Block 2/8, which contains the largest share of the oil and gas, was awarded as part of Norway’s first offshore licensing round in 1965. Production licence 006 went to Amoco, Amerada, Texas Eastern and Noco, and the oil discovery made there was named Valhall. The area containing Hod was awarded to the same group of companies in May 1969 as PL 033, and the first signals that it contained hydrocarbons came that same summer.
A 10-metre-thick oil zone was proven in a chalk layer 2 700 metres beneath the seabed. Although not considered commercial, this represented a milestone as the first indication of oil and gas in carbonate rocks on the Norwegian continental shelf (NCS). The problem was that seismic images were disrupted by a gas cloud located about 1 500 metres beneath the seabed, making them difficult for the geologists to interpret.[REMOVE]Fotnote: Rasen, Bjørn (2007): LF6A. Valhall at 25 … and it’s only the beginning , 59.
Five years were to pass before the area was investigated again. In the meantime, the neighbouring Ekofisk field had been discovered and brought on stream. That sparked new hope, and all doubt was swept aside when Zapata Explorer drilled well 2/11-2 in late 1974 and established that the area contained oil in commercial quantities.
Operator Amoco had made many attempts to prove hydrocarbons in PL 006, but without having luck on its side. It now found fresh inspiration and energy to explore block 2/8 more closely. The 2/8-6 well spudded by Waage Drill I in April 1975 finally encountered evidence of large hydrocarbon volumes, with a 100-metre oil-saturated zone in a Late Cretaceous formation. After this well had been plugged on 30 June, assurance that the discovery was commercial came from drilling two additional wells. Both Valhall and Hod were thereby seen as worth producing.
The Valhall field is an anticline – the geological term for a structure folded upwards – which slopes down in a north-north-west/south-south-east direction. This primarily contains oil in an area covering about 24 300 hectares (243 million square metres). The highest point is some 2 300 metres beneath the seabed, with its base 2 700 metres down. The part of the formation yielding production is limited to about 2 800 hectares, with the most productive region covering only 800 hectares at the crest of the structure. Recoverable reserves originally in place were estimated in 2013 at 185 million standard cubic metres of oil equivalent (scm oe). That included 919 million barrels (147 million scm) of crude oil, 27.4 million scm of natural gas and 5.5 million tonnes (10.5 million scm oe) of natural gas liquids (NGL or condensate).
Compared with many fields on the NCS, Valhall exhibits a number of extreme characteristics:
While a porosity above 45 per cent is not unusual, the highest proportion measured in an intact rock core was about 54 per cent – which means it contained more liquid than rock.
Laboratory measurements of cores show that, despite its high porosity, the permeability of the rock is low – typically between 0.1 and 15 mD in the reservoirs. The permeability of a material is a measure of the ability of oil and gas to flow through it.[REMOVE]Fotnote: Wikipedia. The first well tests demonstrated a higher level of permeability, up to several hundred mD, but most openings have been closed because of severe compression of the chalk layer.
The reservoir had an overpressure of more than 0.8 psi/foot (0.18 bar/metre), with the net pressure in its central area estimated to be 500 psi (34.5 bar). When production began, reservoir pressure was 6 535 pounds per square inch gauge (psig), or roughly 350 barg, at a depth of 2 500 metres beneath the seabed.
The characteristic features of Valhall’s carbonate reservoir are its weak load-bearing capacity combined with high porosity, challenges posed by chalk production, and a high level of compression – up to 15 metres in certain places. Since the field came on stream, these aspects have caused the seabed to subside by slightly over 6.5 metres at the site of the platform complex. The average rate of subsidence is eight centimetres per annum.
The primary structure is in the Tor formation, with a secondary reservoir forming part of the Hod formation. These hydrocarbon-containing structures extend over large areas, and have been named for the locations where they were originally identified. The Tor formation varies considerably in thickness, from nothing to 80 metres. Its reservoir quality is also very variable, with good porosity and permeability in the thickest parts. Generally speaking, the Tor formation has the highest levels of porosity and permeability of the two structures, as well as the biggest reservoir volume.
Chalk, the reservoir rock in Valhall, is primarily formed from fragments of coccolithophores. These unicellular plankton have a typical volume in the order of 0.3 to one micrometre (a thousandth of a cubic metre). In addition come a small quantity of plankton-like foraminifera and fragments of larger fossils, such as bryozoans and the like.
The Tor formation is divided into four main zones: Tor-D, Tor-M1, Tor-M2 and Tor-M3+ (including Tor-Ca). It comprises chalk deposited 60-80 million years ago during the Danian, Maastrichtian and Campanian ages of the Late Cretaceous.
The Hod formation was formed during the Santonian, Coniacian and Turonian ages, which lasted from about 95 to 85 million years ago.
Hydrocarbon sources and reservoir closures
Oil in the Valhall field originated in the Mandal formation, which comprises Kimmeridge clay in Upper Jurassic strata from about 150 million years ago. It probably began to form in the early Miocene, roughly 20 million years ago. A 1 000-metre-thick ”tertiary” shale zone dating mainly from the Palaeocene, Eocene and Miocene epoch (25-65 million years ago) covers the chalk structure to form the cap rock for Valhall. This impervious layer prevents oil and gas escaping from the Valhall reservoir. Hydrocarbons rising from the chalk zone (Cretaceous) penetrated small openings in parts of the shale as well as areas formed by diatoms and other intrusions with better permeability during the Miocene.
That in turn has created the gas cloud which slowed seismic signals over central Valhall and made it difficult to define the topmost layer when the reservoir was finally discovered in 1975. These challenges still exist, but new technology has made it possible to improve understanding of the reservoir’s extent and character.
The decision to develop Valhall was taken in 1977. It was appreciated that success or failure would depend on being able to control the precipitation of chalk in solid form without blocking oil production. Chalk production has always been a problem when drilling appraisal wells.
Valhall came on stream in 1982. Like most fields on the NCS, the recovery method used was pressure depletion – the overlying gas cap expands, the oil is driven out and the pressure falls. Since the very porous chalk is unstabilised, a lot of the reservoir energy derives from pore compression – squeezing the gas-filled spaces. This accounted in 2004 for more than 50 per cent of the energy driving the oil up from the reservoir. Excessive pressure can cause the oil to start boiling – in other words, the gas mixes with the oil in the water. This boiling (or bubble) point for oil declines as the pressure increases. Reservoir pressure in the upper part of the Tor formation have been below the critical bubble point since 1988. Avoiding gas bubbles forming in the oil is particularly important effective waterflooding.
The oil is piped in a dedicated line to the 2/4-J processing platform on Ekofisk and then on to Teesside in the UK together with output from other fields in the Ekofisk area. The gas is led directly into the pipeline to Emden in Germany.
Hod was tied into Valhall in 1991, and its production platform – the first unstaffed offshore facility in Norway – is remotely controlled from the latter field.
The WP wellhead platform was installed in 1996 to increase the number of wells while tapping reserves in the Valhall’s flanks through extended-reach drilling (ERD). Using this technique on the field has proved extremely difficult. Highly deviated wells drilled through the Eocene strata on Valhall have a high risk of failing to reach the flanks as planned. The problems with ERD were an important reason for the Valhall flank development (VFD) project, which involved installing new platforms in these areas in 2002 and 2003. Wells from these facilities make it possible to produce reserves which would have been difficult to access from the field centre.
Waterflooding began in January 2004 from the new IP injection platform, with the goal of providing pressure support to improve the recovery factor. Injecting water on Valhall has particularly targeted two parts of the lower reservoir, in addition to a well on the northern areas of the field. This procedure is very challenging on Valhall because it weakens and washes out the chalk, which is particularly weak on the field to start with. Efforts have been made to reduce this weakening, in part by blending oil-based mud with the injection stream. However, this has merely slowed the process and not prevented the seabed from subsiding (as on Ekofisk).[REMOVE]Fotnote: See the article on Ekofisk on the Ekofisk industrial heritage site.
The new PH platform was installed in 2010 to replace the QP and PCP structures put in place in 1982. These facilities were beginning to age and had subsided more than six metres in relation to the sea level since they were installed.
Barkved, O, Heavey, P T, Kjelstadli, R M, Kleppan, T, and Kristiansen, T G: “Valhall Field – Still on Plateau after 20 Years of Production”, paper presented at Offshore Europe 2003, Aberdeen, UK, 2-5 September 2003.
Valhall and Hod Well History Book , 2014.
Norwegian Petroleum Directorate, Facts .