Wintershall commits to subsea tieback for Nova field development in the North Sea. Statoil employs new type of jackup for its latest drilling program at the Oseberg complex. Oil and gas production offshore the UK looks healthier in the years ahead.
|Jeremy Beckman London|
Nova heading subsea to Gjøa
Wintershall has initiated its second major subsea project as operator offshore Norway. The company has awarded the two main hardware installation contracts for the Nova (ex-Skarfjell) field development, and expects to submit its plan for development and operations to the Norwegian authorities by mid-year.
Nova, discovered in 2012, is in the northeast Norwegian North Sea, mostly within license PL 418. Wintershall estimates recoverable reserves at 80 MMboe. Production will be tied back to the Gjøa field semisubmersible platform via two new subsea templates (the company also operates Vega, an existing tieback to the same facility), with start-up anticipated in 2021. Gjøa will in turn send lift gas and water injection to the Nova wells for pressure support.
Aker Solutions will supply the production system, comprising the templates and a subsea control system, with construction spread between locations in Norway, the UK and Malaysia. Subsea 7 will design and install the two pipe-in-pipe production flowlines and the injection/lift lines, and will also install the entire subsea spread.
In the Barents Sea, Statoil and its partners have agreed to spend $643 million expanding the subsea production network for the Snøhvit LNG project. This will involve developing the Askeladd gas-condensate accumulation north of the Snøhvit field through an initial three wells linked to two subsea templates (again to be supplied by Aker Solutions). The added production, due to start flowing in late 2020, should maintain plateau production at the onshore Hammerfest LNG plant until 2023.
The newly installed Oseberg Vestflanken 2 platform. (Photo courtesy Statoil)
Askepott drilling from Oseberg H
Askepott, one of two new jackups built by Samsung in South Korea for the Oseberg and Gullfaks licensees in the North Sea, has started development drilling from Statoil’s new Oseberg H facility. The unmanned platform, built by Heerema Fabrication Group in the Netherlands, is a first for Statoil offshore Norway, and also its smallest platform, with no process facilities.
Drilling superintendent Niels Hoogerheide described the Cat-J rig as “state of the art” in terms of safety and drilling efficiency. To help the crew familiarize themselves with its capabilities, Statoil also invested in an onboard drilling simulator.Askepott is scheduled to drill nine wells over the next two and a half years for the Oseberg Vestflanken 2 development, with the overall project cost estimated at $830 million.
UK actions lift production
Britain’s offshore production during 2016-2050 could total 11.7 Bboe, according to the Oil & Gas Authority (OGA), 2.8 Bboe more than might have been expected prior to the measures advocated by the Wood Review in 2014 to maximize the UK’s remaining offshore hydrocarbon resources.
The OGA based its findings in part on the results of its 2017 offshore stewardship survey. These suggest that UK production is at its highest since 2011 and likely to go higher this year as new fields come onstream, led by BP’s Clair Ridge and Statoil’s Mariner in the Shetlands area. Output across the sector last year held steady at 1.63 MMboe/d, while overall capex costs fell for the third consecutive year. Opex costs, however, edged upward, with decommissioning expenditure rising by 4%.
Uphill task for west of Shetland E&P
Exploration costs west of Shetland (WoS) remain higher than in other UK offshore regions, according to Westwood Global Energy Group. And developing discoveries in this area is problematic, the consultant added, due to difficulties in securing access to established infrastructure.
Since 1972, 160 exploration wells have been drilled WoS accounting for just 6% of all UK offshore exploratory wells to date. Returns from drilling have been modest, Westwood claimed, with only four commercial discoveries from 23 wells in the area since 2008. This is in part due to the area’s complex geology, with Palaeocene basalt hampering seismic imaging in certain sub-basins. At the same time, finding costs are the highest on the UK continental shelf, at $14/boe, and although the average size of WoS discoveries is greater – 35 MMboe compared with 25 MMboe elsewhere – this is cancelled out by the associated costs of operating in the region, particularly in the harsher deepwater areas, which impacts development economics.
However, the potential resources are strong: Westwood estimates 2.4 Bboe from undeveloped discoveries, with unproven volumes at around 1.9 Bboe, and BP, Hurricane Energy and Siccar Point Energy are all working on new potential mid to large-size developments in the area. But the analysts believes a combination of new technological solutions, new plays and/or cluster developments will be needed to progress more widespread development in the province.
Balmoral reaches tail-end phase
Premier Oil is drawing up plans to decommission the Balmoral facilities in the central UK North Sea, although it may push cessation of production to 2021 after re-evaluating the performance of various fields connected to the infrastructure. In that case, further investments might be needed, the company said, to maintain the integrity of the wells, topsides and subsea equipment.
Some decommissioning is already under way, with Helix Well Ops’ intervention vesselSeawell having entered four suspended Balmoral water injector wells to determine their status and prepare them for P&A at a later date. Premier is also looking to dispose of/sell the Balmoral floating production vessel, which started operating in 1986.
Relief system on standby for Barents well
Add Energy and Trendsetter Engineering will provide access to their Relief Well Injection Spool (RWIS) for a well due to be drilled in the Barents Sea this spring. If called on, the system should facilitate high-rate kill operations – pumping mud at rates above 200 bbl/min – through a single relief well, using multiple vessels.
The RWIS is installed on the relief well wellhead beneath the BOP to provide additional flow connections into the wellbore. By means of high-pressure flex lines, the inlets accommodate pumping units from separate floating vessels (in addition to the relief well rig) to ensure a high-rate kill.