Norway's offshore electrification grid

The Utsira High network powers a number of key fields on the Norwegian Continental Shelf including:

• Johan Sverdrup (Equinor)
• Edvard Grieg (Lundin)
• Ivar Aasen (Akerbp)
• Gina Krog (Equinor)
• Gudrun (Equinor)
• Sleipner (Equinor)

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Partial electrification of Sleipner approved

The Ministry of Petroleum and Energy has approved a revised plan for development and operation (PDO) for partial electrification of the Sleipner field centre. The field centre will be tied to the Utsira High area solution, and Sleipner is expected to cut emissions by more than 150,000 tonnes of CO₂ per year.

“Partial electrification of the Sleipner field centre will contribute to major cuts in emissions from our activities and provide significant assignments for the supplier industry in a demanding time. As the authorities have approved the PDO, we can keep developing the Norwegian continental shelf (NCS) towards the goal of zero greenhouse gas emissions in 2050,” says Arne Sigve Nylund, executive vice president for Technology, Projects and Drilling in Equinor.

In June, Equinor and its partners Vår Energi, LOTOS and KUFPEC submitted a revised plan for development and operation (PDO) to the authorities. The investments are in the size of NOK 850 million. Sleipner is scheduled to be tied in to the Utsira High area solution by the end of 2022.

“Sleipner is an important field on the NCS contributing enormous value to Norwegian society. The partners have focused on being in the forefront of technology development and innovation to carry out for example carbon capture, injection and storage at the field. The decision to partly electrify the field helps the partners in their effort of further developing the field,” says Kjetil Hove, executive vice president for Development and Production Norway in Equinor.

Arne Sigve Nylund, executive vice president for Technology, Projects and Drilling in Equinor, and Kjetil Hove, executive vice president for Development and Production Norway in Equinor.

The Sleipner field centre solution involves laying a power cable from Sleipner to the Gina Krog platform, which will be tied to the power from shore Utsira High area solution.

The Utsira High area solution was originally planned for the four fields: Johan Sverdrup, Edvard Grieg, Ivar Aasen and Gina Krog. The Sleipner field centre and the Gudrun, Gina Krog, Utgard, Gungne and Sigyn tie-in fields will now receive power from shore through the area solution.

In June, Aibel was awarded the EPCIC contract (engineering, procurement, construction, installation and commissioning) for Sleipner modifications. The contract for production and laying of cables was awarded to the NKT cable supplier.

Worth around NOK 400 million, the EPCIC contract will require approximately 170 man-years distributed on two years at Aibel’s offices in Stavanger and at their yard in Haugesund. Purchase of equipment from sub-suppliers is expected to be in the size of NOK 150 million.

Sleipner licence partners: Equinor Energy AS (operator) 59.6%, Vår Energi AS 15.4%, LOTOS Exploration and Production Norge AS 15.0%, KUFPEC Norway AS 10.0%

Original article link: https://www.equinor.com/en/news/20210211-partial-sleipner-electrifiction-approved.html

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PGNiG confirms termination of Russian gas imports from end 2022

Poland's PGNiG has notified Gazprom of its intention to terminate imports of Russian pipeline gas from the end of 2022.


This will now increase the country's reliant on US LNG (which at this time many US Gulf Coast LNG projects still have to be sanctioned and not guaranteed to come online) and the long awaited Baltic pipeline to take Norwegian gas to Poland.


The move is not a big surprise and is completely consistent with all the messages the Poland has been giving over the past few years including aggressively signing up US LNG volumes.


Poland consumes around 17 bcm of gas annually, more than half of which comes from Gazprom under a long-term contract that expires at the end of 2022. It has used the upcoming expiry as an opportunity to diversify its gas supply ahead of time and has consistently stressed that Gazprom is charging Poland too much for the gas noting that Russia has taken advantage of the historic lack of other sources of gas which is now rapidly changing with the advent of LNG.


Related links:

• Nov 2018: PGNiG shuns Russian gas
• Nov 2018: PGNiG expands footprint in Norway
• Jun 2019: PGNiG acquires Total's 22.2% stake in King Lear
• Jun 2019: Tommeliten Alpha Project passes important decision gate towards production in 2024

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Dry well in the Barents near Korpfjell

The 7335/3-1 exploration well on Production Licence 859 has drilled a dry well.

The partners on the licence are: Equinor 65% operator, Lundin 15%, DNO 20%.

The licence lies in the Barents Sea and the 7335/3-1 well is located c.8km southeast of the Korpfjell gas discovery.

Both the primary and secondary exploration targets encountered sandy and poor reservoirs. The well was drilled by the West Hercules drilling rig to 4,268m below the sea surface and water depth was 239m The well has not been permanently plugged and abandoned.

The West Hercules rig will now move to drill a wildcat well 7324/6-1 in PL855 in the Barents Sea.

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Maria, you've gotta see her!

Wintershall has shut-in the Maria field since February, approximately a year after first production, following poor production performance. It is understood that reserves have been downgraded from 207mmbbl to c.60 mmbbl.

The field is now undergoing testing and monitoring to see how best to produce the remaining reserves the recover the lost reserves whilst managing the reservoir. It is understood that the NPD has to review plans and sign off on the field's restart for fear unintended reservoir damage. There is currently uncertainty on whether the field will start up again.

The cause is believed to be poor connectivity between zones. Water injection is provided to the zone below for pressure support. However analysis is now showing low connectivity between the geological layers in the reservoir, and thus the water injection is not working effectively.

Wintershall started production from the Maria oil field on Haltenbanken in the Norwegian Sea in December 2017, one year ahead of schedule and with 20% reduction in costs. Maria was Wintershall’s first own-operated field in Norway.

Wintershall chose an innovative subsea concept to develop the field. Two subsea templates were installed on the seabed above the Maria reservoir and connected via a pipeline network to the existing Kristin, Heidrun, and Åsgard B platforms.

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Total sells Norweigian assets to AkerBP for USD205 million

Total has agreed to sell interests in a portfolio of 11 licences in Norway to AkerBP for a cash consideration of USD205 million. The portfolio includes four discoveries with net recoverable resources of 83mmboe.

The acquisition allows AkerBP to consolidate its position around the Alvheim, NOAKA and Skarv hubs as well as adding exploration acreage near its operated Ula field (AkerBP 80%). Increasing stakes in fields and discoveries and having control of tie-backs will help improve the economics of hubs for AkerBP.

For example two of the discoveries, Trell and Trine, are located near the AkerBP-operated Alvheim field (AkerBP 65% operated interest) and are expected to be produced through the low-cost Alvheim FPSO.

One important part of this transaction is the NOAKA area (North of Alvheim and Krafla Askja) where AkerBP and Equinor are pursuing the development for this complex with FID scheduled for 2020. Resources in NOAKA remain stranded until the partners agree a development concept and export route, but adding acreage and discoveries builds further critical mass on the path to bolstering the case for project sanction. Note that NOAKA is estimated to contain over 500mmboe in resources, but scattered across 15 discoveries hence the complexity of the development. Nevertheless this deal shows further intent by AkerBP to maximise recovery from the area.

Separately the Alve Nord discovery is located north of the AkerBP-operated Skarv field (23.8%) in the Norwegian Sea, and can be produced through the Skarv FPSO as another example of synergy.

The transaction is subject to regulatory approval. The full list of licences being transferred is as follows:

Source: Wood Mackenzie

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Faroe finds a Valentine in Suncor – farms out 17.5% in Fenja to Suncor

Faroe has announced the sale of a 17.5% interest in the Fenja development to Suncor for USD54.5 million which includes the transfer of tax losses.

Faroe will retain a 7.5% interest which fully aligns its equity interest with that of the other fields in the Greater Njord Area (Njord, Bauge, Hyme and Fenja). The transaction crystallises value of the asset pre-development and reduces Faroe’s capex (estimated to GBP70 million).

The PDO for Fenja was submitted in December 2017 and the operator VNG expects recoverable reserves of 97mmboe (72% oil). Fenja contains the Pil and Bue discoveries and will be developed as a subsea tie back to Njord. Pil will be developed first using three horizontal producers supported by water and gas injection wells. Bue will be brought online at a later date.

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VNG to evaluate options for its Norwegian E&P business

As widely expected, VNG's owner EnBW is looking for a partner or buyer for its E&P business VNG - full press release below.

As part of VNG Group’s strategic programme “VNG 2030+”, VNG – Verbundnetz Gas Aktiengesellschaft (VNG AG) will explore strategic options for its oil and gas exploration and production business in Norway and Denmark, VNG Norge AS (“VNG Norge”). As VNG AG sees long term value creation potential in the E&P-business, the main objectives are to maximise the value of VNG Norge and to support further growth to position the shareholding as a leading player on the Norwegian Continental Shelf together with a strategic partner.

VNG Norge is a full-cycle Norway-focused E&P company, with a solid growth portfolio underpinned by the operated flagship asset “Fenja”, one of the largest Norwegian discoveries in recent years (formerly “Pil”), which is proceeding according to plan, sanctioned by VNG AG and fully supported by all shareholders of VNG AG. Overall the company holds interests in 32 licenses in Norway, two in Denmark and participates in five producing fields and in three field developments at the end of 2017.

Source: https://www.vng.de/en/news/vng-ag-evaluate-options-maximise-value-its-norwegian-ep-business

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Norway awards record 75 exploration licences in 2017 APA

Norway has awarded a record number of 75 exploration licences in the APA 2017 licensing round to 34 companies. The licences comprised 45 in the Norwegian North Sea, 22 in the Norwegian Sea and 8 in the Barents Sea.

Statoil was the biggest winnder with 31 awards. Supermajors ConocoPhillips, ExxonMobil, Shell and Total also picked up licences.

Of the E&Ps:

• Aker BP was the winner with 23 licences (14 as operator)
• Lundin has been awarded 14 licences (5 as operator)
• DNO has been awarded in 10 licences
• Faroe Petroleum has been awarded 8 licences (four as operator)
• Cairn Energy has been awarded 5 licences

The Annual Predefined Areas or APA round was introduced in 2003 to encourage exploration and development of discoveries near existing infrastructure. Across all the awards this time, there are three licences with firm drilling commitments, with the remaining having drill or drop options in the next 12-24 months.

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Aker BP submits three PDOs

Aker BP ASA (Aker BP) has submitted the Plans for Development and Operations ("PDOs") for the Valhall Flank West, Ærfugl (formerly Snadd) and Skogul (formerly Storklakken) fields to the Norwegian Ministry of Petroleum and Energy.


Valhall Flank East
This development represents an extension on the western Flank of the Valhall field. It will be developed from a new Normally Unmanned Installation and will be tied back to the Valhall field centre. The platform will be fully electrified and operated remotely from Valhall. Recoverable reserves are estimated at 60mmboe to be drained using six producers with first oil planned for Q4 2019.

Field partners are AkerBP (35.95%) and Hess Norge (64.05%). Aker is in the process of acquiring Hess Norge and has entered into an agreement to farm-down 10% to Pandion Energy.


Ærfugl (formerly Snadd)
This is a gas condensate field near the AkerBP operated Skarv FPSO. The PDO covers the full-field development and includes the resources in both the Ærfugl and Snadd Outer fields which are planned to be developed in two phases.

The first phase includes three new production wells in the southern part of the field tied into the Skarv FPSO with production planned to commence in late 2020. The second phase continues to be worked up and will target the northern part of the field - it is also planned to be tied into the Skarv FPSO with an estimated startup of 2023. The full field development targets 275mmboe.

Partners in Ærfugl are AkerBP (23.8% operator), Statoil (36.2%), DEA (28.1%) and PGNiG (11.9%).
Partners in Snadd Outer are: AkerBP (30% operator), Statoil (30%), DEA (25%) and PGNiG (15%).


Skogul (formerly Storklakken)
Skogul is located 30km north of Alvheim FPSO, and will be developed as a subsea tieback to Alvheim via Vilje. Recoverable reserves are estimated at 10mmboe. The Skogul production well is the 35th well in the Alvheim area and represents the partners' efforts in extending life and recovery in the area. Production is planned for Q1 2020.

Field partners are AkerBP (65% operator) and PGNiG (35%).

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Statoil acquires Martin Linge from Total for USD1.45bn

Total has agreed to sell all of its interests in the Martin Linge field (51%) and Garantiana discovery (40%) on the Norwegian Continental Shelf to Statoil for USD1.45bn with an effective date of January 1st, 2017.Statoil will also receive remaining tax balances with a nominal post-tax value of more than USD 1 billion.

Martin Linge is a long life oil and gas development with estimated recoverable resources in excess of 300 mmboe. Originally scheduled to come onstream in 2017, first production is now expected in 2019 following a series of project delays and cost increases including a tragic accident at the Samsung ship yard in South Korea where the topside is being completed.

Martin Linge is being developed with a manned wellhead platform - the jacket substructure is already installed on location, while the topside is being completed at the Samsung yard in South-Korea and will be transported to Norway early 2018.

Operations will be controlled remotely from an onshore digital operations centre, enabling reduced operational expenditures. Electrification is made possible through a 160 km cable from shore, the longest AC power link in the world. This will reduce CO2 emissions by 200,000 tonnes per year. Following completion of the transaction, Statoil will increase from 19% to a 70% interest in the field.

Arnaud Breuillac, President, Exploration & Production at Total commented "The forthcoming acquisition of the Maersk Oil portfolio, which will make Total the second largest operator in the North Sea, leads us to review our portfolio in this area so as to focus on the assets in which Total will be able to generate synergies and reduce their breakeven points. In this context, given that Martin Linge is Total's only operated asset in Norway, there is limited scope to optimise operations, whereas with Statoil’s leading operating position on the Norwegian Continental Shelf, Statoil is in a better position to optimize this asset for the benefit of all stakeholders. We are therefore satisfied with the agreement with Statoil, a long time trusted partner, which in addition, offers us a satisfactory value for this asset. Norway remains a strategic country for Total as one of the largest contributors to the Group's production and we of course intend to continue bringing our expertise to Norway by focusing in particular on major non-operated assets such as Ekofisk, Snohvit and Johan Sverdrup."

Statoil's EVP for D&P Norway commented "This transaction adds competitive growth assets to our portfolio on the Norwegian continental shelf. The Martin Linge project features innovative solutions to enhance safety, capture value and reduce emissions, in line with our strategy. By leveraging Statoil’s operational experience and existing contracts, we can realise additional opportunities and synergies from these assets."

The transaction involves the transfer of relevant employees from Total to Statoil and remains subject to final due diligence and approval from the relevant authorities. The transaction will increase Statoil's stake in Martin Linge from 19% to 70% with the DFI holding the remaining 30%.

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Point Resources acquires ExxonMobil's Norwegian operated assets

On 29^th March 2017, Point Resources announced its acquisition of ExxonMobil's operated upstream business in Norway for an undisclosed amount (estimated valuation of c.USD1bn). The deal transforms Point Resources into a top 10 producer on the Norwegian Continental shelf and increases production c.10-fold to 48mboepd while adding 128mmboe of oil-weighted reserves. The transaction adds significant technical capability with the transfer of 300 staff to Point Resources.

Point Resources was formed in 2016 by the merger of Core Energy, Spike Exploration and Pure Energy, all portfolio companies of Norwegian E&P private equity specialist HitecVision. The merger created a company with a portfolio weighted towards exploration and development positions (e.g. Brage, Brasse, Pil) and the acquisition of the ExxonMobil assets helps to reweight the portfolio into more of a full cycle one.

The key assets acquired were ExxonMobil’s operated positions: Balder, Ringhorne and Jotun; Forseti is being decommissioned. Point Resources has identified significant upside in the asset base that can be achieved through infill drilling – likely to have been overlooked by ExxonMobil with the portfolio being increasingly immaterial within ExxonMobil’s global business. For ExxonMobil, the divestment leaves it with a non-operated portfolio in Norway and therefore a much lower country cost base, but still provides a platform to access high impact Norwegian and Barents Sea exploration.

Source: Wood Mackenzie
4D seismic has identified new development locations and exploration targets around Balder and Ringhorne

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Barents Sea licence awards

The Norwegian Ministry of Petroleum and Energy has issued ten new production licences in the Barents Sea as part of Norway’s 23rd licencing round, following applications made by 26 companies in January. This is the first time since 1994 that new exploration acreage has been made available to the industry in the southeastern Barents Sea. 

From the International E&P names:

• Lundin has been awarded interests in five licences (three as operator)
• Det Norske has been awarded interests in three licences (one as operator)
• Tullow has been awarded an interest in one licence (non-operated)
• Cairn (through its Capricorn Norge subsidiary) has been awarded three licences (one as operator)

The companies have committed to binding work programmes that primarily include a drill or drop decision to be made within two years.

Barents Sea licence areas
Source: NPD

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Premier Oil exits Norway

Premier Oil Norwegian operation
Source: Premier Oil

On 16 November 2015, Premier Oil announced that it had agreed to sell its Norwegian business to Det Norske for USD120 million. The Norwegian business consists of the Premier Oil Norges subsidiary and includes the Vette development, adjacent Mackerel and Herring discoveries, a non-operated stake in Froy and seven exploration licences.

The transaction is expected to close before year end and proceeds will be used pay down debt. The exit of the business will give rise to a G&A saving of c.USD20 million p.a. as well as remove capital requirements for the Vette development that was progressing towards sanction.

For Premier Oil, the sale is in line with the company’s ongoing portfolio management strategy and is an important step to managing the high debt levels.

For Det Norske, the acquired business will bolster its Norwegian portfolio and Det Norske will be able to offset its production against the tax losses in Premier Oil Norges (from spend on Vette and Froy) which stood at USD146 million as at mid-2015. Det Norske will fund the acquisition from internal cash resources.

Tony Durrant, CEO of Premier Oil commented:

“We are pleased to have reached agreement to sell our Norwegian business to Det norske, one of our long term partners in Norway. Our team in Norway has done an excellent job in bringing the Vette project close to a sanction decision in a low oil price environment. The transaction will realise immediate value from the project as part of our strategy of active management of our portfolio.”

Karl Johnny Hersvik, CEO of Det Norske commented:

“Following the recent closing of the Svenska transaction, the acquisition of Premier is another bolt-on acquisition that further underlines our firm belief in and commitment to the Norwegian Continental Shelf.”

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Ivar Aasen crib sheet

• Contains 4 fields: Ivar Aasen, West Cable, Hanz, Asha
• PDO approved in March 2013
• Development costs relatively high
• Discovery of Asha in December 2012, and inclusion of Asha in development improves economics
• Edvard Greig and Johan Sverdrup could push cost of services market higher
• Ivar Aasen expected to receive transitional terms , whereas other fields will be taxed under new terms

Participation

• Ivar Aasen Area contains 3 licences
• Ivar Aasen/West Cable (PL001B)
• Hanz (PL028B)
• Asha (PL457)
• Field unitisation expected mid-2014
• Estimated unitised participations are: Statoil (41.15%), Det Norske (28.8%)*, Bayerngas (12.34%), Wintershall (7.08%), EON (3.54%), Spike (3.54%), Verbundnetz (3.54%)
• Note that on 25 June 2014, Det Norske increased its stake in PL457 (above unitisation does not reflect this)
• EON to receive 15% WI in PL613 (Barents) and 10% WI in licence PL676S (North Sea) + Cash
• Det Norske increases interest in PL457 from 20% to 40% WI

Reserves

• WM Commercial reserves: 149mmbbl + 181bcf
• Hanz: good reservoir – expect high RF
• West Cable: strong acquisfer support – expect high RF
• Ivar Aasen and Asha reservoir more complex, varying sand quality

 Production

• Ivar Aasen, Asha and West Cable production from 2016; Hanz in 2019
• High rates of gas production expected from some wells due to gas cap in Ivar Aasen and Hanz reservoirs
• Wells will be drilled in order that gas production can be shut off to maximize oil recovery
• Asha gas initially reinjected

Development

• Ivar Aasen, Asha, West Cable: developed using fixed platform
• 20 well slots with partial processing facilities
• Production and injection wells will be drilled using jack-up positioned next to platform to 2016/17
• Hanz will be developed using subsea tie back to Ivar Aasen platform
• Exports via Edvard Grieg facilities

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