Undiscovered resources

Resource-report-2011

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Introduction

One of the NPD’s most important jobs is to produce estimates of undiscovered resources on the NCS. Good administration of the petroleum resources calls for knowledge of their total volume, both discovered and undiscovered, so that policies can be formulated on the basis of extensive information. The NPD has access to all petroleum data from the NCS, and accordingly possesses the best basis for producing an independent and well-qualified calculation of the total resource potential.

Twenty per cent of estimated resources in the NCS have still to be discovered, which shows the significance of continued mapping, exploration and drilling of wells. See figure 2.1. Although the estimate for undiscovered resources has been slightly reduced from the previous resource report in 2009, the potential for finding more remains considerable.

 

Figure 2.1 Total recoverable resources on the NCS

Figure 2.1 Total recoverable resources on the NCS

 

The statistical expected value for undiscovered resources is roughly similar in the three sea areas making up the NCS, but the biggest upside potential is found in the Barents Sea – where large areas are still little explored.

The estimate presented in this report does not include the waters around Jan Mayen or in Norway’s new Barents Sea East area. When new seismic data are available, and these areas have been mapped, the resource base for the NCS will increase. The NPD began to acquire seismic data from these two areas in 2011.

Great uncertainty attaches to the estimate for undiscovered resources, ranging from about one billion scm oe to almost five billion, with an expectation (average) value of 2.6 billion for total resources (liquids and gas). The distribution of undiscovered resources is shown in table 2.1.

 

Table 2.1 Distribution by area of undiscovered resources with uncertainty range.
Liquids are oil and condensate

  Liquids
mill scm oe
Gas
bn scm
Total
mill. scm oe
  P 95 Expec P 5 P 95 Expec P 5 P 95 Expec P 5
North Sea 285 565 910 140 280 465 470 845 1305
Norwegian Sea 85 325 705 130 455 960 260 780 1580
Barents Sea 50 425 1180 80 520 1460 175 945 2460
Total 480 1315 2500 420 1255 2540 1020 2570 4800

 
Expectations are highest for the Barents Sea, where the estimate accounts for 37 per cent of resources, while the Norwegian Sea has the lowest expectation at 30 per cent. See figure 2.2.

 

Figure 2.2 Distribution of undiscovered resources by area

Figure 2.2 Distribution of undiscovered resources by area

 

How undiscovered resources are calculated

The NPD calculates undiscovered resources with the aid of a method known as play analysis. This is a recognised approach, used by both companies and governments. Applied by the NPD for many years, it is very suitable for areas where the geology is known, many prospects have been identified and a number of wells have been drilled. The method is accordingly appropriate for large parts of the NCS. It involves systematising and describing the geological understanding of an area. On that basis, the amount of petroleum which could be proven and produced from each play is calculated. See the box on geological plays.

 

A play

A play is defined within a geographically delineated area where a specific set of geological factors is present so that it should be possible to prove petroleum in producible volumes.

These factors are:  

  1. Reservoir rock, which is a porous rock where petroleum can accumulate. Reservoir rocks in a specific play will belong to a given stratigraphic level.
  2. Cap rock, which is a tight (impermeable) rock overlaying a reservoir rock, so that petroleum can migrate no further and accumulates in the reservoir. The resulting trap must have formed before petroleum ceased to migrate into the reservoir.
  3. Source rock, which is shale, limestone or coal containing organic materials which can be converted into petroleum. The source rock must be mature – in other words, its temperature and pressure are such that petroleum actually forms – and the petroleum must be able to migrate from source rock to reservoir rock.

 

A geographical area can incorporate a number of plays of varying geological ages – one in the Triassic and another in the Cretaceous, for example. Prospects are the fundamental components in a play analysis, and the number of prospects and the amount of petroleum each of them could produce determine the estimated resources for that play.

A play is characterised by geological factors collectively present in a clearly delineated area (basin), both stratigraphic and geographic: reservoir, source and cap rocks. Mapped and unmapped prospects, discoveries and fields can be found within a single play. See figure 2.3.

 

Figure 2.3 The relationship between basin, play, discovery and prospect

Figure 2.3 The relationship between basin, play, discovery and prospect

 

A prospect is a potential petroleum deposit which has been mapped and where the quantity of possible producible petroleum can be calculated. The prospect’s discovery probability is the probability that a well could prove producible petroleum there. In play analysis, the ability to calculate how many prospects could be present in each play is important. The number of possible discoveries and their size must also be assessed. In an area with few or no wells, such assessments are the most important sources of information when developing a resource estimate for the play. The NPD uses new data from mapping and well drilling to update and adjust resource estimates for the relevant plays on a regular basis.

A play is confirmed when a discovery is made in it, and uncertainty no longer prevails over whether the geological factors function. The resource estimates will normally increase when a play has been confirmed. A confirmed play is characterised by a discovery which has proven producible petroleum. The discovery does not need to be commercial. If producible petroleum has still not been confirmed, the play remains unconfirmed. Confirmation of the play is then associated with a probability.

Estimated resources for a play are more uncertain the less is known about the play, and the NPD accordingly specifies resources with an uncertainty range. The NPD’s estimate for undiscovered resources also includes the areas which have not been opened for petroleum activity on the NCS, apart from the waters around Jan Mayen and the new Norwegian area of Barents Sea East. Knowledge about reservoirs in fields and in discoveries yet to be developed is important, but dry wells can also provide valuable data on geological conditions. The NPD also draws on information about mapped prospects in its database, which builds on its own and company work on the NCS.


The NPD’s prospect database

Play analysis is based on knowledge about the number and size of deposits or prospects in each play. A good database of all mapped prospects is important for the NPD. Through numbered licensing rounds and awards in predefined areas (APA), the NPD has access to extensive mapping of prospects by the oil companies. It also has access to the interpretation work conducted by licensees in the licences through participation in exploration committee meetings. In addition, the NPD’s geologists and geophysicists themselves work on extensive prospect mapping. The database contains some 1 500 mapped prospects. The NCS is continuously evaluated, and additional information acquired through seismic mapping and exploration drilling. Each new exploration well leads to the removal of a prospect from the database and, if petroleum is encountered, the prospect is reclassified as a discovery in the database. Mapping can lead to the addition of further prospects.

The NPD collates forecasts for and results of exploration drilling. It compares such data as the quantity of petroleum estimated for the prospect with the volume proven by discoveries. It transpires that operators often make over-optimistic estimates of the amount of petroleum in a prospect. That applies in particular to those which prove to contain oil. There are fewer gas prospects, and experience indicates that forecasts and results agree more closely for these.

Sixty-seven discoveries made in 1998-2007 have been analysed by the NPD. Figure 2.4 compares operator company expectations of the volume of petroleum in a prospect before drilling with the amount actually found. Discoveries are ranked by the operator’s forecast for resources in place and classified by the type of petroleum. The vertical purple lines show the operator’s uncertainty range before drilling, with the expected value as a black square. Red triangles represent the proven volume in the discovery. In this data set, estimated oil in the prospects is 2.5 times greater than the resources proven. Agreement between expectation and result is better for gas than for oil. This could be because gas reservoirs often yield a stronger seismic response, which simplifies mapping of and estimating volume for the deposit.

 

Figure 2.4 Comparison of operator expectations of petroleum volume in 67 deposits before drilling, and the results after drilling

Figure 2.4 Comparison of operator expectations of petroleum volume in 67 deposits before drilling, and the results after drilling

 

Excessive estimates from operators present a challenge for the NPD when adding up prospects to be included in a play analysis. Using the volume of resources in these prospects uncritically will mean that the estimate for undiscovered resources in the play becomes too high. A quality check of the prospects is accordingly carried out before incorporating the volume of resources in the analysis.

The NPD uses information and results from discoveries as a quality check for realistic resources in the prospects and expectations of the number of discoveries in each play. If a play analysis makes uncritical use of excessive estimates for the prospects, the actual discovery history will show a poor match with the modelled estimates for future discoveries generated by the analysis.


Play analysis

The NPD has defined 69 plays which all contribute to the estimate for undiscovered resources, as shown in table 2.2.

 

Table 2.2 Confirmed and unconfirmed plays
Area Confirmed
plays
Unconfirmed
plays
Total
North Sea 19 4 23
Norwegian Sea 9 10 19
Barents Sea 8 19 27
Total 37 32 69

 

A little over half the plays have been confirmed by discoveries. Most of these are located in the North Sea, where 19 of 23 plays are confirmed. The smallest number – eight out of 23 – is in the Barents Sea. That reflects the maturity of these areas. Exploration has been pursued longest in the North Sea, and most of this area has been opened for petroleum activity. Large parts of the northern and eastern Barents Sea remain closed, and a number of plays have been defined in the unopened areas.

Sixteen discoveries were made on the NCS in 2010. None lay in previously unconfirmed plays. The 7220/8-1 (“Skrugard”) and 7225/3-1 (“Nordvarg”) discoveries in 2011 have encouraged fresh optimism in the Barents Sea. Both were made in previously confirmed Jurassic and Triassic plays. They have little effect on the total resource estimate for the Barents Sea. The 16/2-6 (“Avaldsnes”) and 16/2-8 (“Aldous Major South”) discoveries in the North Sea were made in previously confirmed Jurassic plays, and have led to a better understanding of possible migration routes on the Utsira High.

The potential of the 23 plays in the North Sea is indicated with their expected value in figure 2.5. Unconfirmed plays are depicted with a lighter colour above the expected value. This shows the additional potential if the play is confirmed.

 

Figure 2.5 Plays in the North Sea

Figure 2.5 Plays in the North Sea


Figure 2.6 presents the potential of the 19 plays in the Norwegian Sea with their expected value. The 10 unconfirmed plays are depicted with a lighter colour above the expected value. This shows the additional potential if the play is confirmed.

 

Figure 2.6 Plays in the Norwegian Sea

Figure 2.6 Plays in the Norwegian Sea

 

The potential of the 27 plays in the Barents Sea is shown with their expected value in figure 2.7. The 19 unconfirmed plays are depicted with a lighter colour above the expected value. This shows the additional potential if the play is confirmed.

 

Figure 2.7 Plays in the Barents Sea

Figure 2.7 Plays in the Barents Sea

 

The additional potential from unconfirmed plays is smallest in the North Sea and largest in the Barents Sea. Estimates for the plays and areas which are best known from exploration activity over a long time contain the lowest level of uncertainty. That combines with the additional potential of the unconfirmed plays and is reflected in the overall uncertainty for the estimates in each area. Figure 2.8 clearly shows that the uncertainty range is narrowest in the North Sea and widest in the Barents Sea. The uncertainty range is expressed as 90 per cent probability. This means that the probability of coming true is 95 per cent for the lowest resource outcome or higher, and five per cent for the highest resource outcome or higher.

 

Figur 2.8 Undiscovered resources with expected value and uncertainty

Figur 2.8 Undiscovered resources with expected value and uncertainty range

 

Undiscovered resources on the NCS comprise approximately equal volumes of liquids and gas. See figure 2.9. However, big differences exist between the various sea areas, as shown in figure 2.10. Estimates are presented with their expectation (mean) value and uncertainty range.

 

Figure 2.9 Total undiscovered resources divided between oil and gas

Figure 2.9 Total undiscovered resources divided between oil and gas

 

Figure 2.10 Distribution of expected undiscovered liquid and gas resources

Figure 2.10 Distribution of expected undiscovered liquid and gas resources

 

Changes to and reductions in estimated undiscovered resources

The NPD regularly publishes new figures for undiscovered resources on the NCS, with the method used unchanged since the mid-1990s. That provides a good basis for comparing the various estimates. Great uncertainty prevails on a frontier continental shelf about the properties of the plays and the opportunities for making discoveries. Comparing the NPD’s estimates for undiscovered resources from 1996 to 2010 reveals an increase up to 2002, followed by a decline. See figure 2.11. This is a natural consequence of the maturing of the NCS, increasing volumes of data and growing knowledge of geological conditions. In the mature part of the NCS, it is natural that the estimate of undiscovered resources gradually decreases as prospects are explored by drilling and petroleum is proven. Almost 400 million scm oe were discovered on the NCS from 2006 to 2010.

 

Figure 2.11 The NPD’s estimates of total undiscovered resources over time

Figure 2.11 The NPD’s estimates of total undiscovered resources over time for the North, Norwegian and Barents Seas

 

Reduced expectations for gas

The reduction in the estimate for undiscovered resources in the North and Norwegian Seas primarily reflects lower expectations for gas discoveries. In the North Sea, the adjustment is largely based on the discovery histories for several plays. These show that more liquids than gas have been proven compared with earlier estimates, particularly in Jurassic reservoirs. The adjustment for the Norwegian Sea partly reflects lower expectations following new mapping off Lofoten, Vesterålen and Senja, where the prospects in a number of areas are smaller than previously assumed. Moreover, exploration results in the Vøring Basin during recent years have failed to live up to expectations. Figures 2.12 and 2.13 present the NPD’s estimates for undiscovered liquids and gas in the three latest principal analyses, carried out in 2003, 2006 and 2010.

 

Figure 2.12 The NPD’s estimate of undiscovered liquids in the three latest

Figure 2.12 The NPD’s estimate of undiscovered liquids in the three latest principal analyses for the North, Norwegian and Barents Seas

 

Figure 2.13 The NPD’s estimate of undiscovered gas in the three latest

Figure 2.13 The NPD’s estimate of undiscovered gas in the three latest principal analyses for the North, Norwegian and Barents Seas

 

North Sea

The estimate for undiscovered resources in the North Sea has been reduced by 28 per cent since 2006. A number of discoveries have been made in these waters in recent years, totalling almost 200 million scm, but they are generally small. The 16/2-8 (“Aldous Major South”) discovery proven in 2011 is not included in the analysis of undiscovered resources. Expectations for Late Jurassic and Palaeocene plays have been cut back substantially on the basis of discoveries and extensive mapping of prospects in the APA process, both by the oil companies and the NPD. Figure 2.14 shows the Palaeocene play where expectations have been reduced the most.

Most discoveries since 2006 have been made in Jurassic and Triassic plays. The reduction in the NPD’s estimate largely coincides with the volume of resources discovered.

 

Figure 2.14 The Palaeocene play in the North Sea where expectations have

Figure 2.14 The Palaeocene play in the North Sea where expectations have been reduced the most

 

The NPD has adjusted the relationship between liquids and gas in the estimate based on discoveries made. The biggest changes relate to the Upper Jurassic play in Norway’s southern North Sea sector – see figures 2.15 and 2.16 – and to the Triassic to Middle Jurassic play in the northern North Sea sector. See figures 2.17 and 2.18.

 

Figure 2.15 The Late Jurassic play in Norway’s southern North Sea sector

Figure 2.15 The Late Jurassic play in Norway’s southern North Sea sector

 

Figure 2.16 Distribution of gas and liquids in the North Sea’s Late Jurassic

Figure 2.16 Distribution of gas and liquids in the North Sea’s Late Jurassic play

 

A relatively larger number of oil and gas discoveries have been made in the Late Jurassic play. In 2006, the NPD expected that considerable volumes of undiscovered gas would be found in this play, which lies deeply buried in the southern North Sea sector. A number of large prospects have been drilled in this area without making substantial discoveries. The NPD’s estimate for the play has therefore been reduced and the gas/oil ratio adjusted so that it accords to a greater extent with existing discoveries.

Substantial volumes of both gas and oil have been found in the Triassic to Middle Jurassic play in the northern North Sea sector, and some of the largest fields on the NCS belong to this play.

 

Figur 2.17 The Triassic to Middle Jurassic play in Norway’s northern North

Figur 2.17 The Triassic to Middle Jurassic play in Norway’s northern North Sea sector

 

Figure 2.18 Distribution of gas and liquids in the Triassic to Middle Jurassic

Figure 2.18 Distribution of gas and liquids in the Triassic to Middle Jurassic play

 

Figure 2.18 shows that more oil than gas has been discovered since 1980. That trend has continued over the past five years. In 2006, the NPD estimated that a substantial proportion of the undiscovered resources would be gas because deep prospects on both sides of the Viking Graben were interpreted as containing gas. However, exploration drilling since 2006 has shown that the play contains mostly oil, and its gas/oil ratio was adjusted in 2010 to accord better with the discovery history.


Norwegian Sea

The estimate for undiscovered resources in the Norwegian Sea is 35 per cent down from 2006. During these four years, 161 million scm oe have been discovered. Discovery expectations are more or less unchanged for oil, but sharply reduced for gas. This cut largely relates to four plays.

A detailed interpretation of the Jurassic play off Lofoten was conducted by the NPD in 2010. See figure 2.19. Based on a new mapping of prospects, expectations for gas in particular have been sharply reduced in this area.

 

Figure 2.19 The Jurassic play off Lofoten

Figure 2.19 The Jurassic play off Lofoten

 

Because the prospects are smaller than previously assumed and because many of them lie at a shallow depth, expectations for undiscovered gas resources have been reduced.

The Late Cretaceous play in the Nordland III area has been re-evaluated, with the play probability reduced on the basis of certain poorly defined prospects. See figure 2.20. No discoveries have been made in this play.

 

 Figure 2.20 The Late Cretaceous play in Nordland III

Figure 2.20 The Late Cretaceous play in Nordland III

 

Following disappointing results, including the 6302/6-1 (”Tulipan”) discovery and the 6607/2-1 (“Cygnus prospect”) well, the estimate for a Palaeocene play in the Møre and Vøring Basins has been reduced.

 

Figure 2.21 One of the Palaeocene plays in the Norwegian Sea

Figure 2.21 One of the Palaeocene plays in the Norwegian Sea

 

A Late Cretaceous play in the Vøring Basin arouses great expectations. See figure 2.22. This has been investigated with a number of wells, leading to several discoveries. However, these are smaller than expected. That includes 6603/12-1 (“Gro”). The area has been interpreted thoroughly by a number of companies, and the exploration results have led to a reduction in expectations since 2006 for several of the prospects anticipated to have a Cretaceous reservoir. However, a substantial remaining potential in the play has yet to be explored, so that positive results could be possible in the future.

 

Figure 2.22 One of the Late Cretaceous plays in the Norwegian Sea

Figure 2.22 One of the Late Cretaceous plays in the Norwegian Sea

 

Barents Sea

The estimate for undiscovered resources in the Barents Sea is by and large unchanged from the NPD’s analysis in 2009, as described in the NPD’s resource report for that year. A minor change has been made on the basis of the NPD’s interpretation of the southernmost part of the Barents Sea, described in the 2010 report on petroleum resources in the sea areas off Lofoten, Vesterålen and Senja. This mapping work identified new prospects and plays in Troms II and on the Egga Margin, so that the 2010 estimate for the Barents Sea is slightly higher than the figure given in 2009.


Unconventional petroleum resources

Unconventional petroleum resources is a collective term for oil and gas deposits which cannot be recovered commercially with conventional production wells and technology, normally because flow to the wells would be very low.

Geological deposits of unconventional gas are characterised by tight rocks requiring a great many production wells and fracturing of the reservoir for the resources to flow to these producers. Another form involves gas bound up in gas hydrates, a solid from which the gas can only be liberated by such means as heating, pressure depletion or replacement with CO2.

Geological deposits of unconventional oil can occur where the crude is so viscous that it will not flow to conventional production wells. Such oil can be recovered by mining operations or by unconventional techniques such as steam injection. Unconventional oil can also be found in shale, coal or reservoir rocks with very low permeability. In addition, residual oil can be defined as unconventional. This is crude which exists in a permeable reservoir, but in such a low concentration that only water will flow through the rock to the producers.

Rising energy demand and prices are encouraging rapid technological development, so that the dividing line between conventional and unconventional petroleum resources is shifting. Growth in shale gas production since 2005, particularly in the USA, has already become significant for gas markets. If oil prices remain high, faster progress can be expected with the big bitumen and heavy oil fields in Canada and Venezuela.

Technological advances and production of unconventional petroleum primarily occur on land, where well costs are low. Unconventional resources on the NCS have not been mapped so far and are not included in the resource account. The cost of possible recovery would be excessive with today’s technology. It is nevertheless important to keep abreast of technological developments with an eye to future applications and to be able to predict market trends.


Large volumes in place

In most sedimentary basins, the quantity of unconventional resources in place is many times larger than conventional resources in place. This is because petroleum forms in organically rich claystones, usually at depths of four-six kilometres. The claystones must be saturated with petroleum before oil and gas sweat out and migrate upwards through the overlying sediments on their way to the seabed. Part of the petroleum is caught in traps on the way. Such traps are sealed structures comprising permeable reservoir rocks, and these formations contain the conventional resources. Over geological time, traps can be regarded as temporary residences for the petroleum flowing from source rock to surface. Unconventional resources are bound in the source rock (oil and gas shales), in tight sandstone layers, in carbonate rocks and in coal, and can be captured in gas hydrates, shallow gas pockets or as heavy oil near the surface.

The very large volumes of unconventional resources make them attractive but, even with new technology, it will in many cases be very resource-intensive in terms of costs, energy consumption and environmental burdens to produce even small percentages of the volumes in place.


Norway and the NCS

No unconventional petroleum resources of significance are known in mainland Norway. Organically rich Cambrian shales (alun shales) are widespread, particularly in eastern Norway and Finnmark county, but these have been exposed to such high temperatures that the oil has boiled off. Oil shales of the same age are produced in Estonia and are being investigated in the Skåne area of Sweden. Svalbard contains several layers of organically rich shales, and further investigation of Middle Triassic shale (the Botneheia formation) has been proposed.

The NCS contains a number of active petroleum systems and accordingly also has unconventional resources associated both with deep source rocks and with migration routes to the seabed.

Large volumes of gas are found in deeply buried source rocks in the Central Graben (Ekofisk area) and the Viking Trough in the North Sea, and on the Halten Terrace in the Norwegian Sea. In these areas, gas is also likely to be found at very great depths in sandstones with low permeability (tight gas). A conceivable first step in the future could be to assess recovery of those resources which currently lie on the borderline between unconventional and conventional. The 6506/6-1 (“Victoria”) gas discovery on the Halten Terrace is an example of a tight gas find where some of the resources can be produced conventionally. However, large volumes of this gas lie in reservoir rocks with such low permeability that producing it would probably require a great many wells and be extremely expensive with today’s technology. Large quantities of hydrocarbons have leaked to the overlying shale layers from the big fields in the Ekofisk area over several million years. These represent a volume in place which cannot be produced commercially today. A very small proportion lies in rather more permeable rocks.

Anthracite coal is able to absorb a great deal of gas and light oil. Coal is a substantial source of gas in many countries which mine it. The gas has traditionally been produced from abandoned coal mines, but “coal bed methane” has become an exploration goal in itself. This is recovered by drilling production wells into coal, which must usually be fractured by one means or another. Studies are also being conducted into the possible use of carbon injection in connection with gas production from coal. On the NCS, coal has been proven in Lower and Middle Jurassic rocks from just off the coast and out to the fields. In areas with infrastructure, thick coal beds have been identified, for example, in the Sleipner formation at the southern end of the Viking Graben and in the Åre formation on the Halten Terrace. Rough estimates have been made of the total quantity of coal on the NCS, but the NPD is not aware of how many of these deposits contain interesting amounts of gas.

Gas hydrates are a combination of water and gas which forms ice-like crystals. Stable under high pressure and low temperature, they are formed naturally where methane is in contact with pore water in deep seas and under thick permafrost. Gas hydrates can form a continuous layer through sediments a few hundred metres beneath the seabed, and methane will often be trapped under the gas hydrate layer. Gas hydrates are very widespread, and pilot studies have been initiated to look at opportunities for recovering gas from such sources in deep water on the Japanese continental shelf (Nankai Trough) and on land in Canada (the Mallik field). Production can be accomplished by either reducing pressure or increasing temperature around the producers, so that the hydrates convert to gas and water. On the NCS, gas hydrates have been proven in the Norwegian Sea north of Storegga, in the western part of the Barents Sea and off Svalbard. The deposits so far proven on the NCS look like being thin and located in clays, and are therefore unsuitable for production. In the Japanese and Canadian pilot studies, the gas hydrates lie in reservoir rocks.

Producing oil fields will end up with residual oil saturations. Several improved oil recovery (IOR) methods, including carbon or surfactant injection, aim to produce oil from reservoirs with residual saturation. Residual oil also occurs naturally as unconventional resources in large rock volumes beneath oil and gas fields where the seabed was eroded during the ice ages. The bestknown deposits are found under Troll in the North Sea and in the Hammerfest Basin of the Barents Sea.

Extra-heavy oil and bitumen are very viscous liquids. Bitumen has a viscosity of more than 10 000 cp at reservoir temperature. Deposits may be called tar sands, oil sands, natural asphalt or oil-impregnated sands, and are found in many parts of the world – particularly Canada. Extra-heavy oil is rather less viscous than bitumen, and large deposits occur in Venezuela. Thin layers of sand impregnated with extra-heavy oil have been found on the NCS in association with fields, but no deposits likely to be of commercial interest are proven.

Unconventional petroleum resources

Bitumen and extra-heavy oil
No substantial deposits of bitumen or extra-heavy oil have been identified on land in Norway. Petroleum of this type has been observed in a number of wells on the NCS, but it would be difficult to map and produce. Compared with conventional oil and gas on the NCS, this resource attracts little commercial interest in Norway at the moment.

Oil shale
No substantial quantities of oil shale have been identified on land in Norway. Large deposits probably exist offshore, particularly in Late Jurassic and Cretaceous source rocks. The cost of offshore drilling and production, even in moderate water depths, is currently too high for such deposits to be commercially interesting.

Shale gas
No such resources have been mapped in mainland Norway or on the NCS. It is unlikely to become an important Norwegian resource.

Gas hydrates
Research is currently being pursued into carbon injection in gas hydrates. CO2 could replace the methane reservoir, liberating the latter gas for production.

Energy from North Sea coal beds
Parts of the North Sea basin contain large coal beds. Substantial volumes have been proven beneath the Sleipner fields. Ideas for exploiting this energy have been suggested, including igniting it and recovering the heat to drive steam-turbine power stations. Substantial coal deposits also exist on the Halten Terrace in the Norwegian Sea, where most of the oil and gas discoveries in these waters lie, and on the Trøndelag Platform close to the coast between Kristiansund and Bodø. Those beds nearest land lie at a moderate depth under the unconsolidated sediments which were deposited during the ice ages.

 


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The resource report 2011
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09.11.2011