A number of operators on the Norwegian shelf revealed updates of their field development plans at the recent Offshore Northern Seas conference in Stavanger, with a substantial list of projects and refurbishments going forward as part of the revitalisation of the Norwegian shelf. Meg Chesshyre has the details.
Statoil is targeting concept selection for the Skrugard area development in the Barents Sea in 2013, leading to a final investment decision and PDO submission in 2014, Statoil VP development Erik Strand Tellefsen revealed. The operator is hoping to turn the development into a field centre. Skrugard, discovered in April 2011, and Havis in January this year, contain an estimated 4-600 million boe.
Three concepts are under consideration – a circular unit with storage, a ship-shaped until with storage or a 240km pipeline to shore. A pipeline solution requires more capex and offshore loading more opex. Pre-drilling is expected to start in 2016 leading to first production in the later part of 2018. A total of about 40 wells are planned over an eight year drilling programme.
Concept selection for the giant Johan Sverdrup (previously Avaldsnes/Aldous Major) discovery on the Utsira High is targeted for the end of next year with submission of a field development plan in late 2014 and first oil from an initial phase in 2018. It will be a flexible development based on standard solutions, dependent on subsurface conditions, according to field development SVP Øivind Reinertsen.
Statoil is planning to deploy a spar on the Aasta Hansteen field (previously Luva) with an investment decision end 2012/early 2013 ready for first oil end 2016. This will be the world’s largest spar, the first on the NCS, and the first with condensate storage. The harsh environment and water depth of 1300 metres pose particular technical challenges. Technip has a letter of intent for the hull and will lead the project in a consortium with Hyundai Heavy Industries of Korea.
Statoil has also set itself an ambitious target to achieve an average recovery rate of 60% from the fields operated by the company on the Norwegian continental shelf. From last year to this year the average oil recovery rate for Statoil-operated fields in Norway rose from 49% to 50%, constituting 327 million barrels of oil.
‘We work internally in the company and together with partners, research institutions and suppliers to increase recovery,’ explained Siri Espedal Kindem, Statoil’s SVP for technology excellence. ‘We begin this work before a field is even developed and we continue this through the entire production phase.’ Half of the company’s NKr2.8 billion research budget is earmarked for projects to improve recovery, including a special centre for increased recovery in Trondheim.
Statoil’s sub-surface team on the Øseberg field was awarded the Norwegian Petroleum Directorate’s prize for improved oil recovery (IOR) for its work in increasing recovery by means of gas injection at ONS (pictured above). The recovery success story on Øseberg began with the Troll Øseberg gas injection project (TOGI), which came on stream in 1991. From 1991 to 2002 some 21.7bcm of gas were injected into Øseberg. Since then the Øseberg field has used its own gas as pressure support to extract more oil.
In addition to further drilling on the four permanent installations on Øseberg, work proceeds on tying back new discoveries to existing installations. The Stjerne development will come onstream next year. In addition, there are plans for more seabed templates and a fast-track development project in the prospective Øseberg area.
BP Norge’s new Valhall process and hotel platform is expected to start production later this year. A new platform, installed in 2010, was required due to subsidence in the seabed and the need for more efficient operation of the field. It has a design life of 40 years, and replaces the QP, DP and PCP platforms. It has a processing capacity of 120,000b/d of oil and 143mmcf/d of gas. The hotel facilities were put into use last year. There are 180 single bed cabins. It is powered from shore via a 294km long DC cable from Lista. The old PCP platform was shut down in late July.
BP is also mulling the construction and installation of two new platforms, Hod 2 and Valhall Flank West (VFW) between 2015 and 2020 as part of the Greater Valhall appraisal programme. This represents an investment of NKr25-30 billion including drilling of between 20 and 30 production and injection wells in phase one. The aim is significantly to increase the Hod recovery rate and to enhance the development of the west flank of the Valhall field. Removal of the old PCP, DP, QP and Hod1 platforms is scheduled for 2020-25. By 2050 BP aims to have achieved its vision of around 2 billion barrels of oil produced, double the amount produced from the Valhall area so far.
New wells and major workovers are also planned on Ula/Tambar starting next year to extend field life to 2028 and beyond.
First production from BP’s Skarv field (Skarv FPSO pictured above) in the Norwegian Sea is now looked for in the fourth quarter of this year. Start-up has been delayed for a number of reasons – construction delays in Korea, a recent strike in Norway, and weather delays last winter affecting the riser pull-in campaign. The Polar Pioneer is carrying out development drilling.
BG Norge is looking at start-up from the Knarr field in block 34/3 in 1Q 2014. The development consists of subsea wells tied into an FPSO with offshore loading to shuttle tankers and gas export through a new pipeline system into the UK Segal system. A lease-and-operate contract for the Knarr FPSO was awarded to Teekay in June 2011 and construction is well under way at the Samsung yard in Korea. Transocean Searcher will start drilling six production wells mid-2013. The proposed development concept for the Bream field (17/12-1) is similar to Knarr, with subsea wells tied into a leased FPSO. Sanction is currently anticipated end 2012/beginning 2013 ready for first production in 3Q 2015.
ConocoPhillips Norway has three large projects currently in the execution phase – the Ekofisk 2/4L accommodation and field centre, Ekofisk South and Eldfisk II. In addition extensive modifications are being carried out on existing facilities within the Greater Ekofisk area. The owners are investing NKr83 billion in the various development projects (2011 value) on Ekofisk and Eldfisk. Through the three development projects, ConocoPhillips says it is now laying the foundations for value creation in the Greater Ekofisk Area over the next 40 years.
The 2/4L jacket (built by Kvaerner Verdal) and the bridges (built by Smoe in Singapore) were installed on the field in June. The topsides, currently being constructed by Smoe, will be installed on Ekofisk in 2013. The Ekofisk South project includes the construction of the Ekofisk 2/4Z wellhead platform and the subsea facility Ekofisk 2/4VB. The jacket (built by Dragados) and bridge are due for installation this year. The topsides (constructed by Aker Egersund) go in next year. The 2/7S jacket for Eldfisk II is under construction at Dragados and is due for installation next year. The topsides being built by Kvaerner Stord will be completed in 2014. A new equipment room for Eldfisk 2/7A, built by Kvaerner Stord, was installed in July this year.
Sweden’s Lundin Petroleum is planning capital expenditure of NKr25 billion in Norway over the next four years, of which NKr15 billion will be on its operated Edvard Grieg and Brynhild fields, and on Bøyla, in which it is a partner. Production start up from Edvard Grieg (previously Luno) in block 16/1 is looked for in October 2015. Total capex for Grieg is NKr24 billion. A commercial agreement is in place for a co-ordinated development with Ivar Aasen (previously Draupne), operated by det norske oljeselkap, which is expected to start up in the autumn of 2016. Submission of the Ivar Aasen PDO is planned in December 2012, for a production start in the autumn of 2016.
Lundin has selected Norwegian fabrication contractors for Edvard Grieg. Kvaerner Verdal is due to deliver the 13,000te jacket in March 2014, and Kvaerner Stord the 21,000te topsides in April 2015. Transport and installation has gone to Saipem, and Prosafe is supplying a newbuild flotel. Statoil is responsible for the export lines, but the contract has yet to be awarded. Last month Lundin confirmed an option in the Edvard Grieg topside contract for Kvaerner to perform the offshore hook-up and commissioning assistance.
Lundin project director Bjorn Sund is confident of meeting a tight 36-month delivery schedule through the use of Norwegian yards. He observed that Korean yards lacked co-ordinated engineering and procurement, and time was lost with equipment manufactured in Europe being transported to Korea and back. ‘When we evaluated thoroughly you need to add another six months’ minimum construction time [building in Korea], which means that you are losing a season,’ he explained.
First oil from Lundin’s Brynhild field, a tieback to the Haewene Brim FPSO located at Shell’s UK sector Pierce field, is expected in 4Q 2013. Among the contractors are Aker (subsea production system), Technip (pipelines and installation) and Maersk Drilling (jackup). Shell is responsible for topsides modifications on Pierce.
Marathon submitted a PDO for Bøyla (previously Marihøne) in block 24/9-9S in June. Development of the discovery is planned with a subsea facility tied back to Alvheim (pictured above right). Expected production start-up is end 2013 or beginning 2014. Technip has EPIC contract for the subsea facilities.
Total Norge is hoping to award topsides, SURF and FSO contracts for the Martin Linge (previously Hild) field in blocks 30/7, 29/9, 30/4 and 29/6 by the end of the year. A contract for the 16,500te jacket for the field was awarded to Kvaerner in February. Production drilling starts in 2014 and first production is looked for in 2016. A PDO for the NKr26 billion field development was approved by the Storting in June. It has total recoverable reserves estimated at 189 million boe. Partner interests are Total (operator) 51%, Petoro 30% and Statoil 19%.
Wintershall is now eyeing a 2017 production start for the Maria discovery in Norwegian block 6406/3, Bernard Schrimpf, managing director Wintershall Norge said at ONS. The company is looking at either a standalone facility or a subsea tieback to the Heidrun or Kristin fields. Maria has an estimated 60-120 million barrels of oil as well as 2-5bcm of recoverable natural gas. An appraisal well in May confirmed the upper end of the discovery estimate. Concept selection is expected in early 2013, and FID in late 2013/early 2014.
Preliminary resource estimates for Skarfjell, discovered in March this year about 17km south-west of the Gjøa field, range between 60 and 160 million barrels of recoverable oil. Commercial viability as well as potential further upside will need to be confirmed during appraisal drilling in 2103. Additional exploration wells are also planned for 2012/13.
By the end of 2015 Wintershall is planning to invest up to €2 billion in exploration and field development in Norway and the UK. Field development in Norway will concentrate on Knarr and Edvard Grieg, and on Catcher and Cladhan in the UK. Wintershall’s target is to raise the daily production more than tenfold to 50,000 barrels of crude oil equivalent by 2015. The expansion plans are reflected in the rapidly growing number of employees. In 2013 the Wintershall head count in Stavanger is set to rise from over 200 to 300. OE