http://www.offshore-mag.com Jan 1, 2011 Jeremy Beckman • London
Orginal article here
Statoil has committed to compression for three of its main gas production centers on the Norwegian shelf. It aims to prolong output from existing fields under development, and to prepare the facilities for new roles as regional hubs.
The largest project in monetary terms is a subsea compression system for the Åsgard field complex on the Haltenbanken in the Norwegian Sea, where water depths range from 240-310 m (787-1,017 ft). Aker Solutions has the $552-million equipment contract, which includes a subsea compressor manifold station and template, three compressor trains, electrical control systems, HV power distribution, and topside tie-ins.
In the same region, Statoil has put a tag of $368 million on its plan to install a new compressor module on the Kristin platform, designed to introduce lower pressure production. This, the company says, will lift reserves recovery from the Kristin and Tyrihans fields by up to 115 MMboe, and will extend life from these fields and others in the area through 2029-2034. The new equipment should be installed during summer 2013, entering service the following spring.
Finally, in the North Sea, Bergen Group Rosenberg will build and install a compressor module on the Kvitebjorn platform. Statoil describes this as a “pre-compression” project, allowing for production with reduced wellhead pressure. Fabrication is under way on the gas turbine-driven compressor, which should be installed between 2012-2014. Gas from Kvitebjorn is piped to Kollsnes in western Norway. Bergen Group’s $161-$242-million contract includes an option for tie in of a condensate pipeline to the Valemon platform, also currently under construction.
UK majors add platforms
Major operators in the UK central North Sea have embarked on incremental developments. Total plans to install a new platform on the West Franklin field in blocks 29/5b and 29/4d in the high-pressure/high-temperature gas-condensate region. The aim is to produce 85 MMboe of fresh reserves via a new platform and initially three wells, which will be linked to the existing Elgin/Franklin production facilities. Total estimates the cost at $1 billion, and expects to deliver 40,000 boe/d when the platform starts up in 2013.
Apache Corp. has ordered a new satellite oil production platform for mid-2012 for the Forties field, which will be bridge linked to the Forties Alpha platform. OGN Group’s Hadrian Yard close to Newcastle in northeast England, will build the facility under a $242-million contract. It will provide Apache with 18 new slots for drilling development wells, along with HP gas compression for artificial lift and dehydration. Apache estimates Forties has a further 173 MMboe of remaining proved reserves, and is looking to maintain daily oil output at around 60,000 b/d through 2013 and beyond. AMEC, which used to run Hadrian, will manage modifications to Forties Alpha.
Hess extends South Arne
In the Danish North Sea, Hess and its partners DONG Energy, Noreco, and Danoil have approved a Phase III development of the South Arne field in license 07/89. The proposed scheme, designed to extract a further 15 MMboe, involves drilling and stimulation of 11 new wells, and adding two new wellhead platforms to the north and alongside the existing South Arne facility. One of the first contracts to be awarded was a pipeline bundle, which Subsea 7 will fabricate and install in 2012, linking the two new platforms. The field is in a water depth of 60 m (197 ft).
DONG recently made a new oil discovery in the Solsort prospect in license 4/98, drilled by the Maersk Resolute. Three side tracks also were drilled to define the limits of the find, all with positive outcomes.
Apollo shines for Lundin
Lundin Petroleum says its recent oil discovery well on the Apollo prospect in the Norwegian North Sea could be in the range of 15-65 MMboe. Well 16/1-4 was drilled by the Transocean Winner on license PL338 to target an extension of the Jurassic reservoir associated with Det norske oljeselskap’s Draupne find. But results suggest only a limited part of Draupne extends into the license.
At the Palaeocene (Heimdal formation) and Cretaceous levels, two oil columns were encountered. The well also penetrated 60 m (197 ft) of good-quality Cretaceous sands below the oil-water contact, suggesting potential up-dip of the discovery. It is not clear, however, whether Apollo could feature in Lundin’s plan for the Greater Luno Area development, which is expected to go forward later this year.
Studies re-assess Irish fields
Providence Resources has become operator of the Barryroe oil discovery in the North Celtic Sea off southern Ireland. The company says the partners will commission a new 3D seismic survey early in 2011, the results of which will help preparations for an appraisal/pre-development well. Discussions are under way with other consortia on the Irish shelf concerning a rig slot.
Independent analysts have estimated the field’s recoverable contingent resources at 59-144 MMbbl. Barryroe’s crude is waxy, and its reservoir architecture is complex, but Providence says this could be addressed via horizontal, artificially lifted well completions.
Providence also operates the 1981 Spanish Point discovery in 400 m (1,312 ft) water depth, 170 km (105 mi) off western Ireland in the Porcupine basin. Newly interpreted 3D seismic and wide-ranging modeling studies suggest 100-200 MMboe could be recoverable. Field development could involve drilling six to 14 fracture-stimulated wells, with potential plateau production of 30,000 b/d of oil and 250 MMcf/d of gas.
In the St. George’s Channel basin separating Ireland from Wales, the company has signed an optional agreement whereby Star Energy would farm into 50% of Standard Exploration License SEL 1/07. The permit is in 90 m (295 ft) water depth, and contains the mapped extension of Marathon’s 1994 Dragon gas discovery offshore west Wales, and the deeper-lying Orpheus and Pegasus prospects. Star would earn the farm-in right by conducting subsurface studies on Dragon, then participating in an appraisal well.