Exploration

Resource-report-2011

Contents on this page:


 

Introduction

The level of exploration activity on the NCS in recent years has been high. This increase primarily reflects high oil prices and changes to Norwegian exploration policy.

Many discoveries have resulted from the high level of activity. Collectively, however, discoveries in recent years have been too small to replace annual production even though several major finds have been made so far in 2011. The present year could be the first since 1997 in which the resources found are big enough to replace the volume produced.

If production on the NCS is to be maintained at a high level, the size of discoveries must be larger than the average for the past 10 years. Exploration under the basalt layers in deep parts of the Norwegian Sea could open new opportunities, while further discoveries in the North and Barents Seas have encouraged optimism. Opportunities for making large discoveries are probably greatest in parts of the unopened areas on the northern NCS.


Many wells

A total of 1 325 exploration wells had been drilled on the NCS over the 45 years from the first drilling until 31 December 2010. The number of such wells peaked initially in the 1980s, with up to 50 drilled per year. See figure 3.1. A low annual figure for exploration wells characterised the second half of the 1990s and the first five years after 2000.

 

 Figure 3.1 Number of exploration wells spudded by area, 1966-2010

Figure 3.1 Number of exploration wells spudded by area, 1966-2010

Over the past three years, the number of exploration wells spudded has been on a par with or greater than the peak period in the early 1980s. The North Sea continues to account for the largest number of such wells.


Increased exploration

A correlation has historically existed between oil prices and the number of wildcat wells drilled on the NCS. This is illustrated by figure 3.2, where the number of wildcats is compared with the oil price in the previous year.

 

Figure 3.2 Nominal oil prices and number of wildcat wells spudded on the NCS, 1966-2010

Figure 3.2 Nominal oil prices and number of wildcat wells spudded on the NCS, 1966-2010

 

When oil prices rise, the consequence is generally that the number of wildcats increases in the following year. A lot of such wells are spudded in periods with very high oil prices. That occurred in the early 1980s and has been repeated over the past three years. However, this pattern was not so clear in the second half of the 1990s and the first five years after 2000. Oil prices fell sharply during the Asian economic crisis in 1998-99, and the oil companies reacted with a marked cut-back in exploration investment. Oil prices then rose, but exploration remained low for several years.

There were several reasons for the latter development. One could be that exploration activity is particularly affected by price uncertainty. When oil prices change from stable to unpredictable, the result can be lower capital expenditure. Exploration is particularly vulnerable in such conditions because it represents a long-term and risky investment. Financial markets during this period also put heavy pressure on the oil companies to improve their shortterm financial performance, which probably contributed to a postponement of exploration spending.

A sharp rise in demand for oil towards 2010 once again boosted prices, which helped to drive up global exploration activity. High oil prices have also generated optimism on the NCS, and thereby contributed positively to the number of exploration wells.

In addition, the Norwegian government has encouraged more exploration in mature areas through policy changes – including easier entry for new players, increased access to acreage, amendments to the area fee and tax changes. These moves may have contributed to a higher number of wildcats on the NCS than on the UK continental shelf (UKCS) over the past two years. See figure 3.3.

 

Figure 3.3 Number of wildcats spudded on the NCS and the UKCS, 1964-2010

Figure 3.3 Number of wildcats spudded on the NCS and the UKCS, 1964-2010

 

Every little helps

International experience demonstrates that the largest discoveries in a new petroleum province are made early in the exploration phase, and that the size of finds gradually declines. That also holds true for the NCS. In a historical context, discoveries over the past 25 years have been small. However, there will always be exceptions.

The contribution of discoveries to resource growth has been substantially lower over the past 25 years than was the case in the first 20 years of Norway’s oil history. This is illustrated by figure 3.4, which shows resource growth from discoveries by discovery size, and figure 3.5, which presents the cumulative growth in resources on the NCS.

 

Figure 3.4 Resources in discoveries proven in five-yearly periods by discovery size, 1966-2010

Figure 3.4 Resources in discoveries proven in five-yearly periods by discovery size, 1966-2010

 

Figure 3.5 Cumulative growth in resources, 1967-2010

Figure 3.5 Cumulative growth in resources, 1967-2010

 

Since 1998, the annual growth in resources has been lower than annual production. This is illustrated by figure 3.6, which shows resource growth and production per annum.

 

Figure 3.6 Annual resource growth and production, 1990-2010

Figure 3.6 Annual resource growth and production, 1990-2010

 

Varied discovery success

The average discovery success on the NCS is very high by international standards. Sequential exploration, technological developments and steadily growing knowledge have enhanced the probability of making new discoveries. Over the past 30 years, discovery success has risen from around 25 per cent in 1980 to roughly 55 per cent in 2010. See figure 3.7.

 

Figure 3.7 Number of completed wildcats, number of discoveries and

Figure 3.7 Number of completed wildcats, number of discoveries and discovery success on the NCS, 1980-2010

 

Most discoveries continue to be made in the North Sea, where discovery success has averaged about 45 per cent since 1967. It has been very high in recent years, at more than 50 per cent. Exciting discoveries are still being made, with new plays being confirmed in areas with a long exploration history. An interesting region is the Utsira High in the central part of Norway’s North Sea sector, where 32 exploration wells have been drilled. Although regarded as a mature area, it has yielded new types of reservoirs over the past five years. A number of interesting medium-sized discoveries have been made, such as 16/1-8 (“Luno”) and 16/1-9 (“Draupne”). Exploration drilling over the past year has also proven 16/2-6 (“Avaldsnes”) and 16/2-8 (“Aldous Major South”), which could jointly become a major new oil discovery on the NCS. Substantial drilling activity is planned in the area during the time to come.

 

Figure 3.8 The Utsira High in the North Sea

Figure 3.8 The Utsira High in the North Sea

 

Avaldsnes and Aldous
Wells 16/2-6 (“Avaldsnes”) and 16/2-8 (“Aldous Major South”) could jointly rank as the largest oil discovery on the NCS since the 1980s. They were drilled about 40 kilometres south of Grane. Both discoveries have been made in a combination of stratigraphic and structural closure, with Upper Jurassic sandstones forming the reservoir. Well data show that the two discoveries share the same oil/water contact, which indicates communication between them. Based on preliminary resource estimates, a stand-alone development is very realistic.

 

As in the North Sea, the Norwegian Sea has witnessed a positive trend for discovery success and many finds have been made despite disappointing exploration results also being recorded. Since the deepwater part of this region was opened in 1994, 25 wildcats have been drilled in depths beyond 600 metres. See figure 3.9. The discovery rate in deep water is close to 50 per cent, compared with just over 40 per cent in other parts of the Norwegian Sea.

 

Figure 3.9 Deepwater wells in the Norwegian Sea and proven resources by operator

Figure 3.9 Deepwater wells in the Norwegian Sea and proven resources by operator

 

Fewer discoveries than expected have been made in deep water. Results from deepwater wells indicate that proven expected recoverable resources are less than 40 per cent of the resources expected before drilling.


Sub-basalt in the Norwegian Sea

The sub-surface in the western part of the Norwegian Sea was affected by extensive volcanic activity when the North Atlantic opened about 55 million years ago (early Eocene). Lava flowing from the Earth’s interior hardened into layers of basalt, a dark hard rock present beneath the western Norwegian Sea. Sedimentary rocks which could contain petroleum in these areas were largely deposited before the vulcanism began, and accordingly lie beneath the basalt.

This rock is difficult to “see” through, so the challenge is to obtain an impression of the underlying strata. Much work has been devoted to learning more about what lies beneath the basalt, both by companies in production licences and by other projects, such as the Force collaboration.

 

The Force collaboration
FORCE(Forum for Reservoir Characterisation, Reservoir Engineering and Exploration) is a collaboration between oil companies on the NCS whose main jobs are helping to enhance reserves and to prioritise activities which increase exploration success and petroleum recovery. Activities in Force are organised in two technical committees for improved exploration and improved oil and gas recovery respectively. Each committee has sub-committees for network building and projects.


The NPD’s seismic mapping west of the Møre Basin, on the Møre Marginal High, indicates that the latter area was centrally placed in the transport route for sediments from Greenland about 65 million years ago (Palaeocene). See figure 3.10. Coarse-grained sediments were carried by rivers from Greenland eastwards to Jan Mayen and the Møre Marginal High, and deposited as sedimentary fans in the Møre Basin. This process could have deposited reservoir rocks in all three areas during the Palaeocene. The NPD’s interpretation of two-dimensional (2D) seismic data has revealed an area of the Møre Marginal High with no basalt cover. This could function as a “keyhole” for looking beneath the basalt layer.

 

Figure 3.10 The Norwegian Sea with the Møre Marginal High, the Møre

Figure 3.10 The Norwegian Sea with the Møre Marginal High, the Møre Basin and the Vøring Marginal High

 

The NPD acquired 2D seismic data on the Møre Marginal High in the summer of 2011. Together with earlier survey results, this material will be used to plan two shallow wells in this area’s “keyhole”. They are due to be drilled in 2013. Information from these shallow wells will clarify the interpretation of the area. A possible Palaeocene play under the basalt will be highly significant, both for the Møre Marginal High and for prospective areas around Jan Mayen. The play could also be relevant further north – on the Vøring Marginal High, for instance.

Petroleum has been found in and under basalt strata in several parts of the world. The closest discoveries are off Ireland and west of Shetland on the UKCS. Wells have also been drilled to seek petroleum under the basalt on the Faroese continental shelf, so far without success.

Four production licences with prospectivity related to basalt challenges were awarded in the 20th and 21st licensing rounds. No decision has so far been taken on drilling wildcats in any of these licences.

Almost 90 wells have been spudded in the Barents Sea since the first wildcat was drilled there in 1980. The discovery rate in the Hammerfest Basin has been high, even though few of the finds are considered commercial, and stands at roughly 50 per cent compared with just under 40 per cent for the rest of the Barents Sea.

Snøhvit is the only producing field in the Barents Sea. See figure 3.11. This gas field covers the 7121/4-1 (Snøhvit), 7120/8-1 (Askeladd), 7120/7-1 (Askeladd Vest), 7120/7-2 (Askeladd Sentral), 7120/9-1 (Albatross) and 7121/7-1 discoveries. The Goliat oil field is under development. Some discoveries have been made near Snøhvit and Goliat, and the area also contains a number of prospects. The most likely development solution for existing discoveries and possible new finds in the Snøhvit and Goliat area will be to tie them back to existing installations. Stand-alone developments could be relevant for other parts of the Barents Sea.

 

Figure 3.11 Barents Sea South with discoveries to date in 2011

Figure 3.11 Barents Sea South with discoveries to date in 2011

 

Seven exploration wells are due to be drilled in the Barents Sea during 2011. The first two (7120/12-5 and 7119/12-4) were dry, while the next three resulted in discoveries (7220/8-1 (“Skrugard”), 7225/3-1 (“Norvarg”) and 7120/2-3 (“Skalle”)).

Ranked as the largest discovery in the Barents Sea since Goliat in 1980, 7220/8-1 (“Skrugard”) was drilled about 110 kilometres north of Snøhvit. It lies in a rotated fault block where the reservoir is formed of Jurassic sandstones (of the same age as the Snøhvit reservoir). Based on preliminary resource estimates, a stand-alone development could be realistic.

Representing a new gas discovery on the Bjarmeland Platform, 7225/3-1 (“Norvarg”) was drilled in a large dome with reservoirs in the Jurassic and several Triassic levels. Further appraisal drilling will be needed to calculate a resource estimate. The small 7120/2- 3 (“Skalle”) gas discovery lies in Cretaceous and Jurassic reservoir rocks, 25 kilometres north of the Snøhvit area. A development is likely to involve a tie-back to existing installations on Snøhvit.

Oil and gas discoveries outside the Hammerfest Basin have encouraged increased optimism in the Barents Sea. That could lead to more exploration drilling, particularly in areas close to new discoveries.

Twelve production licences were awarded in the Barents Sea in the 21st round. Three of these lie close to 7220/8-1 (“Skrugard”). Interest in other areas of the Barents Sea is great. One of these is the Hoop fault complex, where production licences 537 and 615 involve commitment drilling. Both oil and gas could be found in this area.


High exploration costs

Exploration costs are incurred by production licences from the time they are awarded until a possible discovery is developed, and comprise spending on seismic surveying, exploration wells, field evaluation and administration. These costs have increased in recent years, reflecting both the growth in exploration activity on the NCS and general cost inflation nationally and internationally. See figure 3.12

 

Figure 3.12 Total exploration costs on the NCS by cost category

Figure 3.12 Total exploration costs on the NCS by cost category


Drilling represents the most important single factor in total exploration costs. It can be divided roughly into rig costs and other outlays. Rig costs are determined by the day (rig) rate and the number of drilling days.

Rig rates have increased sharply around the world in recent years. However, they remain higher on the NCS than in other comparable petroleum provinces.

The steep rise in drilling costs and the lack of large new discoveries have contributed to a dramatic increase in finding costs per scm oe discovered. See figure 3.13. Finding costs are an important indicator for companies assessing which petroleum provinces they should invest in. When the deepwater areas of the Norwegian Sea were opened in 1994, the announcement and award of new licences led to the discovery of Ormen Lange in 1997 and Skarv in 1998. In addition, 6707/10-1 (“Luva”) was proven. This led to a rise in resource growth per well and a fall in finding costs per scm oe discovered. Few large discoveries were made in 2000-10. Combined with high rig costs, this led to high average finding costs on the NCS.

 

Figure 3.13 Development in finding costs and resource growth per wildcat

Figure 3.13 Development in finding costs and resource growth per wildcat on the NCS, five-year rolling averages
 

 

Profitable exploration

During the autumn of 2010, the NPD conducted an analysis of exploration profitability in the 2000-10 period. Although discoveries on the NCS were relatively small and exploration costs high during this time, the analysis shows that exploration activities over the period yielded substantial value both for the companies and for the Norwegian community.

A total of 352 exploration wells were spudded during the analysis period, including 242 wildcats and 110 for appraisal. This activity yielded 149 discoveries, which gives a technical finding rate of 62 per cent – very high internationally. Of the wildcats, 219 were drilled in the North Sea.

Exploration wells during the period were drilled in production licences awarded either in recent years or in earlier licensing rounds. Figure 3.14 presents discoveries for the period by the round in which the production licence was awarded.

 

Figure 3.14 Discoveries in 2000-2010 by licensing round. Supplementary awards are placed in the original round

Figure 3.14 Discoveries in 2000-2010 by licensing round. Supplementary awards are placed in the original round

 

Recoverable resources proven during 2000-10 totalled 333 million scm oe of gas and 403 million scm of liquids, or 736 million scm oe in all – on a par with the volume in Ekofisk.

Present value in 2010 money is calculated to be roughly NOK 710 billion for the discoveries and about NOK 200 billion for exploration costs. That makes the net present value for the whole period NOK 510 billion in 2010 money. See figure 3.15.

 

Figure 3.15 Present value of exploration activities, 2000-2010

Figure 3.15 Present value of exploration activities, 2000-2010

 

Although gas represented the largest volume discovered in 2000- 10, oil found made the biggest contribution to value creation. The analysis also shows that the North Sea provided the highest net present value during the period.

A substantial proportion of the discoveries during the period lie in mature areas. A number of these can be tied back to existing infrastructure and thereby extend the producing life and enhance the recovery factor for fields currently on stream. This supplementary value of exploration activities in 2000-10 may be substantial, but is not included in the value estimate for exploration activities.

Statoil (including the former Hydro) accounts for more than half the value created through exploration in 2000-10. Figure 3.16 allocates present value excluding exploration costs for the analysis period by licensee.

 

Figure 3.16 Present value excluding exploration costs by licensee

Figure 3.16 Present value excluding exploration costs by licensee

 

The analysis also shows that “new” companies on the NCS have made a substantial contribution, particularly in the past few years. Such companies are defined as those awarded their first production licence after 1999. During the past two years, they have accounted for more than half the value created by exploration.

Profitability of exploration

The profitability of exploration is defined as the net present value of discoveries made in a period less associated exploration and planning costs. Only discoveries with a positive present value are taken into account when calculating profitability. Those with a negative present value are assumed to remain undeveloped, and only their exploration costs are included. Production and cost profiles are established for each discovery, so that its profitability can be calculated. Opportunities for making several discoveries in a single production licence complicate the allocation of exploration costs to a specific discovery. In a number of cases, too, exploration costs are reported to Statistics Norway (SSB) collectively for several production licences. Appraisal wells form part of exploration operations and are included.

Price assumptions are based on the forecast from the Ministry of Petroleum and Energy (MPE) – the same input used in the analysis of undiscovered resources off Lofoten and Vesterålen (see www.npd.no). Historical export prices (source: SSB) are also used. These are converted to 2010 money using the consumer price index (CPI). All cash flows are converted to 2010 money and discounted to 2010. A fixed discount rate of seven per cent is applied. A discount rate of four per cent is used for the sensitivity calculation.


Unopened areas – mostly in the far north

Half the areas in which oil and gas are expected to be found have yet to be opened for petroleum activity. That applies to the waters around Jan Mayen, the north-eastern Norwegian Sea (parts of Nordland IV and V, Nordland VI and VII, the Vest Fjord and Troms II), Barents Sea North/the Arctic Ocean, the new sea area in Barents Sea East (former area of overlapping claims), parts of Trøndelag I and II, Møre I, the Skagerrak, the coastline off Finnmark and Troms counties, the Bear Island Fan, and the buffer zone around Bear Island. A number of these areas are interesting for their petroleum potential. However, the level of knowledge, distance to markets and existing infrastructure, environmental assets and other user interests differ between the various areas. The basis for the assessments which need to be made and the time scale from a possible opening process until exploration, discovery, development and production will accordingly vary from area to area. Political decisions are required to open new areas for petroleum activity.

 

Former area of overlapping claims

The maritime boundary between Norway and Russia in the Barents Sea and the Arctic Ocean has been the subject of negotiations for roughly 40 years. Tentative agreement was reached between the two countries over a boundary in these waters on 27 April 2010. The treaty between Norway and Russia on the maritime boundary and collaboration in the Barents Sea and the Arctic Ocean was signed in Murmansk on 15 September 2010 and ratified on 7 June 2011 in Oslo. It entered into force on 7 July 2011.

This treaty means that the former area of overlapping claims, covering some 175 000 square kilometres, has been divided into two roughly equal parts. These cover areas in both the northern and the southern Barents Sea. The treaty also contains provisions on collaboration between the two sides if oil or gas deposits were to extend across the boundary line. Should such cross-boundary resources be found, the treaty specifies detailed rules and procedures aimed at ensuring their responsible and cost-effective administration.

The NPD regards the new Norwegian area in the Barents Sea as interesting for petroleum activities. Petroleum has been proven to both the east and the west. This raises hopes that it could also exist in Norway's new sea area. Data there are very limited, and provide an inadequate basis for assessing the resource potential. Seismic surveying was accordingly initiated in the summer of 2011. This work has been commissioned by the NPD at the request of the government, and will be completed in 2012.

In connection with updating the integrated management plan for the marine environment in the Barents Sea and off Lofoten – White Paper no 10 (2010-2011) – it was resolved that the MPE will launch an impact assessment pursuant to the Petroleum Activities Act with a view to awarding production licences in the former area of overlapping claims west of the boundary line in Barents Sea South. Assuming that the assessment provides an appropriate basis, the government will present a White Paper which recommends the opening of these areas for petroleum activity. Work on the assessment will begin in the autumn of 2011.

 


To the top of the page


 

The resource report 2011
Main page Preface Status og utfordringer på norsk sokkel.. Uoppdagede ressurser 3 Fra funn til felt Muligheter og utfordringer for felt i drift

09.11.2011