Deciding on development

person Finn Harald Sandberg, Norwegian Petroleum Museum
The prime concern of an oil company when it discovers hydrocarbons is whether money can be made from them. So the question is what it takes to secure a declaration of commerciality followed by a decision to develop.
— Valhall QP on the right with the drilling platform (DP) on the left. The picture was taken from the living quarters under the helideck of the crane vessel that was brought in for the construction of the process and the compression platform (PCP). Photo: Amoco Norway Oil Company/Norwegian Petroleum Museum
© Norsk Oljemuseum

Where Valhall is concerned, the first discovery was made in 1969 but it took seven years and 10 wells before the field could be declared commercial. The first step is to secure an overview of the most important revenues and expenses. Revenues are calculated on the basis of producible and saleable quantities

  • production profile
  • types of products
  • product prices

Expenses could include

  • drilling wells
  • building and installing facilities for production and transport
  • transport costs
  • operation of facilities (including personnel and catering costs)
  • maintenance costs
  • direct and indirect taxes

Both revenues and expenses are affected by exchange rates if accounts are compiled and expenses incurred in different countries with varying currencies.



A discovery provides the first confirmation that the geologists and geophysicists have correctly interpreted the seismic data from the relevant area.

As a rule, cores from the discovery well will also say something about the types of hydrocarbons (oil, gas or condensate) present and their relative proportions. Indications can also be obtained at this stage about reservoir pressure and temperature.

Appraisal wells will need to be drilled in order to secure a picture of the overall reservoir. How many of these are required will depend on the quality of the original data.

Since great uncertainty always prevails when interpreting the results of wildcat and appraisal wells, probability calculations must be performed to estimate sub-surface reserves.

Terms such as “most probable”, 50/50, 10/90 and 80 per cent levels of confidence are important elements in such assessments (see table 1).

Calculation models developed over many years and computers with massive capacity are required to obtain a credible picture of volumes in the reservoir.

Term Explanation
Most probable quantity The quantity which will most probably be found in the reservoir.
50/50 The value where it is most probable that the quantity will be greater or smaller.
10/90 (or 90/10) The value where the quantity has a 10 per cent chance of being smaller or a 90 per cent chance of being greater (or vice versa).
80 per cent level of confidence The specified upper and lower limits which the quantity has an 80 per cent chance of falling within.
Oil in place The total quantity of hydrocarbons probably present in the reservoir. Often abbreviated to OIP.
Recoverable reserves The estimated quantity of hydrocarbon which can be produced with a certain level of profit.

Table 1. Key concepts in reservoir evaluation.


The models used to calculate revenues yield their highest values when producing the maximum quantity in the shortest possible time (a value is discounted backwards in time using a given discount rate). A big capacity will therefore always be desirable for the production facilities.

However, the Norwegian government’s declared policy has been that ¬– once production is permitted on a field – the goal must be to recover the largest proportion of the hydrocarbons in place. Unfortunately, natural conditions dictate that these two ambitions are usually at odds with each other.

Rapid production will normally leave a larger proportion of the oil and gas in the ground than if reservoir properties such as pressure, temperature and porosity of the source rock are taken into account.

Market conditions also mean that oil and gas must be produced differently. So their proportions in the reservoir are important for the approach taken to depleting the reserves.

Understanding/interpreting the initial analyses of hydrocarbon distribution and behaviour may differ greatly from the actual results.

Valhall also provides an example of this.

Plans for the field ended up with a fairly traditional production curve (green), even through a three-stage development was planned.

A four-year ramp-up from the start of production in 1980 to peak annual output was rather longer than normal, but typical for the three-stage approach taken in the plan for development and operation (PDO).

As operator, Amoco envisaged that it would be possible to maintain production at a commercially acceptable level until around 2000.

When Valhall came on stream roughly a year later than planned, Amoco found that the field was considerably more difficult to produce than it had expected. More than a decade passed before the problems posed by the chalk reservoir were overcome.

New challenges were encountered in 1998, but intensive research and development has provided a new lease of life for Valhall. It is now due to stay on stream almost 50 years longer than expected.

Sample calculation

Hindsight is an exact science, they say. Big variations can be demonstrated for all the important parameters in the period from deciding to launch a project until all the economically producible oil has been recovered.

So the question is what effect all these changes have on the anticipated result. A very simple calculation can demonstrate the huge impact they have had on Valhall.


  1. Production as presented in the PDO versus actual output.
  2. A fixed oil price of USD 12 per barrel for the whole period versus the actual figure (annual average).
  3. Fixed exchange rate of NOK 5 per USD versus the actual rate (annual average).

Without taking account of inflation during the 1980–2000 period, the value of the expected production of oil (and gas) under the assumptions given was about NOK 35 billion.

Based on the actual output and financial figures, however, Valhall’s production was worth some NOK 78.7 billion – more than twice as much. And the field still has more than 30 years to go.


Analysing results from both seismic surveys and wildcat/appraisal wells allows specialists to estimate the relative proportions of oil, gas and other liquids in the reservoir.

Making this distinction is important because the markets for the various products call for very special and different patterns of production.

Crude oil is a commodity which needs very little processing at the production site, while gas must undergo major treatment before being piped to land.

In principle, oil is deliverable to any refinery worldwide which can or wants to use its particular grade. Gas will usually be sold in a consumer market which has or is establishing a distribution network/infrastructure.

As a result, gas deliveries must meet specifications for both chemical quality and physical constraints such as pressure.

Europe’s gas distribution network has become so well developed and flexible in recent years that this market is now increasingly characterised by the same mechanisms which apply for oil sales.


The biggest challenge is predicting the price of oil.

Optimism prevailed in the late 1970s, with crude prices skyrocketing and many people expecting them to reach USD 100 per barrel by 1990. This is perhaps hardly surprising when looking at developments until that point.

During the early years of production from Valhall, these optimistic expectations received a shot across the bows.

.. And things only got worse.

Oil price trends during the original period of Valhall production provide a very good example of how difficult it can be to perform calculations with a high degree of certainty.



The cost of wells represent about a quarter of the total capital spending for development projects which involve platforms on the NCS.

Substantial savings can be made on the expenditure side by optimising the drilling programme in terms of the number of wells and their length.

Utilising subsea facilities with templates and slots for up to eight wells makes it possible to complete production wells before the platform is in place. That ensures early revenues and is beneficial for the project economics.

Until the mid-1980s, every Norwegian field development was based on fixed platforms (Tommeliten, the only purely subsea field, came on stream in 1986).

All production drilling was done from these installations, which ensured better and more stable working conditions, but meant that revenues started to flow later than if everything had been ready when the production facilities were in place.

The sharp and rapid fluctuations in rig rates increase uncertainty in the estimates for total costs.

A cost analysis conducted in the late the late 1990s also showed that well expenses are one of the commonest reasons for major project cost overruns.


In a market with heavy demand and limited capacity, prices will come under pressure on many fronts. The oil industry has experienced such periods several times during the 50 years since Norway became involved in this sector.

Efforts have been made by the Norwegian authorities to reduce the biggest effects of these conditions, but local measures usually have little impact in such a globalised industry.

The various Valhall development projects can illustrate just how difficult it could be to establish reliable estimates and assumptions.

Main development:

  • Original PDO (January 1977): NOK 3 075 million
  • Adjusted PDO (August 1977): NOK 3 460 million
  • At start to production (October 1982): NOK 6 000 million (up 53 per cent from the adjusted PDO)

Wellhead platform (WP):

  • Original estimate (1993): NOK 2.1 billion
  • At start to production (1996): NOK 1.5 billion (down almost 30 per cent)

Injection platform (IP):

  • Original estimate (1993): NOK 4.4 billion
  • At start to production (1996): NOK 7.2 billion (up about 63 per cent)


How petroleum products are to reach market and where these markets are found represent two of perhaps the most important questions which need to be answered. If nobody wants them, they cannot be delivered anywhere either.

Crude oil is traded in a global market, which means it can basically be sold to a refinery virtually anywhere in the world. The challenge is to find a balance between the cost of installing a transport solution and the price obtained for the oil.

Where gas is concerned, it was important when a development decision needed to be taken for Valhall that a sales contract specifying both price and quality was in place with a customer.

The gas to be delivered had to satisfy the requirements set by the buyer, which in turn determined the design of the offshore process facilities.

In addition, storage and loading could not be conducted with an acceptable level of safety and regularity in the open sea under North Sea conditions.

Tie-in to an established transport system was therefore important and beneficial for Valhall’s licensees. That meant the Norpipe facilities operated from Ekofisk.

Following tough negotiations, the two licences succeeded in reaching agreement on a satisfactory solution.

Operation and maintenance

Complicated calculations are required to obtain an overview of expected operating costs for producing field. A number of significant questions have to be considered at an early stage, when not even the main process has been decided. These include:

  • how many compression stages are required?
  • how much reserve capacity is needed?
  • which emergencies need to be handled within a reasonable time?
  • how often must equipment be checked and maintained?
  • are monitoring and maintenance equally important for all components?
  • how many workers are required – during the most labour-intensive periods and for normal operation?
  • how much power will be needed at any time?

As experience was acquired with operations on the NCS, the individual operator could develop some simple rules and assumptions for making such estimates.

When expectations for Valhall had to be determined, however, this experience base was very limited. None of the Valhall licensees had any idea what the Norwegian regulations involved, and few details were available from similar fields on the NCS.

Direct and indirect taxes

This item is primarily affected by political wishes and control. Norway’s distinctive petroleum tax regime has been surprisingly stable over a long period.

The oil companies are also keenly interested in stability, even though they have called for lower taxes on many occasions.

All changes proposed have been greeted with much scepticism and strong protests if they involve higher tax rates. The opposition to cuts has not been quite so fervent, but guarantees are sought that the reduction will be lasting.

Another special Norwegian levy is the carbon tax, paid on emissions of carbon dioxide from petroleum operations on the NCS since 1991. The aim is to reduce the release of this greenhouse gas.

Other duties are also charged on production of oil and gas from the NCS.


Plan for development and operation (2000), Valhall.

Independent project analysis, UIBC, 2007.

Kaasenreport, Norwegian Official Reports (NOU).

Moe, Johannes, et al:  Kostnadsanalysen norsk sokkel .

Rasen, Bjørn (2007):  LF6A.Valhall at 25 … and it’s only the beginning.

Published 25. June 2019   •   Updated 10. August 2020
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