East Shetland Platform Research Articles

Origin of complex mound geometry of Paleocene submarine-fan sandstone reservoirs, Balder Field, Norway

The Balder Field is located on the northwestern margin of the Utsira High in Norwegian Blocks 25/10 and 25/11. The oil is trapped in thick massive submarine-fan sandstones of the Paleocene Heimdal and Hermod Formations and the Early Eocene Balder Formation. These sandstones which were deposited from high-density turbidity currents originating from the East Shetland Platform, are located close to the Paleocene sandstone pinch-out and form thick mounded reservoirs in the field. High-relief mounded geometries are believed to have been caused by a complex interaction between deposition and syn- and post-depositional soft-sediment deformation processes. Slumping, sliding and sand remobilization were the dominant deformational processes. Associated sand injections into overlying shales occurred during the soft-sediment deformation processes which dominantly occurred during Early Eocene. The sandstones which have excellent reservoir properties, appear to be in pressure communication and have a common oil-water contact which is probably related to the soft-sediment deformation processes with associated sand injections.

Eocene succession on the East Shetland Platform, North Sea

A sand-prone Middle Eocene sequence is recognized in three cored boreholes on the East Shetland Platform. Three lithostratigraphic divisions are recognized: Lower Sand Unit, Main Sand Unit and Upper Claystone Unit. The Lower Sand Unit is of fluvio-deltaic origin, occurring on the southern part of the East Shetland Platform. The Main Sand Unit represents the subsequent transgression of the delta. The unit comprises a set of highstand shelf systems tracts separated by glauconitic bands and reflected by palynological assemblage breaks. The presence of reworked palynofloras in sediments of late Middle Eocene age implies derivation of sediment from the north-west part of the East Shetland Platform. Although it is tempting to ascribe sea level changes to the sediment pattern, a tentative correlation with the Hampshire Basin only highlights the difficulties involved.

Distribution of granite and possible Devonian sediments in part of the East Shetland Platform, North Sea

Seismic data on the East Shetland Platform, at about 59°50'N 1°12'E, image 4.7–6.6 km of folded possibly Devonian sediments partly coincident with a geophysical anomaly previously interpreted as a granite pluton at shallow depth. Seismic and potential field data constrain the possible distribution of granite, and well data indicate that shallow, lithologidly variable basement rocks may surround the deep ?Devonian basin. Geology Series Halibut Bank and Bressay Bank sheets. It shows the depth in metres below sea level to base Cretaceous, and the location of the northern end of seismicline FGS-64, illustrated in Fig. 3. Good control on the seismic reflectors down to base Jurassic is provided by well3/28-1. Previous work . Although there is a positive gravity anomaly centred upon the western margin of the East Shetland Platform in block 9/3, Donato & Tully (1982) showed that there is a negative residual gravity anomaly in this area of the East Shetland Platform, when a regional gravity field, based on a model of crustal thinning beneath the Viking Graben, and the gravity effect of the known Tertiary and Mesozoic strata are subtracted from the observed gravity field. They modelled this negative residual gravity anomaly as a granite batholith 40 km in diameter, buried beneath approximately 2 km of sediments, with its centre close to seismic line FGS-64 (Fig.2) Donato & Tully (1982) also described an associated horseshoe-shaped positive magnetic anomaly around the margins of the negative residual gravity anomaly (Fig. 2). They drew an analogy with Chevoit granite, where similar

Sealing fault traps - an exploration concept in a mature petroleum province: Tampen Spur, northern North Sea

The Tampen Spur, located between the East Shetland Platform and the Viking Graben in the northern North Sea, has proved to be a very significant petroleum province. The area includes the Statfjord, Gullfaks and Snorre fields with recoverable reserves in the range 100-500 MSm³, as weIl as severallarge satellite fields in the nearby areas.

The Maureen Field, Block 16/29a, UK North Sea

Abstract The Maureen Oilfield is located on a fault-bounded terrace in Block 16/29a of the UK Sector of the North Sea, at the intersection of the South Viking Graben and the eastern Witch Ground Graben. The field was discovered in late 1972 by the 16/29-1 well, and was confirmed by three further appraisal wells. The reservoir consists of submarine fan sandstones of the Palaeocene Maureen Formation, deposited by sediment gravity flows sourced from the East Shetland Platform. The Palaeocene sandstones, ranging from 140 to 400 ft in thickness, have good reservoir properties, with porosities ranging from 18-25% and permeabilities ranging from 30-3000 md. Hydrocarbons are trapped in a simple domal anticline, elongated NW-SE, which was formed at the Palaeocene level by Eocene/Oligocene-aged movement of underlying Permian salt. The reservoir sequence is sealed by Lista Formation claystones. Geochemical analysis suggests Upper Jurassic Kimmeridge Clay shales have been the source of Maureen hydrocarbons. Estimated recoverable reserves are 210 MMBBL. Twelve production wells have been drilled on the Maureen Field. A further seven water injection wells have been drilled to maintain reservoir pressure.

The Emerald Field, Blocks 2/10a, 2/15a, 3/11b, UK North Sea

Abstract The Emerald Oil Field lies in Blocks 2/10a, 2/15a and 3/1 lb in the UK sector of the northern North Sea. The field is located on the 'Transitional Shelf, an area on the western flank of the Viking Graben, downfaulted from the East Shetland Platform. The first well was drilled on the structure in 1978. Subsequently, a further seven wells have been drilled to delineate the field. The Emerald Field is an elongate dip and fault closed structure subparallel to the local NW-SE regional structural trend. the 'Emerald Sandstone' forms the main reservoir of the field and comprises a homogeneous transgressive unit of Callovian to Bathonian age, undelain by tilted Precambrian and Devonian Basement Horst blocks. Sealing is provided by siltstones and shales of the overlying Healther and Kimmeridge Clay Formations. The reservoir lies at depths between 5150-5600 ft, and wells drilled to date have encountered pay thicknesses of 42-74 ft. Where the sandstone is hydrocarbon bearing, it has a 100% net/ gross ratio. Porosities average 28% and permeabilities lie in the range 0-1 to 1.3 darcies. Wireline and test data indicate that the field contains a continouous oil column of 200 ft. Three distinct structural culminations exist on and adjacent to the field, which give rise to three separate gas caps, centred around wells 2/10a-4, 2/10a-7 and 2/10a-6 The maximum flow rate achieved from the reservoir to date is 6822 BOPD of 24° API oil with a GOR of 300 SCF/STBBL. In-place hydrocarbons are estimated to be 216 MMBBL of oil and 61 BCF of gas, with an estimated 43 MMBBL of oil recoverable by the initial development plan. initial development drilling began in Spring 1989 and the development scheme will use a floating production system. Production to the facility, via flexible risers, is from seven pre-drilled deviated wells with gas lift. An additional four pre-drilled water injection wells will provide reservoir pressure support.

The Cyrus Field, Block 16/28, UK North Sea

Abstract The Cyrus Oilfield is located in Block 16/28 of the UK sector of the North Sea approximately 250 km (155 miles) NE of Aberdeen and 55 km (34 miles) NE of the Forties Field. The trap consists of a broad, very low relief four-way dip closure developed over a deeper tilted fault block. The reservoir consists of submarine-fan sandstones of late Palaeocene age, belonging to the Andrew Formation. Provenance was to the NW resulting from the early Tertiary sea-level fall which exposed the East Shetland Platform. The reservoir has been sub-divided into two zones, an upper zone of interbedded sandstones and mudstones with net to gross ratios of 0.4 to 0.6 and sandstone porositites of 12% to 18%, and a lower zone of massive fine-grained sandstones plus subordinate thin shales and limestones, with net to gross ratios in excess of 0.9 and porosities averaging 20%. The reservoir is filled with undersaturated oil of 35° API and is normally pressured. The estimate of initial oil-in-place is 75 MMBBL. Development of the field is centred on the use of BP's SWOPS (Single Well Offshore Production System) vessel using two horizontal field development wells which feed into a single seabed template for offtake. Ultimate recovery from the field is estimated to be approximately 12 MMBBL.

Deep crustal structure of the northern North Sea Viking Graben: results from deep reflection seismic and gravity data

The combination of deep reflection seismic interpretation (NSDP 84 data set) and 3-D modelling of free-air gravity data resulted in a regional crustal model for the Viking Graben area. The interpretation focuses on the structure of the crystalline crust which is displayed by depth sections, a map of the Moho, a map of the thickness of the crystalline crust and a map of the extension factor β. The thickness of the crystalline crust varies from 10 km near the centre of the graben to 30 km under the adjacent platforms. The thickness of the sedimentary cover varies from 11 km to 1 km, respectively. The topography of the Moho reflects, in a highly smoothed way, the top of the crystalline basement. The “seismic” Moho coincides with the “gravity” Moho, although some discrepancies are observed in the most extensively stretched areas. High β-values are observed, but no indications of the presence of oceanic-type crust associated with a crustal rupture have been found. The results are thought to favour a stretching model of graben development. A strong inclined reflection and associated reflection patterns in the East Shetland Platform are tentatively interpreted as a fragment of the Iapetus Suture. The asymmetrical structure of the graben is assumed to be associated with initial inhomogeneities in the crust.

Scaling Geologic Reservoir Description to Engineering Needs

Summary Three types of reservoir description models have been developed for Balmoralfield, North Sea, for different applications. A depositional model provides ageological basis for constructing a layer model and for exploration for similardeposits. The layer model provides a framework for calculating reservoirvolumetrics. A flow-unit model integrates geological and petrophysicalproperties, thus providing the most properties, thus providing the mostcomprehensive description for simulation and reservoir management. Introduction As a result of the increased interaction between geologists and engineers inresolving reservoir problems, geologists have become more aware of the need tovary the scale and style of geologic description according to particularengineering applications. particular engineering applications. Conventionalgeological descriptions normally are too detailed for reservoir engineeringsimulations and often are not in an appropriate format for relating toreservoir performance. A geological reservoir description of Balmoral field, North Sea, is presented here as an example of different scales and styles ofreservoir description for different applications. This study had threeobjectives:to develop a depositional model that would provide the basisfor a layer model and for provide the basis for a layer model and for anexploration model for similar tertiary deposits in the North Sea,todevelop a geologically based layer model to provide the framework forcalculating reservoir volumetrics, andto develop a flow-unit model thatcombines geologic and petrophysical properties to describe the reservoirpetrophysical properties to describe the reservoir more comprehensively forreservoir management purposes. Balmoral field, discovered by Sun Oil Co. in 1975, is located in the U.K. North Sea Block 16/21 a-b, 140 miles [225 km] off the northeast coast ofScotland (Fig. 1). Production from the field began in 1987 from a Productionfrom the field began in 1987 from a single floating production vessel. Thefield produces from Paleocene sands at an produces from Paleocene sands at anaverage subsea depth of 6,970 ft [2124 m] in water depths averaging 470 ft [143m]. The field is a 6 × 2-mile [9.7 × 3.2-km], northwest-trending, low-reliefanticline cut by a number of faults, trending predominantly northwest, with asecondary set trending northeast to east (Fig. 2). The approximate oil/watercontact (OWC) is at 7,050 ft [2149 m] subsea. Geologic Setting The Balmoral field is located on the southern tip of the Fladen Ground Spur, a southerly extension of the East Shetland Platform, North Sea. The FladenGround Platform, North Sea. The Fladen Ground Spur was a positive featurethroughout the basins of the Witch Ground graben in the west from the SouthViking graben in the east. Thick Mesozoic sediments present in the flanking grabens are absent on theFladen Ground Spur. It was not until the Late Cretaceous Age that the FladenGround Spur began to subside with the surrounding areas, although it stillremained a relatively positive feature. From the end of the Paleocene positivefeature. From the end of the Paleocene Age to the present, the area of theBalmoral field subsided along with the rest of the North Sea and was filledwith clastics from the bordering massifs. During the Paleocene Age, theShetland Platform to the northwest was uplifted and tilted eastward, givingrise to an easterly directed drainage pattern. Consequently, Late Paleocene andyounger clastic sediments in the area are composed of deltaic, shelf, andsubmarine fan deposits that are thought to have been derived from the Scottishlandmass to the west and northwest. Depositional Model Lithologies and Vertical Stratification Sequences. Of the 25 wells in thefield, 19 were cored. These cores were examined for sedimentologiccharacteristics, described below. Almost all the reservoir interval is composed of fine- to medium-grained, moderately to poorly sorted sand. Individual sand beds are typically massiveand unconsolidated except for occasional zones cemented with calcite. Dishstructures and vertical fluid-escape pipes are sometimes preserved within thecalcite-cemented zones. Many beds are probably amalgamated with sharp, erosivebases; however, these are usually not visible owing to the unconsolidatednature of the sand and, quite often, to heavy oil-staining. The calcite-cemented -zones are up to a few feet thick in cores. These zonesappear on sonic logs as high-velocity zones or spikes; thus their presence canbe determined in uncored portions of wells, allowing correlation between wells(Fig. 3). Many of the zones can be correlated across several wells, while otherzones occur within a particular stratigraphic interval in only one particularstratigraphic interval in only one well. JPT P. 202

Geopressured Jurassic reservoirs in the Viking Graben: modelling and geological significance

Formation pressure data from Jurassic and Triassic reservoirs of 192 wells (68 in the Norwegian sector, 124 in the UK sector) in the Viking Graben have been analysed. Several different pressure regimes are distinguished. An ‘open system’ consists of hydropressured reservoirs adjacent to the East Shetland Platform in the west and the Horda Platform in the east. A ‘restricted system’ consists of moderately geopressured reservoirs (overpressure typically lower than 1500 psi) located at greater distance from the platforms, and is interpreted to be in partial pressure communication with the open system through lateral or vertical pressure drainage. A ‘closed system’ consists of geopressured reservoirs practically isolated from the open system. In this system, formation pressure is assumed to be representative of the various overpressuring mechanisms active locally. Pressure data analysis suggests that pore pressure is mainly controlled by rapid loading, aquathermal pressuring, oil generation and possibly by shale dewatering above the depth for the onset of gas generation (formation overpressure typically in the range 1500–2500 psi). Gas generation is interpreted to constitute a major overpressuring mechanism below that depth (formation overpressure higher than 2500–3000 psi). In the former case, a pore pressure gradient approximately 50% higher than the hydrostatic gradient is estimated. In the latter case, a much more drastic overpressure increase with depth is suggested. This model also applies to the Norwegian Central Graben where only a limited number of wells tested Jurassic reservoirs. Despite unavoidable simplification and approximation, this model is believed to provide a better understanding of the areal distribution of geopressured Jurassic reservoirs in the Viking and Central Grabens. It may be used to impose constraints on hydrocarbon migration models and for prediction of porosity preservation in relation to reservoir overpressuring.

Sedimentology and reservoir potential of a ‘marginal facies’ limestone from the Cretaceous of the North Sea

The lower Cretaceous section of UK North Sea well 3/16-1, on the eastern flank of the Shetland Platform, drilled by Sovereign Oil & Gas plc, is dominated by marine ‘shelf-type’ limestones with a very low argillaceous content. In this respect it differs both from the typical open-sea coccolith-rich Chalk and from the argillaceous Cretaceous of the Viking Graben (the Cromer Knoll and Shetland Groups). Diagenesis has resulted in crystal overgrowths, corrosion, and development of very fine to coarsely crystalline void filling calcite. Cavities, of stromatactis type and the result of shell dissolution, are filled with radiaxial fibrous calcite. Porosity is mostly intercrystal with possible contributions from fractures and vugs. Hydrocarbon staining is confined to patches of void-filling calcite and partially cemented fractures. No oil staining was observed in the carbonate matrix. It therefore appears that oil migrated through the rock via fractures but was unable to penetrate the main fabric of the rock. The lithological and petrophysical characteristics of the interval are similar to the Chalk Group of Norwegian well 1/3-1. The thickness is considerably less in 3/16-1, probably as a result of deposition on a topographic high such as existed along the margins of the Viking Graben and the East Shetland Platform during the Cretaceous.

Hydrocarbon Habitat of East Shetland Basin and North Viking Graben of Northern North Sea: ABSTRACT

In the East Shetland basin, Late Jurassic rifting formed tilted fault blocks and unconformity traps sealed by onlapping Cretaceous mudstones. Important oil-bearing reservoirs are Middle and Lower Jurassic marginal/nonmarine sheet sandstones and restricted Upper Jurassic submarine fan/shallow-marine sandstones. Mature Upper Jurassic mudstone and Middle Jurassic coal source rocks located in half grabens downdip of the major fields, and in the flanking western Viking graben, generated oil in Eocene to Miocene time. Study of reservoir pressures, distribution, and structure defines the major Jurassic aquifers in the East Shetland basin. The geometric relationship of these aquifers to the source rock kitchens defines the volumes of source rock drained by the major oil fields. Quantitative modeling of the volume of oil generated and expelled from the source rocks (from geochemical and compaction data) accounts for the inplace reserves of the fields. In the Viking graben, deeply buried Jurassic fault blocks that now contain mainly gas condensate and high pressure salt water were sourced with oil in the Late Cretaceous to Eocene, and with gas in the late Eocene to Recent. Extensive vertical migration of oil has occurred from Jurassic source rocks and reservoirs through thick, microfractured, overpressured Cretaceous mudstones, up the fault zones reactivated in the Tertiary, and into an extensive Paleocene/lower Eocene aquifer sealed by Eocene mudstones. The oil was probably degraded during Miocene freshwater flushing, and displaced out of lower Tertiary traps up onto the East Shetland platform by subsequent gas migration. End_of_Article - Last_Page 794------------

Stratigraphy and Sedimentation of the Palaeocene Sands in the Northern North Sea

Summary The Palaeocene of the North Sea basin between 58°N and 62°N contains a number of reservoir sands. The regional tectonic setting, which was dominated by subsidence in the Viking Graben and Witch Ground Graben areas had an important influence on the thickness and distribution of the Palaeocene sands. Following deposition of the Danian, middle Palaeocene sedimentation was controlled by uplift and faulting along the flanks of these areas with large quantities of sand being shed off the East Shetland Platform. These sands were deposited in a nearshore shallow marine environment. With a decrease in tectonism, late Palaeocene deposition was dominated by the outbuilding of a delta system in the Moray Firth area with the northward spread of sands along the edge of the East Shetland Platform. At this time, the basin became increasingly cut off from open marine circulation. The top of the Palaeocene is marked by a regional unconformity representing a late Palaeocene-early Eocene transgression which affected much of northwestern Europe.

A proposed granite batholith along the western flank of the North Sea Viking Graben

Summary. A pronounced positive magnetic anomaly of approximately 300 gamma occurs over the eastern edge of the East Shetland Platform at approximately 60°N, 1E. After the removal of the regional gravity variation and the gravity effect of the known geological structure, it is found that this magnetic high correlates with a negative gravity residual anomaly of approximately 30 mGal. Seismic data indicate that these anomalies occur in an area of relatively shallow basement on the upthrown side of the main Viking Graben margin fault. The presence of a buried granite batholith of approximately 40 x 40km may explain the gravity, magnetic and seismic observations. The observed deviation of the fault defining the edge of the Viking Graben in the proximity of the proposed granite may be explained in terms of the tectonic influence of the buoyant granite block during the taphrogenic development of the graben.

Development geology of the Piper Oilfield

The Piper Oilfield lis in the UK Block 1517, 125 miles northeast of Aberdeen, Scotland. The field is situated on a shelf south of the East Shetland platform, and near the eastern end of the Moray Firth Basin. The field was discovered in January 1973 from a seismicly mapped structure and confirmed as a major oilfield during the year with five appraisal wells and one exploratory well. A steel platform with 36 well slots and space for two drilling rigs was centrally located over the field in 474 ft. of water in June, 1975, and made ready for production drilling by October 10, 1976. Commercial production was established December 7, 1976, when the P1 well came on stream at more than 30 000 b/d. Production is currently 290 000 stb/d of 37°C API, low sulphur oil and original recoverable reserves are estimated to be 618 million barrels. Production is from the Upper Jurassic Piper Sandstone, a high-energy, marginal marine and marine, shallow, shelf sandstone with gross thickness of 165–454 ft. The field comprises three parallel, tilted fault blocks on the north edge of the Witch Ground Graben. Blocks I and II cover 7149 productive acres and have oil columns of 1312 ft. from 7200 ft. subsea to a common oil-water contact at 8512 ft. subsea. Block III to the southwest borders the Witch Ground Graben and contains a small accumulation with separate oil-water contact at 9199 ft. subsea. A combination of favourable geological and engineering conditions together with extensive use of seismic data before and during development drilling has resulted in high production rates and the need for only one centrally located platform to maximize the recoverable reserves from Piper oilfield.

THE PROVENANCE AND DISTRIBUTION OF THE PALAEOCENE SANDS OF THE CENTRAL NORTH SEA

A study of the detrital heavy minerals from Palaeocene sandstones of the central North Sea basins has revealed that variations exist which cannot be explained in terms of varying conditions either during or after deposition, and therefore reflect the influence of distinct source areas. Four sand bodies have been defined on a mineralogical basis, two of which occur in the Central Graben and southern Viking Graben, derived from the E. Shetland Platform, the other two being developed in the Moray Firth area, derived from the Scottish landmass. These sand bodies, when related to the existing lithostratigraphic framework, define four phases of basin subsidence, with the sand depocentre alternating between the Central Graben and the Moray Firth basin. This oscillation in basin subsidence, the association with volcanogenic sediments and the apparent basement control on distribution of sands in the Moray Firth indicate a degree of tectonic control hitherto undescribed for the Palaeocene of the area.Studies of sandstones in or around the inferred source areas have revealed that the metamorphic basement was the major contributor to the sands of the Moray Firth, rather than the pre‐existing sandstones of Devonian, Permo‐Trias or Jurassic ages which occur on the margins of the Firth. Likewise the Old Red Sandstone or Permo‐Trias sandstones of the East Shetland Platform are not suitable source rocks for the sands of the Central Graben and in this case it has been necessary to postulate the existence, at least until the end of Palaeocene times, of Carboniferous sands on the Platform. Such sands in the central North Sea have been shown to possess a mineralogy not dissimilar from that of the Palaeocene sands in question.