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> Forside > Arkiv > GEUS and the 6th Petroleum Geology Conference 2003

North West Europe & Global Perspectives, London, 6 - 9 October 2003

Read abstracts on presentations by GEUS, conference theme: 'North West Europe & Global Perspectives'

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Migration and accumulation of hydrocarbons in the Danish area during late Cenozoic time: filling of the Kraka, Halfdan, Siri and Nini fields.

Erik.S. Rasmussen, Ole V. Vejbæk, Torben Bidstrup, Stefan Piasecki and Karen Dybkjær

Geological Survey of Denmark and Greenland, Østervoldgade 10, 1350 Copenhagen, Denmark.


A detailed subdivision of the upper Cenozoic succession of the Danish North Sea has resulted in new insight in the long distance and multiple migration of hydrocarbons and in the accumulation of hydrocarbons in different types of traps. The Central Graben area was filled with a thick pile of sediments during the Middle Miocene – Quaternary corresponding to a period of 15 Ma. As hydrocarbon expulsion from the most prolific source rock the Upper Jurassic Bo Member was initiated only 20 Ma years ago and still occur today, the Middle Miocene – Quaternary evolution is important. In the Middle Miocene the Central Graben area was covered by a sea with water depth of 500 to 700 m. During the Late Miocene (Tortonian) the basin was successively filled by prograding slope and deltaic sediments from the north-east. The progradational infill resulted in local tilting of the substratum due to the loading affect of the deposits. In the latest Late Miocene (Messinian) the main input of sediments occurred from the south as illustrated by a thick onlapping succession of upper Messinian sediments. The Pliocene sedimentation was characterised by regular infill from the east within a shelf to shallow marine depositional environment. Following the Miocene and Pliocene depositional evolution the North Sea Basin tilted due to strong uplift of the Fennoscandia Shield and increased subsidence and sedimentation rates within the Central Graben area. This further complicated the maturation of source rock, migration pathways and accumulation of hydrocarbons. The consequence of this complex burial history is examplified by the Kraka and Halfdan fields. The Kraka Field has a large down flank oil accumulation, which is a result of a porosity anormally formed due to early invasion of oil in this position before the late tilting of the North Sea Basin. The history of the non-structural accumulation of the Halfdan Field can easily be modelled and constituted a simple four-way dip closure during the Late Miocene where peak oil migration occurred. The Quaternary tilting of the North Sea Basin due to uplift of the Fennoscandia Shield and strong subsidence of the Central Graben area have resulted in a distinct gradient favourable for long distance migration of hydrocarbons. Possible migration routes especially within Paleocene sand layers have resulted in long distance migration of oil into the Siri submarine valley system. The northernmost indication of hydrocarbons has been recognised as far as 75 km from the source area. Long distance migration of hydrocarbon is also indicated by direct hydrocarbon indications (DHI's) throughout the Cenozoic succession in the Danish North Sea. Especially above known hydrocarbon accumulation in the Central Graben conspicuous DHI's can be seen. This indicates a pronounced vertical migration e.g. along active faults above these structures. [Top]

Thickness and porosity mapping of the upper Danian reservoir zone, Kraka Field, Danish North Sea

Lone Klinkby, Lars Kristensen, Erik B. Nielsen & Lars Stemmerik

Geological Survey of Denmark and Greenland, Øster Voldgade 10, DK-1350 Copenhagen K, Denmark


The Kraka Field in the southern Danish Central Graben is a small and only partly filled chalk field with its main reservoir in the upper part of the Danian Ekofisk Formation. This minor field is surprisingly situated on the top of the largest structure related to halokinetic movements in the Danish Central Graben with a four-way dip closure at top chalk level. A secondary hydrocarbon potential is found in the uppermost Tor Formation (Maastrichtian).

Synthetic seismic modelling combined with detailed interpretation of a 3D seismic data set covering the field has allowed mapping of an additional, Intra-Danian, seismic horizon between the top of the Tor Formation and the top of the chalk. The Intra-Danian seismic horizon can be tied to the base of the porous Danian chalk, thus allowing for the first time seismic mapping of the upper Danian reservoir zone in this area. On a semi-regional scale, the upper Danian is thin north of the field in the western Dan Field area and thickens south and south-east of the field. The reservoir zone is thin, 5-15 m over the top of the field and thickens to 15-25 m in a more or less concentric pattern away from the field before it starts thinning again northwards. The thickness variations indicate that an incipient Kraka structure was present during the uppermost Danian and influenced sedimentation. This is further substantiated by the presence of elongated scours or scars in the area around the top of the field, where the reservoir section has been removed prior to deposition of the overlying Palaeocene succession. The relief of the scars is 10-20 m and the scars are up to 500 m wide and 1–3 km long.

Well log data allow a further subdivision of the upper Danian reservoir zone into three units in the Kraka area. Characteristically, porosities deteriorate down through the reservoir zone as also observed in flank wells in the nearby Dan Field.

Seismic inversion data of the upper Danian reservoir zone show that the high porosities in the large crestal area extend downflank in a southeasterly direction, corresponding to the overall thickness increase in that direction. The estimated free water level is steeply inclined towards the south-east; combined it is taken as evidence for lateral migration into the field from that direction. Migration through the tight lower Danian chalk occurred along faults and anomalous high porosities are preserved in the active fault zones. Porosities are accordingly not only related to structural depth but shows a very complex pattern controlled by a combination of primary facies variations, structuring and filling history. [Top]

Evidence for a major sediment input point into the Faroe-Shetland Basin from southern East Greenland

Michael Larsen1, Andrew G. Whitham2

1 Geological Survey of Denmark and Greenland (GEUS), Geocenter Copenhagen, Øster Voldgade 10, DK-1350 Copenhagen K, Denmark.
2 CASP Department of Earth Sciences, University of Cambridge, West Building, 181a Huntingdon Rd, Cambridge CB3 0DH, UK.


Understanding the timing of sediment supply and demonstrating source areas are crucial for reservoir prediction in frontier basins of the North Atlantic. Recent studies have suggested that East Greenland provided sediment to the Cretaceous–Paleocene Vøring Basin (Morton and Grant 1998; Whitham et al. 2002) and there is strong evidence to support that a western source also existed for the Faroe–Shetland Basin. Pinpointing sediment input sites is an important refinement to these models.

Recent studies suggest that a major sediment input point existed in the Kangerlussuaq region of southern East Greenland in the Late Cretaceous and Paleogene and the sediment transfer path appear to have been controlled by a major northwest-southeast oriented lineament. The presence of a tectonic lineament in the Kangerlussuaq Region is suggested by a number of observations. First, a marked change in the distribution and thickness of the Upper Cretaceous succession shows that two sub-basins with different subsidence history may have existed in the region. Second, Paleogene sediments, which underlie the thick plateau basalt succession, are thickest along the axis of the eastern sub-basin. The dominantly coarse-grained marine and fluvial sediments show south- and southeasterly palaeocurrents parallel to the lineament (Larsen et al. 1999). Last the Paleogene volcanic succession shows important changes across the lineament. To the east of the lineament subaerial plateau basalts rest directly on basement or fluvial sediments, whereas to the west the basal lavas are interbedded with marine sediments and hyaloclastite foreset breccias up to 100 m thick.

With a pre-drift position less that 100 km from the present day Faroe Islands this new information has an important impact on our understanding of reservoir distribution in the Faroes area. Most models for the Paleogene infill of the Faroe-Shetland Basin show basinal sands sourced from the Shetland Platform thinning northwestwards. If the Kangerlussuaq region was a major sediment input point then northwestward thickening sand bodies might be anticipated, radically altering the propectivity of the Paleogene section in areas towards the Faroe Islands


Larsen, M., Hamberg, L., Olaussen, S., Nørgaard-Pedersen, N. and Stemmerik, L. 1999. Basin evolution in southern East Greenland: An outcrop analog for Cretaceous-Paleogene basins on the North Atlantic volcanic margins. Bulletin American Association of Petroleum Geologists 83 , 1236-1261.

Whitham, A.G., Fanning, M., Johnson, C., Morton, A.C., Pickles, C.S. and Strogen, D.P. 2002. Understanding sediment transport paths in the Norwegian Greenland rift: an East Greenland prespective. In: A. Hurst (Ed.) Onshore-Offshore relationships on the North Atlantic Margin . Trondheim: Norsk Geologisk Forening, 205-208. [Top]

Post-volcanic uplift history and basin evolution of the western N. Atlantic margin – evidence from the Palaeogene Kap Dalton Group, East Greenland

Michael Larsen1, Claus Heilmann-Clausen2, Stefan Piasecki1 and Lars Stemmerik1

1 Geological Survey of Denmark and Greenland (GEUS), Geocenter Copenhagen, Øster Voldgade 10, DK-1350 Copenhagen K, Denmark
2 Geological Institute, University of Aarhus, Universitetsparken, DK-8000 Århus C, Denmark


Following the extensive flood basalt volcanism that accompanied onset of sea-floor spreading in the North Atlantic region, marine sedimentation resumed during the Eocene. Along the East Greenland margin, post-basaltic sediments are limited to small, isolated grabens at, respectively Kap Dalton and Savoia Halvø between 68º30'N and 70º15'N. The sediments represent the scattered remains of a much more widespread, fluvial to shallow marine succession deposited at the western margin of the early North Atlantic Ocean.

Recently Larsen et al . (2002) documented the post-basaltic succession of fluvial, estuarine and shallow marine silt- and sandstones to be approximately 100 m thick based on field work in the two outcrop areas. The aim of this presentation is to provide an up-to-date stratigraphic synthesis of the post-basaltic succession at Kap Dalton and Savoia Halvø based on integration of palynological, sedimentological and sequence stratigraphical analyses of the new data set.

At Kap Dalton, the uppermost part of the lava succession contains interbedded marine strata and was thus extruded close to sea level. Subaerial weathering of the top of the lava formation, however, suggests uplift and a prolonged period of non-deposition after the cease of volcanism. This was followed by a marine transgression leading to erosion and deposition of a shallow marine succession dominated by locally derived (volcanic) silt- and sandstones. Two distinct coarsening-upward units topped by cross-bedded arkosic sandstones mark the progradation of the upper shoreface and may indicate episodes of relative sea-level fall at the otherwise subsiding volcanic margin. The uppermost part of the succession consist of siltstones and fine-grained sandstones deposited in a low energy offshore environment.

The study provides more reliable information on basin evolution and uplifts history along the western margin of the northern North Atlantic Ocean in Eocene and Oligocene time and place age constraint on the end of basaltic volcanism. Furthermore, the presence of arkosic sandstones within the early post-basaltic succession has implications for Eocene palaeogeographic reconstructions and provides positive information for the prediction of non-volcanic reservoir units forming a potential Eocene play type.

Larsen, M., Piasecki, S. and Stemmerik, L. 2002. The post-basaltic Palaeogene and Neogene sediments at Kap Dalton and Savoia Halvø, East Greenland. Geology of Greenland Survey Bulletin, 191, 103–110. [Top]

Filling history of a chalk field

O. V. Vejbæk , P. Frykman, N. Bech and C. M. Nielsen

Geological Survey of Denmark and Greenland, Østervoldgade 10, 1350 Copenhagen, Denmark.


This paper presents a study of the hydrocarbon filling history for the Kraka field, a chalk reservoir in the Danish North Sea. Reservoir simulation techniques are applied in combination with backstripping to the simulation of geological time scale secondary migration and filling of the Kraka Field. This chalk field has its main reservoir in the Danian Ekofisk Formation with the Tor Formation as a subordinate reservoir. Porosity is around 30% and permeability around 1 mD for the reservoir section. Excess fluid pressures in the reservoir are now around 5 MPa. Analysis of burial history by backstripping and decompaction shows that this pressure is probably caused mainly by rapid deposition in the latest Miocene to recent times as the magnitude corresponds with the thickness of these deposits. The excess fluid pressure is therefore assumed to originate only after 8 Ma b. p. and not to have dissipated significantly since onset. This means that the effective stress has been constant for at least the last 5 mio years. Porosity has consequently not changed significantly during that time span as compaction was inefficient. Maturation history indicates that main oil charging has occurred in the last 5 Ma. However, anomalous porosity on the southeast flank suggests that earlier hydrocarbon invasion under different trapping conditions has participated in the porosity development there. It is evident that the downward deteriorating porosity and permeability of the matrix require fractures in order to facilitate hydrocarbon migration through the lower part of the Chalk Group. Flow simulation of the filling dynamics of a chalk reservoir shows a complex filling geometry due to the high capillary entry pressures in the low-permeability chalks. Such internal barriers will re-direct the hydrocarbons, and residual oil accumulations can be left on the migration route. Due to differences in capillary entry pressure, the oil will first enter the Tor Formation from the migration pathway in the feeder fracture irrespective of the higher oil phase pressure at the level of the overlying Ekofisk Formation. The difference in capillary entry pressure is due to fundamental differences in reservoir quality of the two formations and not simply caused by a difference in porosity. The process of hydrocarbon charging is slow and equilibration of hydrocarbons with respect to pressure gradients therefore occurs very slowly. A case where hydrocarbons enter the reservoir zone 4 km down flank is investigated. This case shows that a time span in the order of 2 Ma is required for the hydrocarbons to reach the summit in an approximately equilibrium state. Results show that saturation profiles in drilled wells can only be succesfully modelled if re-imbibition is accounted for in the saturation modelling. [Top]

Oseberg Chalk - Targeting the Upside Potential in a Mature Field.

Britze, P., Vejbæk, O.V., Nielsen, E.B., Kristensen, L., Rasmussen, R., Ineson, J., Rasmussen, J.A., Japsen, P., & Sheldon, E.

Geological Survey of Denmark and Greenland (GEUS), Østervoldgade 10, 1350 Copenhagen K, Denmark.


The Norwegian Oseberg Field produces from Jurassic sandstones. Production is declining and additional reserves from other stratigraphic levels are essential to prolong the life span of the field.

The Shetland Group Carbonates of the Hardråde Formation have proven hydrocarbon bearing in many wells situated in the southern part of the Oseberg Field area. In order to evaluate the hydrocarbon potential and estimate the reserves of the Shetland Group chalks, an integrated seismic, sedimentological, petrophysical, biostratigraphical, modelling, and geostatistical study was carried out.

The Hardråde Formation extents onto the Horda Platform from the South into the southern part of the Oseberg Field. The Oseberg structure is thus located on the northwest margin of the North Sea Chalk Basin. The Formation consists generally of interbedded limestones and mudstones of Late Campanian to Maastrichtian age. By use of GR/DT log-lithology, the Formation has been divided into five informal units. Main focus has been on the uppermost reservoir carbonate S1 unit, as this unit is the thickest and is correlatable throughout the southern part of the Field. Petrophysical evaluation of the well data demonstrates that the S1 unit is hydrocarbon bearing sealed both at the top and bottom. The S1 unit consists of slumped or resedimented chalk, in situ pelagic chalk, and bryozoan sand. In general the thickness of the S1 unit varies from 30m in the southern part to less than 10m at the middle part of the Field. Porosity ranges from 10 to 30%, and permeability is expected to be around 1 mD for reservoir quality chalk. Hydrocarbon saturation is strongly affected by capillary forces and very long transition zones are expected. These characteristics are very similar to some Tor and Ekofisk Formation reservoirs of the Central North Sea.

The small thickness of the reservoir unit made it difficult to resolve the S1 unit on the seismic data. Post stack processing of the 3D seismic survey with spectral widening to 60 Hz enabled the interpretation and mapping of the Top, Base, and Isochore of the reservoir unit.

Mapping of the S1 reservoir has been carried in a number of different ways for comparison. Since the reservoir thickness is close to seismic resolution it has been mapped directly as well as with the application of geostatistics. This has allowed investigation of the uncertainty in gross volume. Net – gross ratios have been mapped both deterministically and using geostatistics. Porosity has been mapped using an empirical model as well as utilising inverted seismic data. The inverted seismic data shows some correlation to observed porosity and has thus allowed porosity mapping both using a deterministic approach and a geostatitical approach. Hydrocarbon saturation has been mapped using empirical models as well as more advanced saturation models. In this way, variations in the hydrocarbon pore volume as a function of both mapping approach as wells as inherent uncertainty from data number and resolution have been investigated. [Top]

Modelling seismic response from North Sea Chalk reservoirs resulting from changes in burial depth and fluid saturation

O. V. Vejbæk1, R. Rasmussen1, P. Japsen1, J. M. Pedersen2, G. Marsden3

1 Geological Survey of Denmark and Greenland (GEUS), Østervoldgade 10, DK-1350 Copenhagen, Denmark
2 Ødegaard A/S, Titangade 15, DK-2200 Copenhagen N, Denmark
3 Amerada Hess Aps, Østergade 26B, DK-1100 Copenhagen K, Denmark


Changes in seismic response caused by changes in degree of compaction and fluid content in North Sea Chalk reservoirs away from a well bore are investigated by forward modelling. The investigated seismic response encompasses reflectivity changes, AVO and acoustic impedance. Synthetic seismic sections, impedance cross sections and AVO response are presented as calculated on the basis of selected wells from the South Arne and Dan Fields, Danish North Sea and compared to field records.

The two main variables to use for seismic response prediction away from the well bore is depth of burial (changes in effective stress) and changes in hydrocarbon saturation. Three main modelling tools are used for the modelling: 1) Rock physics, 2) Saturation modelling and 3) Compaction/de-compaction modelling.

Rock physics theory is applied to obtain all necessary parameters for the complete set of elastic parameters for the application of the Zoeppritz equations. The challenge is not only to predict the shear velocity, but also to account for the changes in fluid content via application of the Gassmann equation. An approach akin to the one suggested for the Ekofisk Field by Walls et al. (1998) is applied for the prediction of changes in degree of compaction.

Hydrocarbon saturation in North Sea Chalk is strongly affected by capillary forces due to the small scale of the pores and transition zones in the order of 50 m are not uncommon. For this reason, potent saturation modelling is needed in order create realistic input for the seismic modelling. We use the EQR and similar saturation models, which have proved robust for the prediction of saturation profiles in Danish Chalk reservoirs.

Compaction modelling relies on simple exponential decay of porosity with depth, where abnormal fluid pressures are accounted for. A new set of compaction parameters is presented. These parameters are based on a study on the North Sea Chalk based on some 850 wells. The parameters appear to be sufficiently fine-tuned to allow fairly precise predictions of abnormal fluid pressures from observed average porosity. Based on this, the relative contribution to porosity preservation by abnormal fluid pressure and early hydrocarbon invasion may be estimated.

Modelling results of value in the search for subtle traps include: Reflectivity is correlating with porosity, acoustic impedance is primarily reflecting porosity variation rather than hydrocarbon saturation, and the poisson ratio may be rather sensitive to hydrocarbon saturation.

Walls, J. D., Dvorkin, J., and Smith, B. A. 1998: Modeling Seimic Velocity in Ekofisk Chalk. 1998 SEG Expanded abstracts, 4 p. [Top]

Lower Cretaceous deep-water limestones reservoirs in the Danish North Sea – an underexplored play

Finn Jakobsen1, Helle F. Christensen2, Lars Kristensen1, Lars Stemmerik1

1 GEUS, Øster Voldgade 10, DK-1350 Copenhagen K, Denmark
2 GEO, Maglebjergvej 1, DK-2800 Kgs Lyngby, Denmark


The Lower Cretaceous deep water limestones and marly limestones of the Danish Central Graben form a widespread, but as yet, poorly understood play with large hydrocarbon accumulations. Current production is limited to the DUC operated Valdemar Field, where oil is produced with flow rates of up to 3500 BOPD from long horizontal wells. Additional commercial accumulations occur in the Adda area to the east. In both areas, the reservoir is a thin, usually less than 300 feet (100 m ) thick, highly heterogeneous succession of hemipelagic limestone and marlstone of Late Hauterivian–Early Aptian age. In the Valdemar Field faults and fractures have a significant impact on both hydrocarbon distribution, productivity and well stability during production, and their distribution has been mapped based on image logs and seismic data to identify open and sealing faults/fractures. Combined with detailed petrophysical and geochemical analyses it has been possible to divide the field into discrete structural compartments separated by sealing faults. Gaussian curvature maps have been used to identify weakness zones that may cause deformation or cut of tubing due to differential rock mechanical behaviour of the various facies types.

The initial petroleum recovery from this complex reservoir was estimated to be approximately 1%; this paper describes a multidisciplinary effort of geoscientists, petrophysicists and reservoir engineers to improve knowledge on rock properties and fluid behaviour of this unusual reservoir succession. It is based on large sets of analytical data of porosity, permeability, clay-content and hydrocarbon saturation from cores in the Valdemar area that have been used to quantify internal heterogeneity and to establish a core-to-log correlation. First step towards a better reservoir zonation has been integration of log and core data to establish a coherent sequence stratigraphic framework. The Lower Cretaceous reservoir succession is divided into 14 reservoir zones in the Valdemar Field. Individual zones are below seismic resolution, in the range from 0–59 feet (0–18 m) with averages from 6–35 feet (2–11 m). They are internally heterogeneous and quantification of average reservoir properties is based on core data. The analytical data indicate linear relationships between porosity and permeability and between porosity and clay content; based on corrected log data, it is evident that porosity is depth and pressure dependent and that reservoir quality limestones are restricted to burial depths less than 9000 feet (3 km). The refined reservoir zonation indicates that the reservoir unit consists of two stratigraphic compartments separated by a low porosity, clay-rich limestone interval.

The refined reservoir zonation is consistent with the rock mechanical properties and can be used to guide directional drilling into intervals not affected by pressure drawdown during production. Combined with rock mechanics analysis and fault/fracture mapping it is now possible to delineate mechanical more stable areas where the most sensitive fault zones are avoided – aspects which are important for a low permeability rock where production will last for a long period of time. [Top]

Maastrichtian and Danian chalks of the Dan Field (M-10X), Danish Central Graben

Lars Stemmerik, Jon R. Ineson, Lone Klinkby, Lars Kristensen, Erik B. Nielsen & Emma Sheldon

Geological Survey of Denmark and Greenland (GEUS), Øster Voldgade 10, DK-1350 Copenhagen K, Denmark


The Dan Field of the Danish Central Graben is the largest of the Danish chalk fields. It was discovered in 1971 and hydrocarbons are produced from low-permeability uppermost Cretaceous (Upper Maastrichtian) and Danian chalks. The M-10X well of the Dan Field forms part of the database for the sub-regional integrated reservoir study focussed on the adjacent Kraka Field (Klinkby et al., Session 3, Tues. p.m.) and is representative of the reservoir interval reported by Vejbæk and co-workers (poster session). The aim of this core display is to illustrate features of the main reservoir units encountered in these presentations.

The Upper Maastrichtian section (upper Tor Formation) spans nannofossil zones UC20a–UC20d and comprises a uniform succession of pure pelagic chalks that are typically thoroughly bioturbated, naturally fractured and exhibit porosities of 25–30% and matrix permeabilities (air) of 1–3 mD. Incipient hardgrounds occur rarely and a weak cyclicity is developed, particularly in the lower part of the reservoir section, manifested by a metre-scale alternation of faintly laminated and bioturbated chalk. A prominent mature hardground is developed at the K/T boundary; it represents a significant hiatus, the lowermost Danian (nannofossil zones NNTp1, NNTp2A–D) being absent. The Danian chalk section (Ekofisk Formation, nannofossil zones NNTp2E–NNT2p5B) is subdivided into a lower unit ("Danian tight"), a succession of cherty bioturbated chalks and marly chalks with rare thin marlstone interbeds (porosity [Top]

Sub-basalt imaging – new insight from investigations of petrophysical and seismic properties of Faroes basalts (SeiFaBa project)

Japsen, P.1, Waagstein, R. 1, Andersen, C.2, Andersen, M.S.3, Djurhuus, J. 3, Mavko, G. 4, Boldreel, L.O. 5, Pedersen, J.M. 6, Petersen, U.K. 3, Rasmussen, R. 1, Shaw, F. 7, Springer, N. 1, White, R.S. 8 & Worthington, M. 7

1 Geological Survey of Denmark and Greenland (GEUS), Øster Voldgade 10, DK-1350 København K.
2 Geological Survey of the Faroes (JFS), Postbox 3169,Brekkutún 1, FO-188 Hoyvík
3 Unversity of the Faroe Islands, Noatún 3, FO-100 Tórshavn, the Faroe Islands
4 Stanford University, Dept. of Geophysics, California 94305-2215, USA
5 University of Copenhagen, Geologisk Institut, Øster Voldgade 10, DK-1350 Copenhagen K
6 Ødegaard A/S, Titangade 15, DK-2200 Copenhagen N
7 University of Oxford, Department of Earth Sciences, Parks Road, Oxford OX1 3PR, UK
8 University of Cambridge, Bullard Laboratories, Madingly Road, Cambridge CB3 0EZ, UK


The development of methods of seismic imaging beneath basalts is still hindered by a lack of knowledge about the elastic properties of basaltic sequences and the degree of three-dimensional heterogeneity. The SeiFaBa project (2002-2005) is funded by the Sindri Group as part of the programmes for licensees within the Faroese area and will address these issues.

The Glyvursnes-1 well was drilled by SeiFaBa through the Upper basalt series outside Tórshavn during autumn 2002. A full core and numerous logs were acquired from the 700 m deep well. During the same operations, the existing 660 m deep Vestmanna-1 well was reamed and logged. The two wells are central to a number of closely coordinated experiments, which all are targeted at creating firm data-derived models for seismic wave propagation through a succession of basalt by combining detailed analysis at core, log and seismic scales.

The seismic programme was initiated by a test during summer 2002 and the main part of the acquisition will be carried out during spring and summer 2003. The well site at Glyvursnes gives optimal conditions for combining VSP, offset-VSP and surface seismic experiments: the terrain is flat and the seismic effects of a nearby near-vertical shear zone can be studied in detail.

The investigations will provide a unique data set and new understanding of the petrophysical and seismic properties of Faroes basalt. Drilling of the new bore hole at Glyvursnes and re-logging of Vestmanna-1 in combination with the extensive data set for the Lopra-1 well will give valuable new stratigraphic control of the Lower, Middle and Upper basalt series on the Faroes.

The relations of sonic velocities of basalt to porosity, composition, stress and fluid content will be studied through detailed analysis of well logs and core material. This will allow for explanations of the sonic response of basalt in terms of physical and compositional properties and a better understanding of the seismic signatures of flood basalt successions. [Top]

Up-scaling of shape factors in fractured reservoirs

Flemming If1 & Peter Frykman2

1 COWI A/S, Parallelvej 2, DK-2800 Kongens Lyngby, Denmark. Present: Amerada Hess Denmark, Østergade 26B, 1100 Copenhagen K, Denmark. E-mail: Flemming.If@Hess.com
2 Geological Survey of Denmark and Greenland (GEUS), Øster Voldgade 10, DK-1350 Copenhagen K, Denmark. E-mail: pfr@geus.dk


This paper describes a procedure for calculating the matrix-fracture transfer shape factor for fractured reservoir models. The procedure is implemented in 3D and is using the Continuous Time Random Walk (CTRW) method.

In previous works the method has been implemented only in 2D, and has required a mesh produced by triangulation of the 2D fracture network. The CTRW method used here is extended to 3D in a simpler implementation with rectangular grid cells, which significantly reduces computation effort, but otherwise relies on the same principles. The method is based on modelling of random walk of particles through the matrix media. For each particle the random walk is terminated when the particle encounters a fracture and the random walk time is recorded. The average random walk time for many particles is used for calculating the shape factor for the investigated volume.

The calculated shape factor with this new method is compared with analytical estimates for idealised regular networks of fractures, and is also compared with flow simulation derived shape factors for more realistic fracture networks. The results demonstrate that the new method reproduces analytical and numerical results in simple fracture models from other studies, and furthermore is capable of analysing very complex 3D fracture models and their properties. The method has a potential in traditional dual porosity simulation in oil- and gas studies, and also in transport modelling where diffusion processes are the driving force in exchange between matrix and fractures. The method also has a potential as a general characterisation tool in fractured rock systems, where the shape factor and its distribution can be used as a qualitative descriptor of the rock-matrix block-geometry, and as an indicator of the behaviour of matrix-fracture exchange processes.

The method is incorporated in an upscaling tool where the fracture model can be discretised in different grid cell sizes and geometries and upscaled to larger grid blocks for input to dual porosity reservoir simulation.


Matrix fracture exchange. Shape factors. Upscaling. Dual porosity simulation. [Top]

The structural and geological development of the North-West Atlantic margin, East Greenland

Niels. E. Hamann1, Richard C.Wittaker2 & Lars Stemmerik3

1 Nunaoil A/S, DK-3900 Nuuk, Greenland
2 Geoactic, 1620 9th Street NW, Calgary, Alberta T2M 3L4, Canada
3 GEUS, Øster Voldgade 10, DK-1113 Copenhagen


The acquisition of a regional offshore seismic survey as part of the KANUMAS Project has provided the first data set that allows a more detailed understanding of the structural and depositional history of the East Greenland shelf between aa and xx N.

The East Greenland shelf can be subdivided into a series of tectonic elements, many defined for the first time in this study. Several of the structural elements can be linked to plate tectonics features along the North Atlantic margin, thus confirming the pattern known from the Norwegian shelf.

No wells have yet been drilled on the East Greenland shelf, so no direct stratigraphic correlation of the seismic has been possible; therefore the well-exposed and well-known succession onshore East and eastern North Greenland has been used to calibrate the seismic units.

A major Upper Palaeozoic salt basin, located in the north-eastern part of the shelf, was initially controlled by a pre-existing tectonic framework following a N–S trend in East Greenland and along a WNW alignment in North Greenland. Mesozoic rifting reached maximum intensity in the latest Jurassic and continued into the Cretaceous.

Tectonic activity became concentrated towards the centre of the North Atlantic rift system in successive phases, and basin subsidence began to take a NE orientation along the developing continental margin. Following the opening of the Atlantic Ocean in the Early Eocene deposition took place on a subsiding continental margin in a period of post-rift thermal subsidence. Passive margin subsidence was interrupted by at several distinct phases of regional basin margin uplift and inversion, resulting from several different controlling mechanisms.

GEUS and the 6th Petroleum Geology Conference 2003