Norway’s offshore fields produced record volumes of gas last year, and the country’s oil and gas production is set to climb steadily until 2023, according to the Norwegian Petroleum Directorate (NPD). This is in part due to the recent launch of various major projects, all of which are set to come onstream over the next five years. But another factor is improved performance from existing fields, helped by more efficient drilling and improved regularity of production facilities.
However, more discoveries will be needed to sustain the momentum beyond 2025, the NPD said. The `high-impact’ wildcats across the Barents Sea in 2017 delivered only one commercial find – Lundin’s 10-20 MMcmoe Filicudi – and plans submitted for this year suggest most exploration wells will be in the near-field comfort zone in the North Sea. On a more positive note, the average cost of an exploratory well on the Norwegian continental shelf was down to $30 million last year, around half the typical figure for 2013/14.
The NPD continues to push for exploration farther north, and has lifted its estimate of undiscovered hydrocarbon resources in the Barents Sea by 80%, compared with its previous analysis in 2015. Last year, the directorate also commissioned 4,500 km (2,796 mi) of 2D seismic over the Gardarbank High, a geological ridge between the Spitsbergen Bank and Hopen Deep Arctic regions. This program was a western continuation of a seismic survey acquired in 2016 over the eastern part of the northern Barents Sea. Processing of the full data-set should be completed this summer.
Subsea dominates latest Norway projects
Plans submitted for new Norwegian development projects late last year, and others anticipated during 2018-19, will add $30 billion of investment to the sector, the NPD claimed. One of the largest was Statoil’s $2.5-billion Snorre Expansion project in the North Sea, designed to recover an extra 200MMbbl from the Snorre field and extend production (which began in 1992) beyond 2040. The company plans to add 24 new wells, 12 for production and 12 for injection, connected to six new subsea templates, with alternating water/gas injection. These will be drilled by Transocean, with TechnipFMC supplying the subsea production equipment and Subsea 7 the pipeline bundle system, while Aibel performs associated modifications to the Snorre A platform.
Statoil’s vision of the expanded Snorre field development. (Courtesy Statoil)
Subsea features heavily in some of the other newly submitted proposals, including Statoil’s Askeladd and Troll Phase 3 gas projects in the Barents and North Seas. Aker Solutions will supply two manifolds and four subsea trees to tie Askeladd, discovered in 1981, into the Snøhvit export system to the LNG processing plant at Melkøya, close to Hammerfest. The same contractor will provide two manifolds and nine trees for the Phase 3 development on Troll’s western flank.
As expected, VNG Norge’s first operated project offshore Norway will involve a tieback of the Fenja (ex-Pil/Bue) field in the Norwegian Sea to the revamped Njord floating production platform. Facilities will include two subsea templates with six wells (three horizontal producers and three injectors)
Shell orders floater for Penguins
Shell, which has been a seller in the North Sea in recent years, has confirmed its commitment to the region by sanctioning re-development of the Penguins field, 150 mi (241 km) northeast of the Shetlands. This became necessary following the company’s decision to shut down the Brent field complex to the south: oil and gas from Penguins are currently processed via four subsea drill centers tied back to the Brent Charlie platform, which is close to ceasing production.
Fluor’s division in Manila, which previously delivered the facilities for Shell’s Malampaya Phase 3 project offshore the Philippines, will engineer and fabricate a circular Sevan 400 FPSO with a production capacity of 45,000 boe/d and storage for up to 400,000 bbl of oil. The pre-commissioned floater will also be designed to operate continuously at Penguins without the need for dry docking. Produced oil will be offloaded to a tanker, with the gas exported via a tie-in to the North Sea FLAGS pipeline. Additionally, Shell plans to drill eight new wells, tied back to the FPSO. The company and partner ExxonMobil each have a 50% interest in the project.
According to Wood Mackenzie, the 80-MMbboe project is the largest in the UK North Sea since Maersk Oil’s Culzean in 2015.
Another construction program heading to the Far East is Maersk Oil & Gas’ Tyra redevelopment in the Danish North Sea. McDermott International won the contract to provide engineering, procurement and construction of new topsides for seven of the fields’ platforms, plus connecting bridges, a flare, and six new module support frames (MSFs). Redevelopment is needed because of progressive seabed subsidence: the existing topsides will be removed by Heerema Marine Contractors, with the new MSFs placed (by the same company) on top of the jackets to support the new topside sets: this measure will effectively raise the platforms by 42 ft (13 m).
According to Wood Mackenzie, the 80-MMbboe Penguins project is the largest in the UK North Sea since Maersk Oil’s Culzean in 2015. The analyst foresees potentially up to 13 more UK field developments going forward this year with combined reserves of around 500MMboe, all coming onstream by 2021. As for UK offshore exploration, there could be five wells west of Shetland this year, WoodMac, claimed, and a Nexen-operated well on the HP/HT Glengorm prospect in the central UK North Sea.
Statoil to monitor Sverdrup reservoir changes
Statoil plans permanent reservoir monitoring of the Johan Sverdrup field in the North Sea from the start of production – a first offshore Norway, the company claimed. And the 380 km-network (236 mi) of fiber optic seismic cables on the sea floor and over 6,500 embedded acoustic sensors above the field will be the most extensive system of its type anywhere, the company added. Alcatel Submarine Networks will supply and install the equipment under a frame agreement that could include extending seismic coverage over the field’s southern extent.
The sensors should provide sharper seismic images of changes in the reservoir as production progresses, assisting placement of future wells and water/gas injection requirements. The field has an anticipated lifespan of over 50 years.
