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15 Jun 2011
Shortages of natural gas during the past few winters have raised concerns about the levels of supply in the UK and have led to calls for more storage capacity as a buffer against global supply shocks. The UK is finally addressing the situation, but is it enough?
The UK has a natural gas storage problem. Spain has enough reserves to last an estimated 65 days, Germany’s stand at 77 days and France is on 91 days. In the UK, there could be as few as 14 days of reserves, or about four per cent of its annual consumption.
Reserves jumped significantly after fast-rising oil prices prompted heightened activity to find new sources and increase storage capacity. Natural gas is not used as extensively in the UK as it is in Europe, but it’s still a daunting figure.
What does this mean for the UK? It means that new storage options need to be developed – or future winters could have even more bite.
The supply of gas has changed. There is more worldwide competition and the geopolitical risks have increased. And the UK faces its own unique situation. Until 2004, the UK was a net exporter of gas with plentiful deposits in the North Sea. But with North Sea supplies dwindling by seven per cent a year, the UK has become a net importer. By 2015, it could need as much as three-quarters of its supply from abroad.
“Over the past 20 years there was no particular desire on the part of the government to invest hundreds of millions of pounds in storage that wasn’t going to be needed until well into the future,” points out Paul Love, senior analyst with energy consultancy M&C Energy Group. “Since about 2004 the UK has imported gas chiefly through the Norweigan pipeline and also through liquefied natural gas (LNG).”
This stands in sharp contrast to Europe, where the demand for storage has been rising fast. The UK has made a “dash for gas” in the past few years, mothballing some coal and firing up several new gas-powered stations as many nuclear facilities come to the end of their lives. But is it enough?
Without increased storage, the UK could be left open to the vagaries of the global gas market. While most imports currently come via Norway, with LNG imports making up an increasingly large chunk, Russia is also due to start supplying the UK in 2012 via the new pan-Europe Nord Stream pipeline.
Aside from mitigating risks posed by international disputes (such as the one between Russia and Ukraine in recent years), more gas storage would also allow suppliers to smooth out supply and demand.
“Reservoirs and aquifers represent seasonal storage, which helps to reduce the unitised cost for gas in winter,” says Stefan Tenner, manager of the energy team at PricewaterhouseCoopers, based in Düsseldorf. “You buy additional volumes around April, allowing you to achieve arbitrage between the summer-winter spread.”
Ideally, the UK would do something similar. The close proximity of UK storage sites to the gas grid means that gas could be shifted from the grid during summer periods of low demand and stored elsewhere. The gas could then be returned to the grid during the winter, but this has not been the case – yet.
“In Germany, one of the key drivers behind the boom in gas storage was that utilities wanted more flexibility than what they were used to getting in long-term contracts,” says Tenner. “There was a flexibility cost built into contracts. And the only way out of that was to rent storage capacity.”
A string of storage projects is now under way. The Department of Energy and Climate Change says UK capacity, which stands at about 4.3 billion cubic metres (bcm) now, could rise to about 20bcm by 2021, providing that all the schemes on the drawing board go ahead. Total UK demand at the moment is about 94bcm a year.
There are two main ways to store gas: in depleted reservoirs, such as abandoned oil and gas fields, or in salt caverns (large caverns that are “solution-mined” out of existing salt formations).
While reservoirs tend to be bigger, allowing more gas to be stored in one go, salt caverns are easier and quicker to access, and have shorter filling periods, says Dr Evan Passaris, chief geotechnical engineer at Atkins. There are at least 14 salt cavern projects across the UK at the moment and Atkins is involved in seven.
Salt caverns also require less “cushion gas” than depleted reservoirs (required to maintain pressure and structural integrity) and the vast majority of reserves can be recovered at the end of the cavern’s working life.
“At the end of the useful life of a depleted reservoir, you lose the cushion gas unless you fill it with some form of saline liquid – typically sea water – but that is not something we normally do because it’s not cost effective,” Passaris says.
“You do need both types of storage,” he adds. “You need the reservoirs to meet base demand and cope with seasonal variations. And you need the salt caverns generally to cover the peaks, because they can handle high withdrawal rates. Think of it in these terms: depleted reservoirs act like a deposit account and salt caverns are like an instant access account.”
As such, the salt caverns represent the most efficient and effective option for the UK to pursue, given the strain already being placed on the system. It helps that salt is an ideal storage material. Its porosity and permeability to gaseous products are near zero but can also be hollowed out relatively easily using a solution-mining process.
“Salt is a perfect material because it acts as a container. Healing of fractures is a process distinctively related to salt thanks to its ability to flow plastically, resulting, to some extent, in the closure of fractures,” Passaris says.
Today’s caverns are much bigger than their forerunners. The Teesside project measured only 2,700 cubic metres but the new caverns have typical volumes to the order of 650,000 cubic metres and tend to be clustered together to increase the overall capacity.
Gaz de France is currently developing a £350m cluster of 28 caverns in Cheshire. Portland Gas will be constructing a £500m 14-cavern cluster off the coast of Dorset. And EDF is repurposing 10 salt caverns in Cheshire (that are currently full of brine) in addition to the four existing operating gas storage caverns. E.ON UK is another major developer in this country.
UK caverns are smaller than those in Germany and France, which have the advantage of structural salt domes that the UK lacks. Single German caverns measure as much as a million cubic metres and are 300 to 400 metres high. UK caverns tend to be less than 200 metres high.
“Germany and France’s gas storage capacity is concentrated around salt caverns, because they have very good quality salt dome formations. We don’t have that in the UK – we have thick layers of salt. And that means we can’t build our caverns as large,” Passaris says.
Atkins provides many of the services that go into designing and developing salt caverns, including the geological surveys to locate the best sites; carrying out the analysis and numerical modelling to design the caverns; and ensuring that caverns maintain their integrity as operators inject and withdraw gas.
Developers create caverns by pumping fresh or sea water down a pipe into the salt formation. The high-pressure liquid creates a borehole (leaching string) and the resulting brine is returned through the withdrawal/production string. This process progressively dissolves the salt in a controlled manner and the desired shape of the cavern is created by shifting accordingly the heights of the leaching and the production strings, and by using a nitrogen or compressed air “blanket” that limits the upward leaching of the salt. The progress of the cavern leaching process is monitored at regular intervals by undertaking three dimensional sonar surveys. In all, it can take developers as long as two-and-a-half years to create a salt cavern.
Passaris says there are several problems that developers have to watch out for. Once formed, salt caverns are subjected to volume losses owing to salt creep resulting from the overburden stress on the cavity walls. Deep salt caverns subjected to large overburden stress are likely to suffer excessive closure through creep and the consequent loss of their storage capacity. Furthermore, the withdrawal and injection of gas into a cavern causes temperature changes that result in the development of high thermal stresses on the cavern walls.
“These thermal stresses can be very hazardous, especially cooling stresses, which happen when you remove gas. When you cool the walls of a salt cavern, you increase tensile stresses. And rock materials generally have a low tensile strength. We have to make sure we design the cavern so any tensile stresses can be accommodated without any potential failure of the structure,” Passaris says.
A further potential problem encountered during the construction of the caverns comes from the inherent impurity of rock salt. “The difficulty is that rock salt is not a very homogeneous or pure material. It’s not like the salt on the kitchen table. It is a dirty geological material layered with insolubles, such as mudstones, preventing you from creating a cavern with the ideal shape, which is necessary for its structural integrity. You have to regularly monitor the shape of the cavern under development using sonar techniques,” he adds.
Developers also have to work out what to do with all the brine produced during the solution mining process. In some cases, it can be sold – after separating out the insolubles – for industrial uses, or following its treatment it can be discharged into rivers, lakes, or – better – the sea. It is also possible to feed the brine into a saline aquifer and then use it during the process of retrieving gas from a salt cavern by employing the brine compensation method, also known as “wet storage method”.
As an example, the Portland Gas project in Dorset will use the brine compensation method by injecting brine through a central tube at the bottom of the cavern while withdrawing an equivalent volume of gas through the annular space between the cemented casing and the central brine tube. Gas storage projects that use brine compensation technology do not require cushion gas.
With the UK requiring more storage capacity, salt caverns are likely to remain a popular method, although geology will limit the number of sites where caverns can be built. At the same time, the UK is investing in some major depleted reservoir projects – notably the Deborah gas field project, near Bacton, off the coast of Norfolk. That project alone, due to be completed in 2016, could provide 4.6bcm of extra storage capacity – or double what is currently available. The biggest existing offshore storage currently is the Rough depleted gas field, off the coast of Yorkshire, which has a capacity of 2.8bcm.
Are salt caverns and reservoirs the future as far as gas storage is concerned? According to Passaris, it seems to be heading in that direction. Cylindrical gasholders of the sort seen dotted around London are becoming a thing of the past, he says. Inner-city land is too expensive and is more economically used for housing or other purposes. Having a large amount of gas in a residential area is also not the safest thing.
“The interesting thing about the UK is that, from a security point of view, seasonal storage is required, but because the market is so liquid, it actually sends out a signal that more rapid-cycle facilities are required,” observes Tanner. “The UK was smart to build its pipeline with Norway. But it isn’t a bad idea to build up its storage facilities as back-up flexibility options.”
Though few countries can match the UK’s investments, there has been a boom in gas storage across Europe in recent years.
According to figures compiled by the trade body Gas Storage Europe, total capacity could grow by up to 75 per cent by 2025, if all the projects now planned go ahead. Germany has the biggest storage market, with 20bcm currently and a further 8bcm due by 2025. Austria, Italy and Spain are also planning big jumps in capacity.
Across Europe, though, the UK has the greatest number of projects in development. And its spending is almost double any other country (Germany and Italy are next largest). About two-thirds of those projects (64 per cent) are reservoir projects, 26 per cent salt caverns, with the rest made up of aquifers (eight per cent) and LNG hubs (two per cent). Last November, the European Commission called on EU members to carry out risk assessments of their gas supplies, and to ensure they have at least 30 days of supplies available for households and key customers.
The commission wants to see more investment in storage and transmission networks, and greater liberalisation of energy markets allowing “gas from any source to be bought and sold anywhere in the EU, regardless of national boundaries”.
A report by PwC published in 2010 found that liberalisation in several countries had encouraged more participants into the market, and that increased liquidity had created more demand for short-term storage capacity.
Poland is adopting an alternative approach to gas shortages, constructing a new liquified natural gas (LNG) plant at Swinoujscie, on the Baltic coast. Atkins is working with owners Polskie LNG to oversee its design and construction.
Polish domestic production accounts for 30 per cent of its annual demand and the remainder is provided by Russian imports. Due to open in 2014, the LNG terminal will reduce this reliance on Russian gas. The plant will receive natural gas by sea, increasing Poland’s energy security and reducing the country’s carbon footprint.
According to Steve Novis, managing director of Atkins in Poland: “This is a major investment and it will require precision project management to ensure the concept can be taken through to reality. The facility will be unique in Eastern Europe and, as such, it will be closely watched by other countries in the region.”
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