3. Exploration activity: Exploration and efficiency

Exploration and efficiency

	Fig. 3.13 Pre-licence and licence costs.
	Fig. 3.14 Trend in exploration costs apportioned among the cost components.

Exploration costs

The costs associated with exploration on the Norwegian continental shelf are divided into pre-licence and licence costs. Pre-licence costs are those incurred during the preparation for and drawing up of applications in connection with licensing rounds. Licence costs are all the costs incurred in the production licences from allocation up to the possible approval by the authorities of a Plan for Development and Operation, or to the relinquishment of the licence. The historical development in these costs is shown in Figure 3.13. The costs have decreased in recent years, from just over 14 billion in 1985 to 10 billion in 1991 and around 5.7 billion in 1995 (all figures in 1996 NOK). Licence costs are divided into four main groups: wildcat drilling, general surveys including seismic costs, field evaluation and development, and administration. Figure 3.14 shows the trend in the exploration costs apportioned among these components.

The trend in the exploration costs has historically followed the trend in the exploration activity, which is shown in Figure 3.14 by the number of exploration wells. Since drilling costs have traditionally comprised the most important single factor in the total exploration costs, the reduction from 1985 to 1995 can be largely explained by the drop in the number of exploration wells.

The number of exploration wells per year is, among other ways, determined by the frequency and scope of the licensing rounds and the work obligations stipulated when allocation takes place. However, the market conditions also influence the activity, particularly the price of oil and the rig market. Figure 3.16 shows that there is a clear connection between the nominal price of oil and wildcat drilling on the Norwegian shelf. The high level of exploration activity early in the 1980s took place when the price of oil was very favourable. The reduction in the drilling costs is due to both the reduction in the number of wells and the technological trend in drilling. This has given significant gains in efficiency, for example in the form of more rapid drilling and reduced drilling time. This is important for reducing the drilling costs, since the hiring of drilling installations constitutes a major proportion of the drilling costs.

The cost of installations is determined by the number of drilling days and the price per day (day rate), which is decided by supply and demand in the market for rigs (Fig. 3.15). Figure 3.17 shows how the drilling costs per meter and per well have been reduced in the period from 1985 to 1995. The high figures for 1989 are due to special problems with a well in production licence 146. This figure also shows that the reduction in the exploration costs per well has not been as great as the reduction in the drilling costs per well. The exploration costs per well have remained very stable since 1991, at the same time as the drilling costs per well have dropped significantly. This is due to an increase in the costs of acquiring, processing and interpreting seismic data (general surveys), see Fig. 3.18. This increase results from the change from 2D to 3D seismic with a consequent huge increase in the number of line kilometers of seismic. The costs of seismic data per line kilometre have dropped during this period. Development of hardware has made it possible to carry out a large part of the processing of seismic data simultaneously with acquisition. The advantages of this have been both shorter delivery time and enhanced quality control of the data acquisition. A greater volume of seismic data has reduced the need for appraisal wells and improved the efficiency per wildcat well. This is shown, for example, by the increase in the cost of seismic data being offset by the reduction in drilling costs, resulting in the total exploration costs having dropped.

Fig. 3.19
Trend in exploration costs per resource growth and trend in resource growth per wildcat well.

Exploration efficiency

An indicator of the exploration efficiency on the Norwegian shelf, i.e. how much is found for each NOK invested in exploration, is found by comparing the trend in exploration costs with that of the annual resource growth. Up to the mid-1980s, the exploration costs rose in step with the growth in resources so that exploration costs per resource growth only rose slightly. Since then, the growth in resources has been somewhat less without a corresponding drop in the exploration costs. This has meant that exploration costs per resource growth have increased since the mid-1980s.

In Figure 3.19, the trend in exploration costs per resource growth (finding cost) is plotted together with the trend in resource cost per wildcat well (discovery rate). The figure shows a declining discovery rate and a increasing finding cost through this period. This is typical for a mature petroleum province. Such a trend can, however, be offset by the technological development. In the last two years, we can see a certain rise in the discovery rate and a decline in the finding cost. This may, among other things, be due to improved accuracy as a consequence of increased use of 3D seismic prior to drilling of wildcat wells.

Timing of exploration

Exploration and planning costs accounted for 12% of the total costs on the Norwegian continental shelf in the period 1990-95, whereas the costs in the development and operational phases accounted for, respectively, 58% and 30% of the total costs (Fig. 3.20). The exploration and planning costs do not constitute a dominant proportion of the total costs, but attain great significance because they come early. The NORSOK report states that: "For the Norwegian shelf, a separate analysis indicates that the part played by the break-even price from the activity during the exploration phase, including pre-licence costs, is 4.5 USD/barrel (discounted), despite the costs per resource growth being 1.5 USD/barrel for the same period (non-discounted). This shows the great importance the time span between the allocation and production has for the economy of a field". The time elapsing between discovery and start of production may be reduced by bringing forward the start of production or postponing exploration. Figure 3.21 illustrates that, for a number of fields, a great deal of time elapsed between discovery and production (lead time). The figure shows that discoveries made at the end of the 1970s and in the 1980s had to wait at least 6-8 years before production could start, whereas several of those made in the 1990s have a significantly shorter lead time. The discoveries with the longest lead time are those close to existing infrastructures whose capacity is fully utilised, and also gas discoveries.

Licensing rounds from 1984 to 1994

The Directorate has carried out an analysis of the exploration results and applications made by companies in the 8th-14th licensing rounds, covering the period from 1984 to 1994. The growth in resources, the costs, the profitability and the accuracy of the resource estimates prior to allocation were analysed. The analysis is based on data available as of 31.12.1995.

During this period, a total of 114 production licences were allocated. As of 31.12.1995, 191 wildcat wells had been drilled in these areas and 73 discoveries had been made. The growth in resources was about 855 mill. Sm³ of oil/NGL and 585 bill. Sm³ of gas. Figure 3.22 gives an overview of the number of wildcat wells and technical success rates per licensing round. The technical success rate for these 7 licensing rounds has so far been 38%. A number of wildcat wells still remain to be drilled in licences allocated in the 14th round. Figure 3.23 shows the 20 largest discoveries and fields that were found during the 8th-14th licensing rounds. The resources in discoveries and fields found in the blocks in the 8th round comprise more than 50% of the total growth in resources from licences allocated in the 8th-14th rounds.

A profitability analysis of the results of the 8th-14th rounds shows that a total of 38 discoveries and fields have a positive net present value. This gives an commercial success rate of 20%. The assumptions in the calculations are identical with those used in connection with the annual report for the National Budget. Figure 3.24 presents an overview of the calculated net present value of total costs and gross revenues from the 8th-14th licensing rounds. The calculations show that these licences have today given a net present value somewhat in excess of 60 bill. 1995 NOK. The net present value of the various cost categories is also shown in Figure 3.24. The net present value of the total exploration and planning costs, both pre-licence and licence costs comprise about 30% of the net present value of the total costs. Correspondingly, the net present value of the investment costs constitutes about 40%. The net present value of the total operating costs, including CO₂ -tax and transport costs, constitutes approximately 30%. Investment and operational costs concern only those discoveries and fields that are considered commercial.

When the oil companies apply for new licences on the Norwegian continental shelf, the application must, among other things, document the resource potential in the blocks for which they are applying. Figure 3.25 gives a comparison between the expected value of the prospects mapped and the actual size of the discoveries. It shows that the oil companies largely overestimate the expectations regarding the size of future discoveries. Calculations show that the companies have, on average, overestimated the expectations by a factor of 2.2. These estimates are generally given with an uncertainty range. Even allowing for this, in only one of five cases was the actual size of the discovery within the uncertainty range.

Fig. 3.26
The total pre-licence resource estimate of the companies shown as percentages of the total volume of the discoveries (8th-14th licensing rounds).

The total resource estimates made by the companies are shown in Figure 3.26 as percentages of the total volume of discoveries. The comparison only concerns the evaluated prospects that have resulted in discoveries. Only companies which have evaluated five or more prospects which have resulted in discoveries, are included in this overview. Every company that has applied for new production licences on the Norwegian continental shelf, has had greater expectations than were fulfilled during this period. The yellowbar in the figure shows how the Directorate's resource estimate fits into this comparison.

Figure 3.27 illustrates the great measure of uncertainty associated with exploration. The figure shows a comparison between the Directorate's estimate of the expected resources prior to allocation and the actual growth in resources resulting from the 8th-14th licensing rounds. It reveals a great deviation in some licensing rounds. The results were disappointing in rounds 11, 12 and 13, relative to the pre-licence expectations. This is largely offset by the exceptionally good results from the 8th round.

Find

The forum for improvements in exploration technology, named FIND, is a co-operative project between the oil companies and the Directorate. The objective is to increase our understanding of the factors that are important for improving the success rate on the Norwegian continental shelf. So far, two projects have been initiated: evaluation of drilling results and Supergrid. The supergrid project intends to develop a program to relate all the 3D seismic data into a common coordinate system. The objective is to establish a basis for a regional 3D seismic network.

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