Jeremy Beckman • London
Tyrihans starts up in Norwegian Sea
StatoilHydro has brought on stream Tyrihans, its main new source of production on the Norwegian shelf this year. The field was discovered in the Norwegian Sea Halten Bank region in 1982/83, and has been under development since February 2006. Recoverable reserves are estimated at 186 MMbbl of oil and condensate and 41.5 MMcf of gas.
Tyrihans comprises two structures in 270 m (886 ft) water depth: Tyrihans South, an oil field with a gas cap, and Tyrihans North, a gas-condensate accumulation with a thin oil zone. Both are producing through subsea wells connected to five templates, with the producers incorporating subsea multiphase meters. Production is routed through a 43-km (26.7-mi), 18-in. (45.7-cm) multiphase pipeline to the Kristin semisubmersible platform for processing. Treated gas is channeled through the Aasgard Transport trunkline, with oil and gas piped to the Aasgard C platform for export via tanker offloading.
Tyrihans map (Source: Total)
A separate 42-km (26-mi), 10-in. (25.4-cm) pipeline funnels gas from the Asgard B platform to Tyrihans' two gas injection wells. From next summer, further pressure support will be provided by subsea pumps injecting raw seawater, a first for the Norwegian shelf. During 2016-17, StatoilHydro expects Tyrihans' output to build to a peak of 96,000 boe/d.
Total, a partner in the development, has been drilling an appraisal well on Victoria, one of the Norwegian Sea's and Norway's largest high pressure, high temperature gas prospects. The well reached total depth last month, with a logging/testing program to follow. Results, however, may not be issued until late this year.
UK drilling on downward curve
Drilling activity on the UK shelf between April and June dropped 57% compared with the same period last year, according to Deloitte's latestNorth West Europe Review. The report counted a mere 15 exploration and appraisal well starts throughout the sector during the period, also down 15% from the first quarter of this year.
Of these latest spuds, 54% were West of Shetland and across the Moray Firth, with a further 40% divided between the Central North Sea and the Irish Sea, and only 6% in the southern gas basin.
Graham Sadler, director of Deloitte's Petroleum Services Group, says the low level of activity reflected the difficult economic conditions, the need to control costs, and increasingly tight exploration budgets. He contrasts this with the picture offshore Norway, where E&A drilling rose 50% in the second quarter of this year compared to the corresponding period last year. Here the sector has been lifted by StatoilHydro's intensive near-platform drilling campaign, and by Norwegian government tax incentives.
Oil & Gas UK's latest economic report also identifies a dip in development drilling, with only 31 new wells in this category on the UK shelf in the first quarter of the year. Throughout 2008, there were a total of 170 development wells on UK fields, the association claims, adding that "a significant number of operators are known to have reduced platform-based or externally sourced drilling."
Norway wells maintain momentum
StatoilHydro's rolling exploration program has led to two further finds in the Norwegian Sea. Titan, a small oil accumulation in the Tampen area, was discovered by two wells drilled by the semisubScarabeoV in Upper Jurassic and Brent sands. The oil zones in the wells are thought to be in communication, and the estimated volumes of 5.6-12.5 MMboe should justify development through the Visund infrastructure to the south.
North of Skarv, theOcean Vanguard encountered gas while drilling a mid-lower Jurassic target in 377 m (1,237 ft) of water. Initial results suggest up to 3 bcm recoverable, with potential for further volumes elsewhere in the structure. StatoilHydro is a partner in the BP-operated Skarv/Idun development project, and the partners may consider a tieback once the FPSO is in place.
In the North Sea, Wintershall has achieved its first substantial find since acquiring indigenous operator Revus Energy last December. Its well on the Grosbeak prospect in license PL 378, drilled by theSongaDelta, proved oil and gas in Upper- and Mid-Jurassic reservoirs, with volumes estimated at 35-190 MMboe recoverable. Partner Noreco says there are four other main prospects in the license which could hold up to 375 MMboe gross. The location is east of StatoilHydro's Astero discovery, and is within reach of production infrastructure.
Petrofac buys UK floater
Facilities management specialist Petrofac has acquired theAH001 semisubmersible platform from Hess and Endeavour Energy. Since 1989, the AH001 had been stationed on Hess' Ivanhoe and Rob Roy fields in the UK North Sea, tying in production from Phillips' Renee and Rubie fields in 1999 (later transferred to Endeavour).
The 17,000 metric-ton (18,739-ton) platform has been towed to the McNulty yard in northeast England for an upgrade program, with a view to re-deployment on fields where Petrofac has or can take an interest, via its subsidiary Energy Developments. Currently the facility has processing capacity of 70,000 b/d of oil and 42.5 MMcf/d of gas, with water injection capability of 72,000 b/d.
Petrofac gained its first experience as a production operator in the North Sea in April when the West Don field came onstream. An associated development, Don Southwest, started up in July via two production wells – as with West Don, these are exporting oil to another semisub, theNorthernProducer. During drilling of a water injection well on Don Southwest, the wellbore was sidetracked to an adjacent fault block, immediately south of the field, which revealed a 60-ft (18.3-m) oil column in the Brent formation. This structure and its lateral extent are currently under assessment.
Svane may demand mass fracture
Newly released data from the Danish Energy Agency DEA suggests that the Svane discovery, drilled by Phillips in 2001-02, could be Denmark's largest gas field. The Svane-1A well was drilled in the northeastern part of the Danish Central Graben as a vertical well, with a sidetrack extending the depth to almost 6 km (3.73 mi). Gas and condensate were encountered in several late-Jurassic sandstone layers at a sub-surface depth of 5,400-5,900 m (19,357 ft), 300 m (984 ft) deeper than originally planned.
The well penetrated more than 630 m (2,067 ft) of a gas-filled reservoir without reaching the gas-water contact.
However, the high pressures and temperatures at this depth, with very tight sandstone layers, will make production difficult, probably requiring large numbers of deep wells with hydraulic fracturing. This is a problem DONG may have to solve, as the current operator.
