Discoveries and current field developments

3.1 Discoveries

Development of the discovery portfolio

A total of 434 discoveries have been made on the NCS since the first exploration well was drilled in 1966 and up to 31 December 2013. Fifty-one per cent of these have been developed or are under development.

Discoveries still not sanctioned for development but which are under evaluation account for 24 per cent of the total, and divide between those made before 2000 and from that year. See figure 3.1, which shows that 85 per cent of proven resources have already been developed. By comparison, resources in discoveries under evaluation amount to 10 per cent.


Figure 3.1


Figure 3.1 Discoveries at 31 December 2013 by development status.


About 25 per cent of the discoveries are classified as not very likely to be developed, even in the long term. Their proportion of total resources represents an estimate for possible technically recoverable quantities which are not currently considered to be developed commercially. Should any of these be re-evaluated, they will be included in the portfolio of development projects. See figure 3.3. A few such discoveries have so far reached a decision to develop.

Changes in the number of discoveries without an approved development plan from 31 December 1999 until 31 December 2013 are presented in figure 3.2. A development can embrace several discoveries. Roughly as many discoveries were made in 2013 as in 1999, while numbers in the intervening years have varied considerably. The decline seen for resources in discoveries early in the period reflected decisions to develop several big fields, such as Grane, Snøhvit and Ormen Lange, with the consequent conversion of their resources to reserves in fields. Johan Sverdrup accounted for the marked increase in oil resources from 2010 to 2011. Figure 3.2 also shows that recoverable quantities were significantly lower in 2013 than in 1999. In other words, the average discovery size measured in recoverable quantity is now smaller.


Figure 3.2

Figure 3.2 Development of the discovery portfolio from 1999 to 2013. Discoveries under evaluation and total resources by liquids and gas.


Discoveries are defined as development projects in figures 3.2 and 3.3 and in the rest of chapter 3. In the planned development of Johan Castberg, for example, the 7220/8-1 Skrugard and 7220/7-1 Havis discoveries represent a single project. More discoveries in the area could be included in the development project if they are assessed as commercial.

Changes in the discovery portfolio from one year to another are depicted in figure 3.3, which presents the status at 31 December in 2012 and 2013, changes which increase/reduce the number of development projects, and new discoveries in 2013. Light-tinted bars in the graph indicate a reduction in the number of development projects.


Figure 3.3

Figure 3.3 Change in number of discoveries from 2012 to 2013.


Discoveries where recovery is not very likely/non-commercial are not discussed further in this chapter.


Resources in discoveries

Expected recoverable resources in discoveries are estimated to be 1 056 million Sm3 oe. Of this total, 631 million Sm3 oe lies in discoveries in the planning phase (RC4), 207 million Sm3 oe in those where development is likely but not clarified (RC5), and 218 million Sm3 oe in ones yet to be assessed (RC7).

At 31 December 2013, resources in discoveries accounted for seven per cent of the NPD’s estimate of total petroleum resources. Undiscovered resources accounted at the same time for 21 per cent. See figure 1.1. The quantity of expected recoverable resources can change over time, in part as a result of new knowledge about geology and reservoir conditions, technological advances and commercial status.


Discoveries under evaluation

The portfolio comprised 88 discoveries at 31 December 2013. Figure 3.4 provides an overview of resources in discoveries by NCS area. Johan Sverdrup contains 55 per cent of the discovery resources in the North Sea, while Johan Castberg accounts for 51 per cent of those in the Barents Sea. These two stand out because of their size, and represent 43 per cent of the resources in discoveries.


Figure 3.4

Figure 3.4 Resources in discoveries by NCS area (million Sm3 oe) – Johan Sverdrup and Johan Castberg are shown separately.


Figure 3.5 presents an overview of liquid and gas resources in the discoveries by NCS area. Castberg and Sverdrup are not included. Extensive development studies are currently ongoing for these two. This chapter deals with the many smaller discoveries. Little attention is accordingly given to Castberg and Sverdrup in the rest of the discussion.

The distribution and size of discoveries in the various NCS areas are presented in figure 3.5. Liquids account for 58 per cent of resources in the North Sea, 33 per cent in the Norwegian Sea and 50 per cent in the Barents Sea.


Figure 3.5

Figure 3.5 Discoveries by NCS area and expected recoverable resources at 31 December 2013.


Table 3.1 provides a more detailed overview of the number of discoveries and their size by NCS area. While the average discovery size is weighted towards the big finds, the median size represents the midpoint when ranking discoveries by size.

Table 3.1
Area Number Average discovery size MSm3 oe Median discovery size MSm3 oe Per cent of total
52 13.0 4.4 64
Norwegian Sea 27 7.8 3.8 20
Barents Sea 9 19.0 7.0 16
Totalt 88 12.0 4.7 100

Table 3.1 Overview of the discovery portfolio at 31 December 2013, including Johan Sverdrup and Johan Castberg.


This discovery portfolio is dominated by many small development projects. Closeness to existing infrastructure or unitisation opportunities are crucial for whether and when these will be developed. Most discoveries in the portfolio have been made after 2000, with 42 per cent proven after 2009.


New subsea developments

Figure 3.6 provides an overview of possible development solutions for the 88 discoveries at 31 December 2013.


Figure 3.6

Figure 3.6 Expected development solutions for discoveries.


Subsea facilities phased into existing installations represent the most relevant solution for 68 of the 88 discoveries, with a total of 500 million Sm3 oe of recoverable resources. That gives an average of 7.5 million Sm3 oe per project.

Wells drilled from existing facilities are also a common development solution for small discoveries close to infrastructure with spare capacity. Recoverable quantities for discoveries planned as well developments total 23 million Sm3 oe, or an average of 1.7 million Sm3 oe per project.

In shallow waters, such as the North Sea, simple wellhead installations can be relevant development solutions instead of subsea facilities. Discoveries which require long tie-back to infrastructure with spare capacity, and which cannot justify a stand-alone development on their own, can be brought on stream through the coordinated development of several discoveries.

Figure 3.7 provides an overview of discoveries by the number of years since they were found, their size, and types of hydrocarbons. The oldest discoveries are generally smaller than those made more recently. Sixty per cent of the finds made before 2000 have estimated recoverable quantities of less than four million Sm3 oe. Complex reservoir conditions and distance from existing infrastructure with spare processing and transport capacity can help to explain why they still remain undeveloped.


Figure 3.7

Figure 3.7 Discoveries at 31 December 2013, excluding Johan Sverdrup and Johan Castberg, by number of years since they were made, size and types of hydrocarbons.


All resources in each discovery are shown in figures 3.7 and 3.8 as either oil or gas discoveries. Those defined as hydrocarbon types oil or oil/gas are grouped as oil discoveries. Those defined as hydrocarbon types gas or gas/condensate are grouped as gas discoveries.


Several conditions must be satisfied before discoveries can be phased into existing infrastructure. The most important of these are that spare capacity is available in the infrastructure, that the composition of production from the discovery is compatible with the process and export system, and that that transport distance for the unprocessed wellstream is not too long. Wellstreams which consist primarily of gas are easier to pipe over long distances than those dominated by liquid products. 

The distance regarded as the maximum for transferring unprocessed wellstreams is constantly increasing. Examples of technologies which contribute to this progress are water separation at the wellhead, insulating and heating transport pipelines, and chemical injection to prevent pipelines being plugged by wax and hydrates. The left-hand graph in figure 3.8 presents the smallest distance to existing or planned infrastructure for each of the discoveries under evaluation, with its associated size. The right-hand graph shows that about 80 per cent of resources in the discoveries lie within a tie-in distance of roughly 40 kilometres. That is the longest distance unprocessed oil wellstreams is transferred on the NCS today.



Figure 3.8

Figure 3.8 Discoveries and resources in discoveries, excluding Johan Sverdrup and Johan Castberg, by distance to infrastructure.


Profitability assessments

The NPD contributes to creating the greatest possible value for society from oil and gas activities This includes contributing to coordinated development of several discoveries and fields when that represents the best socio-economic solution.

Licensees in a production licence take development decisions based on profitability after tax. Profitability is determined to a great extent by discovery size, development and operating costs, and oil and gas prices. Assessing the uncertainty in these parameters is important for a decision. The profitability requirements applied in sanctioning a project will vary over time, both within and between companies.

The break-even price is a key measure of profitability. For a project, this will be the product price required to cover production costs and the required return on the capital committed. The break-even price can be calculated before and after tax. When a company decides on a development, the break-even price after tax is the relevant consideration. A company’s calculation of this factor can deviate somewhat from the break-even price before tax.

Break-even prices for discoveries in the planning phase have been calculated by the NPD, before tax and applying a rate of return of seven per cent.

Figure 3.9 shows that great variations exist in the break-even price, from just over USD 30 per barrel to roughly USD 100 per barrel. As illustrated in Figure 3.14, the break-even price has been rising over time. The latest large development projects approved on the NCS have had break-even prices up towards USD 80 per barrel. Although the break-even price says something about the profitability of a project at a given point in time and for a given development concept, it does not embrace all the factors given emphasis when deciding whether to proceed with the project. Uncertainty over the resource base and spare capacity in the infrastructure are the main reasons for failing to sanction most of these discoveries for development.


Figure 3.9

Figure 3.9 Break-even prices in USD (USD 1 = NOK 6) before tax for discoveries in the planning phase (RC4) at 31 December 2013. Calculated by the NPD.


Figure 3.6 shows that a large proportion of the discoveries under evaluation for development will utilise existing infrastructure, which can be a good socio-economic solution. The producing life of the fields is extended and recovery improves because costs for modifications and new investment can be shared.

The cost structure can vary substantially between various developments, depending on the solutions chosen. See figure 3.10. For some projects, a large proportion of the overall cost is incurred at an early stage in the form of capital spending. In other cases, costs may be more evenly distributed over time as operating expenses or tariffs. Weight is given when taking an investment decision to the amount of capital tied up in a project. Greater capital discipline will raise the threshold for development decisions and shift attention to less capital-intensive solutions. This could mean that the companies will shelve a number of projects which are profitable in a socio-economic perspective but fail to meet internal company requirements. That applies both to the choice of development solution and to how far the project is implemented.


Figure 3.10

Figure 3.10 Cost structure for discoveries in the planning phase (RC4).


3.2 Fields under development

Thirteen fields were under development at 31 December 2013. See figure 3.11. Goliat and Aasta Hansteen are in the Barents and Norwegian Seas respectively, with all the rest in the North Sea. Aasta Hansteen, Goliat and Knarr are being developed with floating production facilities. Valemon, Martin Linge, Ivar Aasen, Gudrun and Gina Krog involve fixed installations. The remaining four are subsea developments. Reserves in these field developments total 298 million Sm3 oe.


Figure 3.11

Figure 3.11 Reserves in current field development projects.


Several of the current developments involve discoveries made early in the 1990s or even farther back. This applies to Brynhild (1992), Svalin (1992), Martin Linge (1975), Valemon (1985), Gudrun (1974) and Gina Krog (1974).

Substantial exploration and appraisal activities have been pursued over time in connection with these older discoveries in order to define profitable development projects. More knowledge about such aspects as reservoir conditions has led to considerable changes in estimated recoverable resources and the relationship between liquid and gas. See figure 3.12.


Figure 3.12

Figure 3.12 Development in estimates for recoverable resources since 1992.


One example is Gina Krog (previously Dagny), which was discovered as far back as 1974. This was initially a small gas discovery set to be phased into Sleipner Øst. The 15/6-9 S well drilled in 2006 proved oil and additional gas resources. A further well in the autumn of 2008 showed that this discovery was in communication with Dagny, which also proved to have an oil zone beneath its gas. Before a development decision was taken, a total of 11 exploration wells had been drilled in the area.

An extensive portfolio of fields under development, with many stand-alone projects, is an important reason for the high level of investment in recent years. See figure 3.13. Fabricating facilities and drilling wells account for the bulk of this spending. In addition to the fields themselves, investment embraces the laying of new pipelines and modifications/developments at land facilities. The biggest spending here is for Aasta Hansteen, relating to Polarled and development at Nyhamna.


Figure 3.13

Figure 3.13 Investment forecasts for fields under development by project type.


Increased costs and delays represent challenges for many projects. A number of projects, on fields both in production and under development, have experienced a substantial growth in costs compared with the estimates made at the decision date. These issues are discussed in greater detail in the Vurdering av gjennomførte prosjekt på norsk sokkel (Assessment of projects implemented on the NCS) report published by the NPD in 2013 on behalf of the MPE. The quality of early-phase work and the operator’s follow-up of the project in the execution phase are two key requirements for avoiding cost overruns.

Figure 3.14 presents the break-even price at the decision date for field developments from 2005 to 2013. Despite considerable variation, the trend is a rising break-even price over time, particularly where platform-based projects are concerned. This increase over time primarily reflects growing costs. Projects with the lowest break-even prices are subsea developments which utilise spare processing capacity on existing facilities.


Figure 3.14

Figure 3.14 Break-even price before tax calculated by the NPD at the decision date for sanctioned field development projects since 2005.


3.3 Lead time

A total of 92 fields had been developed and brought on stream on the NCS by 31 December 2013. Development work began at the southern end of the NCS with Ekofisk, and has moved subsequently into new areas where activity has always begun with a stand-alone project. Small fields in the immediate vicinity have eventually been brought on stream with simpler development solutions. These satellites largely utilise the infrastructure of the stand-alone fields. Examples also exist of several fields being developed simultaneously, with one receiving the facilities for processing and transport. The latter is shown as a stand-alone development while the other fields are treated as satellites in figure 3.15, which presents progress in the number of fields and developments which have come on stream. 


Figure 3.15

Figure 3.15 Developments by stand-alone and satellite fields.


The gap between making a discovery and bringing it on stream is known as the lead time. The NPD has calculated that this period for an individual discovery averages 11 years. However, big variations exist. Figure 3.16 presents annual average lead times for individual discoveries which have come on stream.


Figure 3.16

Figure 3.16 Average lead time for individual discoveries.


More than 70 per cent of individual discoveries developed with stand-alone facilities have a lead time of less than 15 years. The bulk of these were discovered between 1980 and 2000. No individual discovery since 2000 has come on stream with stand-alone facilities. See figure 3.17. Those developed have been as satellites and phased into existing installations. See figure 3.18.


Figure 3.17

Figure 3.17 Lead time for fields developed with stand-alone installations.


Figure 3.18 shows that satellite deposits discovered before 1980 have a lead time of seven years and above. Early contract awards and standardised equipment – also known as fast-track projects – are important reasons for the short lead times achieved with discoveries made since 2000. This applies to 37 individual discoveries. One example of a discovery which has come on stream quickly is Atla, found in 2010 and on stream by 2012.


Figure 3.18

Figure 3.18 Lead time for fields developed as satellites.


3.4 Player diversity

Different players on the NCS can contribute varying expertise to realise the greatest possible value creation. The player picture is a function of production licence awards and different company strategies for exploration, development and farming in/out of licences.

Oil prices were around USD 10 per barrel in the late 1990s, and a substantial consolidation took place. Mergers between the big oil companies had direct consequences for the player picture on the NCS. International companies became fewer in number and even larger in size. That occurred at the same time as the NCS, particularly in the North Sea, developed into a more mature petroleum province which, with discoveries declining in size, presented different challenges than before. Exploring mature areas of the NCS was of limited interest for the large oil companies.

The Norwegian government accordingly adopted a number of measures to increase value creation from mature areas. See the Resource report – exploration for 2013. Key measures included giving more companies the opportunity to become licensees and introducing prequalification and tax refund schemes. Small and medium-sized oil and gas companies and European gas/power companies established themselves on the NCS. So did a number of new Norwegian companies. Player numbers increased from 28 at the end of 2000 to 56 by 31 December 2013. This increase in player diversity has been particularly noticeable in exploration.


Figure 3.19

Figure 3.19 Operators for producing fields on the NCS, by type of company.


Table 3.2 below presents today’s operators of producing fields by type of company.

Table 3.2
Large Norwegian companies Statoil
Integrated international oil companies BP, ConocoPhillips, Eni, ExxonMobil, Shell, Total
European gas/power companies Centrica, DONG, GDF Suez
Medium-sized companies Det norske, Marathon, Talisman, Wintershall, BG

Table 3.2 Groupings of operators for producing fields on the NCS at 30 January 2014.


The composition of the operator cohort has changed over time. Figure 3.20 shows how the types of companies serving as operators for field developments on the NCS have changed from one period to another. Large integrated companies dominated in the first phase. Phillips was responsible as operator for developing the first field, Ekofisk. Later, the big Norwegian companies Statoil and Norsk Hydro dominated development activities. A larger number of companies now serve as operators in both development and production stages. The pie chart for the most recent period also includes planned developments.


Figure 3.20

Figure 3.20 Development in types of operator companies for field developments.