Jeremy Beckman • London
Norway round attracts new intake
Norway’s Petroleum and Energy Ministry has issued 10 further production licenses under its 2006 Predefined Areas (APA) scheme, bringing this year’s total of new awards to 58.
The 10 latest licenses are split between the North Sea (six), and the Norwegian Sea and Barents Sea (two each).
DNO was the most successful applicant, gaining three operatorships, with one apiece for Hydro and Statoil. The other five went to non-Norwegian companies, underlining the government’s commitment to opening up the shelf to outsiders. The successful foreigners were Nexen, OMV, Petro-Canada, and Wintershall.
Twenty-two companies will participate in these licenses. They include Genesis Norway, a joint venture between UK independent Genesis and Petroleum Geo-Services. The company is partnering operator Wintershall in part-block 33/12, close to the Statfjord field, and Nexen in part-blocks 34/8, 9 and 11, which includes an untouched gas discovery.
Other lesser-known licensees are Faroe Petroleum and Norwegian company Ener, the latter likely to be acquired later this year by Aberdeen-based Dana Petroleum. Both are in a DNO license within the same prolific chalk basin containing BP’s Valhall field.
The Norwegian Petroleum Directorate is also responding to the industry’s pleas to open up prospective areas previously closed to exploration. Last month, Fugro-Geoteam began the first of two NPD-financed 2D seismic acquisition programs this year in the Nordland VII and Troms II district off mid-Norway. These regions are close to the environmentally contentious fishing waters off the Lofoten Islands.
Frontier activity is also extending farther south. The Petroleum Safety Authority recently authorized Hydro to drill the first-ever exploration well in the Skagerrak region off southern Norway, at a location 49 km (30 mi) south of Farsund.
Ermintrude delivers for Statoil
In the Norwegian North Sea, near-platform exploration remains the safest and preferred option. However, Statoil’s latest success, on the Ermintrude structure, looks somewhat larger than the average routine tieback, with estimated reserves of 50 MMbbl. The well, the first drilled under APA 2003 production license 303, found oil in mid-Jurassic sandstones, 10 km (6 mi) north of the Sleipner complex. A planned sidetrack should determine whether gas and condensate overlie the oil.
Map shows location of Statoil’s Ermintrude oil discovery in production license 303, north of Sleipner.
Oilexco seems to have a monopoly on oil discoveries in the UK North Sea. Its latest find, Huntington in central block 2/14b, may also be its biggest to date. Analysts Merrill Lynch suggested in-place reserves of up to 150 MMbbl, based on the results of the initial discovery in late May, which encountered oil-bearing reservoirs in Upper Jurassic Fulmar sand and the Paleocene Forties intervals. The company has identified two analogous Paleocene structures in block 22/13b to the west, which it also operates.
Northern North Sea platforms for sale
Shell and ExxonMobil continue to downsize their operations in the UK North Sea. In recent years the two companies have offloaded jointly-owned facilities on the Auk, Fulmar, and Kittiwake fields in the northern and central sectors to tail-end optimization specialists Talisman and Venture Production. This spring, ExxonMobil also ceded most of its southern gas basin interests to France’s Perenco.
Now the duo has placed another cluster of declining Northern North Sea assets on the market. These include Cormorant Alpha and North, Eider, Kestrel, Pelican, and Tern, non-operated stakes in the Otter and Hudson fields, and an operated interest in the associated oil export system.
Both companies are also negotiating to sell their combined majority interests in the Dunlin, Dunlin Southwest, Merlin, and Osprey fields to London-based independent Fairfield Energy. Fairfield expects to gain control of all these fields later this year, and plans to drill new wells to prove up further reserves. Fairfield is also in partnerships looking to reactivate the abandoned Crawford and Maureen oilfields in the central North Sea.
Tom Botts, executive vice-president, Shell Exploration & Production in Europe, described the package as “relatively high cost assets...where other operators might be better placed to add value,” producing cumulatively only 25-30,000 boe/d.
UK gas developers under pressure
Speakers at a recent Oil & Gas UK presentation in London continued the negative theme. Willy Rickett, director general of the Energy Group at the Department of Trade and Industry, said that UK oil output has been sliding recently at a rate of 9% per year. “If this trend continues,” he added, “our production will dip from 3 MMb/d currently to 1 MMb/d by 2020.”
There are measures that could be taken to slow the decline, he said, which might realize an extra 600,000 b/d during 2020-30. “That is the challenge. But this is a mature, aging basin with aging infrastructure. That means we have to tackle frontier areas with more difficult geology, just at a time when global economic growth is driving up costs significantly.”
As for gas, imported supplies from Algeria and northwest Europe have helped drive prices in the UK over the past year down from £0.70-£0.20 p/therm. “The current price is equivalent to $20/bbl,” he pointed out. “That’s good news for customers, but low prices and high operating costs create challenges for gas project economics.”
BG Group’s UK upstream vice president Chris Cox agreed that production was getting tougher. “The reserves out there in the UK sector are generally in smaller fields, or in complex high pressure, high temperature reservoirs, or heavy oil, much of it remote from infrastructure and difficult to drill.
One problem is that some of the UK’s older platforms have recently been shut down for longer periods for long-overdue upgrades, and this too has impacted production, Cox claimed. This situation helped push UKCS operating costs 25% above the industry’s forecast in 2006, he added, and costs look set to rise further in 2007-08.
