Prospects slowly brighten for operations off Europe

Aug. 2, 2010
Nervous optimism describes the mood of European operators just past 2010's midpoint as oil prices have recovered from the drastic late 2008 slump, economies slowly emerge from the worst recession since World War II, and financing options resurface.
The hull of Octabuoy, a dry-tree drilling, completion, workover, and storage facility on a semisubmersible production platform, is under construction in China for ATP Oil & Gas Corp., Houston. The reusable unit's first deployment will be in the UK North Sea at Cheviot oil and gas field, where production is to start in 2012-13. The vessel can work in 500-9,500 ft of water, accommodate as many as 12 wells, and handle 25,000 b/d and 50 MMcfd. Installed cost is $600 million, and ATP projects a 50-year useful life. ATP has 100% working interest in Cheviot. Photo courtesy of ATP Oil & Gas.

First half 2010 drilling is up off the UK and slightly lower off Norway as the US gulf oil spill and other regulatory concerns hover.

Nervous optimism describes the mood of European operators just past 2010's midpoint as oil prices have recovered from the drastic late 2008 slump, economies slowly emerge from the worst recession since World War II, and financing options resurface.

OECD Europe gas demand slumped by 5.6% in 2009, according to the International Energy Agency (IEA), as the financial crisis slammed Europe. OECD commented, "The industrial sector and power generation where gas-fired plants are often at the margin have been particularly affected."

Data from Deloitte's Northwest Europe Petroleum Review show that the number of exploratory and appraisal wells drilled off Norway increased 58% in the second quarter from the first quarter of 2010. Drilling off the UK saw a 133% rise in the same period, said Matthew Evans, Deloitte Petroleum Services senior analyst.

"We need to see another quarter worth of data to know if there is a clear recovery process," said Evans.

Norway's exploration and appraisal figures for the first quarters of the past 3 years have held steady because of the country's favorable tax regime and high level of activities by Statoil AS and DNO ASA.

The European Union and Norway jointly account for being the world's fourth largest oil and gas producer. Analysis by the International Energy Agency in its medium term oil and gas markets report presents strong growth in China, India, and the Middle East for oil and gas compared to weaker or flat demand in Europe. Regardless, "both need more investment, a greater focus on energy efficiency, and improved data," IEA said.

Because the economic recovery is still fragile, there is the pervading fear of a double-dip recession. Europe's debt crisis is a compounding factor.

IEA forecasts that OECD Europe's oil supply will fall to 3.3 million b/d by 2015 from 4.5 million b/d in 2009. Meanwhile, oil product demand will drop by 0.7%/year on average from 15 million b/d in 2009 to 13.9 million b/d by 2015. Several reasons explain this: modest economic growth, smaller populations, the transition from fuel oils to renewables and natural gas, and the dieselization of vehicle fleets.

Operators have 33 offshore Europe projects under development, according to oil and gas research firm IHS Herold, of which 61% are in the North Sea and 42% off Norway.

A noticeable trend is that operators are reporting about 15% higher costs for the projects than they originally estimated, said Aliza Dutt, IHS Herold vice-president and senior equity analyst.

Six of the 10 deepest-water projects under development are off Norway. Last year Shell discovered 10-100 bcm of recoverable gas at the 6603/12-1 wildcat in the Norwegian Sea. The well is in 4,514 ft of water, the greatest water depth of any discovery made on the Norwegian shelf.

Ironically, Europe faces an unprecedented gas oversupply with many European companies struggling to respect take-or-pay obligations in 2009. IEA said, "The past 18 months have therefore not seen many projects sanctioned except the much-awaited Nord Stream pipeline."

Although offshore Europe is a mature area, 121 projects are under consideration with 47% off the UK and 41% off Norway. Statoil has eight, BP PLC eight, and Talisman six. Market incentives and innovative technology will be crucial to tapping the more difficult reservoirs that operators are discovering.

Availability of an estimated £30 billion of decommissioning contracts in coming decades is fraught with uncertainties over future oil prices, timing, seasonality, areas of technical inexpertise, and contracting strategies.

This article looks at some of the spending patterns, oil and gas production trends, major projects, and future challenges on the UK and Norwegian continental shelves.

UKCS overview

The UK Continental Shelf (UKCS) satisfied about two thirds of the UK's primary energy demand in 2009: 94% of oil demand and 68% of gas demand.

That is the contribution determined in the 2010 economic activity survey produced by the Oil & Gas UK trade association, which represents operating and supply chain companies in the UK North Sea.

Production averaged 2.38 million b/d of oil equivalent, a decline of nearly 10% from 2008.

A spokeswoman told OGJ that a "decrease in demand and extended maintenance programs in 2009 were in part responsible for a 6% drop in oil production compared with the previous year.

"At 58 bcm, gas production satisfied 68% of total consumption of gas in the UK in 2009. This figure represents a drop of 15% compared with the previous year and was the result of a combination of lower demand and higher imports, particularly of LNG, which partly displaced indigenous production in the marketplace."

In 2010 operators expect to deliver around 2.35 million boe/d, down 5%, making the UK Europe's third largest gas producer (after Norway and the Netherlands) and the world's 19th largest oil producer.

UKCS expenditure

Operators spent £12.3 billion on exploration, development, and operations in 2009.

Capital investment was £4.7 billion, 6% lower than in 2008 and this is expected to rise to £5 billion to £6 billion in 2010 with the improving optimism about business conditions. Investment in 2011 could be £5.5-6.5 billion.

Oil & Gas UK said, "Total operating expenditure fell by 6% to £6.6 billion, and this is expected to remain similar at £6.5 billion in 2010." Unit operating costs fell to $12/boe.

Current investment plans have the potential to deliver 5.25 billion boe from existing fields and 5.9 billion boe from incremental and new field developments.

UK drilling activity

The total number of wells drilled, including sidetracks, was far fewer in 2009 than in 2008 because of lower oil prices and a shortage of finance (Fig. 1):

• 130 development wells, down 24%.

• 23 exploration wells, down 48%.

• 42 appraisal wells, down 31%.

Operators plan 16 firm appraisal wells in 2010, and 25 more are possible.

According to analysis by the Hannon Westwood UK North Sea consultancy, 23 wells were spudded through June 21, 2010, in the UK North Sea (Fig. 2).

"This is the highest number of well spuds for the last 5 years, excluding 2008, which was a bumper year," said Jim Hannon, managing director. "This year there has been a low number of sidetracks. We are recovering nicely, and I think this will be a good year. The reasons for this are improved confidence, access to funds to do exploration and appraisal, successful farmouts, and $70-80/bbl oil prices."

Securing funds to develop commercial discoveries is where the key problem lies. Hannon estimated that $38 billion in capex is needed to underpin 90 near term discoveries in the UK North Sea that hold about 2.8 billion boe (Fig. 3).

Looking at current spending trends, however, only $7.1 billion was spent on new discoveries and field enhancement in 2009 compared with what is needed of at least $7.6 billion/year over the next 5 years.

"There is an oversupply of opportunities and an undersupply of funds for them. The companies that provided these were poorly funded with further problems of the downturn and banks pulling funds," Hannon told OGJ. "There are about 5.2 billion bbl of known oil and gas production in the UK and 2.8 billion of potential discoveries. If we could utilize these, then it would buy us time to move to greener sources and deflect the need for … imports."

The effect is that operators must prioritize projects and take advantage of existing infrastructure and government support or risk being unable to deliver timely production.

New energy policy

It has been 65 years since the UK last had a coalition government.

In May, the Conservative and Liberal Democrat parties agreed to share power following a hung parliament by the electorate.

This new arrangement has raised many questions for UK North Sea operators who recognize the need to increase efficiencies and reduce costs in this mature province, such as:

• What is the new energy policy?

• How long will this coalition government last?

• How do you reconcile differences, for example, where the Liberal Democrats oppose new nuclear developments but the Conservatives support it provided there are no public subsidies?

Nevertheless, operators have repeated the need for government to espouse an integrated energy policy that includes oil and gas to manage the transition to renewables.

Deepwater drilling

Unlike Norway, the UK government has not postponed new deepwater drilling until the investigation into BP PLC's Gulf of Mexico oil spill disaster is completed.

Chris Huhne, the new energy secretary, has doubled environmental rig inspections and is keen to usher through deepwater gas developments such as Laggan/Tomore, which lies West of Shetlands in more than 600 m of water.

So far, around 2 tcf of gas has been discovered, and as much as 4 tcf of potential remains. Bringing these resources to market would cost an estimated £2.6 billion for gas and more than £4 billion for oil.

Higher insurance premiums or tighter regulation are potential consequences for deepwater drilling in British waters. For smaller companies with tiny balance sheets compared with the majors, this could mean being unable to explore West of Shetlands, which is estimated to hold almost one fifth of the UK's remaining hydrocarbon resources.

The Department of Energy and Climate Change (DECC) is also considering boosting indemnity and insurance protection needed to operate in these areas.

Government support

The mature UK North Sea holds up to 25 billion boe recoverable, which offers opportunities for pioneering technologies and techniques to extract these barrels.

In Huhne's first meeting in May with Oil & Gas UK, he pledged to support the industry.

Despite the eagerness to push a green and renewables energy agenda, oil and gas will remain the primary supply sources in the nation's energy mix. The government target is to meet 15% of the country's energy needs from renewable sources by 2020.

Currently oil and gas satisfy 74% of UK primary energy demand, which will marginally drop to 70% in 2020. However, the UK should still be supplying 60% of its demand for oil and 25% of its gas requirements in 2020.

Interrelated with this, therefore, is energy security, and during July's question time in the House of Commons, members of Parliament pressed Huhne, who is a Liberal Democrat, on that, particularly in the next decade. He stressed that the government will reform energy markets to deliver the appropriate mechanisms.

Otherwise the government plans to widen access to the UK's offshore production infrastructure and introduce secondary legislation as soon as possible to extend the scope of the ultrahigh pressure-high temperature field allowance.

UK fiscal regime change

Operators have complained that it is costly in the UK to advance projects due to high production taxes and the heavy UK and EU regulatory burden.

They have warned that this could discourage future investment of £16 billion and jeopardize 1.5 billion boe of reserves over time, Malcolm Webb, chief executive of Oil & Gas UK, told OGJ.

"Already £4 billion of this has been sanctioned. Tax revenues are rising to £9 billion, which is a 30% increase on last year. We need dialogue about the long term future of the fiscal regime and a new model going forward," said Webb.

Investment in the UKCS has to be sustained at above £5 billion/year to maintain future production and maximize recovery of the remaining oil and gas resources. Yet capital investment declined 20% to £4.8 billion in 2008 from £6 billion in 2006 despite a 40% rise in oil price in the same period.

As the government struggles to address the £160 billion deficit by cutting public spending and increasing taxes, lobbying for tax adjustments is highly sensitive. The main advantages that operators are pushing are that the oil and gas industry is the country's largest industrial investor and corporate taxpayer with a central role in ensuring that the UK emerges from the global recession as a strong international competitor.

Operators were relieved not to see any nasty surprises in the emergency budget published June 22. Oil & Gas UK said, "It is encouraging that the Chancellor has delivered a package of fiscal measures, including phased reduction of corporation tax, which aims to promote innovation and stimulate growth and development across the whole of our industry."

The emergency budget held the corporation tax on profits from oil and gas extraction at 30%, held small companies' rate of corporation tax for oil and gas extraction at 19%, and held unchanged the capital allowances on oil and gas extraction activities.

But the fiscal regime does need overhaul. Operators pay 50-75% in tax depending on each field's age. One suggestion is tax breaks for particular developments such as tight gas in the southern gas basin and deep condensate in the Central North Sea, which has already received some tax breaks.

Hannon added, "This would increase the gas reserves being brought to shore. We understand that Treasury is considering these play-focused ideas, but industry and government need to work together to bring about change."

This would build upon amendments introduced last April by former chancellor Alastair Darling to support small and marginal fields as discoveries on the UK Continental Shelf are becoming smaller and more technically challenging.

Subsea focus required

Alistair Birnie, chief executive of the Subsea UK industry body, has called for the government to recognize industry's £5 billion contribution to the UK economy.

Birnie said the subsea sector "must be at the heart of the government's energy strategy. The price of ignoring this valuable sector which is involved in all forms of offshore energy and at the heart of the growth in oil and gas exports and renewable energy will be too high to pay in terms of loss of revenue and jobs to UK PLC."

Subsea represents 43% of oil and gas production, which generated some £12 billion in tax revenues in 2008-09. This percentage is growing year on year, with 70% of new production attributed to subsea. Despite fluctuations in the oil price and the impact of the downturn, tax revenues from oil and gas are forecast to be £8.4 billion in 2010.

The oil and gas subsea sector faces threats from people, equipment, and vessel shortages, and Birnie wants the government to invest in skills and technology development at national and regional levels.

Licensing round

With recovering oil prices and a reduction in rig rates, investor confidence is returning to the UK North Sea following the 33% drop in drilling in 2009 compared with 2008.

The "strong interest" in the 26th licensing round suggests that operators wish to acquire new acreage. A DECC spokeswoman said, "The spread of applications covers a range of areas including Southern Basin, Central & Northern North Sea, and Frontier areas such as West of Shetland."

DECC interviewed applicants through July and expects to announce winners towards the end of 2010.

Operators applied for a record 356 blocks in the round, which offered acreage in all of the UK's territorial waters for the first time in 12 years and tax incentives to explore some areas for gas. This is the largest number since the first licensing round in 1964, which saw 394 blocks requested.

Ireland Atlantic margin

For the first time the Irish government has invited operators to explore the entire Atlantic margin rather than specific blocks.

This is the largest licensing round to date with just over 250,000 sq km in 996 full blocks and 58 part blocks. The area extends 30-380 km mostly in 200 m of water or less to as much as 3,000 m. Application deadline is May 31, 2011.

Two-year licensing options will enable companies to assess the area's potential without a large upfront cash outlay. If satisfied, operators can secure a 15-year license provided an appropriate work program is agreed.

UKCS projects

Eight new fields started up in 2009, bringing 150 million boe of reserves into production. Below we highlight some of the major discoveries and start-ups in 2010.

Catcher. EnCore Oil's Catcher light oil discovery in the Central North Sea shows sizable fields remain. UK North Sea finds have averaged 25 million bbl the past 10 years, but Encore's discovery could hold 300 million bbl in place and 100 million bbl recoverable.

The company recently drilled Catcher East sidetracks that found 82 ft of net hydrocarbon pay in a 236 ft gross interval. A core in the main sand body recovered 44 ft of oil-bearing sand, and the well reached a total depth of 5,931 ft with no oil water contact. EnCore will drill a southwest sidetrack from the 28/9-1 Catcher discovery well.

Bacchus (2011). Apache Corp. leads a consortium comprising Endeavour International Corp. and Shell UK that received DECC's end-June go-ahead to develop Bacchus in the Central North Sea. It will produce through three subsea wells linked to existing infrastructure at Apache's Forties field. Production is to start in the first half of 2011. Bacchus has estimated reserves of 18 million boe.

Huntington (2011). E.ON Ruhrgas UK E&P is to start production in the 2011 fourth quarter from 3-4 production wells and 1-2 water injectors on Sevan Marine's floating, production, storage, and offloading vessel Sevan Voyageur. It has a production capacity of 30,000 b/d that can access additional resources from the deeper reservoirs. According to Noreco, one of the partners, for the first 5 years of production Huntington holds a recoverable 41 million boe, 90% oil.

Breagh (2012). RWE Dea UK is developing Breagh field in the southern North Sea. With 13 billion cu m of reserves it is one of the largest gas fields to be brought onstream. Breagh is a conventional Carboniferous reservoir 65 km off England's northeast coast. Production is to start in 2012.

Maule. Apache's Maule field well started production of 11,750 b/d in late June, 8 months after discovery. It is connected to Forties. James L. House, region vice-president and managing director of Apache North Sea Ltd., said, "The viability of the project was enhanced by the UK government's incentives aimed at encouraging development of smaller fields in the North Sea." Apache will drill a second well at Maule.

Decommissioning work

The first major batch of decommissioning activity in the North Sea is forecast to ramp up quickly in the next year or two.

Brian Nixon, chief executive of Decom North Sea (DNS), a new industry body established last year to connect UK businesses with decommissioning work, said, "This emphasizes that now is absolutely the right time for Decom North Sea to begin its work with the supply chain, and to stimulate the preparation, collaboration, and innovation needed to secure this vital market opportunity."

Fixed platforms to be dismantled include North West Hutton, Miller, Don, Indefatigable, and Frigg, at a combined cost likely to exceed $1 billion through 2013.

Comprehensive plans are drawn up to address decommissioning, but final costs can far exceed original estimates as demonstrated by Total SA's experience at Frigg gas field that straddles the Norwegian and British boundary. Last January, Total resolved a cost dispute with engineering contractor Aker Solutions. In 2004 the contract was estimated at 3 billion kroner, but environmental and safety issues complicated decommissioning and drove up costs.

ConocoPhillips Skandinavia AS (CoPSAS) plans to remove the compressor facility 37/4-A on Ekofisk I in British waters this summer. The compressor previously connected the Norpipe pipeline from Ekofisk to Teesside, UK.

Norwegian overview

Norwegian production of oil, condensate, and NGL should hit 2.2 million b/d this year, 4.5% lower than 2009.

By 2013, oil production is expected to be just over 1.6 million b/d, but gas output is gaining importance with sales in 2010 estimated at 105 billion cu m.

In 2010 including exploration costs, total investments in the revised national budget are estimated at 134 billion kroner, a decline of 2.5% from 2009.

Operators spent 136 billion kroner on the NCS in 2009, making 28 new discoveries and spudding 65 exploration wells. This is nine more exploration wells than in 2008 and a new record (Fig. 4).

Twenty one discoveries were in the North Sea and generally small and close to existing fields. The other seven were in the Norwegian Sea. Only one well was completed in the Barents Sea, which delineated the discovery 7226/2-1 (Obesum), proven in 2008.

The Norwegian Petroleum Directorate said, "The (2010) exploration activity level is expected to fall from last year. The number of exploration wells will probably be between 40 and 50." Operators have spudded 27 exploration wells through mid-July.

The oil and gas industry generated one fourth of Norway's income in 2010. The state's net cash flow from the petroleum sector is estimated at 261 billion kroner.

Norway is focusing on improving recovery from existing fields, gradual exploration in areas already open to the petroleum industry, and access to new acreage with operators keen to explore the northern Barents Sea, Troms II, Nordland VII, and parts of Nordland VI.

NPD estimates the NCS recoverable resource at 8.1 bscm of oil equivalent. Despite the substantial oil price drop and world economic downturn, NCS activity stayed high in 2009. There are concerns regarding the phasing in of future projects depending on future oil prices and government policies. Authorities in 2009 approved development plans for Goliat, Oselvar, and Troll fields. They just approved Marulk and could okay Pi and Nemo later in 2010.

NCS challenges

Norway has banned deepwater drilling in new areas until it reviews lessons from BP PLC's oil spill in the US Gulf of Mexico.

As business confidence improves following the recession, operators are being forced to reassess projects that looked viable with high oil prices, and they are keen to see a clear oil policy and political signals from the government to plan their exploration and development strategies.

NPD has conceded that it may be difficult to reach its target of increasing oil reserves by 5 billion bbl by 2015 as reserves growth has been small since 2005 when the target was first set.

The NPD assumes that 75% of growth in reserves must come from fields already in operation but is disappointed with "the apparent lack of willingness to invest for the future, with a conscious commitment to research, technological development, pilot projects, and the willingness to use new methods on the fields."

Consequently, NPD could not grant an Improved Oil Recovery Award in 2009 but hopes to find a worthy operator this year.

One major criticism of government is that new exploration areas such as deepwater Norwegian Sea are off-limits due to environmental considerations. Without access, operators will be forced to scale back capacity, and it is likely that knowledge and technical expertise will be lost faster than anticipated.

The OLF Norwegian oil industry body said: "Official production forecasts are increasingly dependent after 2020 on output from discoveries which have yet to be made. Finds made after 2008 are expected to account for 42% of production from the NCS in 2030.

"Experience in these waters shows that the period from the award of new production licenses until fields come on stream averages 15 years. If the government's long-term output forecasts are to be met, new and preferably large discoveries must be made quickly."

Around two thirds of the undiscovered resource on the NCS is likely to be in the North and Norwegian Seas, replete with facilities. Operators have high hopes for Barents Sea prospectivity, but because recent discoveries have been small NPD has cut its expectation of the recoverable resource to 910 million cu m from 1,030 million cu m.

License round

In light of BP's gulf oil spill, Norway's latest licensing round has proved controversial for environmentalists who have urged the energy ministry not to offer acreage near the Lofoten archipelago.

Norway offers 94 blocks or parts of blocks in the Norwegian and Barents seas. Bidding opened in June, and the deadline is Nov. 3, 2010. Following the spill, the ministry reduced the blocks on offer from 100 and included 12 blocks in more than 4,900 ft of water.

"Increased knowledge about the accident with the Deepwater Horizon will be part of the basis for this (license award) decision," Energy Minister Terje Riis-Johansen said.

The frontier Barents Sea holds 51 of the available blocks. Norway dropped four blocks from the Nordland V area in the Norwegian Sea, which lies close to land to ensure that there are no accidents "given what happened in the Gulf of Mexico," Riis-Johanson explained. "We wish to proceed with the work of assessing various spill scenarios and gathering facts."

Discoveries on hold

Development of three discoveries on the border between Norway and the UK may be postponed for several years due to profitability and/or complexity issues. These are Lundin-operated 24/6-1 Peik field, Statoil-operated 15/8-1 Alpha, a Sleipner subsea satellite, and 6406/3-2 Trestakk, a subsea satellite to either Åsgard or Kristin.

Norwegian projects

Fields that started production off Norway in 2009 were Rev, Volund, and test production from 33/9-Delta in the North Sea and Alve, Tyrihans, and Yttergryta in the Norwegian Sea.

None has started production in 2010. Norwegian authorities in June approved Eni SpA's Goliath field, which will be the first oil producing field in the Barents Sea from 2013. Other major 2010 developments:

Gudrun (2014). Statoil's Gudrun field will start production in the first quarter of 2014 and improve the capacity utilization at Sleipner following the go-ahead from the Norwegian authorities in June. Gudrun will use 7,400-tonne steel jacket and a partial processing facility and pipe hydrocarbons to Sleipner. Well drilling starts in October 2011. Investment in field installations, pipelines, and drilling will total almost 21 billion kroner, with 11.2 million cu m of oil and 6.6 bcm of gas recoverable.

Trym (2010). DONG E&P Norge AS will bring 4.2 bcm of gas resources to market through two horizontal wells and a subsea facility tied to the Danish Harald facility via a 6-km pipeline. The gas-condensate wellstream will be processed on Harald for further transport. Trym is in 65 m of water and is expected to cost 2.6 billion kroner to develop.

Yme (2010). Using a new jack up production facility and water injection, Talisman Energy Norge AS will start production by the end of 2010 from Yme field in the North Sea. Total investment is an expected 11.5 billion kroner. Yme is the first NCS oil field to be redeveloped after having been shut down. The Beta structure is being developed with subsea wells.

Oselvar (2011). Dong E&P Norge AS will develop Oselvar, which holds 52 million boe 250 km southwest of Stavanger, through a seabed installation with three production wells. Oil and gas will be sent via pipeline to the Ula platform for processing. Production is to start in November 2011.

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