Sandstones of Upper Cretaceous age are proving to be a significant new play along the eastern Atlantic margin. Recent successes offshore West Africa, such as the Jubilee Field, along with other discoveries at Tweneboa, Teak, and Enyenre in Ghana, prove the presence of reservoir quality channel and turbidite sandstones of Turonian and Campanian age. Gross reservoir thickness can exceed 120m and the quality is demonstrated by the Mahogany 2 well in the Jubiliee field, which flowed oil and gas at 4,448 bopd (39o API) and 5.1 MMcfgpd from Turronian aged turbidites. The nearby Enyenra 2A well found two Campanian aged channels containing at combined total of 32m of oil. With the Jubilee Field having booked reserves of 490 MMbo, and upside from other discoveries which could easily double this reserve, the potential of this interval is significant.
In the Norwegian Sea, drilling over the last few years has also demonstrated the presence of Upper Cretaceous aged sandstones. Among these are the Lange Formation (Turonian) sandstones, containing oil in the Sklinna accumulation (Block 6406/1), and the gas-bearing Nise Formation (Campanian) sandstones in the Luva discovery. The quality of the sands is extremely variable, with the Lange at Sklinna being quite shaley, with porosity of 10-18%, while in comparison the Nise sands in well 6707/10-1 have porosity up to 30% and permeability of 1,000mD.
Over the past few years WesternGeco has acquired 6,145 km2 of multiclient 3D seismic data in the West Loppa area of the Barents Sea. The initial West Loppa survey, shot in 2008, targeted the Triassic reservoirs in tilted fault blocks on the western flank of the Loppa High (GeoExpro Vol. 7, No. 3), where Statoil’s Skrugard well has recently made an important discovery (see ‘Hot Spot’, page 92.) The 2009 West Loppa Extension Survey first showed the presence of significant Upper Cretaceous fans further west in the Bjørnoya Basin, so in 2010 surveys were acquired to extend 3D coverage over this play.
To date no significant hydrocarbon discoveries have been made in Upper Cretaceous sandstones in the Barents Sea, but good quality sands have been proven in the Hammerfest Basin to the south of the Loppa High. What therefore is the potential of this play on which Lundin will spud a well shortly?
Potential Reservoirs
Seismic line illustrating terraced nature of Loppa High with associated submarine fans.
Tectonic framework of the Loppa High regionSandstones of the Knurr Formation (Hauterivian/Valanginian) are proven in well 7122/2-1, where a gross reservoir thickness 123m has a net/gross of 90% (10% porosity cutoff) giving a net sand of 111m, with a porosity of 18%. Additional sandstones are present in the Barremian Kolje Formation.
The sands are derived from erosion of the Jurassic and Triassic section from the crest of the Loppa High where today Paleocene aged sediments rest on Triassic rocks. Channel cuts within the southern flank of the Loppa High are visible on seismic data. These are the channels down which the erosive products poured and were deposited as debris flows or turbidites in the basin to the south. Well 7122/2-1 drilled through one such flow (fan) feature. The new WesternGeco seismic dataset displays similar fan bodies within the Upper Cretaceous section and the provenance of the sediment within these fans also appears to be the Loppa High.
The tectonic framework of the Loppa High region is dominated by two conjugate lineament systems that trend north-west to south-east and north-east to south-west. At the southern end of the Loppa High these two systems converge to provide a complex of down-thrown terraces to the west, and a subsidiary structural ridge with adjacent depositional centres. The Upper Cretaceous fans are clearly defined on the 3D dataset, often with bright amplitudes, and are seen to fill the lows in between and around the two high areas.
The excellent quality of the new data allows for good definition of the fan bodies, which can be mapped by amplitude extractions of the key Cretaceous section. The fans themselves appear to vary in gross thickness from 30-100m.
In addition to clear evidence of these fan systems, the seismic data provides considerable evidence of hydrocarbon presence in the form of gas clouds and direct hydrocarbon indicators. These are typically associated with deep-seated faulting.
Hydrocarbon Potential
Seismic line illustrating thickness of sediment in source kitchen with gas clouds and DHIs.
Vrms amplitude extraction maps illustrating fan bodies and inferred transport direction.With no hydrocarbons proven in this play to date, there are obvious risks and questions. Aside from the presence and quality of the reservoir, the main issues revolve around the migration of hydrocarbons into a reservoir and whether the result is likely to be oil or gas. Within the Barents Sea today, the two proven petroleum systems are of Triassic (Kobbe/Steinkobbe) age and Upper Jurassic (Hekkingen) age. Shale of the former is of high quality at outcrop on Svalbard (3-6% TOC), but in offshore wells drilled to date is generally of poorer quality at 1-3%. The Hekkingen shale is a rich source rock with TOC of 3-10%.
Within the Bjørnøya and Sørvestnaget basins in the southern part of the Barents Sea, rocks of this age are extremely deeply buried and have not been penetrated. Modelling predicts them to be in or through the gas window, and to have been through the oil window in the Cretaceous or early Tertiary.
However, thick, low-quality source rock intervals have been recognised within shales of the Knurr and Kolje Formations. TOCs are similar to the Kobbe at 1-3% and are considerably shallower within the western basins, seismic indicating depths of 2,000-4,000m. Within well 7199/12-1 Kolje shale contains kerogen type III and has hydrogen indices up to 200mg HC/gTOC. Generally, the shales are gas prone but some intervals show promise of oil. A similar Upper Jurassic lean shale, the Verrill Canyon Formation, is the source rock for much of the gas found at the Sable Island Field, offshore Nova Scotia, Canada. There the rock has average TOCs of 1.25% and average hydrogen indices of 300mg/gTOC.
It would appear, therefore, that gas is likely to feature in any discoveries to be made. However, migration from the deeper Triassic/Jurassic sources – particularly along the flank of the Loppa High – occurred via faulting and fracturing. It is possible that early migrated oil could have been trapped in Cretaceous sands and still be present if the trap has not been breached.
Untested Cretaceous Fan Play
Seismic line illustrating multiple fan systems.In conclusion, the WesternGeco 3D West Loppa dataset can be seen to have provided an insight into an untested Cretaceous submarine fan play within the Barents Sea region. Although drilling to date has yet to demonstrate the presence of reservoirs locally, the extensive nature of the fan systems provides a material opportunity. Taking a regional perspective, together with seismic evidence, it is suggested that such targets could be expected within the sequence identified as Upper Cretaceous in age.There would appear to be strong evidence of a working petroleum system within the region, from both regional well control and seismic data. The critical issue is whether the play is gas-prone and, if so, what degree of oil potential exists.
By integrating the wells drilled to date, together with the extensive 3D seismic database available, a coherent and consistent geological model of the region can be established which will help further elucidate this intriguing frontier region.
