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The Norwegian Petroleum Directorate is concerned with responsible resource management through cost efficiency and cost control. Cost‐effective solutions make profitable oil and gas production possible. On the other hand, cost cuts must not prevent profitable measures to increase the production.
In recent years, the petroleum industry has worked hard to reduce costs. This has contributed to the implementation of new projects on existing fields and new field development decisions. Continued good profitability and a high activity level on the Norwegian shelf requires sound cost‐effectiveness over a long period of time. At the same time, the industry must ensure that further cost reductions do not have an adverse impact on the opportunity for future value creation. Good project execution is always important for profitability and for responsible resource management.
Development projects costs have been cut by 30 to 50 per cent over the last few years. The price of oil has increased during the same period, leading to companies seeing more profitable projects.
However, requirements related to short‐term returns, capital restrictions in the companies or unnecessarily high risk linked to project implementation can make it challenging to secure approval for major and minor investment decisions in the production licences.
The authorities are concerned with ensuring that the chosen solutions provide the highest returns overall, and with emphasising the importance of maintaining a long‐term perspective rather than looking at what yields the highest returns in the short term.
The oil companies on the shelf are responsible for exploration, development and operations, and do a great job. Nevertheless, it is vital that the Norwegian Petroleum Directorate keeps a close eye on the activities and contributes to ensuring decisions that safeguard the values for society in the best possible way.
One example of this is the authorities’ follow‐up of the Snorre field. It has been producing since 1992, and still contains vast profitable resources. To ensure they are produced, an amended Plan for Development and Operation (amended PDO) was submitted on 21 December 2017. This development plan comes as a result of a determined effort over the last 12‐15 years, by both the companies and the authorities.
The development is one of the largest projects for improved recovery on the Norwegian shelf. The project will contribute to extended field operation and will yield major revenues for both the companies and the Norwegian society.
The further development of the Snorre field yields good resource management, in accordance with the ambitions in Storting Report No. 28 (2010‐2011) – The Petroleum Reportand Proposition 114 S (2014‐2015) “Norway’s largest industrial project – development and operation of the Johan Sverdrup field, including status of the oil and gas activities”.
Snorre is an example worthy of imitation. The authorities believe that there are also other mature fields on the shelf with the potential for further development through drilling of more development wells that yield improved recovery of oil and gas.
The Norwegian Petroleum Directorate will continue the work to increase value creation on both mature fields and new developments – not least through measures for improved recovery and phase‐in of additional resources.
In order to maximise value creation, best possible use of existing infrastructure such as pipelines and available process capacity on the platforms is necessary. It is vital that time‐critical oil and gas resources, for example minor discoveries near aging infrastructure, are proven and developed before the facilities are shut down and removed.
Coordination across production licences can result in advantageous area solutions. Such solutions can contribute to achieving profitability for discoveries that would not otherwise have been developed. The authorities are interested in ensuring that decisions in different production licences safeguard a comprehensive area perspective.
In the summer of 2017, the Norwegian Petroleum Directorate published a resource report, where one of the main messages was that there are still vast values to be extracted on the Norwegian shelf.
The authorities expect the companies to extract all the resources in discoveries and fields that can contribute value to our society, not just “the easy barrels”. There are large volumes of petroleum where production is not currently profitable. These are “technical resources” that could potentially be produced with technology that has not yet been tested or qualified for use on the Norwegian shelf.
With current plans and applied technology, about half of the oil in the oil fields will be left in place. There are also large oil and gas deposits in tight reservoir zones where production is not profitable. By developing and utilising new technology, parts of these resources can also become profitable.
Many fields are far into their production phase and may be nearing shutdown. Therefore, the Norwegian Petroleum Directorate believes that it is urgent that pilot trials using new technology are carried out. This is necessary to verify applicability, to reduce risk and to demonstrate improved recovery potential through various advanced injection methods and new technology, before the relevant fields are shut down.
The Norwegian shelf has been a laboratory for testing and application of new technology. The Norwegian Petroleum Directorate wants this to continue. New technical solutions are a decisive factor in ensuring that even more of the proven oil and gas is profitable to produce.
There are 85 producing fields on the Norwegian shelf, 66 in the North Sea, 17 in the Norwegian Sea and 2 in the Barents Sea. These are profitable fields that contribute revenues for both the companies and the Norwegian state. In 2017, five new fields started producing.
Nine field developments are currently ongoing:
The authorities approved eight Plans for Development and Operation (PDOs) in 2017. In total, these projects have an investment framework of nearly NOK 50 billion.
In 2017, the authorities received a record‐high number of new development plans. The ten development plans have a total investment value of NOK 125 billion. *
(* Njord (Njord future), Bauge and Ekofisk 2/4 Victor Charlie (improved recovery project) were both submitted and approved in 2017.)
The five new fields that started producing in 2017 are Gina Krog, Flyndre, Sindre, Byrding and Maria (Maria started producing in December).
Gina Krog is an old oil and gas discovery from 1974 near the Utsira High in the North Sea. Technology development and new subsurface information contributed to a revitalisation of the discovery, where Statoil is the operator. Gina Krog is well‐facilitated for phasing‐in current and future discoveries in the area.
The Maria field in the Norwegian Sea is Wintershall’s first development on the Norwegian shelf as an operator. The development became NOK 3.7 billion cheaper than expected in the PDO. Production started nearly one year ahead of the original plan. The Maria development is an example of how cooperation between the licensees can lead to excellent utilisation of the infrastructure in an area and contribute to increased value creation. Utilisation of different host facilities has made the Maria development possible.
The other three fields that have started producing are smaller, but important fields that effectively exploit existing infrastructure in the area.
Flyndre is a minor oil field in the Greater Ekofisk Area in the North Sea that was proven in 1974. The field is located on the border between the UK and Norwegian shelves, and is developed with a subsea well tied to the Clyde facility on the UK shelf. Production start‐up was in March 2017. Maersk Oil UK is the operator.
Sindre is a minor oil field that is located northeast of Gullfaks in the northern part of the North Sea. The field was proven through the drilling of a long well from the Gullfaks C platform, and production started through this well in May, after a PDO exemption was granted. Statoil is the operator.
Byrding is an oil and gas field southwest of Gjøa in the North Sea. The field is developed with a twobranch well that was drilled from an available slot on the existing subsea template on Fram H‐Nord. The wellstream is routed via the Fram infrastructure to Troll C. Statoil is the operator.
In 2017, the authorities approved eight Plans for Development and Operation (PDOs) for the fields Utgard, Byrding, Oda, Dvalin, Trestakk, Bauge and amended PDOs for Njord further development and Ekofisk 2/4 Victor Charlie.
All the development plans relate to fields and resources that are tied‐in to existing infrastructure, and this contributes to effectively exploiting available capacity. At the same time, profitability increases, along with the lifetime for the relevant platforms that will process oil and gas from the new fields. It also provides a possibility for additional measures that can contribute to extend tail production from these fields.
In addition, five fields have received a PDO exemption; Goliat (Snadd), Martin Linge (Herja and Hervor), Sindre, Snefrid north and Troll Brent B.
Utgard is a gas and condensate field in the Sleipner area in the North Sea. It extends across the Norwegian‐UK continental shelf border and is estimated to contain about nine million standard cubic metres of oil equivalents (Sm3 o.e.). The largest percentage of the reserves in Utgard is located on the Norwegian side. The development will be tied‐in to facilities on Sleipner. The expected investment is nearly NOK 1.9 billion (Norwegian share). Production start‐up is scheduled for the fourth quarter of 2019. Statoil is the operator.
Byrding is an oil and gas field southwest of Gjøa in the North Sea. It is estimated to contain about 1.8 million Sm3 o.e.. Byrding is developed using an existing subsea template in the Fram area. The expected investment is nearly NOK 1 billion. Statoil is the operator.
Oda is an oil field south of Ula in the North Sea. The recoverable resources are estimated at 7.5 million Sm3 o.e.. The investments for the development are estimated at about NOK 5.4 billion. The field will be tied‐in to Ula, and production is scheduled to start in the third quarter of 2019. Spirit Energy is the operator.
Dvalin is a gas field near Heidrun in the Norwegian Sea. The recoverable resources are estimated at about 18 billion Sm3 of gas. The field will be tied‐in to Heidrun. Investments are expected to reach more than NOK 10 billion. Production start‐up is scheduled for the fourth quarter of 2020. DEA is the operator.
Trestakk is an oil field near Åsgard in the Norwegian Sea. Recoverable resources are estimated at 10.5 million Sm3 of oil. The field will be tied‐in to the Åsgard A ship. Expected investments total about NOK 5.5 billion. Production start‐up is scheduled for the second quarter of 2019. Statoil is the operator.
Bauge is an oil field near the Njord field and the tied‐in seabed development Hyme in the Norwegian Sea. Bauge will be tied‐in to both these fields. The recoverable resources are estimated at 7.9 million Sm3 of oil, 1 million tonnes of NGL and 1.9 billion Sm3 of gas. The investments are estimated at NOK 3.9 billion. Production start‐up is scheduled for the fourth quarter of 2020. Statoil is the operator.
Njord in the Norwegian Sea was shut down in 2016 due to structural problems with the Njord A platform. Njord A and Nord B were towed to shore to be upgraded so that they can produce for several more years. The remaining recoverable resources are estimated at 5.1 million Sm3 of oil, 13.2 billion Sm3 of gas and 4.1 million tonnes of NGL. The investments are estimated at about NOK 15 billion. Production start‐up is scheduled for the fourth quarter of 2020. Statoil is the operator.
Ekofisk 2/4 Victor Charlie is a new subsea template for water injection and drilling and completion of four new injection wells. The chosen solution is well adapted to the need for a quick increase in water injection on Ekofisk and will contribute to ensuring high recovery and good resource utilisation from the field, as well as preventing resources from being squandered. According to plan, water injection from 2/4 VC will improve recovery on Ekofisk by 2.7 million Sm3 of oil equivalents. The expected investment is nearly NOK 2.3 billion. ConocoPhillips is the operator.
The authorities received 10 new development plans (PDO applications) over the course of 2017. These are Njord further development, Bauge, Ekofisk 2/4 Victor Charlie, Valhall flank west, Yme, Skogul, Snorre further development, Ærfugl, Fenja and Johan Castberg. Of these, Njord, Ekofisk 2/4 Victor Charlie, Snorre further development and Yme are amended PDOs.
Snorre further development in the North Sea is one of the largest projects for improved oil recovery on the Norwegian shelf. Snorre is one of the fields on the shelf with the greatest remaining oil volumes. The project involves an extensive subsea development with six new subsea templates tiedin to the Snorre A platform. The project also comprises upgrading the Snorre A platform and increased gas injection. This can yield nearly 30 million Sm3 more oil. The investments are estimated at NOK 19.3 billion (2017‐NOK). With this project, the lifetime of the field will extend to beyond 2040. The PDO was submitted in December 2017. Statoil is the operator.
Johan Castberg in the Barents Sea was proven in 2011. The discovery will be developed on the seabed with ten subsea templates and two satellites tied‐in to a floating production storage and offloading vessel (FPSO). Expected production will yield 88 million Sm3 of oil, and recovery could be significantly improved by drilling more wells. The field will be operated from Harstad and have operations and helicopter transport bases in Hammerfest. The lifetime of the field is expected to extend beyond 2050, and investments are estimated at about NOK 49 billion. The PDO was submitted in December 2017 and production is scheduled to start in 2022. Statoil is the operator.
The development will take place with an unmanned wellhead platform that will be controlled from the field centre on the Valhall field. Wellhead platforms have previously been installed on the southern and northern flanks of Valhall. The new facility will have twelve well slots and six new wells will be drilled. This will yield six available slots for future wells. The development will increase the reserves by about 10 million standard cubic metres of oil.The expected investment is nearly NOK 5,7 billion. Drilling will be carried out with a jack‐up drilling rig and will take place for 1.5‐2 years. The planned drilling start‐up is in the third quarter of 2019. The PDO was submitted in December 2017. Aker BP is the operator.
Fenja (Pil/Bue) is two oil and gas discoveries in the Norwegian Sea. Recoverable oil reserves amount to about 11 million Sm3 of oil and 3.4 billion standard cubic metres of gas. The investment estimates are NOK 10.2 billion. The PDO was submitted in December. The planned production start‐up is in 2021. VNG Norge is the operator.
Ærfugl (Snadd) is a gas discovery covering 60kilometres west of the Skarv field in the Norwegian Sea. The plan is to develop Ærfugl in two phases due to the gas processing capacity on the Skarv production vessel. Phase 1 (south) is scheduled to start production in 2020 and Phase 2 (north) in 2023. Phase 2 also includes Snadd Outer in PL212E, which has the same owners. Total recoverable gas reserves for both phases are 35 billion Sm3, and the investment costs are estimated at NOK 8.5 billion. The PDO was submitted in December 2017. Ærfugl is located in Skarv Unit, where Aker BP is the operator.
The Yme field in the North Sea was in production from 1996 to 2001. It was then shut down, and the facilities were removed. The plan in the new development project is to use a jack‐up facility with a drilling and process system to produce the remaining resources. The expected investment is nearly NOK 8.2 billion. Recoverable oil reserves are about 10,3 million Sm3. The plan was submitted in December 2017. Repsol is the operator.
Skogul in the North Sea is a minor field with a reserve basis of approx. 1.5 million standard cubic metres of oil.The investment is expected to reach NOK 1.5 billion. Skogul is a subsea field that will be developed with a two‐branch well. Oil and gas from Skogul will be processed on the floating production facility Alvheim FPSO. The PDO was submitted in December 2017 and Aker BP is the operator.
Cessation plans for the Trym and Gyda fields were delivered in the first half of 2017. The gas and condensate field Trym is located in the southern part of the North Sea, three kilometres from the border with the Danish sector.
Gyda is an oil field in the southern part of the North Sea, between Ula and Ekofisk. The disposal decision was made in June, and production is scheduled to shut‐down in 2018. A disposal decision has also been made for the old living quarters platform on Valhall in the North Sea.