Gas grid and storage facilities in the UK

The start up of gas production in 1967 from the Leman field in the North Sea heralded a very substantial and ambitious infrastructure project, spanning the 1970s and early 1980s.
The construction of a national grid was designed to bring this newly discovered resource to the major markets and points of consumption around the country, where previously distribution of locally manufactured gas was limited to networks in the main conurbations.
The completed network, known as the National Transmission System (NTS) and owned by National Grid plc, makes gas available today to approximately 11 million domestic, commercial and industrial users, including 40 power stations and comprises approximately 4,200 miles of pipelines and 24 compressor stations. Gas enters the system through seven import points and intermediate storage around the network is provided at eight inland locations.
Gas to end users is supplied through the Local Transmission System, comprising eight distribution networks and circa 170,000 miles of pipelines.
The above infrastructure supports the largest gas market in Europe at just under 80 billion M3 in 2012 (70 million tonnes of oil equivalent) – down from a peak of 97 billion M3 in 2004 and the country’s second largest primary energy source, at 35% (versus 38% for oil).
Its two principal sources of usage are in power generation, accounting for 34%, and in domestic/residential heating at 33%. Gas accounts for about 40% of the fuel used in power generation and 80% of that used for residential heating.
The National Transmission System
The seven gas import points for the NTS points are at St Fergus, Teesside, Easington, Theddlethorpe, Bacton, Burton Point and Barrow. Three of these facilities – St Fergus, Easington (including Rough) and Bacton – process about 80% of the gas entering the country.
The next key link is the network of eight operational storage sites that act as buffers around the system and which fall in to three broad categories:-
Long range – primarily to accommodate seasonal demand swings
Medium range – which have shorter injection/withdrawal times to respond more quickly to short term demand and/or price changes
Short range – to enable rapid/instantaneous delivery of gas in to the system
The storage facilities themselves fall into two main types – depleted oil/gas fields and salt caverns.
Recent developments in the current millennium have necessitated material new additions to the storage network in the form of LNG facilities.
Recent developments
A landmark was reached in 2004, since when the country has not been able to satisfy indigenous gas demand from the UK Continental Shelf (UKCS) in the North Sea, with production there having declined by almost 60%.
Consequently reliance on imported sources has had to increase, with UKCS supplies now only covering circa 45% of national requirements. Imports are sourced from three principal supply points – the Norwegian sector of the North Sea (just over 40%), as LNG (circa 40% of which 90%+ is from Qatar) and the Netherlands Groningen field (circa 15%) via the interconnector in to Bacton; small quantities ( around 5% ) are sourced from Belgium.
So LNG imports now service just under a quarter of the country’s gas requirements and to accommodate this new source three substantial new storage complexes have been commissioned since 2005. These are:-

  • Isle of Grain, Kent – owned by National Grid and originally commissioned in 2005 but subsequently expanded to total storage of one million cubic metres and capable of processing 15 million mt/year (20% of UK demand). This is the largest LNG terminal in Europe
  • South Hook, Milford Haven – jointly owned by Qatar Petroleum (67.5%), Esso (24.15%) and Total (8.35%), the site was commissioned in 2009, has total storage of 755,000 cubic metres and is capable of processing 15.6 million mt/year. This facility, built on the site of the former Esso oil refinery, is closely integrated in to the Qatargas2 supply chain
  • Dragon, Milford Haven – owned jointly by BG Group and Petronas, this site was also commissioned in 2009, has total storage of 320,000 cubic metres and is capable of processing 2.7 million mt/year. This facility is built on the site of the former Gulf oil refinery.

In addition to the above a facility known as Teesside Gasport was commissioned by Excelerate Energy in 2007. This comprises a floating regasification (from LNG) plant, capable of delivering gas into the grid at a rate of up to 17 million cubic metres per day.
With these facilities now in situ, the UK now has Europe’s second largest LNG storage and regasification capacity, after Spain.
Future challenges
Future indigenous shale gas prospects aside, it is projected that the UK’s dependency on imported sources of gas will rise to over 70% by 2020, with a material proportion comprising LNG (circa 60% of gas imports). Juxtaposed with this scenario is the relatively modest amount of gas working storage capacity versus demand in the UK compared with a number of other developed economies. Unlike oil, for which countries are mandated at all times to carry minimum inventories in terms of days’ demand, there are no comparable requirements for gas.
The proximity of the UKCS as a supply source has enabled the country to maintain working storage equivalent to around 4% or 14 days of demand. This compares with France at 30%/87 days, Germany at 22%/69 days, and Italy at 17%/59 days. The USA typically carries about 65 days. Much closer to the UK, and supplied out of the Groningen field, are the Benelux countries of Belgium, carrying 3%, and the Netherlands, carrying 11%.
To enhance its future capability of managing exposure to possible supply disruptions and/or sudden price hikes, the UK will need to increase the size of the storage buffer. Some have suggested that it needs to double from the current position to around 28-30 days; other recommendations have pitched at nearer 60 days.
Whatever level is targeted, the investment requirement will be very substantial. But what is the price of having a measure of protection from supply interruptions and/or cost surges during a cold snap in January?