European gas: running on empty?

The big news coming out of Europe is that it is running out of money, but is Europe also running out of gas? Infield Systems' Peter Kiernan(left) and Dr Roger Knight discuss the future of Europe's gas supply in the light of the growing need to secure energy from Russia and the Middle East. 

The North West European Continental Shelf (NWECS) is Europe's major oil and gas-producing basin, and rapid expansion of NWECS gas production in previous decades contributed to easing the European Union's (EU) dependence on pipeline gas imports from Russia. The growth of (non- EU) Norwegian and Algerian supply, and the more recent entry of other suppliers from the Middle East and North/ West Africa, has in fact contributed to the erosion of Russia's share of the EU's total gas imports from over 70% in the early 1990s to around one-third today. Within the EU the Netherlands emerged as a major European exporter in the 1970s while the UK exported gas briefly from the late 1990s before becoming a net gas importer again in 2005.

However, while Norway's gas output has been growing over the last decade, production in the UK has been declining, and the UK now produces less gas than the Netherlands (which is unlikely to build on its export levels due to expectations of gradual output decline there too). It is also forecast that gas production in Norway will peak early in the next decade, and earlier this year the Norwegian government downgraded its gas resource estimates to 570bcm, a reduction of 31%.

In the longer term, therefore, the EU will need to rely increasingly on diversified sources of imports – in the form of both LNG and pipeline gas – to compensate for indigenous production decline. EU gas consumption will show steady growth over the longer term (albeit at a slower rate than expected before the 2008/09 recession), and thus the share of imports of total EU gas supply will continue to increase. According to the European Commission's Energy Trends to 2030 publication, the EU's level of gas imports is forecast to be 40% higher by that year compared to the level seen in 2005.

However, even as gas output declines in the UK, and is expected to peak in Norway soon after this decade, a sizable total of offshore gas reserves are still expected to come on stream over the next five years at least. In fact, Infield data shows that gas reserves will comprise just over half the reserves in the NWECS that are expected to come on stream by 2016. The recent strong performance of gas reserves coming on stream has been especially remarkable in Norway, which has doubled its gas output over the last ten years – even as its oil output has shown steep decline over the same period. Norway has also joined the ranks of LNG exporters to complement its existing pipeline routes to western continental Europe and to the UK.

For the next decade at least Norway will be a key supplier of gas to Europe, and the Scandinavian producer hopes to build on this through discoveries in the Norwegian and Arctic Barents seas. Meanwhile the UK hopes that continued discoveries in areas such as the West of Shetland area will arrest its decline in production, and thus slow the growth of the UK's gas import dependency.

Norway & UK gas to Europe 2000-10

Norway's gas production has shown spectacular growth over the last ten years. Troll, Norway's largest gas field, began producing in 1996, while another large gas field, Åsgard, began producing in 1999. More recently Snøhvit and the deepwater Ormen Lange fields, two significant gas field developments that have boosted Norway's gas export potential, both began producing in 2007 (Snøhvit is also Norway's first LNG liquefaction project). Gjøa, with reserves of 1.4tcf recently came onstream, with GDF Suez taking over as operator from Statoil. Pipeline projects such as the Tampen Link (from the Statfjord field to the UK's Flags pipeline system) and the Langeland pipeline, which began operating in 2007, have enhanced Norway's gas export capability.

Infield forecasts that around 5.2 billion boe of gas and condensate reserves are likely to come on stream between 2011 and 2017, with the first fields being BP's Skarv, and the Valemon and Gudrun fields which are both operated by Statoil.

Norway's gas production has doubled from 49.7bcm in 2000 to 106.4bcm in 2010, in stark contrast to its oil production which has declined from 3.3 to 2.1 million b/d over the same period. However, Norway's gas boom may not last much beyond the end of this decade without substantial new discoveries. By the early-2020s Norway's gas production may show signs of having peaked, and in early 2011 the Norwegian Petroleum Directorate downgraded its estimates of gas resources in the Norwegian Sea and the North Sea by 31% to 570bcm.

Discoveries of major fields have been few and far between over the last decade, a problem which has been compounded by a downgrading of Shell's Ormen Lange field by 25% in 2009. Norway sees the relatively unexplored Barents Sea as a potential new frontier for gas exploration and development, although recently only the Snøhvit cluster and Goliat fields have been major developable discoveries there. Although the results have been rather disappointing so far the Norwegian government is still pinning its hopes on unlocking the key to the Barents Sea, and has been encouraged by the amount of interest shown in that region in the 21st licensing round (with 51 blocks attracting applications from operators). In June this year Total's Norvarg well may have discovered 10-50bcm of natural gas, according to Total's partner, the Norwegian independent DNO.

Exploration in this region is likely to be encouraged now that Norway and Russia have signed a border agreement determining their maritime boundary in these oncecontested Arctic waters.

In the UK the decline in oil production has been matched by a decline in gas production. Since the middle of the last decade the UK has become a net gas importer, and now the UK even produces less gas than the Netherlands, whose production has remained stable due to the substantial onshore Groningen field. In 2000, when the UK was the largest gas producer in Europe, the country's gas production reached 108bcm, but by 2010 this had declined to 57bcm. Decline is expected to continue, with the UK's DECC forecasting that production could fall further to as low as 37bcm by 2020.

Yet there are still prospects for the UK's gas sector.

Infield forecasts that 4.1 billion boe of gas and condensate reserves are expected to come onstream offshore the UK between 2011 and 2017; including the Cygnus field (operated by GDF Suez), Laggan/Tormore (Total), Jackdaw (BG Group), Franklin West Phase 2 (Total) and Kessog (BP). Total alone is expected to spend $3.8 billion on developing its Laggan and Tormore gas fields West of Shetland (OEJanuary 2010).

This expected decline in gas production will increase the UK's dependence on imported gas via pipeline and in the form of LNG. Imports of LNG began with the opening of the Isle of Grain re-gasification plant in 2005, and in 2009 the South Hook and Dragon terminals became operational at Milford Haven while the second phase of the Isle of Grain expansion was also completed. According to data from DECC, LNG's share of total gas imports rose from 25% in 2009 to 35% in 2010. 

Since 2009 Qatar has become a major supplier of LNG to the UK.

Although Europe's gas import level will increase over the next two decades the NWECS will still remain as a major gas producing region. Norway's gas output growth has been impressive over the last ten years and exploration activity is likely to increase in the Arctic Barents Sea. Meanwhile UK areas such as the West of Shetland are seen as one of the more prospective regions for both oil and gas, given that the UK North Sea is mature. The DECC states that remaining gas reserves – based on proven, probable and possible reserves – amounts to 781bcm in 2010; not an insubstantial amount.

As much as Norway will remain a major exporter of gas to the EU, the European market is becoming increasingly diversified in terms of suppliers as LNG makes a greater impact, a trend that is likely to become more noticeable as this decade progresses. OE

Oilfield services in robust demand
A new IHS Herold study suggests oilfield services will continue to see ‘robust' demand because of strong oil prices and rising E&P budgets worldwide. The analysts' Special Study on the Oilfield Services Sector, released last month and covering Baker Hughes, Cameron, Halliburton, National Oilwell Varco, Schlumberger and Weatherford, anticipates continued strong performance by these multi-service providers in 2011 and 2012.

Demand is expected to be particularly high for oilfield services in North American unconventional oil and gas shale plays, as well as Latin America, South America, the Middle East and West Africa. ‘The moratorium on drilling in the Gulf of Mexico limited, but did not stall, what was otherwise a nice recovery compared with 2009 to 2010. Accordingly, operating margins for the group have exhibited a steady upward trend, which began in 2009,' said IHS senior analyst John Parry, author of the study. ‘The shortage of pressure-pumping capacity for multistage fracturing is likely to ease in 2012, which may soften margins for these services, but the companies in this sector continue to be bullish on markets outside of North America.'

Another bullish outlook for oilfield services came from Colin Welsh, CEO of Simmons & Company International, on the eve of last month's SPE Offshore Europe conference in Aberdeen. Welsh thought the sector's growth over the next decade could be akin to that of the internet boom of the 1990s.

‘At existing commodity prices, the oil & gas industry can support strong levels of spending,' he said. ‘Opex and capex spend will rise by around 18% this year, which will result in rising revenues and profits for oil service companies. This trend looks set to continue in the absence of a double dip in the economy or other financial trauma.

‘The prospects for the oil services sector are more positive than ever, as international and deepwater activity ramps up, emerging market demand drives up commodity prices, and unconventional energy in the US and Europe starts to get exploited. We are entering a significant period of growth – a golden era – for oilfield service companies.' OE


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