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“Energy Frontiers”

1 minute
49 seconds

The easy barrels are gone. The oil we need to keep the world running for the next 20, 30, 40 years will be hard to find and difficult to extract. But we believe the main limitations for future oil supply are not below the ground, but in our heads, in the availability of expertise and technology that can balance the growing demand for energy against the challenges of climate change. This challenge is our inspiration.

There’s never been a better time for good ideas.

Heavy oil reserves

The world’s reserves of extremely thick oils or “heavy oils” are probably twice as large as its holdings of conventional, lighter crudes. Originally, these were light oils too. They became heavy, because the cap rock over the reservoir didn’t form a complete seal. This allowed bacteria to penetrate and consume the lighter components. A great deal has also drained away or simply evaporated, leaving only the heavier compounds behind.

Heavy oil molecules are much larger and more complex than lighter crudes.
Worldwide distribution of heavy crude oil
5.4 trillion barrels
23° 20' 00" S   41° 17' 00" W


The Peregrino challenge

Because of the high viscosity, extracting heavy oil is more of technological challenge than recovering lighter crudes. At the Peregrino oil field off Brazil, we have solved this challenge by combining different technologies and solutions which we’ve applied successfully in other locations.

Learn more by clicking the arrows to the right
Oil bearing layers60 - 80 m
Estimated reserves2.3 billion barrels

Peregrino is located in water just over 100 metres deep, 85 km off the coast of Rio de Janeiro. The field was set into production in spring 2011. Because of the high viscosity, original indications were that only a tenth of the resources could be recovered. But by using a closed high-pressure water solution, we are now looking to increase the recovery rate to around 20% and strive to double. This represents responsible resource economy both for Brazil and for us as the operator.

  • Phase 1: 37 wells; 30 production wells and 7 water injection wells.
  • Two drilling and wellhead platforms

Innovative solutions

A total of 10 horizontal oil producer and two water injection wells have been drilled. The water is injected from two fixed platforms. A ship placed between them receives and processes the well streams which have a high proportion of water. By heating the well stream in huge tanks, the water can be separated from the oil, and pumped back into the reservoir. This maintains pressure and helps to draw oil with it back to the production wells. This solution means we not only take care of the water produced, but we also succeed in recovering far more of the heavy oil than usual.

Complete value chain

The heavy oil from Peregrino is shipped to our terminal in the Bahamas. Here part of the oil is blended with lighter crude to make it easier to refine into different end products. Through this process our position in heavy oil production is strengthened all the way from well to wheel.

Heavy oil research

We’ve taken active steps at our technology centers in Norway and Canada to develop a sustainable value chain for heavy oil. New solutions will play a key role in producing and upgrading these crudes. Our centers support all our heavy oil operations and work simultaneously on environmental technology.

Oil sands – essential but challenging

Canada’s oil sands play a central role in the world’s remaining oil reserves. But the oil is so viscous that extracting it from the sand and clay requires special technology to make it fluid enough for refining.

Statoil’s oil sands are located more than 100 meters below the ground, not in open mines as in other sites in Canada. The technology we use for extraction here is relatively new, called SAGD (Steam Assisted Gravity Drainage). With SAGD, horizontal wells are drilled and injected with steam to heat the reservoir until the bitumen is warm enough to flow and can be moved to the surface through a production well.

The water required for the steam production comes from deep saline aquifers, unsuitable for drinking, livestock or irrigation.

Statoil is continuously working to curb water consumption and cut carbon emissions in our oil sands operations through the development of new technologies.

To extract oil from the
reservoir, steam is injected
(Steam Assisted Gravity Drainage, SAGD)
55°45'21" N   111°2'29" W


Fuel for North America

The Leismer Demonstration project is the first oil sands operation on the Kai Kos Dehseh Leases. Through steady and reliable performance while developing process improvements in its second full year of operation, Leismer reached a peak production point of 21,000 barrels per day in 2012, with production averaging approximately 16,000 barrels per day. Also part of Statoil’s Kai Kos Dehseh project are three other oil sands leases, Corner, Hangingstone and Thornberry, which are all located in the Athabasca region of northwest Alberta. The region holds some of world’s largest remaining oil reserves. These reserves will be essential to ensure sufficient and stable oil supplies for North America in the decades to come.

LocationAthabasca region, Alberta, Canada
Acreage1,100 km2 (Kai Kos Dehseh total)
Prod. periodStartup test production 2011

SAGD - a technological breakthrough

Over 80 per cent of Alberta’s oil sands are buried deep below the earth’s surface and this oil must be recovered using techniques such as steam assisted gravity drainage (SAGD). Pioneered in 1978, SAGD is now widely used on large-scale commercial projects across the Alberta oil sands.


Harsh environments

Estimates predict that about 25% of the world’s undiscovered oil and gas resources are located north of the Arctic Circle. It is further estimated that approximately 84% of these occur offshore. Operating in these areas is extremely challenging. Few parts of the world represent a more vulnerable environment. This makes particularly heavy demands on anyone seeking to pursue industrial activities here.

Statoil is one of the oil industry’s pioneers in creating workable solutions for vulnerable areas. We’ve already demonstrated our ability to balance different concerns and establish a basis for co-existence with the environment, local communities and traditional industries.

Heavy oil gained its thick consistency
because the cap rock over the reservoir
allowed bacteria to penetrate
and consume the lighter components.
The ice that can block subsea pipelines
in cold waters is actually frozen
methane gas, known as hydrate.
This 'ice' will burn if ignited.
71° 36' N   21° 00' E  /  71.6° N   21° E


Sheltered on the seabed

The Snøhvit gas field is the first development in the Barents Sea. It is located in 300 meters of water, north of Norway, at 72°N, the same latitude as the pack ice north of Alaska.

The Gulf Stream keeps the seas up here ice-free all year round. But it also means that winter storms can whip up waves tens of meters high and make surface installations hard to run.

But it’s calm on the seabed. Down here, we can continue stable and secure production regardless of surface weather conditions and temperatures, using energy-efficient subsea installations remotely operated from land.

Location143 km off the Northwestern coast of Norway
Block7120 and 7121
Prod. period2007 -

Multiphase transportation

Gas is piped 143 kilometers from the seabed wellheads to the Melkøya LNG plant on land. But transporting an unprocessed well stream through such a long submarine pipeline presents a number of challenges, including the formation of hydrate, a form of ice. Caused by a combination of high pressure and low temperatures, it can easily block the pipelines. We avoid hydrate formation by adding antifreeze at the wellhead, which is subsequently regenerated in a closed system. We’ve developed these technologies especially for the Norwegian Continental Shelf, and they’re crucial for our ability to operate offshore oil and gas fields so far north.

Beating the bergs

The waters of the far north offer plenty of challenges for offshore operations. Fending off masses of floating ice is just one of the jobs necessary to keep workers safe and oil and gas flowing.

An arctic laboratory

The seas off Newfoundland and Labrador essentially provide a real-time Arctic laboratory, offering a particularly remote and harsh environment for offshore petroleum activities. Statoil’s partner-operated assets, Terra Nova and Hibernia, are located in the area known as Iceberg Alley, characterized by sub-zero temperatures, severe sea states, intensive seasonal fog, pack ice and enormous icebergs. In these areas, new technology is continually developed to address the region’s Arctic-style conditions.

Mobile facilities

Offshore production platforms must be designed to withstand the seasonal presence of sea ice, bergs and harsh weather. These mobile facilities are designed with the ability to disconnect from the seabed and shift location if ice conditions become too severe or bergs threaten to move into the immediate vicinity. Every drilling or production facility must implement a comprehensive ice management strategy to detect, monitor and prevent icebergs from encroaching. When a berg presents a potential threat, a standby vessel is sent off to change the berg’s path and prevent collision with offshore installations.

Desert heat and tropical storms

The Arctic is not alone in presenting climatic and environmental challenges. We’re also operating in vulnerable surroundings in the Sahara for example, under temperatures which can be just as demanding for people and technology as those in the frozen north.

In the Gulf of Mexico, too, tropical hurricanes can subject our activities to forces even greater than the ones we face from winter storms in the Barents Sea.

The map shows potensial
arctic oil and gas areas
Most of the oil and gas
we consume today was
formed by dead
unicellular marine
plankton (dinoflagellates),
sinking to the sea bottom
several hunderd million
years ago.
72° 29' 28.96" N   20° 20' 01.59" E


Arctic Breakthrough

Johan Castberg (Skrugard and Havis) was the first major discovery in the Barents Sea. It is probably also one of the biggest made on the Norwegian continental shelf in the past 10 years. The field lies halfway between Finnmark and Bear Island and we believe it may be an important breakthrough for further exploration in these unexplored waters. The recent done neighbor finding, Havis, is an exciting indication for that. The geology of the area is extremely varied and interpreting the seismic data has been a challenge. 80 dry wells were drilled before Johan Castberg was discovered. Experience from Johan Castberg means that we can now look for similar geological conditions in other places. This gives increased optimism for further drilling in these demanding Arctic waters.

Location240 km off the Northern coast
of Norway

Increased recovery

The Norwegian Continental Shelf is far from exhausted. We estimate that only one third of the reserves have been recovered. But the findings are getting smaller and less accessible. Drilling for new findings and increased recovery from existing sources will go hand in hand in future. Every extra per cent we extract from existing fields increases recovery by 327 million barrels of oil – more than NOK 200 billion in value given an oil price of USD 100/barrel.

Extended lifetime

IR (Increased Recovery) is both a value-adding and a sustainable business. It’s therefore an important outsource for us. Statoil is a world leader in increased recovery. Our largest oil field, Statfjord, was brought on stream in 1979. According to original estimates, it should be closed by now. But, thanks to groundbreaking IR solutions, the field might see its 50-year anniversary. The estimated rate of utilization is now over 66% for the oil and 74% for the gas. That's 26% more than originally estimated, and equates to 1,4 billion extra barrels of oil.

Better seismic creates more values.

The better the underground seismic images we have, the better our chances of locating new findings. Statoil aims to become the world leader in advanced seismic by the end of 2012. Good seismic pictures support our operations by allowing more precise estimates of resources, so we can decide more easily where to drill and how to develop findings in the best way. Seismic can also follow the changes in geological formations as the pressure in oil and gas fields declines. This gives us the information we need to maintain production volumes by drilling new production wells and tying up pockets of isolated oil and gas. On the Norne-field, 4D seismic has raised the rate of recovery to 56 %. That is a world leading figure in subsea fields. On Gullfaks, 62 million barrels extra have been extracted. In the Gulf of Mexico and other places where resources are located at extreme water depths and beneath thick layers of salt or lava, advanced seismic imaging will be essential.


How old is oil?

When were the different oil qualities formed in the history of the earth?

Heavy oil 25 mill years ago, Neogene period
North Sea oil 150 mill years ago, Jurassic period
Middle East oil 250 mill years ago, Triassic period
Drag and rotate to see how 3D seismic reveals resources underground.
60° 29' 30.7104" N   2° 49' 38.3304" E


14 more years – at least

The Oseberg field is a good example of how our IR-technology can extend production lifetimes. New drilling technology, water and gas injection and advanced seismic will prolong the field’s lifetime by as much as 14 years to 2031. Similar numbers are also being achieved on other central fields such as Troll and Gullfaks.

Location140 km off the Western coast of Norway
Block30/6-1, 30/9-1, 30/9-B-19 A
Prod. period1988 -

Keeping up the pressure

Oil and gas are normally forced to the surface by natural pressure inside the field. As production declines, the pressure in the reservoirs also falls. By injecting seawater and gas from the well stream, pressure in the fields can be maintained, so considerably more can be extracted from the reservoirs. Statoil is among the first to pioneer injection technologies, and these are being applied or planned in most of the fields operated by Statoil.

Horizontal drilling

Traditionally, oil and gas wells were drilled vertically, from rigs placed over the wellhead. Today the rig can stay in a fixed position, and steer the drill horizontally towards geological formations thousands of meters away. By drilling wells horizontally we’re able to drain the reservoirs better, so more oil and gas can be extracted. It’s also easier to target pockets of oil and gas.

Oil is one of the few substances that does not dissolve in water. That makes seawater suitable to inject into oil reservoirs to maintain the pressure. The water is easy to separate from the well stream when it reaches the surface.
12° 20' 44" N   1° 43' 04.61" E


A groundbreaker

The technology we’re using on Tyrihans in the Norwegian Sea has set a new standard for subsea development. Increased recovery techniques were here adopted already from startup. Up to two km long horizontal wells has been drilled to improve field drainage. And for the first time pure seawater is injected into the reservoir from a seabed pump. That helps to keep up the pressure in the reservoir and stabilizes the oil zone.

Tyrihans was awarded as one of the world’s five best deep-sea projects during the Deep Offshore Technology conference in Houston in 2009.

Location177 km off the Midwestern coast of Norway
Block6407/1-2, 6407/1-3
Prod. period2009-2029

Remote controlled

The seabed installations are powered by electric control system uses electricity for power rather than hydraulics. To increase safety, a low-voltage approach is developed using existing low-power umbilical and connector technology. This provides a safer operating environment and prevents corrosion risk from stray high-voltage currents.

Heated pipeline

The oil-dominated, unprocessed well stream from the four seabed templates travel for 43 kilometres to a nearby installation through the world’s longest pipeline with direct electric heating.

This keeps the pipelines clear of potential blockages by heating them from the ambient water temperature (approx 6°C) to around 27°C, so preventing the formation of hydrate (hydrocarbon ice) and wax plugs that can occur during production shutdowns and periods of low production rates.

The unprocessed well stream from Tyrihans is transported through a 43 km long electric heated pipeline to the Kristin platform for processing and further transportation.

A “tight oil” revolution

“Tight oil” is a term used for oil produced from tight rock reservoirs with relatively low porosity and permeability. There are huge reserves of such tight oil in the world, and most of it is located in North-Dakota and Montana, USA. The reserves has been known for decades, but until the last few years they have not been commercial exploitable. However, recent advances in drilling technology, like hydraulic fracturing and horizontal drilling, have led to la large jump in daily oil production, and turned these resources into an important part of the future energy mix. Statoil entered the tight oil business by purchasing Brigham Exploration Company’s assets, Bakken/Three Forks, in 2011. Our ambition is to be an industrial player in this fast growing business.

48°04’14”N 103°50’13”W

Bakken/Three Forks

An energy fortune below the grassland

Statoil’s tight oil assets, Bakken/Three Forks, are located in the Williston Basis, a shale and dolomite rock formation under North Dakota’s and Montana’s vast grassland. It covers an area of about 500,000 km2 and holds large reserves of crude oil. Though estimates of total reserves in the formation vary widely, there is no doubt that the formation holds one of the largest oil reserves anywhere in the world.

LocationWilliston Basin, North-Dakota/Montana, USA
Acreage38,000 km2

Hydraulic fracturing

Normally oil is produced from porous rock like sandstone and limestone. The Bakken/Three Forks reservoirs are different. The oil here holes up in dense sedimentary rock which is fractured by large volumes of water and chemicals that are piped in horizontally under high pressure. The pressurized mixture causes the rock layer to crack. These fissures are held open by the sand particles so that the oil from the tight rock can flow up the well.

With this new technology the oil production from the Williston Basin has rose from almost nothing to more than 700 000 barrels a day in few years. Its total reserves have been estimated between 5 and 25 billion barrels o.e. It's about as much as on the Norwegian continental shelf, both produced and remaining.

Infrastructure-led exploration

The age of giant oil findings on the Norwegian Continental Shelf is probably gone. But close to them, there are still a number of smaller findings which were originally considered too small to be developed in isolation. That assumption has changed. Existing infrastructure and new technology are now being directed towards bringing these findings on stream. At Sleipner on the Norwegian Continental Shelf alone, there's enough from these combined reserves to supply Europe with an additional 1,200 Mboe in the years to come.

The actions we've taken to increase
carbon efficiency have reduced emissions
per unit produced on the Norwegian
Continental Shelf to one third
of the worldwide industry average.

Same weight, different
energy content

See how long same weight of different energy sources burns.

Energy content different
energy sources:

Natural Gas 55.6 kJ/g

Iignite Coal 25 kJ/g

Bituminous coal 32 kJ/g

Crude oil 47.9 J/kg

Wood 16.30 kJ/g

58° 25' 04.58" N   1° 43' 04.61" E

Greater Sleipner

Still going strong

The Sleipner gas/condensate field on the Norwegian Continental Shelf started production in 1993. Since then it has produced almost 2 billion Mboe. Sleipner produces more than 170 000 boe/d. The production is declining but capacities are being made available to handle production from new fields in the area. Gudrun plans to start production early 2014 and Gina Krog in early 2017. Sleipner’s time horizon has been stretched to 2032 as a result of Gudrun and Gina Krog tie-ins. There are additional tie-in candidates in the area.

Statoil’s oil sands are located more than 100 meters below the ground, not in open mines as in other sites in Canada. The technology we use for extraction here is relatively new, called SAGD (Steam Assisted Gravity Drainage). With SAGD, horizontal wells are drilled and injected with steam to heat the reservoir until the bitumen is warm enough to flow and can be moved to the surface through a production well.

Sleipner is directly connected to the gas export infrastructure from the NCS to Europe and UK. Since 1996 Sleipner has captured one million tons of carbon dioxide and injected it into the Utsira reservoir for storage 800 meters below seabed.

Location250 km off the Midwestern coast of Norway
Block15/6, 15/9, -2, 6407/1-3
Prod. periodoriginally 1996, now 2032 perspective and beyond

There’s more on the shelf

Good ideas and experience are now bringing other discoveries to life that were once considered too small to be developed in isolation, and too complicated because of high pressures and high temperatures. Now, in combination with others they can increase future production infrastructure at Sleipner. The first field out is Gudrun, discovered back in 1975, the year after Sleipner. Gudrun will come on stream in 2014.

The next field out will probably be Gina Krog. Oil will be offloaded from a storage tanker and gas will be transferred to Sleipner for processing and export.

Deep water

Statoil’s history is peppered with technological breakthroughs that have allowed us to operate in ever greater water depths. During more than 35 years on the Norwegian Continental Shelf we’ve moved from an initial 70-90 metres of water into even greater depths. We’re now drilling in areas deeper than previously thought possible. In the Gulf of Mexico and off Brazil and Angola wells are drilled in more than 2000 metres of water, penetrating no less than 10,000 metres into the Earth’s crust. And off Egypt’s Mediterranean coast, we’ve recently drilled a well in 2,700 metres of water. That’s near the limits of available drilling technology.

Plankton grows fast in
shallow waters. In the
Black Sea alone, 2.7
billion tonnes are formed
each year.

How heavy is oil?

If API gravity is greater than 10, it is
lighter and floats on water; if less
than 10, it is heavier and sinks.

26° 12' 45.79" N   91° 25' 35.65" W

Gulf of Mexico

The pre-salt challenge

The deep-water fields off Angola, Brazil and in the Gulf of Mexico belong to the same geological structure, the so-called pre-salt structure. The reserves here are hidden below several thousand meters of salt layers. That makes it difficult to use seismic data to accurately image the subsurface below and around salt, in order to identify structures to drill. As a result of recent major advances in seismic processing algorithms & computer processing speeds, we can now see sub-salt images much more clearly.

Learn more by clicking the arrows to the right

Jack & St Malo field

Location435 km southwest of New Orleans
BlockWalker Ridge 758

New developments

Along with operator Chevron and other partners, Statoil sanctioned the Jack/St Malo field development, located in the ultra-deepwater Walker Ridge area of the US Gulf of Mexico in autumn 2010. The fields are estimated to contain combined total recoverable resources in excess of 500 million barrels of oil equivalents. The development is considered a new frontier for the oil industry. Statoil is bringing technology and offshore expertise which we believe will benefit us and our partners in developing this play. Statoil has a 25 percent interest in Jack and 21.5 percent in St Malo.

The pre-salt layer also brings another challenge. Under high pressure and at high temperatures, it behaves like a plastic, making it difficult to ensure the stability of the rock. But technological progress has been made, allowing not only stable drilling through the layer of salt, but also reducing well-drilling time.

That makes the deep parts of the Gulf of Mexico to one of our most important priority areas for the future.

Deep-water experience

Fixed platforms reached their physical, safety and financial limits when we passed 400 metres water depth. The Troll and Statfjord platforms represent the peak for these giants. They are still in full operation and remain among the world’s biggest structures, measuring up to 472 metres from the base on the seabed to the top of the flare boom.

Onto the seabed

To exploit deeper resources, both in these waters and even greater depths, we need to think along new lines for exploration, development and production. Subsea installations represent that breakthrough. Since the first such installation was activated in 2001 on the Troll field, most of the fields on the Norwegian Continental Shelf and those close to coastlines now use this technology. By the end of 2019 we plan to build a complete subsea installation which will include processing facilities.

Promising locations

When decisions are made on where to drill and whether to develop deep sea discoveries, Statoil’s long-term deep-water experience is highly significant in promising pre-salt locations as the Gulf of Mexico, the Girassol and Dalia fields outside Angola, and the Jequitinhonha and Espirito Santos Bassin off Brazil.

Statoil is also assigned the role as operator of several promising exploration blocks in the Kwanza Basin, offshore Angola. The Angolan pre-salt occurrences is equivalent the pre-salt occurrences in Brazil where it is made great discoveries in recent years, and is considered one of the most promising exploration areas in the world.

Worldwide oil reserves

Deep-water areas in the Gulf of Mexico and off Brazil and Angola are among the most promising exploration areas in the world.

A question of innovation

Right now - at - industry experts, small businesses, academics and our own people are contributing good ideas that could solve the challenges we face.