Abstract The sandstones of the Lunde (Upper Triassic) and the Statfjord (Lower Jurassic) Formations from the Snorre Field of the Northern North Sea have good reservoir properties which are primarily controlled by sedimentary facies. Dissolution of feldspars and other unstable grains during early diagenesis has resulted in abundant well-formed large vermicular booklets of kaolinite, fine-grained kaolinite and blocky kaolinite. Textural evidence suggests that kaolinite and calcite predate quartz cementation. Kaolinite distribution in the Statfjord and Lunde Formations is related to the porosity and permeability characteristics of the sandstones, facies, homogeneity of sandstones, carbonate cement percentage in the sandstones and multiple stacking of channel units. The distribution of kaolinite is controlled by the flow of ground water with low K + (Na + )/Fl + ratios. The increased leaching observed in the channel sandstones could be due to focused flow during and after deposition through channel deposits as compared to the thinner and finer overbank sands. Greater leaching of feldspars and mica resulting in higher amounts of authigenic kaolinite in the Statfjord Formation can be attributed to more humid climatic conditions and higher meteoric flow rates during early Jurassic time. Diagenetic illite occurs in relatively low concentrations in the Lunde and Statfjord Formation sandstones and may have formed mainly from smectite. The low illite content observed at the present burial depth suggests that illite requires higher temperatures than 80-95°C to form from feldspar and kaolinite. The present distribution of kaolinite in these reservoir rocks will control the distribution of illite at greater burial (>4 km) which would be important for the reservoir quality at those depths.

Abstract Several master faults in the North Sea basin tend to flatten to give low dips at depth, and in this sense form detachments in the rift system. Such low angle faults are identified in the western flank of the Viking Graben (Tampen Spur area), where they occur as both intra- and supra-basement detachments. Interference between detachments and steeper faults results in ramp–flatramp–ramp geometries. In the eastern part of the Gullfaks fault block, a supra-basement detachment is probably associated with anomalously high late Jurassic extension in the Gullfaks Field area. The low-angle Gullfaks detachment also helps explain the presence of sets of parallel east-dipping faults (domino systems), a common feature in the collapsed hanging wall to low-angle detachments. Similar detachments probably exist beneath the Gullfaks Sør block and SE of the Visund fault block. All of these are interpreted as late Jurassic collapse structures directly related to active late Jurassic extensional tectonics. Strong indications of intra-basement detachments are also found in the Tampen Spur area. These detachments are formed by major normal faults that flatten in the basement, as seen beneath the Visund fault block. This geometry may to some extent be related to fault rotation during repeated phases of extension in the Palaeozoic-Early Mesozoic period. However, abrupt flattening of some of the faults in the basement indicates that the master faults follow some of the many pre-existing mechanically weak zones in the basement, primarily low-angle Devonian extensional shear zones or Caledonian thrusts.

Abstract: The Knarr Field is located on the Tampen Spur, Norwegian continental shelf and was discovered in 2008 by the Jordbær well (34/3-1S), with additional resources later added to the field by the Jordbær Vest well (34/3-3S) in 2011. Within the Knarr Field, the Cook Formation is informally divided into the Lower Cook and Upper Cook successions and appears to have prograded from east to west. The Lower Cook consists of Sands 1, 2 and 3 and the Upper Cook consists of Sands 4 and 5, with the sands separated by intraformational mudstones that are commonly chronostratigraphically constrained; the J15 maximum flooding surface separates the Lower and Upper Cook. The tide-dominated Lower Cook is notably heterolithic, with intricate intercalations of sandstone and mudrock lithologies representing tidal channel, tidal bar and intertidal bar facies. The Upper Cook represents a series of coarsening-upwards cycles that displays the systematic changes in facies and ichnology expected for a shoreface succession, consisting of offshore, offshore transition zone and shoreface facies. Palynomorphs confirm these observations and suggest that the Lower Cook was deposited in brackish-water conditions, whereas the presence of more marine fossils in the Upper Cook suggests an increase in marine influence. The integration of the sedimentology and biostratigraphy described herein enabled the establishment of a robust reservoir zonation that has been utilized during the development and ongoing exploitation of the Knarr Field.

Abstract Current recovery from the Statfjord Group in the majority of the fields on the Tampen Spur is less than 50%. A contributing factor to this is an incomplete understanding of multiscale heterogeneities, their distributions within a range of fluvial geobodies and their lateral extent and morphology in inter-well areas. Sedimentary heterogeneities have been modelled, together with petrophysical parameters, at a variety of scales. The modelled properties at a given scale were upscaled to the next level of heterogeneity, thus better honouring effective property values. The use of outcrop analogues is still a key tool for understanding facies relationships and the stratigraphic development of subsurface hydrocarbon-bearing reservoirs. The Lourinhã Formation, Portugal, was used as an analogue to collect both qualitative and quantitative data consistently following a three-phase workflow to capture data at various scales of heterogeneity. Traditional field data collection techniques have been supplemented with the collection of LiDAR data. A digital workflow utilizing interlinked datasets facilitates rapid data analysis and better data visualization with results that are more easily utilized in multiscale modelling studies. These scaled models were used to increase our understanding of the effect on flow of lithofacies and facies association distributions together with internal architectural elements and heterogeneities.

Abstract The evolution of the petroleum systems in the Tampen Spur area, with main focus on the filling directions of the northern part of Snorre field, was addressed through 2D basin modelling (Petromod V. 4.5 and 7.0). The geochemical classification of the petroleum populations in the area represented the framework for considering the different kitchen areas and migration systems. Results from the basin modelling support, in general terms, the previous geochemical classification and petroleum families in the region. However, a separate well-defined main kitchen area for the Snorre Field was deduced opposed to the multiple kitchen areas having contributed to the filling as proposed in the literature. Our conclusions are based on the quantitative evaluation of the different proposed kitchen areas and the timing and extent of petroleum generation. Modelling of petroleum generation was performed using asphaltene kinetics determined on petroleum asphaltenes from Snorre oils. This approach was chosen in order to avoid problems associated with the kinetic variability encountered in the Draupne formation. The petroleum asphaltene kinetics was used to delineate the extent of the kitchen area, which reached the time/temperature conditions necessary for the generation of the analysed oil phase. The results thus differ from conventional oil window approximations as we utilize kinetic source rock parameters in the migrated oil for tracing out the generative basin. Three 2D lines crossing the main kitchen areas were modelled in this study. The models were calibrated to data from eight wells, consisting of measured vitrinite reflectance, corrected well temperatures and pore pressure. Three main kitchen areas were considered; one to the west and northwest of Snorre field, one directly to the north (Møre basin) and one to the east of the field (34/5 kitchen). Modelling suggests that the kitchen area to the west and northwest of Snorre is largely immature and that the volume of potentially generated petroleum is too small to fill the Snorre structure. In the northern kitchen area, the seismic indicated very thin upper Jurassic deposits, which reaches oil window maturities only at a relatively large distance from the structure. The modelling also demonstrated problems related to the filling of the Snorre structure from the Møre Basin. The combined effect of a thin source rock, which implies a regionally large drainage area to fill the structure, and the large distance to the mature kitchen, lead to the conclusion that the Møre Basin did not contribute significant volumes of petroleum to the Snorre field. In contrast, the kitchen area east of Snorre Field (the 34/5 kitchen) proved in the modelling to be mature and volumetrically large enough to account for the entire filling of the Snorre Field.

Abstract The possibility to model petroleum composition during hydrocarbon generation as well as the PVT behaviour of the fluids during migration has only recently become available in modern basin modelling software packages. While various compositional kinetic models of petroleum generation have been published in the past few years, none of the studies presented have attempted to match the composition, physical properties and phase state of known petroleum accumulations. Using compositional data from closed-system non-isothermal pyrolysis experiments, we developed a compositional kinetic model of hydrocarbon generation for a marine Type II source rock, which uses 13 components to describe the generated fluid. The data format selected is compatible with the compositional resolution used in reservoir engineering, thus allowing a direct comparison of predicted compositions and phase behaviour with PVT data of natural fluids. Compositional predictions of the model were tuned to a well-documented maturity sequence from the Tampen Spur, Norway, and the calibrated model implemented in a 2D basin modelling study of the Snorre Field, Norway. The results of the modelling led to an excellent correlation between predicted and reported reservoir fluid properties (formation volume factor, GOR and saturation pressure) for the present-day situation. The results indicate that the Snorre reservoir has received a continuous charge since the late Cretaceous-early Tertiary and that it most likely contained a two-phase system prior to the latest Plio-Pleistocene burial and overpressuring event.

Abstract The Statfjord Field, the largest oil field in the Northern North Sea, straddles the Norway/UK boundary and is located on the southwestern part of the Tampen Spur within the East Shetland Basin. The accumulation is trapped in a 6-8° W-NW dipping rotated fault block comprised of Jurassic-Triassic strata sealed by Middle to Upper Jurassic and Cretaceous shales. Reserves are located in three separate reservoirs: Middle Jurassic deltaic sediments of the Brent Group, Lower Jurassic marine-shelf sandstones and siltstones of the Dunlin Group; and Upper Triassic-lowermost Jurassic fluviatile sediments of the Statfjord Formation. The majority of reserves are contained within the Brent Group; and Statfjord Formation sediments which exhibit good to excellent reservoir properties with porosities ranging from 20-30% permeabilities ranging up to several darcies, and an average net-to-gross of 60-75%. The sandstones and siltstones of the Dunlin Group have poorer reservoir properties where the best reservoir unit exhibits an average porosity of 22%, an average permeability 300mD and net-to-gross of 45%. Structurally, the field is subdivided into a main field area characterized by relatively undeformed W-NW dipping strata, and a heavily deformed east flank area characterized by several phases of ‘eastward’ gravitational collapse. Production from the field commenced in 1979 and as of January 2000, 176 wells have been drilled. The oil is undersaturated and no natural gas-cap is present. The drainage strategy has been to develop the Brent and Dunlin Group reservoir with pressure maintenance using water injection and the Statfjord Formation reservoir by miscible gas flood. However, a strategy to improve recovery by implementing water alternating gas (WAG) methods is gradually being implemented for both the Brent and Statfjord reservoirs. Current estimates indicate that by 2015 a total of 666 x 10 6 Sm 3 (4192 MMBBL) of oil will be recovered and 75GSm 3 (2.66 TCF) gas will be exported from the field.

ABSTRACT The Gullfaks giant oil field in the Norwegian sector of the North Sea was discovered in 1978. The Gullfaks field contains oil reserves on the order of 230 million standard m 3 . Gullfaks represents the shallowest structural element of the Tampen spur. It was formed during the Upper Jurassic to Lower Cretaceous as a sloping high, with a westward structural dip gradually decreasing toward the east. The major north-south-striking faults, with eastward-sloping fault planes, divide the field into several rotated fault blocks. The central and eastern parts of the structure were eroded by the Early Cretaceous transgression. The reservoir sands are the Middle Jurassic delta-deposited Brent Group, the Lower Jurassic shallow marine sandstones of the Cook Formation, and the Lower Jurassic fluvial channel and delta plain deposits of the Statfjord Formation. The Brent reserves in the western part of the field are currently being developed from the Gullfaks A and Β platforms, and the eastern part is being developed from a third platform, Gullfaks C. Water injection is the major drive mechanism, maintaining the reservoir pressure above the bubble point. One of the most important factors in the reservoir development of the Gullfaks field has been the effect of fault transmissibilities on lateral and vertical pressure distributions.