Megaprojects and superlatives generally go hand-in-hand, and development of giant Ormen Lange natural gas-condensate field in the Norwegian Sea extends that trend.
The field, discovered in August 1997, is due to begin producing 2.5 bcfd of gas in October 2007. It will supply 20% of UK gas demand via a 1,200 km pipeline from Norway across the North Sea to Easington, UK. A connection at Sleipner platform will allow gas to be shipped to mainland Europe.
Life of the field, the second largest gas field on the Norwegian Continental Shelf after Troll, is estimated at 30-40 years. The $9.5 billion project is the largest in Norway's history, speakers told the Offshore Technology Conference May 6 in Houston.
Superlatives attributable to Ormen Lange relate to most phases of its operations, from the world's largest diameter wells, to pipelines that must traverse rough subsea terrain, to mitigation of hydrate and ice formation in the sub- zero waters.
The field lies on Block 6305/5 more than 100 km northwest of Aukra, Norway, in 3,300 ft of water near the base of the world's largest marine slide—at 90,000 sq km it is one third the size of Norway.
Reserves are 14 tcf of gas and 180 million bbl of condensate. Ormen Lange, or "giant serpent," is to be developed entirely on the seabed with only the possibility of a floating facility for compressors being installed 7 years after start-up. It is a zero discharge project.
Participants in Ormen Lange are Norsk Hydro ASA, AS Norske Shell, Statoil ASA, Esso Norge AS, Conoco- Phillips, BP Amoco Norge AS, Norway's state Petoro AS, and Gassco, the Norwegian gas transport operator. Shell will operate the field in the production phase, and Gassco will operate the pipelines after completion.
Most project spending will occur in 2005-06.
Field development
Already begun, Ormen Lange development faced numerous technical challenges, most of which were solved in Norway, the speakers said.
Field area conditions are seabed temperatures of –1-2º C., 30 m waves, and 40 m/sec winds, and the 40 by 10 km reservoir is 1,900 m below the seabed. Five wells have defined the field.
Norsk Hydro, which operates 12 other platforms in the North and Norwegian seas, and its partners decided the best option was to lay pipelines up the Storegga slide escarpment to a condensate separation plant at Nyhamna, Norway.
The A and B templates and manifolds 4 km apart will accommodate eight wells each and should drain the field, but the C and D templates can be tied in nearby if needed.
Subsea compression is to be added in 2016-17, and a decision on whether to use subsea or floating technology must be taken in 2011-12, said Bengt Lie Hansen, Norsk Hydro senior vice-president and chairman of the Ormen Lange management committee.
Continuous umbilicals that parallel the pipelines from the field to the condensate separation plant will permit control of production from Nyhamna.
With Ormen Lange producing, Norway's gas exports will reach 3.7 bcfd, making the country the world's third largest gas exporter after Russia and Canada, Hansen said.
The production facilities will be built near the upper headwall of the slide, said Petter Bryn of Norsk Hydro.
Multidiscipline studies showed low probability of further slides during field life or environmental damage, gas leakage, or other hazards in connection with operation of the field. A $100 million database resulted from the studies.
Multiphase pipelines
Two, 30-in. multiphase pipelines will carry the full well stream from producing wells to the Nyhamna plant. They will traverse a seabed pocked with peaks as high as 200 ft and scale the slide's headwall at a 25-35º angle. Pipeline inclination will be greater than 2.5º on 10% of the distance, greater than 1.5º on 20%, and greater than 1º on 30%.
From shore, concrete-coated pipe will be used out to 550 m of water and polypropylene-coated pipe the rest of the way to the field. Dredging, trenching, and rock dumping could represent as much as 20% of project cost, said Andres Henriksson of Norsk Hydro. For instance, 2.8 million tones of rock will be installed to level the route.
The system design enables well production to be routed through either manifold, production through only one pipeline, gas circulation (back flow from the plant or export line), and dynamic pigging (high velocity production rate). Pigging would occur with inspection every third year.
Two, 6-in. methyl ethyl glycol lines are planned to mitigate hydrate formation. The design includes a dosage system at each well and has 100% excess capacity available for overdosing. Studies showed little risk of low MEG concentrations in the 30-in. lines.
The 30-in. and MEG pipelines take separate routes at optimum locations for each.
The subsea compression concept involves providing 52 Mw of electric power at Ormen Lange to serve four, 12.5 Mw compressors and utilities, said Bernt Bjerkreim, Norsk Hydro chief engineer, subsea gas compression.
Ormen Lange's base case calls for floating compression facilities, but the operating group believes subsea compression will be qualified by the time it is needed. Statoil faces a similar compression challenge at Snøhvit field, Bjerkreim said.
The Langeled export pipeline consists of a 44-in. section from Sleipner to Easington to begin service in 2006 and a 42-in. section from Nyhamna to Sleipner to activate with Ormen Lange start-up in 2007. Langeled is the world's largest submarine pipeline.
Wells, other facilities
Design life is 30 years for field facilities and 50 years for the pipelines and umbilicals, said Thomas Bernt, Norsk Hydro subsea manager. Design temperature range is 85º to –20º C.
Well templates 44 by 33 m are to be installed in 2005. Hydro will drill the first eight wells and then use the well data to design the remaining wells. Horizontal wellheads will be used.
Wells will consume 78 drilling days and cost $33 million each. The project members decided to use eight wells with 95/8-in. tubing at a total cost of $264 million rather than 14 wells with 7-in. tubing at a cost of $462 million, said Robin Hartmann of Shell.
Fewer wells also minimize the risk of well intervention. "You cannot tolerate more than two wells down," Hartmann said.
The reservoir averages 28% porosity, has a permeability range of 6,250-35,000 md, and pressure of 4,060 psi. Well flow rates of 300-450 MMscfd are expected.
