- Testing of Saga's Kristin discovery in Mid-Norway's Halten Bank last spring. The positive results helped spur the new plan for a joint development including sister field Lavrans and two Statoil-operated accumulations. [16,026 bytes]
Mid-Norway gas stakes mountEurope's unquenchable thirst for gas is accelerating Mid-Norway's latest ambitious development. The Halten Bank South project is comparable to Asgard B, in that it links gas and condensate from several fields with different operators. But unlike Asgard's scheme, which took many years to resolve to the partners' satisfaction, Halten Bank South could go forward within a year of its main discoveries being confirmed.
Saga and Statoil propose merging four fields into one unit, with the host production facility, a TLP, housed on Saga's Kristin Field on block 6406/2. Kristin is a high pressure, high temperature reservoir, extensively appraised since its discovery in 1995. Sister field Lavrans, also part of the equation, was discovered shortly afterwards, with similar pressure characteristics. Statoil is contributing its Trestakk, Tyrihans North and South fields situated to the east, having earlier toyed with a standalone development scheme for Tyrihans North.
If the PDO is approved following presentation next June, production should start in 2001. Combined reserves are 200 bcm of gas and 100 million cu meters of oil and condensate. Saga would operate the field development, while Statoil takes charge of gas/fluids transportation and terminals. A link into the new Asgard area pipeline system might be feasible, perhaps involving added compression on the Asgard B facilities. But a new dedicated pipeline could also be under discussion.
If approved, this will be North West Europe's first new TLP since Conoco's Heidrun, also on the Halten Bank. It will include gas injection facilities to maximize condensate recovery from Kristin. Lavrans exploitation will involve some form of pressure depletion.
In Saga's other Norwegian stronghold, Snorre, the partners have decided on a steel semisubmersible with a full drilling package and associated subsea production facilities for the field's second development phase.
This will be based 9 km from the existing Snorre production TLP, and will produce an estimated 360 million bbl of oil plus some gas from the reservoir's northern flank (to be reinjected in order to boost oil recovery). Processed oil will be sent through a new line to the Statfjord B facilities for storage and onward export. Norway's Energy Ministry will issue its verdict on the PDO next spring - approval should lead to production in summer of 2000. Water depths, at 300 meters, are lower than those for the central installation.
Statoil, meanwhile, is also working on a collective plan for the Snohvit, Askeladden and Albatross gas discoveries in the Barents Sea with a view to exporting the 10 tcf-plus reserves to shore near Hammerfest for liquefaction. 2001 is the current target -again dependent on government approval next spring.
Central North Sea drilling intensifiesPhillips has announced an oil and gas discovery, named Kate, which extends across Phillips-operated UK block 22/28a and Shell/Esso's 22/23b. Two intervals were tested in the well, flowing 11,500 b/d and 22 MMcf/d in total. The water depth was 96 meters. A second exploration well is underway funded by the two block partners, this time operated by Shell, targeting another nearby prospect. Nearest infrastructure is the ETAP complex processing platform on BP's Marnock Field, 16 km to the south-east.
Amoco UK also has a new find in UK block 30/11b, provisionally titled Appleton Beta, which it claims could form a new hub for central area oil and gasfield developments. Managing director Clive Fowler described the oil quality as exceptionally high and light, with flow rates of 6,329 b/d and 13.4 MMcf/d of associated gas. Appleton is in a high pressure, high temperature area close to several development prospects including Amoco's Halley.
A new central area project team has been established, led by Richard Bozanich, to look at the hub options. Coincidentally, Amoco announced a long-term $160 million drilling program, scheduled to start in late 1998, using two newbuild harsh environment jackups, Rowan's Super Gorilla and Santa Fe's Universe-class Galaxy III, currently under construction by FELS in Singapore. Initial drilling will focus on further development of Amoco's Arbroath Field, in order to sustain production levels at around 30,000 b/d of oil into the next century.
Another Santa Fe jackup, the Britannia, recently performed what was claimed to be the world's first offshore underbalanced drilling operation, on Shell's Leman Field in the UK southern gas basin. Previous drilling using conventional mud system had led to mud losses of around 8,000 bbl. Through switching to nitrogen to reduce the hydrostatic load of the drilling fluid, mud losses to the formation were subsequently minimized.
BJ Services masterminded the package, which comprised nitrogen generators and compressors providing capacity up to 2,600 cf/m at 4,000 psi. Using conventional nitrogen pumping equipment and liquid nitrogen tanks, up to 20 of these tanks would have been needed every 24 hr to maintain the drilling process, BJ claims, which would have rendered the operation financially prohibitive.
Danish mainstay overlooked in acreage awardsDenmark has issued the first new licence awards under its new open-door policy. Acreage on offer lay outside the mature Central Graben area, where most Danish exploration has been sited to date. Of the five licences awarded, two went to groups led by Amerada Hess, which recently kick-started Denmark's South Arne oil development. But Statoil missed out, despite having revived the sector through its Siri Field discovery and subsequent development. Other awards went to Agip and a Maersk-led group for license 4/97, thought to be targeting a deep Triassic structural play.
A timetable was also announced for Denmark's 5th licensing round, covering all acreage west of the 6 degree-15 minute longitude - the same area opened for the 4th round, awarded in 1995. Applications are due in by January 27.
Where competition for acreage is close, a sliding scale rule may be applied, last used in the 3rd round. This opens the way to increased state participation during production, which seems like a retrograde step. On the other hand, the Oil and Energy Ministry may be confident of a high number of applications, with the Danish production sector currently buoyant, helped by the prospect of a new oil trunkline from South Arne.
Porcupine Basin yet to deliverIreland has also released details of its next licensing round, covering the South Porcupine Basin frontier region. On offer are 156 blocks in waters varying from 200 meters in the area close to the coast, descending to 2,500 meters in the south-west of the basin. Bids are due in by December 15, 1998, with licenses effective for 15 years.
The government's short-term oil hopes took a knock recently when Statoil decided to pull out of its planned Connemara Field development on the northern margin of the Porcupine Basin. Extended well tests on the two discovery wells yielded lower flow rates than expected, with faster than anticipated pressure drop. Statoil concluded that the Jurassic sandstone reservoirs were unconnected, and that the field was uncommercial.
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