At Least 9 More Decades for North Sea Oil

Oil and gas production in the UK North Sea can continue until the end of this century provided the right government policy decisions are made, according to Scottish Energy Minister Fergus Ewing.

Speaking to Rigzone at the Offshore Technology Conference in Houston Tuesday afternoon, Ewing said:

"In domestic terms, the [Scottish] industry is having a second major opportunity with a huge number major new developments going ahead, some of which are extensions of existing developments. For example, the Clair Ridge field has the potential to produce oil until 2055 according to BP."

Clair Ridge is a project to further develop the Clair field with additional fixed platforms.

"The Clair field was actually discovered in 1977, and that's ironic because we were told by London that the oil would run out in the 90s, and then in the 90s that it was going to run out in the Noughties," Ewing said.

"I think it's a theme that's losing credibility because if BP comes along and says the Clair Ridge field will continue to produce until 2055 it's a bit liberal to say the oil is going to run out because it ain't."

Ewing said that there were "huge opportunities" domestically for the Scottish oil and gas sector that would keep oil and gas production going.

"My personal view is that oil and gas production [offshore Scotland] will continue for the rest of the century provided we make the right policy decisions," he said.

But Ewing insisted that fiscal stability is required and that a lot of damage to the sector was caused by the unexpected tax hikes that were introduced in the UK in 2011.

"Fortunately, a lot of that damage was undone the following year when the UK Treasury realized they had unsettled the whole industry, internationally, and shaken confidence in the viability of investing in the North Sea and west of Shetland. So, they then introduced measures on field allowances and decommissioning which we've welcomed. But in order to make sure that the longevity of the basin, especially in the southern North Sea, is as it should be there will no doubt be a need for more fiscal incentives than there are now," Ewing said.

"It's blindingly obvious that if it costs an extra $20 or $30 a barrel to get more oil out and if major operators have to invest hundreds of millions, if not billions, to do so then they have the choice of making that investment in fields where the oil does not cost an extra $20 or $30 a barrel, and therefore there does need to be a partnership between government and industry."

"The impression I get is that they realized they made a big mistake and they acted to try to correct that and with a deal of success. But the danger is that perhaps in the Treasury they feel that it is currently a situation of 'Problem solved!' and complacency is the most dangerous attitude that you can have in government because almost always the problems are more complex than you realize."

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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Bilfinger Salamis Wins Chevron North Sea Contract

Bilfinger Salamis UK reported late Thursday that it has won a major contract with Chevron Upstream Europe to provide maintenance services to the company's North Sea platforms.

The contract, which has a potential value of approximately $77.5 million, will last for three years and has two additional renewal options. It will secure continuity of employment for more than 80 Bilfinger Salamis employees offshore and onshore.

Services provided to Chevron's assets – Alba North, Alba FSU, Captain WPP, Captain FPSO and the Erskine Platform – will include the supply of deck crews, rigging, coatings and insulation work, scaffolding, rope access, specialist cleaning and architectural services.

Bilfinger Salamis Delivery Manager Doug Sheal commented in a statement:

"We see this long-term contract award as an opportunity to invest further in our people and the equipment assigned to Chevron and further cement our positive working relationship. The contract award to Bilfinger Salamis UK builds on our existing track record, relationships and knowledge of the assets in a seamless manner without disruption to crews work plans or safety culture."

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Tendeka to Grow Presence in North, South American Market

Tendeka, the provider of completions systems and services to the upstream oil and gas industry, announced Tuesday plans to significantly grow its North and South American market presence by promoting its full portfolio of complementary completions products and services in the region.

By opening an office in Canada to directly supply the Canadian market and widening its South American oil and gas market with an increased presence Tendeka will supplement its swellable packer market with its innovative technologies and services that have already added value to client's wells in other regions around the world.

Since its inception in 2009 Tendeka has gone from strength to strength and is a global employer. With 18 regional bases strategically located in key energy hubs, the company is now set to expand further.

Tendeka is a major player in the North American swellable packers market and has supplied packers for use in conventional and unconventional applications in liquid shales including the Bakken, Eagleford, Utica, Niobrara and Permian developments. Tendeka also supplies monitoring, modelling and control systems and services that manage reservoir performance, enhance production and reduce downtime.

Ken Miller, Tendeka vice president of North and South America, said: "We have achieved over 200% top line growth over the last 24 months in our international markets including North America. Swellable packers remain an important part of our North American service offering, particularly to the fraccing market, but we have established that there is a demand for the full range of Tendeka products and services not just in North America but also in Canada and South America.  Our recent contract wins for Cyclic Steam Stimulation monitoring, AICD in SAGD and software for reservoir interpretation are evidence of our increased market penetration in these regions.

"These systems combine to maximise output and efficiency from the reservoir," explained Miller. "We recently strengthened our position in Calgary; initial indications show that our assessment of the market conditions was correct and there is a strong demand for our wider systems offerings, especially in heavy oil operations. Brazil is also a key focus for us where we have recently established solid routes to market and been awarded seven figure contracts. 

Tendeka's CEO Gary Smart said: "Our full portfolio of completions systems and services now includes: leading electronic gauge, distributed and wireless monitoring technologies, to monitor reservoir performance; modeling software, to provide reservoir interpretation and build scenarios; wireless intelligent completions systems, to control reservoir production; sand and inflow control devices, to control reservoir phase filtering; and swellable and mechanical packers, to provide effective zonal isolation. This suite of completions products and services are all industry proven and has been developed to add value to our clients wells through improved production."

Smart continued: "We are keen to explore the wider market opportunities for the whole range of Tendeka systems and services. Our focus on geographic growth will continue to allow us to bring our existing high value portfolio to clients in new territories as well as providing an established route to market for the new product innovations that are currently under development in our research bases in Europe and North America. The oil and gas industry is a challenging one and Tendeka seeks to positively impact our clients' profitability through the implementation of innovative completions systems and services."

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At Least 9 More Decades for North Sea Oil

Oil and gas production in the UK North Sea can continue until the end of this century provided the right government policy decisions are made, according to Scottish Energy Minister Fergus Ewing.

Speaking to Rigzone at the Offshore Technology Conference in Houston Tuesday afternoon, Ewing said:

"In domestic terms, the [Scottish] industry is having a second major opportunity with a huge number major new developments going ahead, some of which are extensions of existing developments. For example, the Clair Ridge field has the potential to produce oil until 2055 according to BP."

Clair Ridge is a project to further develop the Clair field with additional fixed platforms.

"The Clair field was actually discovered in 1977, and that's ironic because we were told by London that the oil would run out in the 90s, and then in the 90s that it was going to run out in the Noughties," Ewing said.

"I think it's a theme that's losing credibility because if BP comes along and says the Clair Ridge field will continue to produce until 2055 it's a bit liberal to say the oil is going to run out because it ain't."

Ewing said that there were "huge opportunities" domestically for the Scottish oil and gas sector that would keep oil and gas production going.

"My personal view is that oil and gas production [offshore Scotland] will continue for the rest of the century provided we make the right policy decisions," he said.

But Ewing insisted that fiscal stability is required and that a lot of damage to the sector was caused by the unexpected tax hikes that were introduced in the UK in 2011.

"Fortunately, a lot of that damage was undone the following year when the UK Treasury realized they had unsettled the whole industry, internationally, and shaken confidence in the viability of investing in the North Sea and west of Shetland. So, they then introduced measures on field allowances and decommissioning which we've welcomed. But in order to make sure that the longevity of the basin, especially in the southern North Sea, is as it should be there will no doubt be a need for more fiscal incentives than there are now," Ewing said.

"It's blindingly obvious that if it costs an extra $20 or $30 a barrel to get more oil out and if major operators have to invest hundreds of millions, if not billions, to do so then they have the choice of making that investment in fields where the oil does not cost an extra $20 or $30 a barrel, and therefore there does need to be a partnership between government and industry."

"The impression I get is that they realized they made a big mistake and they acted to try to correct that and with a deal of success. But the danger is that perhaps in the Treasury they feel that it is currently a situation of 'Problem solved!' and complacency is the most dangerous attitude that you can have in government because almost always the problems are more complex than you realize."

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

At Least 9 More Decades for North Sea Oil

Oil and gas production in the UK North Sea can continue until the end of this century provided the right government policy decisions are made, according to Scottish Energy Minister Fergus Ewing.

Speaking to Rigzone at the Offshore Technology Conference in Houston Tuesday afternoon, Ewing said:

"In domestic terms, the [Scottish] industry is having a second major opportunity with a huge number major new developments going ahead, some of which are extensions of existing developments. For example, the Clair Ridge field has the potential to produce oil until 2055 according to BP."

Clair Ridge is a project to further develop the Clair field with additional fixed platforms.

"The Clair field was actually discovered in 1977, and that's ironic because we were told by London that the oil would run out in the 90s, and then in the 90s that it was going to run out in the Noughties," Ewing said.

"I think it's a theme that's losing credibility because if BP comes along and says the Clair Ridge field will continue to produce until 2055 it's a bit liberal to say the oil is going to run out because it ain't."

Ewing said that there were "huge opportunities" domestically for the Scottish oil and gas sector that would keep oil and gas production going.

"My personal view is that oil and gas production [offshore Scotland] will continue for the rest of the century provided we make the right policy decisions," he said.

But Ewing insisted that fiscal stability is required and that a lot of damage to the sector was caused by the unexpected tax hikes that were introduced in the UK in 2011.

"Fortunately, a lot of that damage was undone the following year when the UK Treasury realized they had unsettled the whole industry, internationally, and shaken confidence in the viability of investing in the North Sea and west of Shetland. So, they then introduced measures on field allowances and decommissioning which we've welcomed. But in order to make sure that the longevity of the basin, especially in the southern North Sea, is as it should be there will no doubt be a need for more fiscal incentives than there are now," Ewing said.

"It's blindingly obvious that if it costs an extra $20 or $30 a barrel to get more oil out and if major operators have to invest hundreds of millions, if not billions, to do so then they have the choice of making that investment in fields where the oil does not cost an extra $20 or $30 a barrel, and therefore there does need to be a partnership between government and industry."

"The impression I get is that they realized they made a big mistake and they acted to try to correct that and with a deal of success. But the danger is that perhaps in the Treasury they feel that it is currently a situation of 'Problem solved!' and complacency is the most dangerous attitude that you can have in government because almost always the problems are more complex than you realize."

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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Lundin: North Sea Oil Find Luno II May Hold 160M Barrels

OSLO - Swedish oil company Lundin Petroleum AB estimated that its Luno II discovery off Norway could yield as much as 160 million barrels, the latest in a string of finds that have revived interest in the North Sea.

It was the first indication of the size of the find, and the market was slightly disappointed.

Lundin said it expects the southern part of Luno II to contain between 25 million and 120 million barrels of oil equivalent. Another section to the north could produce between 10 million and 40 million barrels, the company said.

Lundin shares fell 2.2% to trade at SEK152.00 after the announcement, reflecting both uncertainty about the exact size of Luno II and the announcement Sunday of an increase in oil company taxes in Norway.

Luno II is located in a geological formation in the middle of the North Sea called the Utsira High. This is where Lundin discovered the Edvard Grieg in 2007 and the Johan Sverdrup in 2010, both significant finds.

"We are pleased to announce another significant discovery in the Utsira High region, which in terms of size and location is likely to be commercial," said Lundin chief executive Ashley Heppenstall.

Lundin's recent success on the Utsira High has contributed to renewed interest in the North Sea, where most companies thought there was nothing left to find after four decades of oil activity.

Statoil recently reported the discovery of between 40 million and 150 million high-value barrels near Gullfaks, a nearly depleted field in the northern North Sea where production began in the mid-80s.

Mr. Heppenstall said the company continues to explore Utsira High and said he was optimistic about further discoveries.

Lundin is the operator of production license 359 where Luno II was found, with a 40% ownership stake. Statoil ASA and Premier Oil Plc each have a 30% stake in the field.

Copyright (c) 2013 Dow Jones & Company, Inc.

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Global Impact of North American Shale Gas Boom Forces Qatar to Shift Focus

The global impact of the U.S. shale gas boom was in further evidence this week as Qatar Petroleum, along with its MOU partner, Centrica, made its first move into the North American exploration and production (E&P) market in a $1 billion acquisition of Canadian assets from Suncor Energy. North America had been earmarked by Qatar as a guaranteed market to sell its copious Liquefied Natural Gas (LNG) export capacity in, but the U.S. Shale boom has turned this idea on its head, as the middle-eastern NOC becomes the latest foreign power to move into the North American E&P arena. The assets being acquired (to be 40% owned by Qatar Petroleum) are well spread over the country in 3 provinces, and the British Columbia set of the assets will no doubt form a potential export opportunity as Kitimat becomes Canada’s LNG exporting center in the coming years.

A look at Qatar Petroleum’s world-standing will shed light on just how significant a move this is, and just how big an impact the shale boom is having on world energy markets. Qatar is the world’s largest LNG exporter by a significant distance with around 78 million tonnes per year (mtpa) of export capacity, and Qatar Petroleum is the operator of all of it. Its nearest rivals, including Indonesia (34 mtpa), Malaysia (24 mtpa) and Australia (23 mtpa), are dwarfed in comparison. Efforts to catch up with Qatar have been led by the Australians, with plans in place to expand the industry in that country significantly by 2020. But these plans are beginning to fall into ruin, as many projects are being cancelled or delayed for various reasons, chiefly a lack of skilled labor and extreme rises in projected costs  – Chevron’s Gorgon LNG project is now projected to cost $50 billion, for example. Plans in new regions of potential LNG exports, such as Mozambique/East Africa, are likely to be a long way off into the future, so Qatar, on the face of it, looks to be in an extremely strong position as the global leader of gas exports. Yet it still moved into this new market.

Recent years have seen Indian, Chinese and other far-eastern NOC’s moving into the North American market following the U.S. shale gas boom, countries without strong domestic markets, but this is arguably the first time a reasonably stable world gas power has felt the need, or has been forced, to join the party. Even as recently as the company’s 2011 Annual Report, Qatar Petroleum lists North America as the target market for its LNG Production “mega-trains” 6 & 7 at its Ras Laffan complex. Whilst the company also listed more ensured markets of Asia and the Middle East as destinations, these “mega-trains” have a total capacity of 15.2 mtpa, and the potential income from exporting this amount of gas to the U.S. had to be replaced, as the LNG import terminals on the American east coast became obsolete and began to sit idle after shale gas began to quickly flood the domestic market.

In the company’s first move to combat the potential harm caused by the shale gas boom, Qatar Petroleum, along with partner ExxonMobil, submitted plans to the relevant authorities to convert its 15.6 mtpa import facility at Sabine Pass, Texas, into an export terminal of the same capacity, in a clear effort to recoup some of the shortfall back by profiting on U.S. exports in the future. However, this follow-up move into Canadian E&P provides a more immediate solution to Qatar’s problem, with net 2P reserves of around 390 bcfe (90% gas) and net production of 100,000 mcfe/d. In fact, this move is not really any different to what Woodside Petroleum are planning, the company is reportedly in talks over acquiring Canadian gas assets, and Woodside is a company who recently shelved an LNG project in Australia to look for a cheaper option, standing it in stark comparison to the world leader in LNG exports.

Widescale exports of U.S./North American shale gas may be as far as 3 to 5, even 10 years into the future, so for the time being, shale gas will remain trapped within those borders. But now the world leading gas exporter has got involved, the global impact of the U.S. shale boom is extremely hard to deny, no matter how trapped the physical quantities of gas may well be.

Evaluate Energy is a leading provider of efficient data solutions for oil & gas company analysis.

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Drilling Begins at WellStar's North Dakota Wells

WellStar Energy Corp. announced that the first well has been drilled and the second well has been spud on its anticipated primary non-operated joint venture (JV) in Dunn County, North Dakota. The Company expects to have a 40 percent working interest in each of the wells upon completion of the acquisition from a private Colorado corporation (the "Vendor") of certain non-operated oil and gas properties consisting of approximately 18,271 gross (7,273 net) contiguous acres located in North Dakota (the "Assets") which will constitute a "fundamental acquisition" (the "Acquisition") for the Company under the policies of the TSX Venture Exchange (the "TSXV").

In addition, two wells have recently been drilled and completed in the Bakken formation on the Company's anticipated secondary joint venture lands, which are contiguous to the primary joint venture but have a different operating partner. The wells are currently producing from two drilling units in which the Company has a potential 12.497 and a 5.208 percent working interest. The Vendor, through consultation with the Company, participated in the FREDERICKS USA 43-26H well (the Fredericks Well). Upon closing of the Acquisition, the Company expects to have a 5.208 percent working interest in the Fredericks Well. The second well, GARY BELL USA 23-36H ("Gary Bell Well") was successfully drilled and completed. The Vendor, through consultation with the Company, went non-consent on the Gary Bell Well. The Company expects to have a 12.497 percent working interest in the Gary Bell Well upon closing of the Acquisition after a three hundred percent penalty is paid from production revenue. Both wells have been put on confidential well status.

WellStar reported it entered into a purchase and sale agreement, as amended with the Vendor in connection with the proposed Acquisition. The Company and the Vendor have entered into a second amending agreement dated April 3 whereby the parties have agreed, among other things, to extend the termination date of the Purchase Agreement from April 16 to May 15. In addition, pursuant to the terms of the Amending Agreement, the purchase price for the Assets has been increased to $51,600,000 from $51,550,000.

Closing of the Acquisition is subject to, among other things, the Company securing satisfactory financing and obtaining approval of the TSXV, including review of a title opinion with respect to the Assets. There can be no assurance that the Acquisition will be completed as proposed or at all. As such, trading in the Company's shares remains highly speculative.

WellStar President Andrew H. Rees commented, "Management is extremely pleased that drilling has commenced on its anticipated primary JV and with the success of the two wells recently completed on its potential secondary JV as they mark the first wells drilled on the leases subsequent to the effective date of the Acquisition (being November 1, 2012 in the event that the Acquisition is completed). The Company has potential exposure to 17 gross (5.21 net) wells that have either been recently drilled or are currently scheduled to be drilled. These consist of 3 gross (0.58 net) wells drilled in 2013, 1 gross (0.4 net) well that is currently in progress and 13 gross (4.23 net) additional wells currently scheduled to be drilled; 10 of which are expected to be drilled on the primary JV and 3 of which are expected to be drilled on the secondary JV."

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Potential Gas Discovery at North Kendang-1

South East Asia-focused Salamander Energy reported Thursday that it has suspended its North Kendang-1 exploration well, offshore Indonesia, as a potential gas discovery.

The NK-1 well – located in the South East Sangatta production sharing contract – was spud by the Ocean General (mid-water semisub) rig on February 10. So far, the well has been drilled to approximately 8,318 feet.

Salamander said the well drilled through a predominantly shale-prone section throughout the Pliocene and – on reaching the first Upper Miocene reservoir target at 8,310 feet – the well took "a significant kick from an influx of high pressure hydrocarbon gas" into the well bore at a wellhead pressure of around 4,000 pounds per square inch.

As a result of encountering high pressure gas, the well experienced what Salamander described as operational challenges that ultimately led to its suspension before evaluating the reservoir section. The gas has been sampled and is being analyzed with initial results pointing to a wet gas, while pressure data indicate a potentially significant column height.

Salamander is reviewing the option to return to NK-1 as part of the current drilling campaign, in order to drill ahead and evaluate the Upper Miocene section.

Salamander Chief Executive John Menzies commented in a statement:

"Finding wet gas at North Kendang is highly encouraging for continued exploration in the North Kutei basin, though further drilling will be required to determine reservoir quality and a range of hydrocarbon volumes. As the well results are integrated into the geological model and technical evaluation continues, we will drill the Bedug prospect with a view to returning to North Kendang thereafter."

Salamander said the Ocean General rig is now being mobilized to the Bontang PSC to drill the Bedug-1 exploration well, the third well in the firm's multi-well program in the North Kutei basin.

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BP Finds Gas Condensate at North Uist

Faroe Petroleum reported Friday that the 213/25c-1V exploration well, at the North Uist exploration prospect west of Shetland, has found gas condensate.

The well was targeting several reservoir objectives, the most significant of which was the North Uist prospect. It reached a total vertical depth of approximately 15,400 feet and encountered gas condensate in sandstone reservoirs in the target section.

Faroe said that an extensive data set was collected, including wireline logs, pressure data and side-wall cores. A full formation and volume evaluation is now underway.

The company added that preliminary results indicate varying reservoir quality and cautioned that the commercial potential has yet to be evaluated. Traces of hydrocarbons were also found in the shallower Cardhu prospect.

The 213/25c-1V exploration well is located near to Chevron’s Rosebank oil discovery, which is also on the Corona Ridge, west of the Shetland Islands.

The drilling operation was carried out by BP using the Stena Carron drillship. The well will now be plugged and abandoned.

Faroe Chief Executive Graham Stewart commented in a statement:

"After a long period of drilling activity on this wild-cat exploration well, we are pleased to have made a discovery in the North Uist exploration well, although we had however hoped for better quality reservoir.  The result proves another working hydrocarbon system in the frontier west of Shetlands which is good news for further prospectivity in these UK waters.

"The partnership will now undertake extensive analysis of the considerable volumes of data and samples collected from the well operations before deciding on the next steps."

London-based investment bank Westhouse Securities commented: "The wording of the press release in our view suggests that the prospect does not appear to be a commercial success (at least not at present)."

Oil sector analysts had a mixed response to the news. 

Analysts at FoxDavies were more upbeat. "That this well is currently still under review is promising, and the fact that this is a frontier area must also be borne in mind as, regardless of whether North Uist is a success of not… the data will be integrated into the existing seismic and help refine the understanding of the geology."

After a disappointing drilling campaign last year, capped by the plugging and abandoning of its Rodriguez South well in the Norwegian Sea, Faroe is participating in five exploration wells that will be drilled during the remainder of 2013.

Faroe holds a 6.25-percent stake in North Uist.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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Total Gets NPD Nod for North Sea Appraisal

The Norwegian Petroleum Directorate has granted Total E&P Norge AS a drilling permit for well 7225/3-2, cf. Section 8 of the Resource Management Regulations.

Wellbore 7225/3-2 will be drilled from the drilling facility Leiv Eiriksson (UDW semisub) at position 72 57' 05.17" north and 25 58' 23.34" east.

The drilling program for well 7225/3-2 relates to drilling of an appraisal well in production license 535. Total E&P Norge AS is the operator with an ownership interest of 40 percent. The other licensees are North Energy ASA with 20 percent, Det norske oljeselskap ASA with 20 percent, Valiant Petroleum Norge AS with 13 percent and Rocksource Exploration Norway AS with 7 percent.

The production license consists of blocks 7225/3 and 7226/1, and was awarded in the 20th licensing round in 2009.

Wildcat well 7225/3-2 is the second exploration well in production license 535.

The permit is contingent upon the operator securing all other permits and consents required by other authorities prior to starting drilling activities.

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Egdon Awarded North Sea License

UK-focused Egdon Resources reported Thursday that it has been awarded a license for North Sea blocks 41/18 and 41/19 off the North Yorkshire coast by the Department of Energy & Climate Change. The licence was awarded as a result of 26th UK Seaward Licensing Round and Egdon will hold a 100-percent interest as well as operatorship.

Egdon estimates potential for the drilled structure that already exists in the license area, the 41/18-1 well (drilled by Total in 1966), to contain substantial prospective resources in the range of between 40 and 272 billion cubic feet of gas.

Egdon intends to re-evaluate this gas discovery through a work program that will include the acquisition, reprocessing and interpretation of existing 2D seismic data over the blocks together with detailed analysis of the previous well results and regional geological evaluation. Egdon said that it would seek to drill a well from an onshore location to appraise the discovery made by the original 1966 well.

Egdon Managing Director Mark Abbot commented in a company statement:

"We are delighted to have been awarded this 26th Round license over these high potential blocks in one of our focus areas. We believe that our proposed approach of appraising and potentially developing this prospect via an onshore to offshore well could unlock the value in one of the earliest North Sea gas discoveries and we look forward to commencing our detailed technical evaluation."

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Maersk Extends North Sea Energy Enhancer Gig

Northern Offshore, Ltd. reported that its subsidiary, Northern Offshore U.K. Limited, has received a declaration from Maersk Olie og Gas AS exercising the first of three one-year options for the jackup Energy Enhancer (300' ILC). The commencement date of the option period is mid-July 2013, which commits the Energy Enhancer to Maersk for continued operation in the Danish Sector of the North Sea until June 2014. This option exercise adds approximately $48 million to the company's contracted revenue backlog.

"We are pleased with the opportunity to continue our relationship with Maersk and sincerely appreciate their commitment to Northern Offshore. The Energy Enhancer is performing very well and this contract extension provides a significant increase in revenue from this unit. There are two remaining one-year options and with the North Sea market continuing to strengthen, we remain optimistic about this sector for the foreseeable future," Gary W. Casswell, Northern Offshore's president and CEO, said.

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Maersk Extends North Sea Energy Enhancer Gig

Northern Offshore, Ltd. reported that its subsidiary, Northern Offshore U.K. Limited, has received a declaration from Maersk Olie og Gas AS exercising the first of three one-year options for the jackup Energy Enhancer (300' ILC). The commencement date of the option period is mid-July 2013, which commits the Energy Enhancer to Maersk for continued operation in the Danish Sector of the North Sea until June 2014. This option exercise adds approximately $48 million to the company's contracted revenue backlog.

"We are pleased with the opportunity to continue our relationship with Maersk and sincerely appreciate their commitment to Northern Offshore. The Energy Enhancer is performing very well and this contract extension provides a significant increase in revenue from this unit. There are two remaining one-year options and with the North Sea market continuing to strengthen, we remain optimistic about this sector for the foreseeable future," Gary W. Casswell, Northern Offshore's president and CEO, said.

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ConocoPhillips to Shut 3 North Sea Gas Fields

LONDON - ConocoPhillips will close its J-Block natural-gas operations in the U.K. North Sea for 10 days from April 8, the company said Thursday.

In a notice on its website, ConocoPhillips said the shut-down, which is weather dependent, will involve the Judy/Joanne, Jade and Jasmine fields, which together supply between 4.5 million and 5 million cubic meters of gas a day.

Last week, the U.K. government issued a statement to reassure consumers that the country's supply of natural gas would be sustained, despite the closure of a crucial pipeline connected to mainland Europe, during an ongoing period of unseasonably cold weather, and the low volume of gas in storage.

Also Thursday, Houston, Tx.-based ConocoPhillips said its onshore Teesside Oil Terminal, in northeast England, will close from July 3 to July 27. Crude oil and natural gas liquids from J-Block and the Greater Ekofisk Area fields are delivered to Teesside, at a rate of between 9.5 million and 10.7 million cubic meters a day.

Copyright (c) 2012 Dow Jones & Company, Inc.

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EnerMech Scores Work for BG Group's North Sea Fields

Mechanical engineering services company, EnerMech, has been awarded a process services contract by BG Group which could be worth up to $24 million (GBP 16 million).

The three year contract (+1 year option) covers all BG Group's UK North Sea assets including the Lomond, North Everest and Armada platforms.

The workscope includes the provision of topside process, flange management and nitrogen services and is the first contract EnerMech has secured with BG Group.

Aberdeen-based EnerMech said the contract win will create new jobs and take its total workforce to more than 1,400.

EnerMech's director of Process, Pipeline & Umbilicals, Les Graves, said: "We are looking forward to assisting BG Group in supporting their assets in the North Sea and this award reaffirms our position as a major supplier of process services to the oil and gas sector."

In January EnerMech acquired Australian valves engineering and servicing company, Valve Tech Engineering, in a multi-million pound deal which followed the acquisition in December of Cape Town based Water Weights International SA (Pty) Ltd which specializes in heavy load testing of cranes and lifting equipment.

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North Sea Oil Industry 'Needs UK's Stability'

The oil and gas industry is better supported as part of the UK than it would be in an independent Scotland, Coalition ministers have claimed, as they pledged to help boost investment and promote exports.

Scottish Secretary Michael Moore, Business Secretary Vince Cable and Energy Secretary Ed Davey published a long-term strategy to back the industry during a visit to Aberdeen.

Speaking to an audience of oil and gas executives, they said an independent Scotland would struggle to absorb the costs of supporting the industry, which include tax breaks for exploration and scrapping old rigs.

The claims came as a consortium of oil companies led by BP announced a GBP 330 million drilling program that could lead to further development of the giant Clair field in the Atlantic, west of Shetland.

Mr. Cable said oil and gas would continue to provide 70% of Britain's energy needs into the 2040s. He said the UK Government would provide tax certainty, supply chain support and skills development as part of its long-term plan.

Dismissing the SNP s drive for independence, he said: "A bigger country is better at absorbing shocks it's simple logic. A modest change has a significant impact on GDP. In a country 10 times smaller, the shock would be proportionally bigger."

Mr. Davey said: "Only the UK can deliver what is required over a sustained period if you are going to get the most out of the oil and gas industry. The UK is a large economy that is why we can provide the support. Smaller economies have difficulty absorbing the costs."

The SNP has put oil at the heart of its case for independence. First Minister Alex Salmond insists Scotland is on the cusp of a second oil boom, though the claim was dismissed by a think-tank earlier this week.

Fergus Ewing, Scottish Energy Minister, said: " I am delighted the UK Government is following the Scottish Government s lead in recognizing the importance of the industry by launching its own oil and gas strategy.

"It highlights the positive future of the industry, the extent of reserves, and the benefit to the balance of payments and production taxes. I welcome the view there will be a long-term future for the oil and gas industry well beyond 2055."

Meanwhile the BP-led consortium including Shell, Conoco-Phillips and Chevron said drilling had already begun on the first of five wells planned over the next two years at Clair.

Up to 12 wells could be drilled, depending on initial results.

The field, holding eight billion barrels, was discovered 35 years ago but production only started in 2005 owing to the difficulty of extracting and bringing the oil ashore.

BP North Sea regional president Trevor Garlick said: "This is a major milestone and a further big commitment to the west of Shetland by BP and its co-venturers. If successful, the appraisal program could pave the way for a third phase of development at Clair. This is now a real possibility."

Copyright 2013 Newsquest Media Group All Rights Reserved

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EnerMech Scores Work for BG Group's North Sea Fields

Mechanical engineering services company, EnerMech, has been awarded a process services contract by BG Group which could be worth up to $24 million (GBP 16 million).

The three year contract (+1 year option) covers all BG Group's UK North Sea assets including the Lomond, North Everest and Armada platforms.

The workscope includes the provision of topside process, flange management and nitrogen services and is the first contract EnerMech has secured with BG Group.

Aberdeen-based EnerMech said the contract win will create new jobs and take its total workforce to more than 1,400.

EnerMech's director of Process, Pipeline & Umbilicals, Les Graves, said: "We are looking forward to assisting BG Group in supporting their assets in the North Sea and this award reaffirms our position as a major supplier of process services to the oil and gas sector."

In January EnerMech acquired Australian valves engineering and servicing company, Valve Tech Engineering, in a multi-million pound deal which followed the acquisition in December of Cape Town based Water Weights International SA (Pty) Ltd which specializes in heavy load testing of cranes and lifting equipment.

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North Sea's Magnolia Prospect Comes Up Dry

The Magnolia exploration well was drilled to its target depth of approximately 4,920 feet true vertical depth subsea, fulfilling the partners' license obligations.

The well hit its primary targets – the Captain, Corable and Punt sandstones within the Lower Cretaceous interval – but no significant hydrocarbons were encountered, according to Trapoil. The well will now be plugged and abandoned.

The operator of license P1610 is Dana Petroleum, which has a 45-percent interest. Partners in the license include: Summit Petroleum (25 percent), Atlantic Petroleum UK (20 percent) and Trapoil (10 percent). The P1610 license is located to the south and southeast of the producing Captain Field in the Moray Firth and is also close to the Blake and Ross fields.

In February, Trapoil reported that it was buying one third of the Trent East Terrace Area license, located in the southern North Sea, from Perenco UK.

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North Sea's Magnolia Prospect Comes Up Dry

The Magnolia exploration well was drilled to its target depth of approximately 4,920 feet true vertical depth subsea, fulfilling the partners' license obligations.

The well hit its primary targets – the Captain, Corable and Punt sandstones within the Lower Cretaceous interval – but no significant hydrocarbons were encountered, according to Trapoil. The well will now be plugged and abandoned.

The operator of license P1610 is Dana Petroleum, which has a 45-percent interest. Partners in the license include: Summit Petroleum (25 percent), Atlantic Petroleum UK (20 percent) and Trapoil (10 percent). The P1610 license is located to the south and southeast of the producing Captain Field in the Moray Firth and is also close to the Blake and Ross fields.

In February, Trapoil reported that it was buying one third of the Trent East Terrace Area license, located in the southern North Sea, from Perenco UK.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here