“Energy Frontiers”
49 seconds
down - to go deeper into
our future energy sources...
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.
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
| Operator | Statoil |
|---|---|
| Block | BM-C-72004 |
| Oil bearing layers | 60 - 80 m |
| Estimated reserves | 2.3 billion barrels |
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). SAGD involves drilling two parallel horizontal wells deep underground. Steam is injected into the shallower well, creating a steam chamber in the oil-bearing sands. The heat lowers the viscosity of the oil, which then flows downward to the deeper-producing well. From there, it is extracted to the surface by traditional pumping techniques.
The water used to create the steam comes from deep saline aquifers, unsuitable for drinking, irrigation, or use by livestock. More than 90 per cent of the water is recycled and re-used. Water used by plants, animals or people are not be used.
Statoil is continuously working to curb water consumption and cut carbon emissions in our oil sands operations through the development of new technologies.
reservoir, steam is injected
(Steam Assisted Gravity Drainage, SAGD)
Fuel for North America
The Leismer Demonstration Plant is a pilot project which started production in January 2011. The plan is to scale up to an expected capacity of 18,800 barrels per day within the first 24 months. 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.
| Location | Athabasca region, Alberta, Canada |
|---|---|
| Acreage | 1,100 km2 (Kai Kos Dehseh total) |
| Purchased | 1848 |
| Operator | Statoil |
| Prod. period | Startup test production 2011 |
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.
because the cap rock over the reservoir
allowed bacteria to penetrate
and consume the lighter components.
in cold waters is actually frozen
methane gas, known as hydrate.
This 'ice' will burn if ignited.
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.
| Location | 140 km off the Northwestern coast of Norway |
|---|---|
| Block | 7121/4-1 |
| Discovered | 1984 |
| Operator | Statoil |
| Prod. period | 2007 - |
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.
arctic oil and gas areas
we consume today was
formed by dead
unicellular marine
plankton (dinoflagellates),
sinking to the sea bottom
several hunderd million
years ago.
| Location | 200 km off the Northern coast of Norway |
|---|---|
| Block | 7220/8-1 |
| Discovered | 2011 |
| Operator | Statoil |
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 600 million barrels - the same amount as the largest new findings on the Norwegian Continental Shelf over the last ten years.
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 will probably see its 50-year anniversary. The estimated rate of utilization is now reaching 70% for the oil and 75% for the gas. That's 20% more than originally estimated, and equates to 300-400 million extra barrels.
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 utilization to 60 %. 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?
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.
| Location | 140 km off the Western coast of Norway |
|---|---|
| Block | 30/6-1, 30/9-1, 30/9-B-19 A |
| Discovered | 1979 |
| Operator | Statoil |
| Prod. period | 1988 - |
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.
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.
| Location | 177 km off the Midwestern coast of Norway |
|---|---|
| Block | 6407/1-2, 6407/1-3 |
| Discovered | 1982/83 |
| Operator | Statoil |
| Prod. period | 2009-2029 |
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.
Low CO2 emissions
The oil produced from our tight oil plays is a light crude quality, and should not be confused with oil shale, which is very different with regards to oil quality and extraction methods. Oil production from Statoil’s tight oil US-assets is also CO2 efficient, with emissions per barrel below the average level for oil produced at the Norwegian Continental Shelf, which has the lowest average CO2 emissions from offshore oil production in the world.
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.
| Location | Williston Basin, North-Dakota/Montana, USA |
|---|---|
| Acreage | 38,000 km2 |
| Purchased | 2011 |
| Operator | Statoil |
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.
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
Still going strong
The Sleipner oil and gas field on the Norwegian Continental Shelf started production in 1993. Since then it has produced more than 1,700 Mboe. But even if Sleipner’s production now is declining, the store of knowledge and ideas generated by the project has risen conversely. Sleipner has been a great inspiration for both us and our partners in bringing out new ideas to increase recovery. This will give the Greater Sleipner area 20 more productive years to go.
| Location | 250 km off the Midwestern coast of Norway |
|---|---|
| Block | 15/6, 15/9, -2, 6407/1-3 |
| Discovered | 1974/83 |
| Operator | Statoil |
| Prod. period | originally 1996, now 2020 perspective and beyond |
New discoveries
There are a number of old discoveries in the North Sea and the Norwegian Sea that are being gradually connected to existing infrastructure. We also still believe that new discoveries, both large and small, will be made in the vicinity. The gigantic Johan Sverdrup discoveries, for example, were found in part of the North Sea where there are already large fields in production. This makes developing these fields faster and cheaper.
Fast development
Discoveries that are made close to existing infrastructure can be developed rapidly by using well-known and cost-effective solutions - almost straight off the production line. This strategy can halve the time taken from discovery to production and can prolong the life of the fields by decades.
(Former Aldous/Avaldsnes)
| Location | 140 km off the coast of South West Norway |
|---|---|
| Block | 16/2-8, 16/2-6 |
| Year of discovery | 2011 |
| Operator | Statoil |
| Partners | Statoil, Petoro, Lundin, DNO, Mærsk |
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.
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.
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
| Location | 435 km southwest of New Orleans |
|---|---|
| Block | Walker Ridge 758 |
| Discovered | 2004 |
| Operator | Chevron |
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.
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 innovate.statoil.com - industry experts, small businesses, academics and our own people are contributing good ideas that could solve the challenges we face.
Challenge!