Tampen Spur Area Research Articles

Utilising borehole image logs to interpret delta to estuarine system: A case study of the subsurface Lower Jurassic Cook Formation in the Norwegian northern North Sea

The Lower Jurassic Cook Formation forms a regressive and transgressive sandstone wedge of shallow marine reservoir sandstones. It is distributed mainly in the Norwegian sector of the northern North Sea and the formation has proven to be hydrocarbon bearing. A case study of this formation from the Tampen Spur area presents a methodology for reconstructing depositional environments in areas of scarce data coverage and poor seismic quality using limited core-coverage, wire-line logs and borehole image logs. The core material and image logs are from different wells. The latter offer interesting opportunities for sedimentological descriptions and interpretations both in cored and uncored sections, particularly as the resolution of the tool (mm-scale under optimal conditions) enables identification of sedimentary structures. In order to avoid over-interpretation, a system of descriptive, simple and robust image facies was established for this study. These include: horizontal lamination, low-angle lamination, cross-stratification, as well as mottled and deformed strata. The Cook Formation is interpreted here as a regressive tidal-fluvial delta to transgressive wave-dominated estuary couplet with offshore shale above and below. The tidal-fluvial delta of the regressive part seems to be at odds with the regional context as the regressive part of the Cook Formation in the Tampen Spur area is interpreted as a wave-dominated delta system. Internally, the regressive part of the Cook Formation thickens westwards with 68% which is unusual for the otherwise tabular regressive Cook Formation in the Tampen Spur area. Both the thickness and depositional environment difference of the regressive part of the Cook Formation can be explained with temporary fault movement of a blind fault located basinward during basin infill. This could have created a fault-induced monocline that led to wave sheltering of the tidal-fluvial delta system. A spit-barrier system was probably associated with the monocline sourced by longshore drift from the otherwise wave-dominated coast of the regressive Cook Formation. After basin infill and removal of basin relief, the subsequent transgression resulted in the formation of a wave-dominated estuary.

Physical modelling of sand injectites

Sand injectites are structures that result from intrusion of fluidized sand into fractures. We have studied them in the Tampen Spur area of the North Sea, and have reproduced them experimentally, by driving compressed air through layers of sand, glass microspheres, and silica powder. The silica powder was cohesive and capable of hydraulic fracturing, whereas the sand and glass microspheres were almost non-cohesive and therefore able to fluidize. The models were dynamically similar to their natural counterparts, for as long as equilibrium was static. When the processes became dynamic, so that inertial forces were significant, the scaling was approximate and the corresponding Reynolds numbers differed. The experimental apparatus was a square box, 1 m × 1 m wide, resting on a grid of fluid diffusers. During the experiments, the fluid pressure increased, until it attained and surpassed the weight of overburden. Flat-lying hydraulic fractures, containing air, formed within cohesive and least permeable layers. Heterogeneities in material properties and layer thicknesses were responsible for localizing fracture networks. When any one network broke through to the surface, rapid flow of air through the fractures fluidized the underlying mobile materials and even depleted some of the layers. Some of the fluidized material extruded at the surface through vents, forming volcanoes and sheets. The remainder lodged at depth, forming sand injectites or laccoliths. Conical sand injectites formed preferentially, where layers had high resistance to bending. Laccoliths formed nearer the surface, where overlying layers had low resistance to bending. The experimental sand injectites were broadly similar to those in the Tampen Spur area of the North Sea, as well as other areas.

A new approach to bridge the effect of organofacies variations on kinetic modelling and geological extrapolations

Reliable prediction of petroleum formation is impeded by significant variations in organofacies that result from varying conditions during source rock deposition. Basin simulation programs can model lateral variations but are limited in their ability to account for vertical variations due to the impact on computation time and lack of representative kinetic parameters. Here we present a model that merges the petroleum formation characteristics of different organofacies, vertically distributed in a heterogeneous source rock, prior to kinetic modelling. This approach allows the evaluation of one single overall kinetic model that accounts for the different petroleum generation characteristics of a variety of organofacies preserved in a source rock and balance the different petroleum formation processes according to their importance within the different organofacies. Bulk petroleum generation kinetics were determined on eleven Draupne Formation samples taken from a well in the Tampen Spur area using programmed temperature open system pyrolysis at 0.1, 0.7 and 5.0 K/min. The samples covered the entire Draupne Formation from its bottom to its top in the studied well. Individual measurements taken at the same heating rate were summed to one pyrolysis yield curve and normalized to the average Rock-Eval S2 value. The three summed curves were then used as input to determine a kinetic model that is representative of the Draupne Formation in this well. Enhanced kinetic modelling was applied in order to account for the expected variations of frequency factors. After geological extrapolation, the resulting kinetic model represents the petroleum generation characteristics of the entire Draupne Formation in the study area, accounting for the variability in source potential across organofacies.

A probabilistic approach to improved geological knowledge and reduced exploration risks using hydrocarbon migration modelling

This paper elaborates a methodology for assessing the consequences of uncertainties in the source and reservoir models on hydrocarbon phase distributions in prospects by improving the a-priori probability distributions. The uncertainties of geological systems can be described by probabilistic distributions of quantified geological variables, such as source rock and reservoir thicknesses. A Monte Carlo simulation of hydrocarbon generation, expulsion, migration and entrapment is carried out with probabilistic distributions defining important input variables. A weight for each simulation run is computed from a misfit function that describes how well the modelled oil and gas columns fit the observed columns in a set of calibration wells. These weights are used to compile a-posteriori probability distributions of the input variables. The resulting probability distributions, therefore, describe the uncertainties of the geological system after the calibration of the migration model. In a demonstration example from the Tampen Spur area of the North Sea, the most sensitive geological input distributions become significantly narrower, thus limiting the range of possible outcomes. Other distributions become more uneven, with peaks and lows. The changes in the variable distributions have been quantified and variables can, therefore, be ranked with respect to their impact on changes in probabilities for key outcomes. A large number of simulation runs is required for the proposed method to be effective because many simulation runs result in too large a misfit. A statistical fit of a second-order function to the misfit values allows for the effective screening of input variables, thus reducing the computing time, in the demonstration example, to 15% of the unscreened times. The result of the analysis is that the effect of geological uncertainties on output values is effectively reduced and that a quantitative learning has been obtained. This knowledge can be applied in other hydrocarbon generation and migration studies within the study area, allowing for more rapid and more accurate estimates of oil and gas resources before drilling.

Eocene sandstone intrusions in the Tampen Spur area (Norwegian North Sea Quad 34) imaged by 3D seismic data

The Eocene of the northern North Sea is characterised by fine-grained mudstones and isolated sandbodies. Three-dimensional (3D) seismic data reveal that the Eocene mudstones are intensely deformed by polygonal faulting and contain numerous discordant amplitude anomalies. The anomalies identified in the Tampen Spur area are similar to discordant anomalies previously described from the Eocene in the South Viking Graben and the Outer Moray Firth. Detailed mapping shows that the anomalies are often conical in three dimensions, with dimensions ranging from 100 to 200 m height and a few hundred metres to a few kilometres lateral extent. Well calibrations show that the anomalies arise from sandstones tens of metres thick encased in mudstone. The discordant amplitude anomalies are interpreted as large-scale conical sandstone intrusions fed from deeper Paleocene sandbodies. Individual conical intrusions may contain millions of cubic metres of sandstone and may provide fluid migration paths, potential reservoirs, and pose a drilling risk when exploring for deeper targets.

An integrated basin modelling study applying asphaltene kinetics from reservoired petroleum in the Snorre Area, northern North Sea

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.

Detachments and low-angle faults in the northern North Sea rift system

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-flat-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.

The Statfjord 3-D, 4-C OBC survey

This paper presents initial processing and interpretation of 3-D multicomponent seismic data acquired over parts of Statfjord Field in the last quarter of 1997. Statfjord Field, in the Tampen Spur area straddling the British/Norwegian border in the northern portion of the Viking Graben, covers about 500 km2 and has estimated oil reserves of 674×106 m3. Production started in 1979. The reservoir units are Jurassic sandstones of the Brent Group, Dunlin Group, and Statfjord Formation.

Controls on Late Jurassic, subtle sand distribution in the Tampen Spur area, Northern North Sea

The role of fault growth and linkage is an important, but poorly understood, factor in controlling the distribution of sediments within extensional settings. Tectonostratigraphic analysis of the Statfjord East fault system, located in the East Shetland Basin of the Northern North Sea, demonstrates the importance of Late Jurassic normal faulting in controlling the nature of subtle, hanging wall traps. Wells in Norwegian Block 34/7 have penetrated prospective sandstone reservoirs that correlate with several thin, but seismically resolvable, units within syn-rift sediments of the Statfjord East hanging wall. Detailed 3D seismic interpretation and mapping of amplitude anomalies in Block 34/7 and the adjacent part of Block 33/9 reveal a number of spatially discontinuous stratigraphic units within the Late Jurassic, syn-rift Draupne Formation. These depositional units are spatially related to sub-basins, which are controlled by interaction and linkage of several en echelon fault segments. The main control on the distribution of local depocentres is the along-strike displacement variation associated with fault propagation by segment linkage. A close association between sandstone occurrence and structural position, suggests a model in which shoreline migration is controlled by the dynamics of fault lengthening through time.

The Zeta Structure: a footwall degradation complex formed by gravity sliding on the western margin of the Tampen Spur, Northern North Sea

The Zeta Structure (NOCS Block 34/4) is situated to the north of the Snorre Field, in the Tampen Spur area of the northern Viking Graben. The Zeta area shows a tectonic development and geometry markedly different from the typical fault blocks of the northern Viking Graben, which are most commonly asymmetric half-graben, with hydrocarbons trapped at the crest. The Zeta Structure is a ‘twisted’ horst block between two opposed major fault complexes. It occupies a ‘conjugate overlapping’ transfer zone. An east-dipping, rather flat fault in the Zeta Structure appears to be locally anomalous and is well imaged on 3D seismic data. This fault has been cored in Well 34/4–5 and defines the boundary between Lower Jurassic in the hanging wall and Triassic rocks in the footwall. The fault is remarkably clear on seismic data, and is seen to truncate the top of the older Inner Snorre Fault. The Jurassic section has in part been carried into the pre-existing hanging wall basin east of the Inner Snorre Fault, where it has been protected from Late Jurassic erosion. The Zeta Fault is interpreted to be a gravity slide, generated as a result of footwall uplift and gravity collapse adjacent to the Inner Snorre Fault. Those slide blocks, which have not been carried east into the hanging wall basin and remain on the Zeta Ridge, show a well-defined internal stratigraphy which can be mapped on seismic data. Unusually, the Zeta gravity-slide is itself cut by younger, steeper faults, which dip to the west and comprise the western margin of the ‘twisted’ horst. Thus the fault zone at the eastern flank of the horst predates the gravity sliding, while the fault zone at the western flank post-dates the sliding. Forward modelling of the full syn-rift history predicts a total footwall uplift of c. 1750 m at the crest of the Zeta Structure. The Zeta gravity-slide can still be located on seismic data where it has been faulted down to the west, towards the Marulk Basin, as also can an associated erosional (footwall) unconformity. Both the fault plane and the unconformity are buried by the Draupne Formation indicating that all tectonic activity occurred during the Late Jurassic (s.l.) and did not extend into the Cretaceous.

PVT and phase behaviour analysis in petroleum exploration

This paper describes the application of PVT data, routinely determined for almost all conventional oil tests, with respect to petroleum exploration in a broader context. The use of PVT and phase behaviour analysis focuses on phase envelope evolution as a function of source rock maturity and secondary migration using both laboratory analyses and natural examples from the Ekofisk, Eldfisk and Snorre Fields as well as data from the Tampen Spur area and Barents Sea in general. PVT analysis is demonstrated to be applicable for relative maturity estimation, recognition of mixing effects, volumetric evaluation of complex reservoir filling histories and as a screening tool for oil population characterisation. PVT analysis is used in this paper as a tool complementary to organic geochemistry, allowing the integration and interpretation of data reflecting fluid response to geological conditions on a regional scale.

ノルウェー領北部北海Ｖｉｇｄｉｓ油田 落差の小さな断層によるシーリングについて

The Vigdis field is located approximately 200km north-west of Bergen in Norway. The water depth ranges from 230m in the south to 300m in the north.The hydrocarbon is accumulated in a westerly tilted fault block in the Tampen Spur area, where numerous fields also have been discovered.The main reservoir rock in the field is the Middle Jurassic Brent Group deltaic sandstone. The Brent delta prograded from south to north with its thickness of around 200m in the field. The Brent Group is traditionally subdivided into five formations in this area from the youngest to oldest: Broom, Rannoch, Etive, Ness and Tarbert. Although each formation basically has a high sand/shale ratio, the lowest sand/shale ratio or relatively high shale content is observed in the Ness Formation which behave very important role in the fault seal in this field.The field, consisting of three structural elements, called Vigdis West, Vigdis Middle and Vigdis East is bounded to the east by a truncation of the Base Cretaceous Unconformity, to the north and west by OWC and bounded to the south by the E-W trending cross fault. The displacement of E-W trending cross faults is so small that the Brent Group is juxtaposed each other across the faults. Thus the faults might be considered to be non-sealing, which was a main exploration risk for Vigdis Middle.After drilling of exploration/delineation wells, the fault plane analysis along each boundary fault revealed that the Ness Formation, richest in shale content enhanced the sealing capacity of fault. The OWC in the field vary among the structural elements. It becomes shallower from Vigdis West to Vigdis Middle. The relative positions of the Ness Formation and other sandstone rich formations along the faults control the OWC discrepancies.

Migration of hydrocarbons in the Tampen Spur area, Norwegian North Sea: a reservoir geochemical evaluation

Abstract This paper describes the application of reservoir geochemical protocols to a study of oil-field and regional petroleum compositional variations in the major fields in the Tampen Spur area. The Tampen Spur high is located in the middle of several oil-mature to gas-mature source-rock kitchens and most of the structures might receive petroleum from several different directions. Based on the definition of several different petroleum populations within the Tampen Spur area, we define five major petroleum charging systems. Correlating the petroleum population variations with geological information allows us to derive likely migration/fill scenarios for many of the oil-fields and requires us to invoke a new Upper Jurassic carrier system in parts of the area connecting Brent Group reservoirs across major faults. Based on this hypothesis, two exploration wells were drilled on structures to test this carrier and petroleum was found in one of the structures. An understanding of the migration pathways and petroleum drainage efficiency of the basins is of great economic interest, because most of the smaller substructures are marginally economic. Thus, it is important to provide an effective risk analysis and ranking of the satellite prospects prior to drilling. This study has demonstrated that filling and migration in a geological province are controlled by a series of complex processes and that the filling history of the structures within the Tampen Spur is more complicated than suggested earlier.

Results from a palaeomagnetic investigation of the Brent Group sediments in wells 34/10–16 and 34/10–17 showing evidence for complete remagnetization of the sediment

Abstract Cores from wells 34/10–16 and 34/10–17 in the Tampen Spur area, Norway were studied to establish a magnetic polarity stratigraphy for the Brent Group in the area. Approximately 100 samples from each well were treated by traditional thermal and alternating field demagnetization procedures and the apparent polarities determined. Thin sections were studied and scanning electron microscopy carried out with the purpose of verifying a primary origin of the remanent magnetization. Correlation of the two wells based on the polarity logs was in agreement with the lithoand biostratigraphic correlations. However, the mineralogical analysis did not determine any primary magnetic minerals, although potential remanence carrying diagenetic minerals were observed. This, combined with magnetic data indicating extensive remagnetization of the sediment, lead to the conclusion that the remanent magnetization of these sediments is late diagenetic, probably of Tertiary age. The results are not encouraging with respect to the use of palaeomagnetism as a chronostratigraphic tool for these sediments. It may, however, be useful for dating diagenetic events and, as a result of the strong secondary magnetization, magnetic orientation techniques can be successfully applied to the core material.

Subsidence, maturation and migration history of the Tampen Spur area

A complete study of the petroleum system of the Tampen Spur area has been carried out. The approach used was a two-dimensional TEMISPACK analysis of a seismic line crossing the area where various hypotheses could be tested and later applied in a three-dimensional sense. The profile crosses from the deepest part of the ‘Tampen Graben’ across the Visund Ridge and the Marflø Ridge to the Sogn Graben in the east. Four source rocks have been taken into account, two marine [the Draupne (the most prolific) and the Heather] and two deltaic [the Brent and the Dunlin]. Two different prospect types can be defined: the Brent at the top of the tilted blocks and Heather sand bodies at the foot of the eroded tilted blocks. Various hypotheses about the geometry of these sand bodies and about the contact between the rich Draupne source rocks and the sands have been tested. Maturation started in the middle Cretaceous, between 100 Ma in the deepest eastern part of the section (Sogn Graben) and 80 Ma for the Draupne on the Tampen Spur west graben. At this time, the structures were already sealed by the Cretaceous shales. Apart from the Visund Ridge, all the prospects are currently in the condensate or gas window. Overpressures are compatible with large closed faults. More data are required about the possible sealing of minor faults before any conclusions can be drawn. There is no easy migration path from the rich Draupne rocks to the brent reservoir and various hypotheses are discussed to explain the regional petroleum potential. One possible explanation for the regional charge is the contribution of the other source rocks, the Heather, the Brent and the Dunlin.

Subsidence, maturation and migration history of the Tampen Spur area

A complete study of the petroleum system of the Tampen Spur area has been carried out. The approach used was a two-dimensional TEMISPACK analysis of a seismic line crossing the area where various hypotheses could be tested and later applied in a three-dimensional sense. The profile crosses from the deepest part of the ‘Tampen Graben’ across the Visund Ridge and the Marflø Ridge to the Sogn Graben in the east. Four source rocks have been taken into account, two marine [the Draupne (the most prolific) and the Heather] and two deltaic [the Brent and the Dunlin]. Two different prospect types can be defined: the Brent at the top of the tilted blocks and Heather sand bodies at the foot of the eroded tilted blocks. Various hypotheses about the geometry of these sand bodies and about the contact between the rich Draupne source rocks and the sands have been tested. Maturation started in the middle Cretaceous, between 100 Ma in the deepest eastern part of the section (Sogn Graben) and 80 Ma for the Draupne on the Tampen Spur west graben. At this time, the structures were already sealed by the Cretaceous shales. Apart from the Visund Ridge, all the prospects are currently in the condensate or gas window. Overpressures are compatible with large closed faults. More data are required about the possible sealing of minor faults before any conclusions can be drawn. There is no easy migration path from the rich Draupne rocks to the brent reservoir and various hypotheses are discussed to explain the regional petroleum potential. One possible explanation for the regional charge is the contribution of the other source rocks, the Heather, the Brent and the Dunlin.

Recognition of caprock leakage in the Snorre Field, Norwegian North Sea

The aim of this study was the evaluation of the distribution of hydrocarbons in the Cretaceous ‘caprock’ succession that unconformably overlies the Triassic-Lower Jurassic reservoir of the Snorre Field. The Snorre Field is located in the Tampen Spur area of the Norwegian North Sea. Evaluation of the hydrocarbon distribution was based on data from hydrocarbon shows encountered during drilling and organic geochemical data from canned cuttings' samples, 27 DST oils and rock samples from two wells. Oil shows were recorded in the Cretaceous Shetland Group. Over the crest of the structure, oil shows were present up to 400m above the top of the reservoir. The occurrence of these shows coincided with high (>50%) gas wetness values of [ ∑(C 2–C 4) ∑(C 1–C 4) ]100 . The incidence of these high gas wetness values also showed evidence of a relationship with the thickness of the underlying oil column, but showed a poorer correlation with evidence of undercompaction/overpressuring in the Cretaceous-Tertiary succession. Gas chromatography and combined gas chromatography-mass spectrometry data from selected rock samples indicated that the liquid hydrocarbons in the caprock succession were similar in composition to the oil from the underlying reservoir. Although diffusion processes may play a part in the distribution of gaseous hydrocarbon compounds, bulk flow processes provide a better explanation for the distribution of liquid hydrocarbons in the caprock succession. The distribution pattern of the caprock hydrocarbons makes it unlikely that leakage along major fault planes represents the major emplacement pathway for these hydrocarbons. A combination of relatively low pore entry pressures in the undercompacted Cretaceous strata and extensive microfracturing of the caprock succession provide a more appropriate mechanism. Published estimates of hydrocarbon migration in the vicinity of the northern Tampen Spur suggest that the reservoirs of the Snorre Field began to receive a hydrocarbon charge during deposition of the Shetland Group, or shortly afterwards. Development of undercompaction/overpressuring in the argillaceous strata of the Shetland, Rogaland and Hordaland Groups may therefore be directly related to the filling history of the underlying reservoir.

Migration of petroleum into Brent Group reservoirs: some observations from the Gullfaks field, Tampen Spur area North Sea

Abstract Whereas the processes of petroleum generation and primary migration are beginning to be understood from a quantitative viewpoint, the process of secondary migration is still incompletely quantitatively understood. We estimate that typically the carrier systems feeding Brent Group reservoirs contain an average of around 3% residual oil saturation, the petroleum flowing in high saturation petroleum rivers through the most permeable carrier bed zones. Most of the carrier porosity contains no petroleum. The filling of the Brent Group reservoir in the Gullfaks field (Tampen Spur) is elucidated by petroleum geochemistry and this study indicates that the field has filled from more than one source basin and has been biodegraded post oil-emplacement. The complex filling and degradation history suggests that geochemical study of reservoir petroleum columns is a useful exercise providing information on the fillpoints of these complex reservoir systems and potentially information on the palacohydrogeology of the area.

Petroleum Migration, Accumulation, and Biological Degradation in the Tampen Spur Area, Norwegian North Sea: ABSTRACT

Petroleum Migration, Accumulation, and Biological Degradation in the Tampen Spur Area, Norwegian North Sea: ABSTRACT

SEDIMENTATION, SEA‐LEVEL RISE AND TECTONICS AT THE TRIASSIC‐JURASSIC BOUNDARY (STATFJORD FORMATION), TAMPEN SPUR, NORTHERN NORTH SEA

Statfiord Formation reservoir rocks (Rhaetian‐Sinemurian) of the Tampen Spur area, Northern North Sea consist of coarse‐ and fine‐grained units in alternation, in a succession up to 300‐m thick in places. The formation is interpreted in terms of coastal fans and fan deltas on a low‐energy coastline.Four broad facies associations are distinguished: subaerial fan and distal fan (partly subaqueous) deposits make up the coarse‐grained units, while the fine‐grained units consist of lagoon‐bay and floodbasin‐bay sediments. The deposits interpreted as subaerial fan‐plain and braided‐stream channels are dominantly cross‐stratified and plane‐bedded, coarse‐grained sandstones and fine‐conglomerates. The distal fan deposits, mainly massive or bioturbated finel/medium‐grained sandstones tend to occur at the base or top of the coarse units.The deposits interpreted in terms of a lagoon‐bay setting consist of wave‐rippled, flaser/lenticular bedded siltstone and fine‐grained sandstone in a “background”of dark grey mudstone with occasional coal beds. This association is thought to have originated largely in front of the fans. The floodbasin‐bay association, consisting mainly of red‐and green‐coloured, massive and bioturbated mudstone and silty sandstone is believed to have accumulated in ephemeral floodbasin lakes or in the inner regions of coastal embayments, between fans. In addition to the main associations, there are also marine reworked sandstones at the top of the formation in some areas.Sedimentation time trends within the coarse‐grained units reflect fan shifting and progradation. On the formation scale, the coarse units become coarser and more laterally‐continuous upward, whereas the fine units become dominated by the lagoon‐bay facies at younger stratigraphic levels.It is argued that the former was a response mainly to tectonics, while eustatic sea level rise accounts for the increase in marine deposits through time. The marine sandstone at the top of the formation suggests a transition from a low energy, protected shoreline to a higher energy, more open one; a change that is related to basin enlargement and increased rate of relative sea level rise at the Statfjord‐Dunlin Formation transition.