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Total recoverable resources on the NCS at 31 December 2018 were estimated to be 15.6 billion standard cubic metres (scm) of oil equivalent (oe), including quantities already produced.
The expected value of remaining recoverable resources is 8.3 billion scm oe, with roughly half that amount already proven in fields and discoveries. These big volumes provide the basis for a high level of value creation from the oil and gas industry for a long time to come.
At 31 December 2018, there were 85 discoveries where the licensees had yet to submit a plan for development and operation (PDO) to the government. These contain total recoverable resources of 660 million scm oe, and represent 15 per cent of remaining discovered petroleum resources.
Roughly half the total resources in the discovery portfolio lie in the North Sea, just under a third in the Norwegian Sea and about a fifth in the Barents Sea. The total investment required to develop the whole portfolio is estimated to be in the order of NOK 400 billion in 2018 value.
The average size of discoveries in the portfolio has declined over the past 20 years. Phasing into existing infrastructure is therefore the most likely development solution for most of them. Maintaining existing infrastructure and utilising its spare capacity are important preconditions for realising the assets in the discovery portfolio.
It is also important that new facilities are built with enough flexibility to accept additional resources, and that development and activity are coordinated where that would maximise value for society.
There were 85 producing fields on the NCS at 31 August 2019. Oil and gas production has remained at a high and stable level from the early 2000s, and rising oil output means overall production could reach a new peak in 2023.
Reserves in fields increased by about 1 400 million scm oe in 2000-18, equivalent to more than three Johan Sverdrup fields. The reason is that decisions have been taken on a number of different measures for improved recovery from the fields. Better sub-surface understanding, drilling of more wells, improved recovery measures, and greater operational efficiency are factors contributing to increasing reserves and thereby to greater value creation.
More than half the investment on fields in 2018 related to wells. In recent years, cost control and efficiency improvements have cut the average bill per production well by more than 40 per cent. Operating costs on most fields have also been substantially reduced. They fell by 30 per cent on average from 2013 to 2017. New solutions, including automation and remote operation, improved use of data and more efficient operation, could further reduce costs and help to increase production even more.
As production from existing fields declines, more spare capacity will become available in the infrastructure. To exploit this, exploration must be pursued around the mature fields, infrastructure owners must promote spare capacity, and companies must collaborate on phasing in additional resources.
Such phasing in helps to reduce unit costs and extend the producing life of the host field, and means that a greater proportion of the resources can be produced.
The NPD has mapped volumes in place for tight reservoirs in 42 discoveries and fields. This work indicates that some 2 000 million scm oe are present. Achieving profitable production from tight reservoirs calls for the development of cost-effective solutions which increase reservoir exposure in the wells so that the oil and gas flow better.
Nevertheless, in a number of cases, production can only become profitable through a tie-back to existing infrastructure. Since tight reservoirs are expected to have a long production horizon, deciding on their development before the commercial life of existing infrastructure becomes a constraint will be important.
A study of the potential offered by using advanced methods for enhanced oil recovery (EOR) was conducted by the NPD in 2017. This work has now been updated and expanded to cover more fields and discoveries. A recovery potential of about 350 million scm oe has been estimated, with an uncertainty range from 180 to 500 million scm.
EOR could thereby contribute to recovering substantial volumes if the methods are qualified for use on the NCS. To achieve this, it is important that licensees test EOR methods through field pilots.
Concern for the natural environment has always been an integrated part of managing Norway’s oil and gas resources, and is taken into account in all phases of the activity – from exploration and development to production and field cessation. The industry is subject to strict regulations covering both emissions to the air and discharges to the sea.
Financial instruments, such as emission pricing through the CO₂ tax and allowance trading, gives the industry a self-interest in identifying and implementing emission-reducing measures.
Although petroleum production is expected to increase up to 2023, overall CO₂ emissions and produced water discharges are expected to remain stable. This means that both emissions to the air and discharges to the sea per unit produced will decline.
Where emissions are concerned, that partly reflects a steady expansion in power from shore. Once the Utsira High area solution becomes operational, more than 40 per cent of production from the NCS will be run with power from shore.