petroleum is a key tool in hydrocarbon exploration. Most geological information relates to the static rock framework, but oil which has moved through rock strata contains within it unique information for example on carrier interconnectivity and migration directions. Migrated petroleum also provides information on both source rock facies and temperatures of maturation and expulsion. In addition, physical changes which affected the petroleum during the migration process are preserved as geochemical "fingerprints"; these changes can be interpreted in terms of the mixing of different petroleums in a trap, leakage from the trap, biodegradation and mode of migration. Most processes affecting petroleum during migration and in a trap, whether they are biochemical, physical or This paper considers the principles of deciphering basin-scale hydrocarbon migration patterns using the geochemical information which is present in trapped petroleum. Petroleum accumulations in subsiding basins can be thought of as "data archives" within which stored information can help us to understand aspects of hydrocarbon formation and migration. This information can impart a time-resolved picture of hydrocarbon migration in a basin in response to processes associated with progressive burial, particularly in the context of the occurrence and periodic activity of faults.This review, which includes a series of tentative models of migration-related processes in the extensional Halten Terrace area, offshore mid-Norway, illustrates how we can use information from the migrating mobile hydrocarbon phase to improve our knowledge of the static geological system. Of particular importance is the role of sub-seismic heterogeneities and faults in controlling migration processes. We focus on how the secondary migration process can be enhanced in a multi-source rock basin such as the Halten Terrace, thereby increasing prospectivity.

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Petroleum inclusion and geochemical data from core extracts were applied to deduce a model for oil migration, overpressure development and palaeo-leakage of oil from currently dry structures in the Haltenbanken Vest area. The existence of fluorescent oil type inclusions in quartz in the Smørbukk (Åsgard-2) field suggest that oil migrated into this structure 70–50 million years before present (Ma bp). This is also the case for the dry structures 6506/12-4, 6506/11-3 and 6506/11-1, west of the main Smørbukk Fault Zone. Black oil inclusions with medium gas/oil ratio (GOR) occur in these fields together with condensate-type petroleum inclusions. This suggests that the dry structures transformed from containing oil to condensate before leakage. Petroleum extracted from inclusions in these structures and in nearby fields have identical marine type II kerogen signatures. Source rocks at the Spekk Formation level in the current drainage area of Smørbukk and these dry structures, were immature 70–50 Ma bp and the Smørbukk Sør (Åsgard-3) field did not fill at this early time. Thus, oil must initially have entered into Smørbukk from areas to the W-SW, through the currently pressure sealing Smørbukk Fault Zone which today marks the westward limit of the Smørbukk field. Diagenesis in this fault zone caused the much later overpressure development and petroleum was lost from the 6506/12-4, 6506/11-3 and 6506/11-1 structures as overpressure built up regionally. Petroleum loss from these structures with their often thick seals must have occurred via self-propagating open-fracture-induced mechanisms. Lack of petroleum in the Cretaceous strata above these structures suggests that leakage occurred to even shallower strata. This could imply that the Cretaceous strata in Halten Vest were overpressured at the time of leakage. In contrast, the oil in the Cretaceous Lysing and Lange Formation (above the Jurassic reservoirs in Smørbukk and Smørbukk Sør) most likely originated (based on geochemistry and GORs) from the Jurassic reservoirs below and not from Cretaceous strata. This migration event would have been facilitated if it occurred before these sands became overpressured as they are today. Modelling suggests that the Spekk Formation became mature in the Smørbukk Sør region <10 Ma bp and microthermometry of oil inclusions from Smørbukk Sør supports filling during the past 10 Ma. This implies that caprock failure in the Halten Vest structures 6506/12-4, 6506/11-1 and 6506/11-3 most likely occurred after filling of the Smørbukk Sør and 6406/3-1 structures. Rapid regional burial during the past 10 Ma caused local migration of oil into Smørbukk Sør, Smørbukk and 6406/3-1 structures, and generation of high GOR oils in the deeper Halten Vest region. High GOR petroleum inclusions in the Halten Vest structures signify this event and suggests that caprock fracturing occurred after a gas-condensate had replaced oil in these traps. Rapid burial during the past 3 Ma is likely to have caused the current overpressure and associated leakage in Halten Vest. The fact that these traps did not later refill in this progressively subsiding and maturing basin must be related to trap pressures remaining too close to the actual fracture pressures.

In this contribution we present the results of an integrated investigation of selected nitrogen-and oxygen-bearing compounds in Norwegian Central Graben crude oils. We first provide an interpretation framework built on hydrocarbon biomarkers, and then use this framework to relate polar compound geochemistry to the influences of source facies (Farsund versus Mandal Formations), maturity, migration and reservoir lithology. Oil maturity could be assessed using established changes in carbazole annelation (N1 DBE 9 vs. 12 vs. 15 classes), as well as hydrocarbon biomarkers. 29Ts/(29Ts+NH) correlated best with the polar compound maturity data. Secondary migration fractionation appears nevertheless to have played a role, as seen by increased DBE 9 and 12 carbazole and benzocarbazole proportions and a loss of C2-3 DBE 12 homologues within carbonate reservoirs as compared to intraformational Upper Jurassic siliciclastic reservoirs. Thus migration distances, pathways and wettability of carrier systems ostensibly play a significant role in carbazole distributions of the Central Graben oils, manifesting itself as apparent maturity retardation. In an attempt to eliminate the migration component from maturity assessment, we here present a novel ternary diagram including dibenzocarbazoles (N1 DBE 15) and phenolic species (O1 DBE 4 and 5) based on a single measurement using the FT-ICR-MS. However, the integration of such results into 3D-modelling software must be conducted to clarify source kitchen, migration pathways and distances.

Recent discoveries of hydrocarbons along the western margin of the Norwegian Barents Shelf have emphasised the need for a better understanding of the source rock potential of the Upper Palaeozoic succession. In this study, a comprehensive set of organic geochemical data have been collected from the Carboniferous – Permian interval outcropping on Svalbard in order to re‐assess the offshore potential. Four stratigraphic levels with organic‐rich facies have been identified: (i) Lower Carboniferous (Mississippian) fluvio‐lacustrine intervals with TOC between 1 and 75 wt.% and a cumulative organic‐rich section more than 100 m thick; (ii) Upper Carboniferous (Pennsylvanian) evaporite‐associated marine shales and organic‐rich carbonates with TOC up to 20 wt.%; (iii) a widespread lowermost Permian organic‐rich carbonate unit, 2–10 m thick, with 1–10 wt. % TOC; and (iv) Lower Permian organic‐rich marine shales with an average TOC content of 10 wt.%. Petroleum can potentially be tied to organic‐rich facies at formation level based on the gammacerane index, δ13C of the aromatic fraction and/or the Pr/Ph ratio. Relatively heavy δ13C values, a low gammacerane index and high Pr/Ph ratios characterize Lower Carboniferous non‐marine sediments, whereas evaporite‐associated facies have lighter δ13C, a higher gammacerane index and lower Pr/Ph ratios.