Jeremy Beckman • London
Subsea center to assemble Ormen Lange compression station
Aker Solutions has opened a new subsea test/construction hall at its yard in Egersund in western Norway. The 1,900-sq m (20,451-sq ft), 26-m (85-ft) high facility is designed to accommodate large, sensitive structures demanding high cleanliness standards.
The first equipment to occupy the site will be the pilot subsea compression station Aker is developing for the Ormen Lange project in the Norwegian Sea, with dimensions of 35 x 6.5 x 13 m (115 x 21 x 42 ft) and a weight of 1,100 metric tons (1,212 tons). Statoil placed the order in July 2006 with the aim of evaluating whether subsea compression is practical in 900 m (2,953 ft) water depth for future phases of Ormen Lange, as a lower cost alternative to a platform.
Statoil plans to incorporate four trains identical to Aker’s pilot module on its full-scale compression station. Following assembly and testing in Egersund, the pilot will be transferred to the gas-reception terminal at Nyhamna for endurance testing in a purpose-built test pit.
The second phase of the Ormen Lange development, operated by Norske Shell, is nearing completion. Subsea 7 has chartered the new ROV support vesselNormand Pioneer for a variety of duties, including subsea template and pipeline inspection, and ship wreck surveys. The vessel can accommodate two work class and four observation class ROVs, all equipped to operate in water depths of 1,200 m (3,937 ft).
Statoil eases pressure at Statfjord
Statoil has re-classified Statfjord as predominantly a gas field, following changes implemented under the Statfjord Late Life project. The field has been one of the mainstays of Norwegian North Sea oil (and associated gas) production, having delivered 4 Bboe since coming onstream in 1979.
Under the recent redevelopment, Statoil is lowering the pressure of the Statfjord reservoirs, causing increased quantities of gas to bubble out of the remaining oil volumes. The field’s three platforms have been modified to handle oil and gas at lower pressures. Depending on the outcome, the company adds, similar schemes could be implemented at the Gullfaks and Oseberg field centers.
At the Kollsnes process terminal on Norway’s southwestern coast, Gassco has started tie-in work for the new P12 gas pipeline from Statoil’s nearby Troll A field. This is part of a modification program designed to decrease pressure losses from Troll A, thereby sustaining current production capacity. Gassco also is replacing and expanding the MEG regeneration and water treatment facilities at Kollsnes, which also handle gas from various other fields in the North Sea.
Topaz tied into Schooner
RWE-Dea has brought on stream the Topaz field 23 years after its discovery in the UK southern gas basin. An earlier attempt to develop the field in association with the Schooner extension project was unsuccessful. Instead, RWE-Dea opted for a single subsea well tieback via a 15-km (9.3-mi) pipeline to Tullow’s Schooner platform. The gas is exported to the Theddlethorpe terminal on England’s east coast through the Caister Murdoch trunkline system.
Also in the southern UK sector, Hansa Hydrocarbons has acquired Serica Energy’s operating interest in blocks 48/16a and 48/16b. Hansa farmed into the latter block last year, co-funding an appraisal well on the 2002 gas discovery Thoresby (previously named Chablis). This well encountered a higher-quality reservoir and hydrocarbon saturation.
Hansa is acquiring new high-resolution 2D seismic and is reprocessing existing 3D data to provide a more accurate depth image of the Leman sandstone reservoir with a view to tabling a development plan later this year.
Subsea fields can sustain UK’s future
The UK needs to develop a conveyor belt of smaller fields to sustain production at respectable levels, according to Oil & Gas UK CEO Malcolm Webb. In his keynote speech at a recent conference in London, Webb said the average size of discoveries on the UK shelf was around 15 MMboe, with 25 MMboe the typical size for a new UK development project.
Since the mid-1970s, UK fields have delivered a total of 40 Bboe to date, he added, with around 15-25 Bboe still to be recovered. “There is still huge potential in the northern North Sea,” he claimed, “even bigger in the central North Sea. “However, we must be smart in using the infrastructure in place, which was put in on the back of the mega-fields found in the early days of North Sea E&P. If we don’t use that infrastructure, it will be taken away, as these smaller fields do not justify their own infrastructure.”
Webb said investment was being further hampered by lack of progress on relief for decommissioning of UKCS installations. The industry had built up a £15 billion ($24.44 billion) decommissioning liability, he said, but the government has so far resisted requests for provisions to allow some of these funds to be redeployed for capital investment.
Howard Wright, analytical services manager at Infield, said the main challenge facing North Sea operators is aging infrastructure. Most of the early production facilities had a design life of 25 years, which in many cases has been exceeded. Over the next 10 years, condition monitoring will become increasingly important, he said, if these structures are to remain serviceable. “Being able to tieback new projects into existing infrastructure will also be important, particularly in terms of the associated liabilities.”
Chris Bird, technical director for Centrica Energy Upstream, which recently acquired Venture Production, agreed that recent UK gas prices of 40-50 p/therm ($0.65-0.81/therm) were making gas development sub-economic. “We need higher gas prices to invest in the future.” But he also felt resources and money were being wasted through over-engineering or poor project management.
Sevan study for Frøy
Det Norske Oljeselskap has commissioned a study by Sevan Marine into the potential application of a Sevan cylindrical-shaped FPSO for the Frøy field redevelopment in the Norwegian North Sea. This would be bridge-linked to an unmanned, dry-tree wellhead platform.
However, according to partner Premier Oil, various other development options are under review with companies operating in the Frøy/Heimdal area. One joint study, it claims, is reviewing export options as part of a wider area scheme also encompassing the Rind (formerly Little Frøy), Tue, and Frigg Delta/Gamma fields.
